OFFSHORE STANDARD DNV-OS-F101 SUBMARINE PIPELINE SYSTEMS

OCTOBER 2010

DET NORSKE VERITAS FOREWORD DET NORSKE VERITAS (DNV) is an autonomous and independent foundation with the objectives of safeguarding life, property and the environment, at sea and onshore. DNV undertakes classification, certification, and other verification and consultancy services relating to quality of ships, offshore units and installations, and onshore industries worldwide, and carries out research in relation to these functions. DNV service documents consist of amongst other the following types of documents: — Service Specifications. Procedual requirements. — Standards. Technical requirements. — Recommended Practices. Guidance. The Standards and Recommended Practices are offered within the following areas: A) Qualification, Quality and Safety Methodology B) Materials Technology C) Structures D) Systems E) Special Facilities F) Pipelines and Risers G) Asset Operation H) Marine Operations J) Cleaner Energy O) Subsea Systems

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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 person for 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 Det Norske Veritas. Offshore Standard DNV-OS-F101, October 2010 Changes – Page 3

Acknowledgement The current revision of DNV-OS-F101 has been sponsored by three different Joint Industry Projects. The work has been performed by DNV and discussed in several workshops with individuals from the different companies. They are hereby all acknowledged for their valuable and constructive input. In case consensus has not been achievable DNV has sought to provide acceptable compromise agreement. The two material related JIP's have in total been sponsored by:

BP MRM Technip Chevron NSC Tenaris Corus PTT V&M Europipe Saipem Vector FMC Sintef Vetco Hydro Statoil Woodside JFE Subsea7 The operation JIP has been sponsored by:

ConocoPhillips Gassco Shell DONG Hydro Statoil ENI In addition, individuals from the following companies have been reviewers in the hearing process:

Acergy Hydro Statoil Allseas Inoxtech Sumitomo Corp., Europe Butting Intec Tenaris Dalmine Europipe JFE V & M Deutschland Gorgon Nippon Steel DNV is grateful for the valuable co-operations and discussions with the individual personnel in these companies.

CHANGES •General • Main changes As of October 2010 all DNV service documents are primarily Since the previous edition (October 2007), this document has published electronically. been amended, most recently in October 2008. All changes have been incorporated and a new date (October 2010) has In order to ensure a practical transition from the “print” scheme been given as explained under “General”. to the “electronic” scheme, all documents having incorporated amendments and corrections more recent than the date of the latest printed issue, have been given the date October 2010. An overview of DNV service documents, their update status and historical “amendments and corrections” may be found through http://www.dnv.com/resources/rules_standards/.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 4 – Changes

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Contents – Page 5

CONTENTS

Sec. 1 General...... 13 Sec. 4 Design - Loads...... 34 A. General...... 13 A. General...... 34 A 100 Introduction...... 13 A 100 Objective...... 34 A 200 Objectives ...... 13 A 200 Application ...... 34 A 300 Scope and application ...... 13 A 300 Load scenarios ...... 34 A 400 Alternative methods and procedures...... 14 A 400 Load categories...... 34 A 500 Structure of Standard ...... 14 A 500 Design cases...... 34 A 600 Other codes ...... 14 A 600 Load effect combination...... 34 B. References ...... 15 B. Functional Loads ...... 34 B 100 Offshore Service Specifications...... 15 B 100 General...... 34 B 200 Offshore Standards ...... 15 B 200 Internal Pressure loads...... 34 B 300 Recommended Practices...... 15 B 300 External Pressure loads...... 35 B 400 Rules ...... 15 B 500 Certification notes and classification notes ...... 15 C. Environmental Loads...... 35 B 600 Other references...... 15 C 100 General...... 35 C 200 Wind loads...... 35 C. Definitions ...... 18 C 300 Hydrodynamic loads...... 35 C 100 Verbal forms ...... 18 C 400 Ice loads...... 36 C 200 Definitions ...... 18 C 500 Earthquake ...... 36 C 300 Definitions (continuation)...... 21 C 600 Characteristic environmental load effects ...... 36 D. Abbreviations and Symbols...... 22 D. Construction Loads...... 38 D 100 Abbreviations...... 22 D 100 General...... 38 D 200 Symbols ...... 24 D 300 Greek characters ...... 24 E. Interference Loads ...... 38 D 400 Subscripts...... 25 E 100 General...... 38 Sec. 2 Safety Philosophy...... 26 F. Accidental Loads ...... 38 F 100 General...... 38 A. General...... 26 A 100 Objective...... 26 G. Design Load Effects ...... 39 A 200 Application...... 26 G 100 Design cases...... 39 G 200 Load combinations...... 39 B. Safety Philosophy Structure ...... 26 G 300 Load effect calculations...... 40 B 100 General...... 26 B 200 Safety objective...... 26 Sec. 5 Design – Limit State Criteria ...... 41 B 300 Systematic review of risks ...... 27 B 400 Design criteria principles...... 27 A. General...... 41 B 500 Quality assurance...... 27 A 100 Objective...... 41 B 600 Health, safety and environment ...... 27 A 200 Application ...... 41 C. Risk Basis for Design ...... 27 B. System Design Principles ...... 41 C 100 General...... 27 B 100 Submarine pipeline system layout...... 41 C 200 Categorisation of fluids...... 27 B 200 Mill pressure test and system pressure test...... 42 C 300 Location classes ...... 28 B 300 Operating requirements ...... 43 C 400 Safety classes ...... 28 C 500 Reliability analysis...... 28 C. Design Format ...... 43 C 100 General...... 43 Sec. 3 Concept Development and Design Premises .... 29 C 200 Design resistance ...... 43 C 300 Characteristic material properties...... 44 A. General...... 29 C 400 Stress and strain calculations...... 45 A 100 Objective...... 29 A 200 Application...... 29 D. Limit States...... 46 A 300 Concept development ...... 29 D 100 General...... 46 D 200 Pressure containment (bursting) ...... 46 B. System Design Principles ...... 29 D 300 Local buckling - General ...... 46 B 100 System integrity ...... 29 D 400 Local Buckling – External over pressure only B 200 Monitoring/inspection during operation ...... 29 (System collapse)...... 46 B 300 Pressure Protection System...... 30 D 500 Propagation buckling ...... 47 B 400 Hydraulic analyses and flow assurance ...... 30 D 600 Local Buckling - Combined Loading Criteria...... 47 D 700 Global buckling ...... 49 C. Pipeline Route...... 31 D 800 Fatigue ...... 49 C 100 Location ...... 31 D 900 Ovalisation...... 50 C 200 Route survey ...... 31 D 1000 Accumulated deformation ...... 50 C 300 Seabed properties...... 32 D 1100 Fracture and supplementary requirement P ...... 50 D 1200 Ultimate limit state – Accidental loads...... 51 D. Environmental Conditions...... 32 D 100 General...... 32 E. Special Considerations ...... 51 D 200 Collection of environmental data...... 32 E 100 General...... 51 D 300 Environmental data...... 32 E 200 Pipe soil interaction ...... 51 E 300 Spanning risers/pipelines...... 52 E. External and Internal Pipe Condition ...... 33 E 400 On bottom stability ...... 52 E 100 External operational conditions ...... 33 E 500 Trawling interference...... 52 E 200 Internal installation conditions...... 33 E 600 Third party loads, dropped objects ...... 53 E 300 Internal operational conditions ...... 33 E 700 Thermal Insulation...... 53

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E 800 Settings from Plugs ...... 53 D. Clad or Lined Steel Linepipe...... 77 D 100 General...... 77 F. Pipeline Components and Accessories...... 53 D 200 Pipe designation ...... 77 F 100 General ...... 53 D 300 Manufacturing Procedure Specification ...... 77 F 200 Design of bends...... 54 D 400 Manufacture ...... 78 F 300 Design of insulating joints ...... 54 D 500 Acceptance criteria...... 78 F 400 Design of pig traps ...... 54 D 600 Inspection...... 79 F 500 Design of valves...... 54 F 600 Pipeline fittings ...... 55 E. Hydrostatic Testing...... 80 E 100 Mill pressure test...... 80 G. Supporting Structure...... 55 G 100 General ...... 55 F. Non-destructive Testing...... 80 G 200 Pipe-in-pipe and bundles...... 55 F 100 Visual inspection...... 80 G 300 Riser supports...... 55 F 200 Non-destructive testing ...... 80 G 400 J-tubes ...... 55 G 500 Stability of gravel supports and gravel covers ...... 55 G. Dimensions, Mass and Tolerances ...... 81 G 100 General...... 81 H. Installation and Repair...... 56 G 200 Tolerances ...... 81 H 100 General ...... 56 G 300 Inspection...... 82 H 200 Pipe straightness...... 56 H 300 Coating...... 56 H. Marking, Delivery Condition and Documentation ...... 84 H 100 Marking...... 84 Sec. 6 Design - Materials Engineering...... 57 H 200 Delivery condition...... 84 H 300 Handling and storage ...... 84 A. General...... 57 H 400 Documentation, records and certification ...... 84 A 100 Objective ...... 57 A 200 Application...... 57 I. Supplementary Requirements...... 84 A 300 Documentation ...... 57 I 100 Supplementary requirement, sour service (S)...... 84 I 200 Supplementary requirement, fracture arrest B. Materials Selection for Linepipe and properties (F)...... 85 Pipeline Components...... 57 I 300 Supplementary requirement, linepipe for plastic B 100 General ...... 57 deformation (P) ...... 86 B 200 Sour service...... 57 I 400 Supplementary requirement, dimensions (D) ...... 87 B 300 Corrosion resistant alloys (informative) ...... 58 I 500 Supplementary requirement, high utilisation (U) ...... 88 B 400 Linepipe (informative) ...... 58 B 500 Pipeline components (informative)...... 59 Sec. 8 Construction - Components and Assemblies... 89 B 600 Bolts and nuts...... 59 B 700 Welding consumables (informative)...... 59 A. General...... 89 A 100 Objective ...... 89 C. Materials Specification...... 59 A 200 Application...... 89 C 100 General ...... 59 A 300 Quality assurance ...... 89 C 200 Linepipe specification ...... 60 C 300 Components specification ...... 60 B. Component Requirements ...... 89 C 400 Specification of bolts and nuts ...... 60 B 100 General...... 89 C 500 Coating specification...... 60 B 200 Component specification...... 89 C 600 Galvanic anodes specification...... 61 B 300 Induction bends – additional and modified D. Corrosion Control...... 61 requirements to ISO 15590-1...... 89 D 100 General ...... 61 B 400 Fittings, tees and wyes - additional requirements to D 200 Corrosion allowance ...... 61 ISO 15590-2...... 90 D 300 Temporary corrosion protection...... 61 B 500 Flanges and flanged connections - additional D 400 External pipeline coatings (informative)...... 62 requirements to ISO 15590-3...... 91 D 500 Cathodic Protection...... 62 B 600 Valves – Additional requirements to ISO 14723...... 92 D 600 External corrosion control of risers B 700 Mechanical connectors...... 93 (informative) ...... 63 B 800 CP Insulating joints...... 93 D 700 Internal corrosion control (informative) ...... 64 B 900 Anchor flanges ...... 94 B 1000 Buckle- and fracture arrestors...... 94 Sec. 7 Construction – Linepipe ...... 66 B 1100 Pig traps...... 94 B 1200 Repair clamps and repair couplings...... 94 A. General...... 66 A 100 Objective ...... 66 C. Materials for Components ...... 94 A 200 Application...... 66 C 100 General...... 94 A 300 Process of manufacture ...... 66 C 200 C-Mn and low alloy steel forgings and castings...... 94 A 400 Supplementary requirements...... 66 C 300 Duplex stainless steel, forgings and castings...... 95 A 500 Linepipe specification ...... 66 C 400 Pipe and plate material...... 95 A 600 Manufacturing Procedure Specification and C 500 Sour Service ...... 95 qualification ...... 66 D. Manufacture...... 95 B. Carbon Manganese (C-Mn) Steel Linepipe...... 67 D 100 Manufacturing procedure specification (MPS) ...... 95 B 100 General ...... 67 D 200 Forging...... 95 B 200 Pipe designation ...... 67 D 300 Casting ...... 95 B 300 Manufacturing...... 67 D 400 Hot forming...... 96 B 400 Acceptance criteria...... 69 D 500 Heat treatment...... 96 B 500 Inspection ...... 72 D 600 Welding...... 96 D 700 NDT ...... 96 C. Corrosion Resistant Alloy (CRA) Linepipe ...... 75 C 100 General ...... 75 E. Mechanical and Corrosion Testing of Hot Formed, Cast and C 200 Pipe designation ...... 75 Forged Components...... 96 C 300 Manufacture ...... 75 E 100 General testing requirements ...... 96 C 400 Acceptance criteria...... 75 E 200 Acceptance criteria for C-Mn and low alloy steels ...... 97 C 500 Inspection ...... 76 E 300 Acceptance criteria for duplex stainless steels...... 98

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F. Fabrication of Risers, Expansion Loops, Pipe Strings for D 500 Installation procedures...... 109 Reeling and Towing...... 98 D 600 Contingency procedures ...... 109 F 100 General...... 98 D 700 Layvessel arrangement, laying equipment and F 200 Materials for risers, expansion loops, pipe strings for instrumentation ...... 109 reeling and towing ...... 98 D 800 Requirements for installation...... 110 F 300 Fabrication procedures and planning...... 98 F 400 Material receipt, identification and tracking...... 98 E. Additional Requirements for Pipeline Installation Methods F 500 Cutting, forming, assembly, welding and Introducing Plastic Deformations...... 111 heat treatment...... 98 E 100 General...... 111 F 600 Hydrostatic testing ...... 98 E 200 Installation manual...... 111 F 700 NDT and visual examination ...... 99 E 300 Qualification of the installation manual ...... 111 F 800 Dimensional verification...... 99 E 400 Installation procedures...... 111 F 900 Corrosion protection ...... 99 E 500 Requirements for installation...... 111 G. Hydrostatic Testing...... 99 F. Pipeline Installation by Towing...... 112 G 100 Hydrostatic testing ...... 99 F 100 General...... 112 G 200 Alternative test pressures...... 99 F 200 Installation manual...... 112 F 300 Qualification of installation manual ...... 112 H. Documentation, Records, Certification and Marking ...... 100 F 400 Operating limit conditions ...... 112 H 100 General...... 100 F 500 Installation procedures...... 112 F 600 Contingency procedures ...... 112 Sec. 9 Construction - Corrosion Protection and F 700 Arrangement, equipment and instrumentation ...... 112 Weight Coating...... 101 F 800 Pipestring tow and installation...... 112 A. General...... 101 G. Other Installation Methods ...... 112 A 100 Objective...... 101 G 100 General...... 112 A 200 Application...... 101 H. Shore Pull...... 113 B. External Corrosion Protective Coatings ...... 101 H 100 General...... 113 B 100 General...... 101 H 200 Installation manual...... 113 B 200 Coating materials, surface preparation, H 300 Qualification of installation manual ...... 113 coating application and inspection/testing of coating...101 H 400 Operating limit conditions ...... 113 H 500 Installation procedures...... 113 C. Concrete Weight Coating ...... 101 H 600 Contingency procedures ...... 113 C 100 General...... 101 H 700 Arrangement, equipment and instrumentation ...... 113 C 200 Concrete materials and coating manufacture...... 102 H 800 Requirements for installation...... 113 C 300 Inspection and testing ...... 102 I. Tie-in Operations...... 113 D. Manufacture of Galvanic Anodes...... 102 I 100 General...... 113 D 100 Anode manufacture...... 102 I 200 Installation manual...... 113 I 300 Qualification of installation manual ...... 113 E. Installation of Galvanic Anodes ...... 102 I 400 Operating limit conditions ...... 113 E 100 Anode installation...... 102 I 500 Tie-in procedures...... 113 I 600 Contingency procedures ...... 114 Sec. 10 Construction - Installation...... 104 I 700 Tie-in operations above water ...... 114 I 800 Tie-in operations below water ...... 114 A. General...... 104 A 100 Objective...... 104 J. As-Laid Survey...... 114 A 200 Application...... 104 J 100 General...... 114 A 300 Failure Mode Effect Analysis (FMEA) and J 200 Specification of as-laid survey...... 114 Hazard and Operability (HAZOP) studies...... 104 J 300 As-laid survey...... 114 A 400 Installation and testing specifications and drawings.....104 J 400 As-laid survey of corrosion protection systems...... 114 A 500 Installation manuals ...... 104 A 600 Quality assurance...... 104 K. Span Rectification and Pipeline Protection ...... 114 A 700 Welding...... 104 K 100 General...... 114 A 800 Non-destructive testing and visual examination...... 105 K 200 Span rectification and protection specification...... 114 A 900 Production tests...... 105 K 300 Span rectification...... 115 K 400 Trenching...... 115 B. Pipeline Route, Survey and Preparation...... 105 K 500 Post-installation gravel dumping ...... 115 B 100 Pre-installation route survey ...... 105 K 600 Grout bags and concrete mattresses...... 115 B 200 Seabed preparation...... 106 B 300 Pipeline and cable crossings ...... 106 L. Installation of Protective and Anchoring Structures...... 116 B 400 Preparations for shore approach ...... 106 L 100 General...... 116 C. Marine Operations ...... 106 M. Installation of Risers...... 116 C 100 General...... 106 M 100 General...... 116 C 200 Vessels ...... 106 M 200 Installation manual...... 116 C 300 Anchoring systems, anchor patterns and anchor M 300 Qualification of the installation manual ...... 116 positioning ...... 106 M 400 Operating limit conditions ...... 116 C 400 Positioning systems ...... 107 M 500 Contingency procedures ...... 116 C 500 Dynamic positioning...... 107 M 600 Requirements for installation...... 116 C 600 Cranes and lifting equipment...... 107 C 700 Anchor handling and tug management ...... 107 N. As-Built Survey ...... 116 C 800 Contingency procedures ...... 107 N 100 General...... 116 N 200 Specification of as-built survey ...... 116 D. Pipeline Installation ...... 107 N 300 As-built survey requirements...... 117 D 100 General...... 107 N 400 Inspection of impressed current cathodic corrosion D 200 Installation manual...... 108 protection system...... 117 D 300 Review and qualification of the installation manual, essential variables and validity ...... 108 O. Final Testing and Preparation for Operation ...... 117 D 400 Operating limit conditions ...... 109 O 100 General...... 117

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O 200 Specification of final testing and preparation for D. Construction - Installation and Pre-Commissioning...... 128 operation...... 117 D 100 General...... 128 O 300 Procedures for final testing and preparation for D 200 DFI-Resumé...... 129 operation...... 117 O 400 Cleaning and gauging...... 117 E. Operation - Commissioning...... 129 O 500 System pressure testing...... 118 E 100 General...... 129 O 600 De-watering and drying ...... 119 O 700 Systems testing...... 119 F. Operation ...... 129 F 100 General...... 129 P. Documentation...... 119 F 200 In-Service file...... 129 P 100 General ...... 119 G. Abandonment...... 129 Sec. 11 Operations and Abandonment...... 120 G 100 General...... 129 A. General...... 120 H. DFI Resumé...... 129 A 100 Objective ...... 120 H 100 General...... 129 A 200 Scope and application ...... 120 H 200 DFI resumé content...... 129 A 300 Responsibilities ...... 120 A 400 Authority and company requirements...... 120 I. Filing of Documentation...... 130 A 500 Safety philosophy...... 120 I 100 General...... 130 B. Commissioning...... 120 Sec. 13 Commentary (Informative)...... 131 B 100 General ...... 120 B 200 Fluid filling ...... 120 A. General...... 131 B 300 Operational verification ...... 120 A 100 Objective ...... 131 C. Integrity Management System...... 120 B. Cross References ...... 131 C 100 General ...... 120 C 200 Company policy ...... 121 C. Design Philosophy...... 132 C 300 Organisation and personnel...... 121 C 100 Safety Class discussion ...... 132 C 400 Condition evaluation and assessment methods...... 121 C 200 Structural reliability analyses...... 132 C 500 Planning and execution of activities ...... 121 C 300 Characteristic values ...... 133 C 600 Management of change ...... 121 C 700 Operational controls and procedures...... 121 D. Loads...... 133 C 800 Contingency plans...... 121 D 100 Conversion of pressures...... 133 C 900 Reporting and communication...... 121 C 1000 Audit and review...... 121 E. Design Criteria...... 133 C 1100 Information management ...... 121 E 100 General...... 133 E 200 Condition load effect factors...... 133 D. Integrity Management Process ...... 122 E 300 Calculation of nominal thickness...... 133 D 100 General ...... 122 E 400 Pressure containment - equivalent format...... 134 D 200 Evaluation of threats and condition ...... 122 E 500 Pressure containment criterion, incidental pressure D 300 External inspection...... 122 less than 10% above the design pressure...... 134 D 400 In-line inspection...... 123 E 600 HIPPS and similar systems ...... 134 D 500 Corrosion monitoring...... 123 E 700 Local buckling - Collapse ...... 135 D 600 Integrity assessment ...... 124 E 800 Buckle arrestor ...... 135 D 700 Mitigation, intervention and repairs...... 124 E 900 Local buckling - Moment...... 135 E 1000 Local buckling - Girth weld factor...... 135 E. Re-qualification ...... 125 E 1100 Ovalisation ...... 135 E 100 General ...... 125 E 200 Application...... 125 F. API Material Grades...... 136 E 300 Safety level...... 125 F 100 API material grades...... 136 E 400 System pressure test ...... 125 E 500 Deterioration ...... 125 G. Components and Assemblies...... 136 E 600 Design criteria ...... 125 G 100 Riser Supports...... 136 G 200 J-tubes ...... 136 F. De-commissioning...... 126 F 100 General ...... 126 H. Installation ...... 136 H 100 Safety class definition ...... 136 G. Abandonment...... 126 H 200 Coating...... 136 G 100 General ...... 126 H 300 Simplified laying criteria ...... 137 H 400 Reeling ...... 137 Sec. 12 Documentation...... 127 I. References...... 139 A. General...... 127 A 100 Objective ...... 127 App. A Structural Integrity of Girth Welds in B. Design...... 127 Offshore Pipelines...... 140 B 100 Structural...... 127 B 200 Linepipe and pipeline components A. General...... 140 (including welding) ...... 127 A 100 Objective ...... 140 B 300 Corrosion control systems and weight coating ...... 127 A 200 Introduction...... 140 B 400 Installation...... 128 A 300 Application...... 140 B 500 Operation...... 128 B 600 DFI-Resumé ...... 128 B. Assessment Categories ...... 141 B 100 General...... 141 C. Construction - Manufacturing and Fabrication ...... 128 C 100 Linepipe and pipeline component ...... 128 C. Generic ECA for Girth Welds Subject to Strains Less than C 200 Corrosion control system and weight coating ...... 128 0.4% Assessed According to ECA Static – Low...... 143 C 300 DFI-resumé ...... 128 C 100 General...... 143

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D. 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 ...... 173 D 100 General...... 145 E 300 Qualification of longitudinal and girth butt welds welding procedures ...... 173 E. Girth Welds under Strain-based Loading Assessed E 400 Qualification of welding procedures for According to ECA Static - Full ...... 148 corrosion resistant overlay welding...... 175 E 100 General...... 148 E 500 Qualification of procedures for Pin Brazing and E 200 Assessment methodology ...... 149 Aluminothermic welding of anode leads...... 176 E 600 Qualification of welding procedures F. Girth Welds Assessed for temporary and permanent attachments According to ECA Fatigue ...... 151 and branch welding fittings to linepipe ...... 176 F 100 General...... 151 E 700 Qualification of welding procedures for structural F 200 High-cycle fatigue...... 152 components...... 177 F 300 Low-cycle fatigue ...... 152 E 800 Qualification of welding procedures for hyperbaric dry welding ...... 177 G. Testing Requirements...... 152 G 100 General...... 152 F. Examination and Testing for Welding Procedure G 200 Straining and ageing ...... 153 Qualification ...... 177 F 100 General...... 177 H. ECA Validation Testing ...... 154 F 200 Visual examination and non-destructive testing H 100 General...... 154 requirements ...... 178 F 300 Testing of butt welds ...... 178 App. B Mechanical Testing and Corrosion Testing ... 156 F 400 Testing of weld overlay ...... 179 F 500 Testing of pin brazing and aluminothermic welds ...... 180 A. Mechanical Testing and Chemical Analysis ...... 156 F 600 Testing of welds for temporary and permanent A 100 General...... 156 attachments and branch outlet fittings to linepipe ...... 180 A 200 General requirements to selection and preparation of samples and test pieces ...... 156 G. Welding and PWHT Requirements ...... 180 A 300 Chemical analysis ...... 156 G 100 General...... 180 A 400 Tensile testing...... 156 G 200 Production welding, general requirements ...... 180 A 500 Charpy V-notch impact testing...... 157 G 300 Repair welding, general requirements ...... 181 G 400 Post weld heat treatment...... 182 A 600 Bend testing ...... 157 G 500 Welding of pipeline girth welds ...... 182 A 700 Flattening test...... 158 G 600 Welding and PWHT of pipeline components...... 183 A 800 Drop weight tear test...... 158 A 900 Fracture toughness testing ...... 158 H. Material and Process Specific Requirements ...... 183 A 1000 Specific tests for clad and lined linepipe ...... 159 H 100 Internally clad/lined carbon steel and A 1100 Metallographic examination and hardness testing...... 159 duplex stainless steel...... 183 A 1200 Straining and ageing ...... 160 H 200 13Cr martensitic stainless steel...... 184 A 1300 Testing of pin brazings and aluminothermic welds...... 161 H 300 Pin brazing and aluminothermic welding...... 185 B. Corrosion Testing ...... 161 I. Hyperbaric Dry Welding ...... 185 B 100 General...... 161 I 100 General...... 185 B 200 Pitting corrosion test ...... 161 I 200 Qualification and testing of welding personnel for B 300 Hydrogen Induced Cracking test ...... 161 hyperbaric dry welding ...... 185 B 400 Sulphide Stress Cracking test ...... 161 I 300 Welding processes for hyperbaric dry welding ...... 186 I 400 Welding consumables for hyperbaric dry welding...... 186 App. C Welding...... 165 I 500 Shielding and backing gases for hyperbaric dry welding ...... 186 A. Application ...... 165 I 600 Welding equipment and systems for hyperbaric dry A 100 General...... 165 welding ...... 186 A 200 Welding processes ...... 165 I 700 Welding procedures for hyperbaric dry welding...... 186 A 300 Definitions ...... 165 I 800 Qualification welding for hyperbaric dry welding ...... 187 A 400 Quality assurance...... 165 I 900 Qualification of welding procedures for hyperbaric dry welding...... 187 B. Welding Equipment, Tools and Personnel ...... 165 I 1000 Examination and testing ...... 187 B 100 Welding equipment and tools ...... 165 I 1100 Production welding requirements for dry hyperbaric B 200 Personnel...... 166 welding ...... 187 B 300 Qualification and testing of welding personnel for hyperbaric dry welding ...... 166 App. D Non-Destructive Testing (NDT) ...... 188

C. Welding Consumables...... 166 A. General...... 188 C 100 General...... 166 A 100 Objective...... 188 C 200 Chemical composition ...... 167 A 200 Applicability of requirements...... 188 C 300 Mechanical properties...... 167 A 300 Quality assurance...... 188 C 400 Batch testing of welding consumables for A 400 Non-destructive testing methods ...... 188 pipeline girth welds...... 167 A 500 Personnel qualifications...... 188 C 500 Shielding, backing and plasma gases...... 168 A 600 Timing of NDT...... 189 C 600 Handling and storage of welding consumables ...... 168 B. Manual Non-Destructive Testing and D. Welding Procedures...... 168 Visual Examination of Welds...... 189 D 100 General...... 168 B 100 General...... 189 D 200 Previously qualified welding procedures...... 168 B 200 Radiographic testing of welds ...... 189 D 300 Preliminary welding procedure specification ...... 169 B 300 Manual ultrasonic testing of welds in C-Mn/low alloy steel D 400 Welding procedure qualification record ...... 169 with C-Mn/low alloy steel weld deposits ...... 190 D 500 Welding procedure specification ...... 169 B 400 Manual ultrasonic testing of welds with CRA D 600 Welding procedure specification for repair welding ....169 (duplex, other stainless steels and D 700 Contents of pWPS...... 169 nickel alloy steel) weld deposits...... 193 D 800 Essential variables for welding procedures ...... 170 B 500 Manual magnetic particle testing of welds ...... 194

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B 600 Manual liquid penetrant testing of welds...... 195 A 200 References...... 222 B 700 Manual eddy current testing of welds ...... 195 B 800 Visual examination of welds...... 196 B. Basic Requirements ...... 222 B 900 Acceptance criteria for manual non-destructive testing B 100 General...... 222 of welds with nominal strains < 0.4% and no ECA...... 196 B 200 Documentation...... 223 B 1000 ECA based non-destructive testing acceptance criteria B 300 Qualification...... 223 for pipeline girth welds ...... 196 B 400 Ultrasonic system equipment and components...... 223 B 1100 Repair of welds ...... 199 B 500 Calibration (reference) blocks...... 224 B 600 Recorder set-up ...... 225 C. Manual Non-destructive testing and Visual Examination of B 700 Circumferential scanning velocity ...... 225 Plate, Pipe and Weld Overlay...... 199 B 800 Power supply...... 225 C 100 General ...... 199 B 900 Software ...... 225 C 200 Plate and pipe ...... 200 B 1000 Reference line, band position and coating cut-back .....225 C 300 Weld overlay ...... 200 B 1100 Reference line tools...... 225 C 400 Visual examination ...... 201 B 1200 Operators...... 225 C 500 Residual magnetism ...... 201 B 1300 Spares...... 225 C 600 Acceptance criteria for manual non-destructive B 1400 Slave monitors...... 225 testing of plate, pipe and weld overlay ...... 201 C. Procedure ...... 226 D. Non-destructive Testing and Visual Examination of C 100 General...... 226 Forgings...... 202 D 100 General ...... 202 D. Calibration (Sensitivity Setting) ...... 226 D 200 Ultrasonic and magnetic particle testing of C-Mn and D 100 Initial static calibration...... 226 low alloy steel forgings ...... 202 D 200 Gate settings...... 226 D 300 Ultrasonic and liquid penetrant testing of D 300 Recording Threshold...... 227 duplex stainless steel forgings...... 203 D 400 Dynamic calibration...... 227 D 400 Visual examination of forgings...... 204 D 500 Recording of set-up data ...... 227 D 500 Acceptance criteria for forgings...... 204 E. Field Inspection ...... 227 E. Non-destructive Testing and Visual Examination of E 100 Inspection requirements ...... 227 E 200 Operational checks...... 228 Castings ...... 204 E 300 Adjustments of the AUT system...... 229 E 100 General ...... 204 E 200 Ultrasonic and magnetic particle testing of F. Re-examination of Welds ...... 229 C-Mn and low alloy steel castings ...... 204 F 100 General...... 229 E 300 Ultrasonic and liquid penetrant testing of duplex stainless steel castings ...... 205 G. Evaluation and Reporting ...... 229 E 400 Radiographic testing of castings ...... 206 G 100 Evaluation of indications ...... 229 E 500 Visual examination of castings ...... 206 G 200 Examination reports ...... 229 E 600 Acceptance criteria for castings ...... 206 G 300 Inspection records ...... 229 F. Automated Non-Destructive Testing...... 206 H. Qualification ...... 229 F 100 General ...... 206 H 100 General...... 229 F 200 Documentation of function and operation ...... 207 H 200 Scope...... 229 F 300 Documentation of performance ...... 207 H 300 Requirements ...... 229 F 400 Qualification...... 207 H 400 Variables ...... 230 F 500 Evaluation of performance documentation ...... 207 H 500 Qualification programme ...... 230 H 600 Test welds ...... 230 G. Non-Destructive Testing at Plate and Coil Mill ...... 207 H 700 Qualification testing ...... 230 G 100 General ...... 207 H 800 Reference destructive testing ...... 231 G 200 Ultrasonic testing of C-Mn steel and CRA plates...... 207 H 900 Analysis...... 232 G 300 Ultrasonic testing of CRA clad C-Mn steel plate ...... 208 H 1000 Reporting...... 232 G 400 Alternative test methods...... 208 G 500 Disposition of plate and coil with unacceptable I. Validity of Qualification...... 232 laminations or inclusions ...... 208 I 100 Validity...... 232 G 600 Visual examination of plate and coil...... 208 I 200 Essential variables...... 232 G 700 Acceptance criteria and disposition of surface imperfections...... 208 J. Determination of Wave Velocities in Pipe Steels...... 232 J 100 General...... 232 H. Non-Destructive Testing of Linepipe at Pipe Mills...... 208 J 200 Equipment ...... 232 H 100 General ...... 208 J 300 Specimens ...... 233 H 200 Suspect pipe ...... 209 J 400 Test method...... 233 H 300 Repair of suspect pipe ...... 210 J 500 Accuracy ...... 233 H 400 General requirements for automated NDT systems...... 210 J 600 Recording...... 233 H 500 Visual examination and residual magnetism ...... 212 H 600 Non-destructive testing of pipe ends not tested by App. F Requirements for Shore Approach automated NDT equipment...... 213 and Onshore Sections...... 234 H 700 Non-destructive testing of pipe ends...... 213 H 800 Non-destructive testing of seamless pipe...... 214 A. Application ...... 234 H 900 Non-destructive testing of HFW pipe ...... 214 A 100 Objective ...... 234 H 1000 Non-destructive testing of CRA liner pipe ...... 215 A 200 Scope and limitation...... 234 H 1100 Non-destructive testing of lined pipe ...... 215 A 300 Other codes ...... 234 H 1200 Non-destructive testing of clad pipe ...... 216 A 400 Definitions...... 234 H 1300 Non-destructive testing of SAWL and SAWH pipe .....217 H 1400 Manual NDT at pipe mills ...... 219 B. Safety Philosophy ...... 235 H 1500 Non-destructive testing of weld repair in pipe ...... 221 B 100 General...... 235 B 200 Safety philosophy...... 235 App. E Automated Ultrasonic Girth Weld Testing.... 222 B 300 Quantification of consequence ...... 235 A. General...... 222 C. Design Premise ...... 236 A 100 Scope...... 222 C 100 General...... 236

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C 200 Routing ...... 236 E. Construction...... 238 C 300 Environmental data...... 236 E 100 General...... 238 C 400 Survey ...... 236 E 200 Linepipe ...... 238 C 500 Marking...... 237 E 300 Components and assemblies...... 238 E 400 Corrosion protection & coatings...... 238 D. Design...... 237 F. Operation ...... 238 D 100 General...... 237 F 100 General...... 238 D 200 System design ...... 237 D 300 Design loads...... 237 G. Documentation...... 238 D 400 Design criteria...... 237 G 100 General...... 238

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DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.1 – Page 13

SECTION 1 GENERAL

A. General the protection of the environment. — provide an internationally acceptable standard of safety A 100 Introduction for submarine pipeline systems by defining minimum 101 This standard gives criteria and guidance on concept requirements for concept development, design, construc- development, design, construction, operation and abandon- tion, operation and abandonment ment of Submarine Pipeline Systems. — serve as a technical reference document in contractual matters between Purchaser and Contractor A 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 summary General 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.1 Phases Concept development, design, construction, operation and abandonment Pipeline 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 pipe2 Extent 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 abandonment Geometry 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 A201 Loads 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 limitation Linepipe 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 F Fluids Categories Table 2-1 Sour service Generally conforming to ISO 15156 Installation 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

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applicable to this standard, may be designed according to this standard. — Appendix C contains requirements to welding including 3) 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 Testing 4) The owner may apply this standard on sub-sets of the limits of this stand- ard. Typical example of excluded items is smaller diameter piping such (AUT) of girth welds. 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 onshore A 400 Alternative methods and procedures parts of the submarine pipeline system. 401 In case alternative methods and procedures to those specified 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 specified herein, see Sec.2 C500. — nnn within the same sub-section (e.g. 512) — X or Xnnn to another sub-section within the same section A 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 given in 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.

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B. References B 400 Rules The latest revision of the following documents applies: B 100 Offshore Service Specifications The latest revision of the following documents applies: DNV Rules for Certification of Flexible Risers and Pipes DNV-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 Marine DNV-OSS-401 Technology Qualification Management Operations DNV Rules for Classification of Fixed Offshore B 200 Offshore Standards Installations The following documents contain provisions which, through reference in this text, constitute provisions of this Offshore B 500 Certification notes and classification notes Standard. The latest revision of the following document The latest revision of the following documents applies: applies. DNV CN 1.2 Conformity Certification Services, Type DNV-OS-A101 Safety Principles And Arrangements Approval DNV-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 rials DNV-OS-E201 Oil And Gas Processing Systems DNV CN 7 Non Destructive Testing DNV-OS-F201 Dynamic Risers DNV CN 30.4 Foundations DNV CN 30.6 Structural Reliability Analysis of Marine B 300 Recommended Practices Structures The latest revision of the following documents applies: B 600 Other references DNV-RP-A203 Qualification Procedures for New Technol- ogy API RP5L1 Recommended Practice for Railroad DNV-RP-B401 Cathodic Protection Design transportation of Line Pipe DNV-RP-C203 Fatigue Strength Analysis of Offshore Steel API5LW Recommended Practice for Transpor- Structures tation of Line Pipe on Barges and Marine Vessels DNV-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 Edition DNV-RP-F102 Pipeline Field Joint Coating & Field Repair ASME/ANSI B16.9 Factory-Made Wrought Buttwelding of Linepipe Coating Fittings DNV-RP-F103 Cathodic Protection of Submarine Pipelines ASME B31.3 2004 Process Piping by Galvanic Anodes DNV-RP-F105 Free Spanning Pipelines ASME B31.4 2006 Pipeline Transportation Systems for Liquid Hydrocarbons and Other DNV-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 Systems DNV-RP-F108 Fracture Control for Pipeline Installation ASME BPVC-V BPBV Section V - Non-destructive Methods Introducing Cyclic Plastic Strain Examination DNV-RP-F109 On-bottom Stability Design of Submarine ASME BPVC-VIII-1 BPVC Section VIII - Div. 1 - Rules for Pipelines Construction of Pressure Vessels DNV-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 Rules DNV-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 Plastics DNV-RP-F113 Pipeline Subsea Repair ASTM A370 Standard Test Methods and Defini- DNV-RP-F204 Riser Fatigue tions for Mechanical Testing of Steel DNV-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

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ASTM 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 defect ASTM 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 rules ASTM E165 Standard Test method for Liquid Pen- for gasketed circular flange connec- etrant Inspection tions - Part 1: Calculation method ASTM 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 ultrasonic ASTM 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 weld ASTM 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 transportation ASTM E1444 Standard Practice for Magnetic Parti- systems cle Examination ISO 2400 Welds in steel -- Reference block for ASTM 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 in AWS C5.3 Recommended Practices for Air Car- steel, nickel, titanium and their alloys bon Arc Gouging and Cutting (beam welding excluded) - Quality levels for imperfections BSI 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 analysis BSI PD 5500 Specification for Unfired fusion ISO 7005-1 Metallic flanges – Part 1: Steel welded pressure vessels Flanges EN 287-1 Qualification test of welders - Fusion ISO 7963 Non-destructive testing -- Ultrasonic welding - Part 1:Steels testing --- Specification for calibration block No. 2 EN 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

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ISO 9000 Quality management systems -- Fun- ISO 12094 Welded steel tubes for pressure pur- damentals and vocabulary poses - Ultrasonic testing for the ISO 9001 Quality management systems - detection of laminar imperfections in Requirements strips or plates used in manufacture of welded tubes ISO 9001 Quality systems -- Model for quality assurance in production, installation ISO 12095 Seamless and welded steel tubes for and servicing pressure purposes - Liquid penetrant testing ISO 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 profiles ISO 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 area ISO 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 for ISO 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 and ISO 9712 Non-destructive testing -- Qualifica- responsibilities tion and certification of personnel ISO14732 Welding personnel -- Approval testing ISO 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 materials ISO 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 carbon ISO 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 alloys ISO 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: Offshore ISO 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 flanges ISO 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

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ISO 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 increments ISO 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 to ISO 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 completed ISO 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 during ISO 17640 Non-destructive testing of welds -- installation of the pipeline. Ultrasonic testing of welded joints 207 Atmospheric zone: The part of the pipeline system above ISO 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 and MSSSP-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 upper NS 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- C. Definitions pose 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 product order to conform to this standard and from which no deviation manufactured in lengths that require spooling onto a take-up is permitted. reel, during the primary milling or manufacturing process. 102 Should: Indicates that among several possibilities, one is 216 Commissioning; Activities associated with the initial recommended 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 Offshore Standard DNV-OS-F101, October 2010 Sec.1 – Page 19 the pipeline temporarily out of service. particles or liquid droplets. 218 Commissioning, Pre-, Activities after tie-in/connection 236 Fabrication: Activities related to the assembly of and 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 strength 219 Concept development phase: The concept development in order to compensate for material strength reduction from phase 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 and included 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; or components in the pipeline system to create a structural joint — deterioration of functional capability to such an extent that resisting applied loads and preventing leakage. Examples: the safety of the installation, personnel or environment is Threaded 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 the flanges, 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 multiple 222 Construction phase: The construction phase will typi- extruded headers, reducers and transition sections cally include manufacture, fabrication and installation activi- 242 Flange: Collar at the end of a pipe usually provided with ties. Manufacture activities will typically include manufacture holes in the pipe axial direction for bolts to permit other objects of linepipe and corrosion protection and weight coating. Fab- to be attached to it. rication activities will typically include fabrication of pipeline components and assemblies. Installation activities will typical 243 Fluid categorisation: Categorisation of the transported include 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 Fx()= p design, construction and operation. p

224 Corrosion allowance (tcorr): Extra wall thickness added F is the distribution function for xp during 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, see Sec.6 D200. 246 Hydrogen Induced Cracking (HIC): Internal cracking of rolled materials due to a build-up of hydrogen pressure in 225 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 while 226 Corrosion protection: Use of corrosion resistant materi- subjected to tensile stresses (residual and/or applied). The als, 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 necessarily ing leakage. embrittled by hydrogen. HISC by corrosion in presence of 228 Design: All related engineering to design the pipeline hydrogen sulphide is referred to as Sulphide Stress Cracking including 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 test ries, 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 a tial installation or use until permanent decommissioning of the product or service and comparing the results with specified equipment 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 the 232 Design phase: The design phase will typically be split Contractor to describe and demonstrate that the installation into FEED-phase, basic design and detail design. For each method and equipment used by the Contractor will meet the design 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 the hydrodynamic 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, through 234 Engineering Critical Assessment (ECA): Fracture which a pipe can be pulled to form a riser. The J-tube extends mechanics assessment of the acceptability of flaws in metallic from the platform deck to and inclusive of the bottom bend at materials. 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.

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256 Limit state: A state beyond which the structure no longer 276 Offshore installation (object): General term for mobile satisfies the requirements. The following limit states catego- and fixed structures, including facilities, which are intended ries 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 of 257 Lined pipe (L): Pipe with internal (corrosion resistant) valves, or failure of the pressure control system and activation liner where the bond between (linepipe) backing steel and liner of the pressure safety system. material is mechanical. 278 Operation, Normal: Conditions that arise from the 258 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 include 259 Load categories: Functional load, environmental load, steady flow conditions over the full range of flow rates, as well interference load or accidental load, see Sec.4 A. as possible packing and shut-in conditions where these occur 260 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 the mation, 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 include 262 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 obtain the 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 as see 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 or application 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 seam sible for planning, execution and documentation of manufac- formed by welding without the addition of filler metal. The turing. longitudinal seam is generated by high frequency current 268 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 hot ified properties may be achieved and verified through the forming process resulting in a tubular product without a proposed manufacturing route. welded seam. The hot forming may be followed by sizing or cold finishing to obtain the required dimensions. 269 Material resistance factor (γm): Partial safety factor transforming a characteristic resistance to a lower fractile 286 Pipe, Submerged Arc-Welded Longitudinal or Helical resistance, see Sec.5 C200 Table 5-4. (SAWL or SAWH): Pipe manufactured by forming from strip or plate, and with one longitudinal (SAWL) or helical 270 Material strength factor (αu ): Factor for determination of the characteristic material strength reflecting the confidence (SAWH) seam formed by the submerged arc process with at in 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 the 273 Nominal pipe wall thickness: The specified non-cor- submarine pipeline system to operate safely and withstand the roded 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 integrity 274 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 Offshore Standard DNV-OS-F101, October 2010 Sec.1 – Page 21 tankage, 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 positive any other equipment, facility or building used in the transpor- tolerance of the pressure safety system, see Figure 1 and tation of fluids. Sec.3 B300. See also Submarine pipeline system. 304 Pressure, Maximum Allowable Operating (MAOP): In 291 Pipeline walking: Accumulation of incremental axial relation to pipelines, this is the maximum pressure at which the displacement 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 the 292 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 not exceeded, 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 manufacture 293 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 pressure associated instrument and alarm systems, see Figure 1 and during 1-year operation. Sec.3 B300. 307 Pressure, Propagating (ppr): The lowest pressure 294 Pressure safety system: The system which, independent required for a propagating buckle to continue to propagate, see of 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 be 295 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, this 297 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 test to a specified reference elevation, see Figure 1 and Sec.3 B300. the pipeline system for tightness (normally performed as 298 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 his is the maximum internal pressure the pipeline or pipeline sec- behalf, who is responsible for procuring materials, components tion 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- 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 necessary procedures and instructions for planning and per- forming the required actions). Accidental Accidental Pressure Incidental Pressure Pressure Internal 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 Protection required standards and specifications. System

Pressure Pressure 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. procedures and work instructions) applicable to the specific case. Pressure Pressure Control System 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 stated C 300 Definitions (continuation) conditions of operation and maintenance and during a speci- fied time interval. 301 Pressure, Initiation: The external over-pressure required to initiate a propagating buckle from an existing local buckle 317 Re-qualification: The re-assessment of a design due to or 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 a Local 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 and sure adjusted for the column weight, see Sec.4 B200. installations above water. The riser extends to the above sea 303 Pressure, Maximum Allowable Incidental (MAIP): In emergency isolation point between the import/export line and relation 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 2010 Page 22 – Sec.1 keep 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 floater riser, its supports, all integrated pipelining components, and — the connection point to the subsea installation (i.e. piping corrosion protection system. manifolds are not included) — the first valve, flange, connection or insulation joint at a 322 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. In quantitative terms, risk is the quantified probability of a The component above (valve, flange, connection, insulation defined 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 or respect 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 material which 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 for 325 Single event: Straining in one direction. specific applications. 326 Slamming: Impact load on an approximately horizontal 339 System effects: System effects are relevant in cases member from a rising water surface as a wave passes. The where many pipe sections are subjected to an invariant loading direction 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 pipeline 328 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 not 329 Specified Minimum Yield Stress (SMYS): The minimum included, see Sec.2 C500. yield stress prescribed by the specification or standard under which the material is purchased. 342 Temperature, design, maximum: The highest possible temperature profile to which the equipment or system may be 330 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 of waves and tides. 343 Temperature, design, minimum: The lowest possible temperature profile to which the component or system may be 331 Splash Zone Height: The vertical distance between exposed to during installation and operation. This may be splash zone upper limit and splash zone lower limit. applied locally, see Sec.4 B107 332 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. -2 a probability of being exceeded equal to 10 , as determined 351 Yield Stress (YS): The measured yield tensile stress. from the long term distribution of individual waves. If this value is not available, an approximate value of the splash zone height may be taken as: 100 0.46 Hs D. Abbreviations and Symbols Where D 100 Abbreviations 100 Hs = significant wave height with a 100 year return period 335 Submarine Pipeline: A submarine pipeline is defined as ALS Accidental Limit State the 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), see The pipeline may, be resting wholly or intermittently on, or Sec.7 B102 buried below, the seabed. API American Petroleum Institute 336 Submarine Pipeline System: a submarine pipeline sys- ASD Allowable Stress Design tem extends to the first weld beyond: ASME American Society of Mechanical Engineers

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.1 – Page 23

ASTM American Society for Testing and Materials MPQT Manufacturing Procedure Qualification Test AUT Automated Ultrasonic Testing MPS Manufacturing Procedure Specification BE Best Estimate MR Modified Requirement (to ISO 3183), see BM Base material Sec.7 B102 BS British Standard MSA Manufacturing Survey Arrangement C Clad pipe MT Magnetic Particle Testing C-Mn Carbon Manganese MWP Multiple Welding Process CP Cathodic Protection N Normalised CRA Corrosion Resistant Alloy NACE National Association of Corrosion Engineers CTOD Crack Tip Opening Displacement NDT Non-Destructive Testing CVN Charpy V-Notch OD Outside Diameter DAC Distance Amplitude Correction P Production DC Displacement controlled PIM Pipeline Integrity Management DFI Design, Fabrication and Installation PRE Pitting Resistance Equivalent DNV Det Norske Veritas PRL Primary Reference Level DP Dynamic Positioning PT Penetrant Testing DWTT Drop Weight Tear Testing PTFE Poly Tetra Flour Ethylene EBW Electron Beam Welded PWHT Post weld heat treatment EC Eddy Current Testing pWPS preliminary Welding Procedure Specification ECA Engineering Critical Assessment Q Qualification EDI Electronic Data Interchange QA Quality Assurance EMS Electro Magnetic Stirring QC Quality Control ERW Electric Resistance Welding QP Quality Plan ESD Emergency Shut Down QRA Quantitative Risk Assessment FEED Front End Engineering Design QT Quenched and Tempered FLS Fatigue Limit State ROV Remotely Operated Vehicle FMEA Failure Mode Effect Analysis RT Radiographic testing G-FCAW Gas-Flux Core Arc Welding SAWH Submerged Arc-welding Helical GMAW Gas Metal Arc Welding SAWL Submerged Arc-welding Longitudinal HAT Highest Astronomical Tide SC Safety Class HAZ Heat Affected Zone SCF Stress Concentration Factor HAZOP Hazard and Operability Study SCR Steel Catenary Riser HFW High Frequency Welding SENB Singel Edge Notched Bend fracture mechanics specimen HIPPS High Integrity Pressure Protection System SENT Single Edge Notched Tension fracture mechan- HIC Hydrogen Induced Cracking ics specimen HISC Hydrogen Induced Stress Cracking SLS Serviceability Limit State ID Internal Diameter SMAW Shielded Metal Arc Welding IM Installation Manual SMLS Seamless Pipe ISO International Organization for Standardization SMTS Specified Minimum Tensile Strength J-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 failure KV Charpy value SNCF Strain Concentration Factor KVL Charpy value in pipe longitudinal direction SRA Structural Reliability Analysis KVT Charpy value in pipe transversal direction SSC Sulphide Stress Cracking L Lined pipe or load effect ST Surface testing LAT Lowest Astronomic Tide TCM Two Curve Method LB Lower Bound TMCP Thermo-Mechanical Controlled Process LC Load controlled TOFD Time of Flight Diffraction LBW Laser Beam Welded TRB Three Roll Bending LBZ Local Brittle Zones UB Upper Bound LRFD Load and Resistance Factor Design ULS Ultimate Limit State LSZ Splash Zone Lower Limit UO Pipe fabrication process for welded pipes M/A Martensitic/Austenite UOE Pipe fabrication process for welded pipes, MAIP Maximum Allowable Incidental Pressure expanded MAOP Maximum Allowable Operating Pressure USZ Splash Zone Upper Limit MDS Material Data Sheet

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 24 – Sec.1

UT Ultrasonic testing pel Elastic collapse pressure, see Eq. 5.11 UTS Ultimate Tensile Strength pf Failure probability VT Visual Testing pf,T Target nominal failure probability WM Weld Metal ph Mill test pressure, see Sec.7 E100 WPQT Welding Procedure Qualification Test pi Characteristic internal pressure WPS Welding Procedure Specification pinc Incidental pressure YS Yield Stress pinit Initiation pressure p D 200 Symbols ld Local design pressure p Local incidental pressure, see Eq. 4.1 201 Latin characters li plt Local test pressure (system test), see Eq. 4.2 a Crack depth pp Plastic collapse pressure, see Eq. 5.12 A Cross section area ppr Propagating pressure, see Eq. 5.16 Ae 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 5.2 Ai 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 or As π ⋅()D − t ⋅t Pipe steel cross section area Resistance R Tensile strength B Specimen width m Rpx Strength equivalent to a permanent elongation of D 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 failure E Young's Modulus Sr Ultimate state f0 t Characteristic thickness to be replaced by t or t Dmax _ Dmin Ovality c 1 2 as relevant, see Table 5-2 D T Temperature f Minimum of f and f /1.15, see Eq. 5.9 cb y u t, tnom Nominal wall thickness of pipe (un-corroded) f Tensile strength to be used in design, see Eq. 5.6 u T0 Testing temperature fu,temp Derating on tensile stress to be used in design, see t , t Pipe wall thickness, see Table 5-2 Eq. 5.6 1 2 tcorr Corrosion allowance, see Table 5-2 fy 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 t Fabrication thickness tolerance, see Table 7-18 g Gravity acceleration fab t Measured minimum thickness H Residual lay tension, see Eq. 4.10 and Eq. 4.11 m,min Tmax Maximum design temperature, see Sec.4 B100 hl Local height at pressure point, see Eq. 4.1 Tmin Minimum design temperature, see Sec.4 B100 Hp Permanent plastic dent depth tmin Minimum thickness href Elevation at pressure reference level, see Eq. 4.1 Tpop Planned operational period, see Sec.4 C600 Hs Significant wave height TR/TR’ Reference period for operation/ceasing opera- ID Nominal inside diameter tion, see Sec.4 C600 k number of stress blocks TSafe Planned time to cease operation, see Sec.4 C600 L Characteristic load effect TWF Time between generated weather forecasts. MMoment W Section modulus or Specimen thickness. N Axial force in pipe wall ("true" force) (tension is W Submerged weight positive) or Number of load effect cycles sub ni Number of stress blocks D 300 Greek characters Ni Number of stress cycles to failure at constant amplitude α Thermal expansion coefficient O Out of roundness, Dmax - Dmin αc Flow stress parameter, see Eq. 5.22 OD Outside nominal diameter αfab Fabrication factor, see Table 5-7 pb Pressure containment resistance, see Eq. 5.8 αfat Allowable damage ratio for fatigue, see Table 5-9 pc Characteristic collapse pressure, see Eq. 5.10 αgw Girth weld factor (strain resistance), see Eq. 5.30 pd Design pressure PDi (i’th) Damaging event, see Eq. 5.34 pe External pressure

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.1 – Page 25

αh ⎛ R ⎞ ρcont Density pipeline content ⎜ t0,5 ⎟ ⎜ R ⎟ ρt Density pipeline content during system pressure ⎝ m ⎠ max test Minimum strain hardening σ Standard deviation of a variable (e.g. thickness) αp Pressure factor used in combined loading criteria, σ Equivalent stress, Von Mises, see Eq. 5.38 see Eq. 5.23 e σh Hoop stress, see Eq. 5.39 αpm Plastic moment reduction factor for point loads, see Eq. 5.26 σl Longitudinal/axial stress, see Eq. 5.40 τ lh Tangential shear stress αU Material strength factor, see Table 5-6 β Factor used in combined loading criteria D 400 Subscripts ε Strain A Accidental load εc Characteristic bending strain resistance, see Eq. 5.30 BA Buckle arrestor εf Accumulated plastic strain resistance c Characteristic resistance εl.nom Total nominal longitudinal strain d Design value εp Plastic strain Sd Design load (i.e. including load effect factors) εr Residual strain Rd Design resistance (i.e. including partial resistance factors) εr,rot Residual strain limit E Environmental load γA Load effect factor for accidental load, see Table 4-4 e External γC Condition load effect factor, see Table 4-5 el Elastic γE 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) direction γinc Incidental to design pressure ratio, see Table 3-1 M Moment γm Material resistance factor, see Table 5-4 p Plastic γrot Safety factor for residual strain R Radial direction γSC Safety class resistance factor, see Table 5-5 s Steel η Usage factor SSLS κ Curvature UULS ν Poisson’s ratio X Crossover (buckle arrestors) μ Friction coefficient

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 26 – Sec.2

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 overall tion, operation and abandonment of pipelines. level, but may be followed by more detailed objectives and requirements in specific areas. These policies should be used as A 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 systems which 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 pipeline 202 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 the final 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 ment, design and construction phases; and maintain integrity in impose any threat to fishing gear. - Diverless installation and maintenance. the operations phase. Statements such as those above may have implications for all or 203 This section also provides guidance for extension of this individual phases only. They are typically more relevant for the standard 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 safety 101 The integrity of the submarine pipeline system con- objective, one could also start with a risk assessment. The risk structed to this standard is ensured through a safety philosophy assessment could identify all hazards and their consequences, and then enable back-extrapolation to define acceptance criteria integrating 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 in safety systems shall be in accordance with DNV-OS-A101 and the choice of three safety classes (see B400). The choice of safety DNV-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 Abandonment Business development Business development Concept Basic design Detail design Linepipe and assemblies Components coating weight and protection Corrosion Pre-intervention Installation Post-intervention Pre-commissioning Commissioning management Integrity repair and Inspection Re-qualification 2* & 3 4, 5 & 6789 10 11 Establish Integrity Maintain Integrity

Figure 1 *indicates Section in this Standard. Integrity assurance activities during the pipeline system phases

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 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 system B 300 Systematic review of risks — corrective action to establish possible acceptability of 301 A systematic review shall be carried out at all phases to products identify and evaluate threats, the consequences of single fail- — preventative action to prevent re-occurrence of similar ures and series of failures in the pipeline system, such that nec- non-conformities. essary remedial measures can be taken. The extent of the review 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 frequent human activity and thus a greater likelihood and consequence of damage to the pipeline. This also includes areas where pipe- lines are installed parallel to existing pipelines and pipeline C. Risk Basis for Design crossings. C 100 General B 400 Design criteria principles 101 The design format within this standard is based upon a 401 In this standard, structural safety of the pipeline system limit state and partial safety factor methodology, also called is ensured by use of a safety class methodology. The pipeline Load and Resistance Factor Design format (LRFD). The load system 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 is assigned to each limit state. C 200 Categorisation of fluids B 500 Quality assurance 201 Fluids to be transported by the pipeline system shall be categorised according to their hazard potential as given by 501 The safety format within this standard requires that Table 2-1.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 28 – Sec.2

Table 2-1 Classification of fluids 403 For normal use, the safety classes in Table 2-4 apply: Category 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 E B Flammable and/or toxic fluids which are liquids at Location Class Location Class ambient temperature and atmospheric pressure condi- tions. Typical examples are oil and petroleum products. 12 1 2 Methanol is an example of a flammable and toxic fluid. Temporary1,2 Low Low - - 3 C Non-flammable fluids which are non-toxic gases at Operational Low Medium Medium High ambient temperature and atmospheric pressure condi- tions. Typical examples are nitrogen, carbon dioxide, 1) Installation until pre-commissioning (temporary phase) will normally be argon and air. classified as safety class Low. D Non-toxic, single-phase natural gas. 2) For safety classification of temporary phases after commissioning, spe- E Flammable and/or toxic fluids which are gases at ambi- cial consideration shall be made to the consequences of failure, i.e. giving ent temperature and atmospheric pressure conditions a higher safety class than Low. and which are conveyed as gases and/or liquids. Typical 3) Risers during normal operation will normally be classified as safety class examples would be hydrogen, natural gas (not otherwise High. covered under category D), ethane, ethylene, liquefied petroleum gas (such as propane and butane), natural gas * Other classifications may exist depending on the conditions and critical- liquids, ammonia, and chlorine. ity of failure the pipeline. For pipelines where some consequences are more severe than normal, i.e. when the table above does not apply, the 202 Gases or liquids not specifically identified in Table 2-1 selection of a higher safety class shall also consider the implication, on should be classified in the category containing fluids most sim- the total gained safety. If the total safety increase is marginal, the selec- ilar in hazard potential to those quoted. If the fluid category is tion of a higher safety class may not be justified. not clear, the most hazardous category shall be assumed. C 500 Reliability analysis C 300 Location classes 501 As an alternative to the LRFD format specified and used 301 The pipeline system shall be classified into location in this standard, a recognised structural reliability analysis classes as defined in Table 2-2. SRA) based design method may be applied provided that:

Table 2-2 Classification of location — the method complies with DNV Classification Note no. Location Definition 30.6 "Structural reliability analysis of marine structures" 1 The area where no frequent human activity is antic- — the approach is demonstrated to provide adequate safety ipated along the pipeline route. for familiar cases, as indicated by this standard. 2 The part of the pipeline/riser in the near platform (manned) area or in areas with frequent human Guidance note: activity. The extent of location class 2 should be based on appropriate risk analyses. If no such anal- In particular, this implies that reliability based limit state design yses are performed a minimum distance of 500 m shall not be used to replace the pressure containment criterion in shall be adopted. Sec.5 with the exception of accidental loads.

C 400 Safety classes ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 401 Pipeline design shall be based on potential failure conse- 502 Suitably competent and qualified personnel shall perform quence. In this standard, this is implicit by the concept of the structural reliability analysis, and extension into new areas of safety 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- Table 2-3 Classification of safety classes els shall be calibrated against identical or similar pipeline Safety Definition designs that are known to have adequate safety on the basis of class this standard. If this is not feasible, the nominal target failure Low Where failure implies low risk of human injury and probability level shall be based on the failure type and safety minor environmental and economic consequences. class as given in Table 2-5. This is the usual classification for installation phase. Medium For temporary conditions where failure implies risk of Table 2-5 Nominal failure probabilities vs. safety classes human injury, significant environmental pollution or Limit Probability Bases Safety Classes very high economic or political consequences. This is States Low Medium High Very the usual classification for operation outside the plat- 4) form area. High 1) -2 -3 -3 -4 High For operating conditions where failure implies high risk SLS Annual per Pipeline 10 10 10 10 of human injury, significant environmental pollution or ULS 2) Annual per Pipeline1) very high economic or political consequences. This is FLS Annual per Pipeline3) 10-3 10-4 10-5 10-6 the usual classification during operation in location class 2. ALS Annual per Pipeline - Pressure containment 10-4- 10-5-10-6 10-6- 10-7-10-8 402 The partial safety factors related to the safety class are 10-5 10-7 given in Sec.5 C100. 1) Or the time period of the temporary phase. 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 Offshore Standard DNV-OS-F101, October 2010 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 to A 100 Objective presence of ice. 101 This section identifies and provides a basis for definition 304 An execution plan should be developed, including the of 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 phases A 200 Application — contacts with Purchaser, authorities, third party, engineer- 201 This section applies to all pipeline systems which are to ing, verification and construction Contractors be 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 aspects related to design, construction, operation and abandonment should be considered. Due account should be given to identifi- cation of potential aspects which can stop the concept from B. System Design Principles being 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 resistance 302 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 unplanned 303 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 system's 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- uations ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — 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 2010 Page 30 – Sec.3 previous experience are not sufficient for a reliable prediction of 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 Typical maximum be determined in the design phase. pressure - monotonic B 300 Pressure Protection System decay. 301 A pressure protection system shall be used unless the pressure source to the pipeline system cannot deliver a pres- sure in excess of the incidental pressure including possible dynamic effects. The pressure protection system shall prevent the internal pressure at any point in the pipeline system rising to an excessive level. The pressure protection system com- Function Denisty Probability prises the pressure control system, pressure safety system and associated instrumentation and alarm systems.

Guidance note: Pre ssure 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 not exceeded at any point in the pipeline system during normal Typical maximum operation. The pressure control system should operate auto- pressure distribution for matically. The local design pressure is defined in Sec.4 B200. high integrity pressure Due account shall be given to the tolerances of the pressure protection systems control 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 pressure control system operating tolerance. 303 The purpose of the pressure safety system is to protect

the downstream system during incidental operation, i.e. to Probability Denisty Function ensure that the local incidental pressure is not exceeded at any point in the pipeline system in the event of failure of the pres- sure control system. The pressure safety system shall operate automatically. Due account shall be given to the tolerances of Pre ssure the pressure safety system. Hence, the maximum allowable incidental pressure is equal to the incidental pressure minus the Figure 2 pressure 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 probability of exceedance less than 10-2. If the pressure probability density -2 function does not have a monotonic decay beyond 10 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 in pressure 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 When the submarine pipeline system is connected to another sys- inc 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 Offshore Standard DNV-OS-F101, October 2010 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 particular 402 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, normal operation, shut-down (e.g. closing of valves) and all foreseen 104 It is recommended that pipeline ends are designed with non-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 the maximum design temperature profile based on conservative C 200 Route survey insulation values reflecting the variation in insulation proper- 201 Surveys shall be carried out along the total length of the ties of coatings and surrounding seawater, soil and gravel. planned pipeline route to provide sufficient data for design and 404 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 define peratures locally due to e.g. opening of valves is allowed and an installation and pipeline corridor which will ensure safe shall 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 existing 101 The pipeline route shall be selected with due regard to and planned installations and possible wrecks and obstructions safety of the public and personnel, protection of the environ- shall be performed. Examples of such installations include ment, and the probability of damage to the pipe or other facil- other submarine pipelines, and power and communication ities. 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 accurate minimum, include the following: route maps and alignments, scale commensurate with required Environment 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 environment Seabed 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 the Facilities 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 unstable Third 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 2010 Page 32 – Sec.3 performed. 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 Conditions C 300 Seabed properties 301 Geotechnical properties necessary for evaluating the D 100 General effects of relevant loading conditions shall be determined for 101 Environmental phenomena that might impair proper the seabed deposits, including possible unstable deposits in the functioning of the system or cause a reduction of the reliability vicinity 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 —tide 302 Geotechnical properties may be obtained from generally — waves available geological information, results from seismic surveys, — internal waves and other effects due to differences in water seabed topographical surveys, and in-situ and laboratory tests. density Supplementary information may be obtained from visual sur- —current veys or special tests, as e.g. pipe penetration tests. —ice — earthquake 303 Soil parameters of main importance for the pipeline — soil conditions response 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 data quate laboratory tests or from interpretation of in-situ tests. In 201 The environmental data shall be representative for the addition, classification and index tests should be considered, geographical areas in which the pipeline system is to be such 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 amount 304 It is primarily the characteristics of the upper layer of and accuracy of data shall be assessed and, if significant, shall soil 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 along shallow soils may be relatively more uncertain than for deeper the pipeline route, the pipeline may be divided into a number soils. Also the variations of the top soil between soil testing of sections, each of which is characterised by a given water locations 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 characteristic value(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 principle uncertainties. 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. This tom including boundary layer effects may be required for the may include tidal current, wind induced current, storm surge on-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 respect 306 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 Offshore Standard DNV-OS-F101, October 2010 Sec.3 – Page 33

304 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 conditions phenomena 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 conditions 101 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 inspection ment 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 during the design life 102 Other conditions affecting external corrosion which shall 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 and 103 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 fluid tem for onshore vs. offshore pipeline sections. shall be considered. Reference is made to DNV-RP-O501 104 The impact on the external pipe condition of the third Erosive Wear in Piping Systems.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 34 – Sec.4

SECTION 4 DESIGN - LOADS

A. General B. Functional Loads A 100 Objective B 100 General 101 This section defines the design loads to be checked by 101 Loads arising from the physical existence of the pipeline the 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 — weight 201 This section applies to all parts of the submarine pipeline — external hydrostatic pressure system. — internal pressure — temperature of contents A 300 Load scenarios — pre-stressing 301 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 structure cross 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, both sidered. vertical and horizontal — permanent deformations due to frost heave 302 The most unfavourable scenario for all relevant phases — changed axial friction due to freezing and conditions shall be considered. Typical conditions to be — possible loads due to ice interference, e.g. bulb growth covered 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 operation A 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 shall ferent 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 exceedance 402 Unless the load is categorised as accidental it shall be less than of 10-2. Different temperature profiles for different categorised 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 account described 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 shall 501 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 taken be governed either by the 100-year functional load effect, the into account if the capacity to carry other loads is affected by 100-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 be 601 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 loads Each 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 Offshore Standard DNV-OS-F101, October 2010 Sec.4 – Page 35

Pressure (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 in

Table 4-1 Pressure terms Pressure Abbreviations Symbol Description Mill test - Ph Hydrostatic test pressure at the mill, see Sec.7 System test - Pt The pressure to which the complete submarine pipeline system is tested to prior to commissioning, see Sec.5 B200 Incidental - Pinc Maximum pressure the submarine pipeline system is designed for Maximum 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 tolerance Design - 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 pressure Maximum 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 loads 202 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 from umn 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- (4.1) ding). pli = pinc + ρcont ⋅ g ⋅()href − hl (4.2) C 300 Hydrodynamic loads plt = pt + ρt ⋅ g ⋅ ()href − hl 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 be pinc 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 or relative water particle velocity hl is the elevation of the local pressure point (positive upwards) — inertia forces which are in phase with the absolute or rela- tive water particle acceleration plt 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, and ρt 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 open B 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 the external pressure shall not be taken as higher than the water analysis may be required to have a robust design. pressure 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 describing 302 In cases where the external pressure decreases the the wave kinematics at the particular water depth in question capacity, the external pressure shall not be taken as less than including surf zones hydrodynamics where applicable. The the water pressure at the considered location corresponding to suitability of the selected theory shall be demonstrated and high astronomic tide including storm surge. documented.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 36 – Sec.4

305 The current-induced drag and lift forces on the subma- the normal wave impact zone, may be exposed to wave loading rine 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 and wave-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 growth interaction is preferable. — Increased pipe surface roughness and resulting increase in 306 Data from model testing or acknowledged industry prac- drag coefficient and reduced lift coefficient tice may be used in the determination of the relevant hydrody- — Any beneficial effect of the weight of the marine growth namic coefficients. shall be ignored in stability analyses 307 Where appropriate, consideration shall be given to wave 317 Tide loads shall be considered when the water depth is a direction, short crested waves, wave refraction and shoaling, significant parameter, e.g. for the establishment of wave shielding 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 a function of water depth shall be considered. C 400 Ice loads 309 Where parts of the pipeline system are positioned adja- 401 In areas where ice may develop or drift, the possibility cent to other structural parts, possible effects due to distur- of ice loads on the pipeline system shall be considered. Such bance of the flow field shall be considered when determining loads may partly be due to ice frozen on the pipeline system the wave and/or current actions. Such effects may cause an itself, and partly due to floating ice. For shore approaches and increased or reduced velocity, or dynamic excitation by vorti- areas of shallow water, the possibility of ice scouring and ces 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 accidental number of closely spaced pipes, then interaction and solidifi- depending on its frequency. cation effects shall be taken into account when determining the mass and drag coefficients for each individual pipe or for the 402 In case of ice frozen to parts of the submarine pipeline whole bundle of pipes. If sufficient data is not available, large- system, (e.g. due to sea spray) the following forces shall be scale model tests may be required. considered: 311 For pipelines on or close to a fixed boundary (e.g. pipe- — weight of the ice line spans) or in the free stream (e.g. risers), lift forces perpen- — impact forces due to thaw of the ice dicular to the axis of the pipe and perpendicular to the velocity — forces due to expansion of the ice vector shall be taken into account (possible vortex induced vibrations). — increased wind, waves and current forces due to increased exposed area. 312 In connection with vortex shedding-induced transverse vibrations, the increase in drag coefficient shall be taken into 403 Forces from floating ice shall be calculated according to account. 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 ice ence 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. When submarine 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 Offshore Standard DNV-OS-F101, October 2010 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 ’ : Contingency time to Δ : Start-up time C start cease operation

TC: Contingency time TWF: Weather forecast intervals T : Operation R T’ =T +T +T reference period R WF Safe C

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 End

Figure 1 unfavourable relevant combination, position and direction of Determination 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 environmental weather 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 for Uncertainty in the weather forecast for the operational period a given seastate and appropriate current and wind conditions shall 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 1 FL()= 1 – ---- (4.3) that it can be ceased and put into safe condition within 72 hours E N including 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 based on reliable weather forecast less than established operation F(LE) is the cumulative distribution function of LE, and N is the limit during this operational reference period for ceasing the number of load effect cycles in a sea-state of a duration not less operation. 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 quake the duration is less than 6 months unless defined as weather Permanent condition restricted conditions. The environmental load effect for tempo- rary conditions shall be taken as the 10-year return period for 100-year 100-year 10-year the 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-year 605 Conditions not defined as weather restricted conditions 1-year 1-year 1-year 10-year or temporary conditions shall be defined as permanent condi- tions. The environmental load effect for permanent conditions 10-year shall 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 2010 Page 38 – Sec.4

D. Construction Loads E. Interference Loads D 100 General E 100 General 101 Loads which arise as a result of the construction of the 101 Loads which are imposed on the pipeline system from pipeline system, comprising installation, pressure testing, 3rd party activities shall be classified as interference loads. commissioning, maintenance and repair, shall be classified These loads include but are not limited to trawl interference, into functional and environmental loads. anchoring, vessel impacts and dropped objects. 102 All significant loads acting on pipe joints or pipe sec- 102 The requirement for designing the submarine pipeline sys- tions during transport, fabrication, installation, maintenance tem for interference loads shall be determined based upon inter- and repair activities shall be considered. ference frequency studies and assessment of the potential damage. If the annual probability of occurrence is less than 10-2 103 Functional Loads shall consider forces generated due to the load shall be classified as accidental load, see F. imposed tension during pipeline installation, maintenance and repair. 103 For calculations of trawl interference loads, reference is 104 Environmental loads shall consider forces induced on given to DNV-RP-F111 Interference between Trawl Gear and the pipeline due to wind, waves and current, including deflec- Pipelines. tions and dynamic loads due to vessel movement. 104 The trawling loads can be divided in accordance with the 105 Accidental loads shall consider inertia forces due to sud- three crossing phases: den water filling, excessive deformation in overbend and sag- bend, and forces due to operation errors or failures in 1) Trawl impact, i.e. the initial impact from the trawl board equipment that could cause or aggravate critical conditions, or beam which may cause local dents on the pipe or dam- see Sec.10 A300. age to the coating. 106 Other loads to be considered are: 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- — stacking of pipes ing over the pipe. This will usually give a more global — handling of pipe and pipe sections, e.g. lifting of pipe, pipe response of the pipeline. joints, pipe strings and pipe spools, and reeling of pipe 3) Hooking, i.e. the trawl board is stuck under the pipe and in strings extreme cases, forces as large as the breaking strength of — pull-in at landfalls, tie-ins, trenching etc. the trawl wire are applied to the pipeline. — pressure testing — commissioning activities, e.g. increase in pressure differ- Hooking is normally categorised as an accidental load. ential due to vacuum drying. 105 The trawl impact energy shall be determined consider- 107 Operating limit conditions shall be established relevant ing, as a minimum: for the construction activity under consideration, see C600 and Sec.10 D400. — the trawl gear mass and velocity 108 Typical construction loads for pre-installed risers, riser — the effective added mass and velocity. supports/guides and J-tubes on jackets and similar installations The impact energy shall be used for testing of the pipeline are: coatings and possible denting of the pipeline wall thickness. In case piggy-back lines these shall also have adequate safety — wind-induced forces, in particular wind-induced vortex against trawl impacts. Reference is given to DNV-RP-F111. shedding, on parts which are designed to be submerged after installation of the load-bearing structure 106 Other 3rd party interference loads shall be calculated — deflections/forces generated during load-out of the load- using recognised methods. bearing structure — transportation forces due to barge movements — launch forces due to deflection and hydrodynamic loads (drag, slam and slap) on the structure F. Accidental Loads — deflections/forces generated during installation of load- bearing structure F 100 General — inertia loads on the riser supports/guides due to pile driv- 101 Loads which are imposed on a pipeline system under ing abnormal and unplanned conditions and with an annual proba- — re-distribution of support forces when possible temporary bility of occurrence less than 10-2 shall be classified as acci- riser supports are removed and the riser turned into the dental loads. final position — cold springing of the risers (elastic pre-deformations) 102 Typical accidental loads can be caused by: — tie-in forces generated when the riser is connected to the tie-in spool/pipeline — extreme wave and current loads — dynamic loads from pre-commissioning activities, e.g. — vessel impact or other drifting items (collision, grounding, flooding and de-watering with pigs. sinking, iceberg) — dropped objects 109 The load combinations to be considered shall be selected — seabed movement and/or mud slides to reflect the most severe load combinations likely to be —explosion encountered during the construction phase under considera- tion. — fire and heat flux — operational malfunction 110 The most severe load effect may be taken as mean ±3 — dragging anchors. standard deviations unless otherwise stated. Guidance note: 103 Size and frequency of accidental loads, for a specific This will typically apply to when dimensional tolerances are added. pipeline system, may be defined through risk analyses. Refer- ence is also made to DNV-RP-F107 Risk Assessment of Pipe- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- line Protection.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.4 – Page 39

G. Design Load Effects extreme functional, environmental, interference or accidental load effect. These have been denoted design cases. Unless spe- G 100 Design cases cial evaluation of critical 100-year design case is carried out, 101 Each static limit state, see Sec.5 D, shall be checked for the design cases defined by combinations of characteristic load the load effect induced by the most critical 100-year design effects in Table 4-3 shall be used. case of functional, environmental, interference and accidental 103 In addition to the conditions defined above, fatigue limit loads. The 100-year load effect is the load with an annual prob- -2 state and accidental condition shall also be checked. The char- ability of 10 of exceedance in a period of one year. acteristic load definitions for this combination are given in 102 The most critical combination is normally governed by Table 4-3.

Table 4-3 Combinations of characteristic loads effects for different design cases Design case Load Functional Environmental Interference Accidental combination5) load load load load Functional design case a, b 100-year1) 1-year Associated NA Environmental design case a, b Associated2) 100-year3) Associated NA Interference design case b Associated2) Associated UB NA Fatigue design4) case c Associated Associated Associated NA Accidental design case d Associated Associated Associated BE Characteristic load definition n-year: Most probable maximum in n years, UB: Upper Bound, BE: Best estimate

1) 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 following format: design criteria, e.g. Eq. (5.19).

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- L = L ⋅γ ⋅γ + L ⋅γ + L ⋅γ ⋅γ + L ⋅γ ⋅γ (4.4) Sd F F c E E I F c A A c 202 The design load effect shall be calculated for each In 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 c (4.6) ε Sd = ε F ⋅γ F ⋅γ c + ε E ⋅γ E + ε I ⋅γ F ⋅γ c + ε A ⋅γ A ⋅γ c (4.7) SSd = SF ⋅γ F ⋅γ c + SE ⋅γ E + SI ⋅γ F ⋅γ c + SA ⋅γ A ⋅γ c

Table 4-4 Load effect factors and load combinations Limit State / Load Design load combination Functional loads 1) Environmental load Interference loads Accidental loads combination γ F γ E γ F γ A ULS a System check2) 1.2 0.7 b Local check 1.1 1.3 1.1 FLS c 1.0 1.0 1.0 ALS d 1.0 1.0 1.0 1.0

1) 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 2010 Page 40 – Sec.4

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 (f and f ) considered load (in the extreme case, “flat sea”), the whole pipeline will y u 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 global in Table 4-5. Condition load effect factors are in addition to the response of a pipeline is denoted S. Counting tensile force as load effect factors and are referred to explicitly in Eq. (4.5, 4.6 positive: and 4.7). π 2 2 (4.8) Table 4-5 Condition load effect factors, γ S()pi = N− pi ⋅ Ai + pe ⋅ Ae = N− ⋅()pi ⋅()D−2⋅t2 − pe ⋅D C 4 Condition γc Pipeline resting on uneven seabed 1.07 307 Split up into functional, environmental and accidental effective force, the following applies: Continuously stiff supported 0.82

System pressure test 0.93 π 2 2 SF ()pi = N F − pi ⋅ Ai + pe ⋅ Ae = N F − ⋅()pi ⋅()D − 2⋅t2 − pe ⋅ D Otherwise 1.00 4 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 = N Reference is given to DNV-RP-F110 Global Buckling of Subma- A 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 calculations 301 The design analyses shall be based on accepted princi- S = H − Δp ⋅ A ⋅ 1− 2 ⋅ν − A ⋅ E ⋅α ⋅ ΔT (4.11) ples of statics, dynamics, strength of materials and soil i i ()s mechanics. where: 302 Simplified methods or analyses may be used to calculate the load effects provided that they are conservative. Model H = Effective (residual) lay tension tests may be used in combination with, or instead of, theoreti- Δ pi = Internal pressure difference relative to as laid cal calculations. In cases where theoretical methods are inade- ΔΤ = Temperature difference relative to as laid.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 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 layout 101 This section provides design and acceptance criteria for — space requirements the possible modes of structural failure in pipeline systems. — movements of the Riser or J-tube A 200 Application — cable/pipeline approach — Riser or J-tube protection 201 This standard includes no limitations on water depth. — in-service inspection and maintenance However, 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 achieved 202 This standard does not specify any explicit limitations by one or a combination of the following means: with respect to elastic displacements or vibrations, provided that the effects of large displacements and dynamic behaviour, — concrete coating including fatigue effect of vibrations, operational constraints — burial and 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 only applicable to pipelines that are straight in stress-free condition 107 Relative settlement between the protective structure and and are not applicable to e.g. bends. the submarine pipeline system shall be properly assessed in the 204 For parts of the submarine pipeline system which extend design of protective structures, and shall cover the full design onshore complementary requirements are given in life of the submarine pipeline system. Adequate clearance Appendix 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, and B 100 Submarine pipeline system layout avoiding penetration into the main pipe material. Other welds shall be continuous, and made in a manner minimising the risk 101 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 other 102 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 doubler ders, etc. The minimum distance should be determined based rings, clamps, or other parts of supports. upon anticipated deflections, hydrodynamic effects, and upon risk-based evaluations. The detailed routing shall take the min- 112 Riser and J-tube supports shall be designed to ensure a imum 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 fluids impact loads from vessels and other mechanical interaction. of categories B, D and E (see Sec.2 C) should be designed for Risers and J-tubes should not be located inside the loading inspection pigging. In cases where the pipeline design does not zones of platforms. allow inspection pigging, an analysis shall be carried out in

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 42 – Sec.5 accordance 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 the consequences of failure) leading to a leak is acceptable. For plt ≥ 1.05 · pli (5.1) corrosive fluids of other categories the benefit of inspection pigging on operational reliability shall be evaluated. — Low Safety Class during normal operation: 115 For piggable components the internal diameter of the component 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 test Local 201 The purposes of the mill test are: Local requirement incidental design 5% above pli pressure, p — to constitute a pressure containment proof test pressure li — to ensure that all pipe sections have a minimum yield stress. Internal pressure Internal Filled with Filled with Therefore, the mill test pressure is defined in terms of stress water operating utilisation, see Sec.7 E100, rather than in terms of design pres- 1 content sure. 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 test 202 The purpose of the system pressure test is to prove the pressure 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 as 203 The pipeline system shall be system pressure tested after with the system pressure test is allowed by agreement given installation in accordance with Sec.10 O500 unless this is that the mill pressure test requirement of Sec.7 E100 has been waived 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 the following requirement: limitations in Table 5-1 for waiving the system pressure test.

Table 5-1 Requirements to waive system pressure test Requirement Other 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 the safety 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 errors

lation. ---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 Offshore Standard DNV-OS-F101, October 2010 Sec.5 – Page 43

Table 5-1 Requirements to waive system pressure test (Continued) Requirement All 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 critical detectability 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 plastic strains 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). R ()f ,t B 300 Operating requirements R = c c c (5.4) Rd γ ⋅γ 301 Operating requirements affecting safety and reliability m SC of the pipeline system shall be identified during the design where phase, and shall be documented in the DFI Resumé and R is the characteristic resistance reflected in the PIM system. c fc is the characteristic material strength, see Eq. 5.5 and Eq.5.6 tc is the characteristic thickness, see Table 5-2 and C. Design Format Table 5-3 γm, γSC are the partial resistance factors, see Table 5-4 and 5-5 C 100 General 202 Two different characterisations of the wall thickness are 101 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 in ify 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 tt-tcorr

Where 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 corrosion acteristic 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 the 104 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 state C 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 2010 Page 44 – Sec.5

Table 5-3 Minimum wall thickness requirements Nominal 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 - Medium The 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 in E404. C 300 Characteristic material properties

205 The material resistance factor, γm, is dependent on the 301 Characteristic material properties shall be used in the limit 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 engineering Table 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 to be used in the limit state criteria are: γ m 1.15 1.00 1) The limit states (SLS, ULS, ALS and FLS) are defined in D. (5.5) f y = ()SMYS − f y,temp ⋅α U 206 Based on potential failure consequences the pipeline f = SMTS − f ⋅α (5.6) shall be classified into a safety class see Sec.2 C400. This will u ()u,temp U be reflected in the safety level by the Safety Class resistance Where: factor γSC given in Table 5-5. 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 tensile locations. 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 regard Pressure containment 2) 1.046 3),4) 1.138 1.308 1) to material type and potential temperature and/or ageing Other 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 strength 2) The number of significant digits is given in order to comply with the ISO — Young's 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 is documented. 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 stress discontinuity 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 Offshore Standard DNV-OS-F101, October 2010 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-Mn and 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- erties 305 Any difference in the de-rating effect of temperature for — variations in cross sectional area (actual diameter or wall tension 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 calculated Table 5-6 Material Strength factor, αU from the point where the material stress-strain curve deviates Factor Normally Supplementary requirement U from a linear relationship, see Figure 3. αU 0.96 1.00 Stress Note: For system pressure test, αU shall be equal to 1.00, which gives an allowable 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 cold deformations giving different strength in tension and compres- 0.5% Strain sion, a fabrication factor, αfab, shall be determined. If no other information exists, maximum fabrication factors for pipes Figure 3 manufactured by the UOE or UO processes are given in Reference for plastic strain calculation Table 5-7. The fabrication factor may be improved through heat treatment or external cold sizing (compression), if documented. Guidance note: The yield stress is defined as the stress at which the total strain is Table 5-7 Maximum fabrication factor, α 0.5%. As an example for a 415 grade C-Mn steel, a unidirectional fab strain of 0.5% corresponds to an elastic strain of approximately Pipe Seamless UO & TRB & UOE 0.2% and a plastic strain of 0.3%.

ERW ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- α fab 1.00 0.93 0.85

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 46 – Sec.5

D. Limit States — system collapse (external pressure only) — propagation buckling D 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 in Sec.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 2 2 D (pc ()t − pel ()t )⋅ ()pc ()t − p p ()t = pc ()t ⋅ pel ()t ⋅ p p ()t ⋅ f 0 ⋅ - 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) ⎝ D ⎠ ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- p ()t = el 1−ν 2 102 In case no specific design criterion is given for a specific 2⋅t limit 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 – D D 200 Pressure containment (bursting) f = ------max min- o D 201 The following criteria are valid provided that the mill (5.13) pressure 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 5-7 teria: Guidance note: In the above formulas, t shall be replaced by t1 or t2 as given in the design criteria. pb ()t1 (5.7) p − p ≤ lx e ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- γ m ⋅γ SC Where Guidance note: Ovalisation caused during the construction phase shall be plx = pli during operation, (see Sec.3 B300 and 4 B200) and included in the total ovality to be used in design. Ovalisation due p = p during system test. to external water pressure or bending moment shall not be lx lt 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 pipeline pb ()t = ⋅ fcb ⋅ (5.8) D − t 3 shall meet the following criterion (system collapse check): where pc ()t1 pe − pmin ≤ (5.14) f γ m ⋅γ SC ⎡ u ⎤ (5.9) fcb = Min⎢ f y ; ⎥ ⎣ 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 minimum 204 Reduction in pressure containment resistance due to true wall thickness, t . compressive forces (load controlled), N, shall be considered. 1 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 to D 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 Offshore Standard DNV-OS-F101, October 2010 Sec.5 – Page 47

D 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 local buckling 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 installed and spacing determined based on cost and spare pipe philoso- D 600 Local Buckling - Combined Loading Criteria phy. 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 ⎛ 2 ⎞ D/t < 45 (5.16) 603 A displacement-controlled condition is one in which the p 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 axis is imposed but the circumferential bending that leads to Propagating pressure, ppr, is the pressure required to continue a 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, effective An 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:

p X p ≤ (5.17) 2 e 1.1⋅γ ⋅γ ⎧ 2 ⎫ 2 m SC ⎪ M Sd ⎪⎧γ ⋅γ ⋅ S ()p ⎪⎫ ⎪ ⎛ p − p ⎞ m SC Sd i ⎜ i e ⎟ ⎨γ m ⋅γ SC ⋅ + ⎨ ⎬ ⎬ + ⎜α p ⋅ ⎟ ≤1 αc ⋅ M p ()t2 ⎪ αc ⋅ S p ()t2 ⎪ ⎝ αc ⋅ pb ()t2 ⎠ where the crossover pressure px is ⎩⎪ ⎩ ⎭ ⎭⎪ (5.19a) ⎡ ⎛ t ⋅ L ⎞⎤ 2 BA (5.18) pX = p pr + ()p pr,BA − p pr ⋅ ⎢1− EXP⎜− 20 2 ⎟⎥ ⎣ ⎝ D ⎠⎦ 2 ⎧ 2 ⎫ 2 ⎪ M Sd '()t2 ⎧γ m ⋅γ SC ⋅ SSd '()pi ,t2 ⎫ ⎪ ⎛ pi − pe ⎞ ⎨γ m ⋅γ SC ⋅ + ⎨ ⎬ ⎬ + ⎜α p ⋅ ⎟ ≤1 ppr,BA is the propagating buckle capacity of an infinite arres- α α ⎜ α ⋅ p ()t ⎟ tor. This is calculated by Eq. 5.16 with the buckle arre- ⎩⎪ c ⎩ c ⎭ ⎭⎪ ⎝ c b 2 ⎠ 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 2010 Page 48 – Sec.5

pi is the internal pressure, see Table 4-3 the following equation: pe is the external pressure, see Sec.4 B300 2 p is the burst pressure, Eq. 5.8 2 2 b ⎧ ⎧ ⎫ ⎫ ⎪ M Sd ⎪γ m ⋅γ SC ⋅ SSd ⎪ ⎪ ⎛ pe − pmin ⎞ Sp and Mpdenote the plastic capacities for a pipe defined by: ⎨γ m ⋅γ SC ⋅ + ⎨ ⎬ ⎬ + ⎜γ m ⋅γ SC ⋅ ⎟ ≤1 α ⋅ M ()t ⎪ α ⋅ S ()t ⎪ ⎜ p ()t ⎟ ⎩⎪ c p 2 ⎩ c p 2 ⎭ ⎭⎪ ⎝ c 2 ⎠ S p ()t = f y ⋅π ⋅ (D − t )⋅t (5.20) (5.28a) M ()t = f ⋅ (D − t )2 ⋅t (5.21) p y 2 ⎧ 2 ⎫ 2 ⎪ M 'Sd ()t2 ⎧γ m ⋅γ SC ⋅ S'Sd ()t2 ⎫ ⎪ ⎛ pe − pmin ⎞ ⎨γ m ⋅γ SC ⋅ + ⎨ ⎬ ⎬ + ⎜γ m ⋅γ SC ⋅ ⎟ ≤1 MSd’ = MSd/Mp (normalised moment) α α ⎜ p t ⎟ ⎩⎪ c ⎩ c ⎭ ⎭⎪ ⎝ c ()2 ⎠ SSd’ = SSd/Sp (normalised effective force) (5.28b) D/t ≤ 45, P < P fu 2 i e α c = ()1− β + β ⋅ (5.22) f y 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 3 α = (5.23) pc is the characteristic collapse pressure, Eq. 5.10. This p ⎨ ⎛ p − p ⎞ p − p 2 ⎪ i e i e shall be based on thickness t2. 1− 3β⎜1− ⎟ ≥ ⎩⎪ ⎝ pb ⎠ pb 3 Guidance note: The left hand side of the combined loading criterion is referred to ⎧ 0.5 for D / t2 < 15 as interaction ratio in order not to mix it with “unity check”. In a ⎪ unity check, the loads are normally directly proportional to the uti- ⎪⎛ 60 − D / t2 ⎞ β = ⎨⎜ ⎟ for 15 ≤ D / t2 ≤ 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 / t2 > 60 Displacement controlled condition αc is a flow stress parameter and αp account for effect of D/t2 608 Pipe members subjected to longitudinal compressive ratio. 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 ()t2 , 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. γ ε

---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 − p ⎞ −1.5 ⎜ min e ⎟ in the b equations. ε c (t, pmin − pe ) = 0.78⋅⎜ − 0.01⎟ ⋅ ⎜1+ 5.75⋅ ⎟ ⋅α h ⋅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 continuously moment also has a lateral point load, this should be included sustained with the associated strain by a modification of the plastic moment capacity as follows: γε = Strain resistance factor, Table 5-8

M p,point load = M p ⋅α pm (5.25) ⎛ Rt0,5 ⎞ αh =⎜ ⎟ , Table 7.5 and Table 7.11 where ⎜ R ⎟ ⎝ m ⎠max

αpm = Plastic moment reduction factor accounting for point load αgw = See Sec.13 E1000. D / t R 609 Pipe members subjected to longitudinal compressive 2 strain (bending moment and axial force) and external over α pm = 1− (5.26) 130 Ry pressure shall be designed to satisfy the following condition at all cross sections: R = Reaction force from point load 0.8 ⎛ ⎞ 2 ⎜ ⎟ R y = 3.9⋅ f y ⋅t 2 (5.27) ⎜ ε Sd ⎟ pe − pmin (5.31) + ≤1 D/t2 < 45, pmin < pe ⎜ ε c (t2 ,0) ⎟ pc (t2 ) 607 Pipe members subjected to bending moment, effective ⎜ ⎟ axial force and external overpressure shall be designed to satisfy ⎝ γ ε ⎠ γ m ⋅γ SC

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 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 Steel Table 5-8 Resistance strain factors, γ e Structures Safety class DNV-RP-C205 Environmental Conditions and Environmen- Low Medium High tal Loads 2.0 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 against iceability 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 action 701 Global buckling implies buckling of the pipe as a bar in - vibrations of the pipeline system, e.g. due to vortex shedding compression. The pipeline may buckle globally, either down- (current, waves, wind, towing) or fluid flow wards (in a free span), laterally ("snaking" on the seabed), or - supporting structure movements vertically (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 fatigue taken 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 fatigue a 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 high buckling. 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 be 705 Load-controlled global buckling may be designed in used shall be determined on a case-by-case basis, and shall accordance 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 allowed provided 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 808 ture pipelines: — determination of Stress Concentration Factor (SCF) not included in the S-N curve — exposed on even seabed — determination of accumulated damage, see 809.

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807 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 in determining the long-term distribution of fatigue loading D – D effects. Where appropriate, deterministic or spectral analysis f = ------max min- ≤ 0.03 (5.33) may be used. 0 D 808 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 amplitudes for the case of low-cycle fatigue), versus number of cycles to — a corresponding reduction in moment resistance has been failure, N. The S-N curve shall be applicable for the material, included construction 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- ments N curve shall be based on the mean curve of log (N) with the — additional cyclic stresses caused by the ovalisation have subtraction of two standard deviations in log (N). If a fracture been considered mechanic 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 the allowable defect sizes determined by the ECA or a fracture 902 Ovalisation shall be checked for point loads at any point mechanics 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 deformation varying amplitude of random order, the linear damage hypoth- esis (Miner's Rule) may be used. The application of Miner's 1001 Accumulated plastic deformation of pipe caused by Rule 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 increased stant amplitude stress or strain range blocks, (σr)i or (εr)i, and ovality, special consideration shall also be made of the effect the 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 il= — pipeline parts with virtual anchor, and — pipeline laying on seabed slope, or Where: — pipeline connected to pulling force (e.g. connected to SCR). Dfat =Miner's sum k = number of stress blocks D 1100 Fracture and supplementary requirement P ni = number of stress cycles in stress block i 1101 Pipeline systems shall have adequate resistance against Ni = 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 Accumulated Pipelines and DNV-RP-F204 Riser Fatigue. In cases where strain plastic strain this guideline is not applicable, allowable damage ratios are given in Table 5-9. ε l,nom ≤ 0.4% Materials, welding, workman- ship and testing are in accord- ance with the requirements of Table 5-9 Allowable damage ratio for fatigue this standard Safety Class Low Medium High As an alternative girth welds α 1/3 1/5 1/10 allowable defect sizes may be fat assessed according to 811 The split between the different phases of the design Appendix A. fatigue life as described in Table 5-9 shall be agreed in the ini- 0.4% < ε l,nom The integrity of the girth welds tiation phase of the project and be based on the highest safety shall be assessed in accordance class during the lifetime. with Appendix A 2) 1.0% < ε l,nom 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 toughness D 900 Ovalisation — adequate DWTT shear fracture area 901 Risers and pipelines shall not be subject to excessive — lowering the stress level ovalisation and this shall be documented. The flattening due to — use of mechanical crack arrestors bending, together with the out-of-roundness tolerance from — by a combination of these methods.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.5 – Page 51

Design solutions shall be validated by calculations based upon Note to table: Standard industry practice assumes safety factors equal to 1.0 for relevant 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 characteristic ture arrest properties need not be applied when the pipeline resistance. In this standard, accidental loads and events are introduced in a design 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 standard fracture 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 required Charpy V-notch impact energy shall be specially considered. E. Special Considerations D 1200 Ultimate limit state – Accidental loads E 100 General 1201 The design against accidental loads may be performed 101 This subsection gives guidance on conditions that shall by direct calculation of the effects imposed by the loads on the be evaluated separately. Both the load effects and acceptance structure, or indirectly, by design of the structure as tolerable criteria are affected. to accidents. E 200 Pipe soil interaction 1202 The acceptance criteria for ALS relate to the overall 201 For limit states influenced by the interaction between the allowable 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 i'th damaging which shall all be properly accounted for in the simulation of event, PDi, times the structural failure probability conditioned the pipeline soil interaction. on this event, Pf|Di. The requirement is accordingly expressed as: 202 The main soil characteristics governing the interaction are the shear strength and deformation properties. p ⋅ P ≤ p (5.34) 203 Pipeline characteristics of importance are submerged ∑ fDi Di fT, weight, diameter stiffness, roughness of the pipeline surface, and initial embedment from installation which shall all be where 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 must be large enough to ensure that the resulting probability is eval- 204 All relevant load effects shall be considered. This uated with sufficient accuracy. includes: 1204 The inherent uncertainty of the frequency and magni- — load duration and history effects (e.g. varying vertical tude 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, water shall 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 is applied, it shall be ensured that system performance and local 205 Some soils have different resistance values for long term failure modes (e.g. strain rate, local buckling, joint overloading loading and for short term loading, related to the difference in and joint fracture) are adequately accounted for by the models drained and non-drained behaviour and to creep effects in drained and 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 expansion ate partial safety factors. The adequacy of simplified design loops, global buckling or when displacements are allowed for check 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, ploughing with 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 by Table 5-11 Simplified Design Check versus Accidental loads gravel) and susceptible to global buckling the uplift resistance Prob. 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 effects 10-2 – 10-3 To be evaluated on a case by case basis etc., it is difficult to define universally valid methods for simulation -3 -4 of pipe soil interaction effects. The limitations of the methods used, 10 – 10 γC = 1.0 γC = 1.0 γC = 1.0 -4 -5 whether theoretically or empirically based, shall be thoroughly 10 – 10 γC = 0.9 γC = 0.9 considered in relation to the problem at hand. Extrapolation beyond -5 -6 10 – 10 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 2010 Page 52 – Sec.5

E 300 Spanning risers/pipelines special supporting structures or anchoring devices other than weight coating, shall be designed against sinking as described 301 Spanning risers and pipelines shall have adequate safety under 405 above. Special considerations shall here be made to against local buckling, fatigue, fracture and ovality and these mechanical components such as valves and Tee's. shall be documented. 409 It shall be documented that pipelines situated on the sea 302 For design of free spanning pipelines, reference is made to DNV-RP-F105 Free Spanning Pipelines. For fatigue design bottom have adequate safety against being lifted off the bottom of 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 open trench, or buried in such a way that under extreme functional 410 The most unfavourable combination of simultaneously and environmental loading conditions, the pipeline will not acting vertical and horizontal forces on the pipeline shall be move 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 directionality a 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 vertical 402 Liquid or gas pipelines in the air- or gas-filled condition load level. shall have a specific gravity which is higher than that of the surrounding 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 sustain enced by unstable slopes, that could lead to slope failure and the anticipated friction force. flow of soil that will impact the pipeline, the probability of such 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 upon shall 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 to required. wave action may lead to a reduction of the shear strength of the soil. This shall be considered in the analysis, particularly if the 404 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 with minor corrosion allowance this reduction may be omitted and 416 If the stability of the pipeline depends on the stability of the nominal thickness used. the seabed, the latter should be checked. 405 Buried pipelines shall have adequate safety against sink- E 500 Trawling interference ing or flotation. For both liquid and gas pipelines, sinking shall be 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 pipe is less than that of the soil, then no further analyses are required 502 The acceptance criteria are dependent on the trawling to document safety against sinking. If pipelines are installed in frequency (impact) and the safety classification (pull-over and soils 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 an uefied, 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 the requirements of D above. H 407 If the specific submerged weight of the gas- or air-filled P ≤ 0.05η (5.35) pipe is less than that of the soil, it shall be documented that the D shear strength of the soil is adequate to prevent flotation. Thus, where: in soils which are or may be liquefied, the specific weight of the buried gas- or air-filled pipeline is not to be less than that H permanent plastic dent depth of the soil. p = η = usage factor given in Table 5-12. Load effect factors 408 Pipelines resting directly on the sea bottom without any equal to unity.

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Table 5-12 Usage factor (η) for trawl door impact requirements for components in Sec.8. 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 1-100 0.3 requirements -4 10 -1 0.7 All Non-linear FE analyses F100 504 When allowing for permanent dents, additional failure Components according to; ASME VIII listed below 2) Division 2 / EN 13445 / PD modes such as fatigue and collapse shall be taken into account. 5500 Any beneficial effect of internal over-pressure, i.e. "pop-out" shall not normally be included. The beneficial effects of pro- Induction ISO 15590-1 tective coating may be taken into account. The impact effec- Bends F200 tiveness of coating shall be documented. Fittings Bends: F200 Tees: ASME B31.4, B31.8 F600 505 Pullover loads shall be checked in combination with Flanges 15590-3/ ISO 7005-1 or other relevant load effects. All relevant failure modes for lat- NORSOK L005 / EN 1591-1 eral buckling shall be checked. Accumulation of damage due to subsequent trawling is not normally allowed. Valves ISO 14723 F500 Mechanical ASME VIII Division 2 / EN 506 Hooking loads shall be checked in combination with other connectors 13445 / PD 5500 relevant load effects. All relevant failures modes shall be checked. Couplings and DNV-RP-F113 E 600 Third party loads, dropped objects repair clamps, Hot taps: API RP 2201 hot taps 601 The pipeline shall be designed for impact forces caused Bolting ASME VIII Division 2 / EN by, e.g. dropped objects, fishing gear or collisions. The design 13445 / PD 5500 may be achieved either by design of pipe, protection or means CP Insulating ASME VIII Division 2 / EN F300 to avoid impacts. joints 13445 / PD 5500 602 The design criteria shall be based upon the frequency/ Anchor flanges N.A. see Note 2) likelihood of the impact force and classified as accidental, Buckle and environmental or functional correspondingly, see D1200. fracture arres- 603 For guidance on impacts, reference is made to DNV-RP- tors F107 Risk Assessment of Pipeline Protection. Pig traps ASME VIII Division 2 / EN F400 13445 / PD 5500 E 700 Thermal Insulation 1) Other recognised equivalent codes may be used. 701 When a submerged pipeline is thermally insulated, it 2) Required in case the code used in the design of a component does not take shall be documented that the insulation is resistant to the com- into account forces other than the internal pressure, see 105. bination of water, temperature and hydrostatic pressure. 702 Furthermore, the insulation should be resistant to oil and 103 All pressure containing components used in the subma- oil-based products, if relevant. The insulation shall also have the rine pipeline system shall generally represent at least the same required mechanical strength to external loads, as applicable. safety level as the connecting riser/pipeline section. 703 Degradation of the insulation during construction and 104 The component shall be designed to accommodate the operation should be considered. loading from connected the pipeline section and vice versa with appropriate safety. E 800 Settings from Plugs 105 The design of pipeline components shall be according to 801 For loads from plugs, reference is given to DNV-RP- recognised codes. If the code used in the design of a compo- F113 Pipeline Subsea Repair. nent does not take into account forces other than the internal pressure, additional evaluations, e.g. non-linear FE analyses according to; ASME VIII Division 2 / EN 13445 / PD 5500, are required in order to address the maximum forces that can F. Pipeline Components and Accessories be transferred to the component from the connecting pipeline sections under installation and operation. F 100 General 101 This Subsection is applicable to pressure containing The strength shall, as a minimum be: components (e.g. bends, flanges and connectors, Tee’s, valves — equivalent to the connecting pipeline, or etc.) used in the submarine pipeline system. Supporting struc- ture requirements are given in G. — sufficient to accommodate the most probable maximum 100-year load effect that will be transferred to the compo- 102 Design of components may be based on the industry rec- nent from the connecting pipeline under installation and ognised codes as listed in Table 5-13 but shall also comply operation, see Sec.4. with the structural design and functional requirements of this sub-section and with the material, manufacturing and test 106 The load scenarios as described in Sec.4 as well as par- ticular loads associated with the component shall be analysed. This implies that also external hydrostatic pressure shall be considered in the design with respect to both strength and inter- nal leakage when relevant. 107 For material susceptible to HISC, see Sec.6 D500. 108 Sealing systems should be designed to allow testing without pressurising the pipeline. 109 The pigging requirements in B114 and B115 shall be considered for the component.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 54 – Sec.5

110 Transitions in C-Mn and low alloy steels where the nom- η = usage factor as given by Table 5-13 inal material thickness or yield stress is unequal shall be in N = pipe wall force accordance with ASME B 31.8 Appendix I, Figure 15 or equally recognised codes. Transition in C-Mn linepipe by M = bending moment. means of an external or internal taper shall not be steeper than 1 in 4. If transitions to these requirements are not feasible, a Table 5-14 Usage factors for equivalent stress check transition piece shall be inserted. Safety class 111 Transitions in duplex stainless steels and 13Cr marten- Low Medium High sitic stainless steels shall be such that the local stresses will not η 1.00 0.90 0.80 exceed 0.8 SMYS. Guidance note: 112 Internal transitions between different wall thicknesses The ovalisation of the bend has typically to be determined by and 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 joints is 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, monolithic The 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 with required reflection off the parallel internal surface. mechanical properties and dimensions identical to that of the 114 Specifications for installation and make-up of the com- adjoining pipeline. ponent shall be established. 303 Insulating joints shall be capable of meeting the test 115 The pressure testing of components (i.e. Factory Accept- requirements given in Sec.8 B900 and to withstand the effects ance Test) to be in accordance with specified design code. of the environment without loss of performance. 304 To protect insulating joints and CP equipment from F 200 Design of bends lightning effects, lightning protection shall be installed. Surge 201 This Standard does not provide any limit state criteria arrestors should be mounted across insulating joints and output for 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 documented 202 As an alternative to recognised codes the following sim- decompression, creep and temperature properties. O-ring seals plified 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 interlock σe ≤ 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 is σ ≤ σ 2 +σ 2 −σ ⋅σ + 3⋅τ 2 (5.38) valid during all relevant pipeline operating conditions. Sealing e h l h l hl will be sensitive to internal deflections, enlargement of gaps D − t and changes in their support conditions. Valve operation will σ = ()p − p 2 (5.39) be sensitive to friction and clearances. h i e 2⋅t 2 502 Consideration should be given to requirements for dura- bility when exposed to abrasive material (e.g. weld scale, sand N M σ = + etc.) or to fire loads. l π ⋅ (D − t ) ⋅t 4 4 (5.40) 2 2 π ⋅ (D − (D − 2 ⋅t2 ) ) 503 Valves with requirements for fire durability shall be 32 ⋅ D qualified by applicable fire tests. Reference may be made to

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.5 – Page 55

API 6FA and ISO 10497 for test procedures. void for internal pipes. Release of effective axial force by end 504 Valve control systems and actuators shall be designed expansions, lateral and/or vertical deformations or buckling and 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 is ments 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 as ice. spacers, bulkheads etc. 505 If the code or standard used for design of a component G 300 Riser supports does 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 as pipeline sections, the additional calculations or qualification that of the riser they support. However, if safety considerations tests shall be performed. indicate that the overall safety is increased by a reduction of F 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 to B31.8 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 recommended that 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, element welded to the transverse bars only. If this is impracticable, stresses, effective weld length, stress concentrations and alternative 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-term 603 Y-pieces and tees where the axis of the outlet is not per- performance of the material with regard to creep, sea water and pendicular 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-tubes 604 The design of hot taps shall ensure that the use of and the 401 An overall conceptual evaluation shall be made in order design of the component will result in compliance with API RP to define the required: 2201, "Procedure for Welding and Hot Tapping on Equipment — safety class in Service". — impact design 605 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 301 above includes evaluation of whether the j-tube shall be — the fitting is demonstrated to be able to accommodate the 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. Socket welding 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. Supporting Structure G 500 Stability of gravel supports and gravel covers 501 This applies to all types of gravel supports and covers, G 100 General such as free span supports for installation and operating phases 101 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, axial as 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, advantage may be taken of other loading conditions, e.g. pressure con- — weight of gravel supports and/or covers and pipeline tainment 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 horizontal quences compared to those of ordinary pipelines. — uncertainty in soil characteristics 202 The combined effective force for a pipe-in-pipe or a — resistance against hydrodynamic loads bundle 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 data external pressure for each component shall be taken as the — subsea gravel installation tolerances, both horizontal and pressure acting on its external surface, i.e. the pressure in the vertical.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 56 – Sec.5

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 resulting 101 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 — instability according 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, no 103 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- (5.41) evant installation phases and techniques to be used, including: γ rotε r ≤ ε r,rot — 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 straightness shall 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 affecting strain levels are acceptable when all relevant effects are taken present and future operations and modifications shall also be into account. Discontinuities due to weight coating, buckle considered. arrestors, in-line assemblies etc. shall be considered. 206 The requirement for straightness applies to the assumed 106 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 also variation 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. stinger installation 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 pipelines shall 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 due ditions 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 proposed pipeline 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 system shall be modified accordingly. H 300 Coating 110 The flattening due to a permanent bending curvature, 301 Concrete crushing due to excessive compressive forces together 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.

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SECTION 6 DESIGN - MATERIALS ENGINEERING

A. General B. Materials Selection for Linepipe and Pipeline Components A 100 Objective B 100 General 101 This section provides requirements and guidelines to the selection of materials for submarine pipeline systems and to 101 Materials for pipeline systems shall be selected with due the external and internal corrosion control of such systems. consideration of the fluid to be transported, loads, temperature Also 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 all siderations for fabrication applicable to the design phase are components of the pipeline system. The following material addressed. characteristics shall be considered: 102 The purpose of performing materials selection is to — mechanical properties assess the feasibility of different candidate materials (includ- — hardness ing CRA’s) to meet functional requirements for linepipe and — fracture toughness for other components of a pipeline system. It may also include — fatigue resistance a cost comparison between candidate materials, including the — weldability calculated costs for operation and any associated risk cost (see — corrosion resistance. D701). This activity is generally carried out during conceptual design of submarine pipeline systems. 102 Materials selection shall include identification of the fol- lowing supplementary requirements for linepipe given in A 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 properties tive 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.5 202 Functional requirements for materials and manufactur- D1102 (see B407-408) ing procedures for linepipe and pipeline components are con- — supplementary requirement D, more stringent dimensional tained in Sec.7 and 8, respectively. Manufacture and requirements (see B402) installation of systems for external corrosion control is — supplementary requirement U, increased utilisation (see addressed 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 to detailed 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, corrosion allowance and provisions for internal corrosion control. In the B 200 Sour service material selection document design premises for materials selection should be identified, making reference to the design 201 Pipelines to route fluids containing hydrogen sulphide basis and any other relevant project documents, together with (H2S) shall be evaluated for ‘sour service’ according to the applicable codes and standards. ISO 15156. For all pipeline components exposed to such inter- nal fluids, materials shall be selected for compliance with this 302 Any requirements and conditions on pipeline fabrication standard. For materials specified for sour service in and 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). For pipeline. 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 by 303 As a result of design activities, specifications of linepipe ISO 15156 (e.g. type 13Cr steels), shall be qualified according material, pipeline components (including bolts and nuts), pipe- to the said standard. The same applies if a material specified line coatings (including field joint coating and any concrete for sour service is to be used beyond the conditions specified coating), anode manufacture and installation shall further be (e.g. max. hardness). In accordance with ISO 15156-2/3, the prepared as separate documents. Moreover, the design docu- pipeline owner shall verify and retain the qualification records mentation 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 2010 Page 58 – Sec.6

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 and ISO 15156 are applicable to equipment designed and con- improved structural integrity. The tolerances specified in structed using conventional elastic design criteria. When other Sec.7 I400 are considered to be in the uppermost range of what design criteria are applied qualification testing shall be consid- may be achieved by reputable pipe mills. Stricter tolerances ered, unless relevant documentation is provided. and additional requirements such as e.g. pipe eccentricity may 204 Supplementary requirements to sour service in this be specified for further improvements, but may be costly as standard are given in Sec.7 I100 and Sec.8 C500. machining may be required. Corrosion testing of the CRA material of clad or lined linepipe B 300 Corrosion resistant alloys (informative) 403 For alloy 625 clad or lined pipe specified to be seawater 301 Type 13Cr martensitic stainless steels (i.e. proprietary resistant, testing according to ASTM G48, Method C, should alloys developed for oil/gas pipelines) are generally consid- be considered, with acceptance criteria as for 25Cr duplex, see ered fully resistant to CO2-corrosion, provided welds have Sec.7 C409. adequate PWHT. 22Cr and 25Cr duplex stainless steel and austenitic CRA’s are also fully resistant and do not require Gripping force of lined linepipe PWHT. Duplex and martensitic stainless steels may be less tol- 404 In accordance with Sec.7 D510 the gripping force shall erant 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 bending may not be effective for CRA’s. stresses. If no particular requirements are identified the 302 Under conditions when water, oxygen and chloride can requirement should be based on the gripping force obtained be 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 properties resistance shall be considered for each specific application. For special 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 temperatures Alloy 625 (UNS N06625) is generally considered immune to up to approximately 250°C. For TMCP processed pipes and ambient temperature seawater. Also type 25Cr duplex (e.g. cold formed pipes not subjected to further heat treatment UNS S32750/S32760) are generally resistant to ambient tem- mechanical properties may change due to strain aging, causing perature seawater but require more stringent control of micro- e.g. increased yield stress. This may further affect the critical structure in base material and weld, consequently corrosion defect size considerably if the pipe is strained above the yield testing are often included for the qualification of manufactur- stress. ing and fabrication procedures of these materials. Type 22Cr duplex, AISI 316 and Alloy 825 (UNS N08825) are not resist- Fracture arrest properties ant 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 a concentrations 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 which line components require special considerations of the suscepti- reflect the actual conditions or on full-scale tests. The fracture bility 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 to reduce the HISC susceptibility of welds for 13Cr martensitic Calculations should be carried out by use of the Battelle Two stainless steel. For duplex stainless steel, HISC design recom- Curve Method (TCM) and the appropriate correction factor for mendations 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 from 304 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 base B 400 Linepipe (informative) material of such pipes are fit for intended use after significant 401 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 Offshore Standard DNV-OS-F101, October 2010 Sec.6 – Page 59 pipe longitudinal weld overmatches the strength of the base cable as subsea bolting material without cathodic protection material. It is further recommended to have a limited cap rein- but should only be used in the solution annealed or annealed forcement of the longitudinal weld in order to avoid strain con- condition (ASTM B446) or cold-worked to SMYS 550 MPa centrations. maximum, unless exposure to cathodic protection can be Supplementary 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 delivery to be in accordance with Supplementary requirement U. In 604 To restrict damage by HISC for low alloy and carbon case of more than 50 test units it must be demonstrated that the steels, the hardness for any bolts and nuts to receive cathodic actual 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 for and 20 the actual average yield stress shall as a minimum be solution annealed or cold-worked type AISI 316 austenitic 2.3 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 and 501 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-installed obtain 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 coatings homogeneity, and the absence of internal flaws are of impor- may prevent efficient cathodic protection. PTFE coatings have tance. 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 during later 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 that If welds between the component and other items such as line- are specific for pipeline installation welding are given in pipe are to be post weld heat treated at a later stage, or if any Sec.10. Below is provided guidance regarding the influence of other heat treatment is intended, a simulated heat treatment of weld metal strength on allowable defect size as determined by the 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 equal of components require qualification of a specific welding pro- to or higher than (overmatching properties) the base material is cedure for welding of the joint between the component and the to minimise deformation in the area adjacent to any possible connecting 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 generally vided 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 the of elastomers and polymers for use in the specific application scatter in the pipe material yield stress, it is normally required and 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). An B 600 Bolts and nuts ECA involving undermatching weld metal will require special 601 Carbon and low alloy steel bolts and nuts for pressure considerations, see Appendix A. containing and main structural applications shall be selected in Temperature effects accordance 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 the Table 6-1 Carbon and low alloy steel bolts and nuts for pressure base material. Hence, undermatching may be experienced for bearing or main structural applications high operation temperatures (e.g. snaking scenario). This is Temperature 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 Specification 602 When bolts and nuts shall be used at elevated tempera- C 100 General ture 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 steps protection 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 2010 Page 60 – Sec.6 manufacturing facility, but excluding any permanent external/ conforming to supplementary requirement S internal coating. — if supplementary requirement P apply, the relevant strain- ing for the installation process, possible corrective actions C 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 be selection according to this section and referring to Sec.7, shall specified. be prepared by the Purchaser. The specification shall state any options, additional requirements to and/or deviations from this C 300 Components specification standard pertaining to materials, manufacture, fabrication and 301 A specification reflecting the results of the materials testing of linepipe. selection according to this section and referring to Sec.8, shall 202 The material specification may be a Material Data Sheet be prepared by the Purchaser. The specification shall state any referring to this standard. options, additional requirements to and/or deviations from this standard pertaining to materials, manufacture, fabrication and 203 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 — material type, delivery condition, chemical composition — whether data of the wall thickness variation (tmax and tmin) 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 Offshore Standard DNV-OS-F101, October 2010 Sec.6 – Page 61 ification 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 coating are 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 environment 503 For pipeline components in CRA materials to receive — expected form of corrosion damage (see Guidance note CP, 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 inspection installation of galvanic anodes shall be prepared. These docu- and planned frequency of inspection ments shall define requirements to materials, properties of — consequences of sudden leakage, requirements to safety anodes (as manufactured and as-installed, respectively) and and reliability associated 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 is D 100 General recommended for C-Mn steel pipelines of safety class Medium and High carrying hydrocarbon fluids likely to contain liquid 101 All components of a pipeline system shall have adequate water during normal operation. For nominally dry gas and for corrosion 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 be 102 Pipeline systems may be exposed to a corrosive environ- considered during design/engineering for later inclusion in ment both internally and externally. Options for corrosion mit- fabrication and installation specifications. Optional techniques igation 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 surface may serve to compensate for internal and/or external corrosion roughness affecting pipeline coating operations. Conditions for and 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 water rosion 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 pipeline's 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 pipeline's 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 2010 Page 62 – Sec.6

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 requirements D 400 External pipeline coatings (informative) and guidelines to FJC are also applicable to any field repairs of factory coating 401 “Linepipe coating” (also referred to as “factory coating or “parent coating”) refers to factory applied external coating 408 The design and quality control of field joint coatings is systems (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 martensitic or 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 dumping or 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 during layers 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 the pipelines for reel laying and prefabricated risers). “Coating minimum requirements in ISO15589-2. DNV-RP-F103 is field 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 the b) 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 may d) 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 high e) 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 be f) 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 adequate g) 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 are h) 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 HISC 404 For thermally insulating coatings, properties related to include control of galvanic anodes by diodes and use of special flow assurance also apply; e.g. specific heat capacity, thermal anode alloys with less negative closed circuit potential. (These conductivity and the degradation of such properties by high techniques require that the pipeline is electrically insulated from operating external pressure and internal fluid temperature. conventional CP systems on electrically connected structures). In case conventional bracelet anodes are still to be used, welding of 405 Pipeline components should have external coatings pref- anodes to any pressure containing components in these materials erably matching the properties of those to be used for linepipe. should be avoided. If this is not practical, CP design may compensate for inferior properties. However, risks associated with HISC by CP shall ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- be 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 Offshore Standard DNV-OS-F101, October 2010 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 galvanic tions 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 offshore pipeline 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 standards uated. — 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 the 505 Unless otherwise specified by or agreed with the owner, feasibility of CP by anodes on adjacent structure(s) or a pipelines shall be designed with a self-sustaining CP system bracelet anode concept exceeding a spacing of 300 m in based 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 C E500). Guidance note: For shorter pipelines (up to 30 km approximately), CP may be The above requirements for documentation of CP design is an achieved by anodes installed on structures at the end of the amendment to ISO 15589-2 pipeline (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 concept requires, however, that the design and quality control of fac- 509 For CP design of pipeline system components with tory applied coatings, field joint coatings and coating field major surfaces in structural steel (e.g. riser bases), reference is repairs are closely defined (e.g. as in DNV-RP-F106 and made to DNV-RP-B401. DNV-RP-F102). A recommended procedure to calculate the protective length of anodes on an adjacent structure is given in 510 Design of any impressed current CP systems installed at DNV-RP-F103 (ISO 15589-2 gives an alternative procedure land falls shall comply with ISO 15589-1. Requirements to but, 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 above considerations 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 heated tabs with pressure applied on the bracelet assembly. Connector by an internal fluid. In the splash zone, the riser coating may cables shall be adequately protected; e.g. by locating the cables be exposed to mechanical damage by surface vessels and to the gap between the anode bracelets and filling with a marine operations, whilst there is limited accessibility for moulding compound. inspection and maintenance. 507 A calculation procedure for pipeline CP design using 603 The riser section in the ‘atmospheric zone’ (i.e. above conventional bracelet anodes and a maximum anode spacing the splash zone) is more shielded from both severe weathering of 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 below some default values which represent minimum requirements the lowest astronomical tide (LAT), an adequately designed

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 64 – Sec.6

CP 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 detailed marginally effective. design and must therefore be evaluated during conceptual 605 Different coating systems may be applied in the three design. The following options for corrosion control may be corrosion 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 with a 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 linings zones: (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 degradation 607 External cladding with certain Cu-base alloys may be should be taken into account. The necessity for corrosion used for combined corrosion protection and anti-fouling, pri- allowance and redundant systems for fluid processing should marily 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. For ing 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 of atmospheric and submerged zones, and in the splash zone if water and deposits counteracts internal corrosion in general functional 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 an D403 are also relevant for riser coatings, dependent on the par- option for corrosion control, the following main parameters ticular corrosion protection zone. The applicable requirements shall be considered: to properties for each coating system and for quality control shall be defined in a purchase specification. The general — chemical compatibility with all fluids to be conveyed or requirements 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 of tional 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 by 609 In the submerged zone, the considerations for selection pigging operations of coating in D403 apply. In addition, resistance to biofouling — resistance to rapid decompression is relevant in surface waters of the submerged zone and the — reliability of quality control during coating application lowermost section of the splash zone may have to be consid- — reliability of (internal) field joint coating systems, if appli- ered. cable 610 Riser FJC’s shall have properties matching the selected — consequences of failure and redundant techniques for cor- pipe coating. In the splash zone, field joint coatings should be rosion mitigation. avoided 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 reduction cent coating. in dry gas pipelines ("flow coatings" or “anti-friction coat- ings”). Any such coatings should have a minimum specified D 700 Internal corrosion control (informative) thickness of 40 μm and should comply with the minimum 701 Options for internal corrosion control should be evalu- requirements in API RP 5L2. Although such coatings can not ated aiming for the most cost-effective solution meeting the be expected to be efficient in preventing corrosion attack if overall 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 retaining operation 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 may sis"). 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 chemicals quences (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 for failures should reflect the designer's confidence in estimating hydrate inhibition, diluting the water phase) the fluid corrosivity and the efficiency of options for corrosion control being evaluated. Depending on the failure mode, con- — dispersants (for emulsification of water in oil) sequences of failure may include costs associated with — scavengers (for removal of corrosive constituents at low increased maintenance, repairs, lost capacity and secondary concentrations). damage to life, environment and other investments.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.6 – Page 65

707 The reliability of chemical treatment should be evalu- — provisions for injection and techniques/procedures for ated in detail during the conceptual design. Important parame- monitoring of inhibitor efficiency ters to be considered are: — consequences of failure to achieve adequate protection, and redundant techniques. — anticipated corrosion mitigating efficiency for the actual fluid to be treated, including possible effects of scales, For pipelines carrying untreated well fluid or other fluids with deposits, etc. associated with this fluid high corrosivity and with high requirements to safety and reli- — 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.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 66 – Sec.7

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 of 101 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 with treatment, expansion and final shaping. A301. 102 Materials selection shall be performed in accordance 304 The liner pipe of lined linepipe shall be manufactured in with 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 shall 104 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 weld J: “PSL 2 pipe ordered for offshore service”, with some addi- shall be MWP (see A302). tional and modified requirements. A 400 Supplementary requirements 105 Manufacturers of linepipe shall have an implemented quality 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 in 201 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 specification comply with recognised practices or proprietary specifications 501 A linepipe specification reflecting the results of the will normally be acceptable provided they comply with the materials selection (see Sec.6 C200), referring to this section requirements 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 to 301 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 and Seamless (SMLS) qualification Pipe manufactured by a hot forming process without welding. Manufacturing Procedure Specification (MPS) In order to obtain the required dimensions, the hot forming may be followed by sizing or cold finishing. 601 Before production commences, the Manufacturer shall prepare a Manufacturing Procedure Specification (MPS). The High Frequency Welded (HFW) MPS shall demonstrate how the specified properties may be Pipe formed from strip and welded with one longitudinal seam achieved and verified throughout the proposed manufacturing formed 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 and the use of filler metal. The forming may be followed by cold consistency of the product. All main manufacturing steps from expansion 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 one longitudinal (SAWL) or helical (SAWH) seam formed by the References to the procedures established for the execution of submerged 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 following may be followed by cold expansion or reduction. information (as applicable): 302 CRA linepipe may, in addition to SMLS and SAWL, be manufactured according to one of the following processes: — steel producer — plan(s) and process flow description/diagram Electron Beam Welded (EBW) and Laser Beam Welded (LBW) — project specific quality control plan Pipe formed from strip and welded with one longitudinal seam, — manufacturing process with or without the use of filler metal. The forming may be fol- — target chemical composition lowed by cold expansion or reduction to obtain the required — steel making and casting techniques dimensional tolerances. These welding processes shall be sub- — ladle treatments (secondary refining), degassing, details of ject to pre-qualification testing according to Appendix C. inclusion shape control, super heat

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 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 standard Manufacturing 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 or eter as part of first day production, unless as allowed in A609. modified requirements to ISO 3183 Annex J are highlighted in For 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 requirements of qualification testing providing all essential variables in A609 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 pipe from 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 in in this section. This includes all stated production tests plus tables are marked in accordance with B102 with AR and MR additional 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 designation unless 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. MR 606 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 with the qualification testing. The tests shall be performed on the SMYS 450 MPa, meeting the supplementary requirements for actual 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 Manufacturing 607 Additional MPS qualification testing may be required by Purchaser (e.g. weldability testing, analysis for trace elements Starting material and steel making for 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 heat making, 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 2010 Page 68 – Sec.7 materials 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-automatic allowable 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 using oxygen 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 not 304 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 and 305 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 hydrogen 306 Pipe ends shall be cut back sufficiently after rolling to versus flux moisture content are provided (meeting the ensure freedom from defects. AR requirement in B318), the maximum residual moisture content General 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 welds manufacture 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 performed tain any repair welds. in accordance with ISO3183 Annex C.4. Any repair welding 308 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. AR 309 If agreed, strip and plate shall be inspected ultrasonically HFW pipe for laminar imperfections or mechanical damage, either before or after cutting the strip or plate, or the completed pipe shall be 327 The abutting edges of the strip or plate should be milled subjected 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 continuously 310 Plate or strip shall be cut to the required width and the monitored. AR weld bevel prepared by milling or other agreed methods before 329 The weld seam and the HAZ shall be fully normalized forming. AR subsequent to welding. MR 311 Cold forming (i.e. below 250°C) of C-Mn steel shall not Heat treatment introduce a plastic deformation exceeding 5%, unless heat treatment 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 shall be performed as recommended by the Manufacturers of the 331 The documented procedures shall be in accordance with plate/strip and welding consumables. AR any recommendations from the material Manufacturer with regard to heating and cooling rates, soaking time, and soaking 313 Welding personnel for execution of all welding opera- temperature. AR tions shall be qualified by in-house training. The in-house training program shall available for review on request by Pur- Cold expansion and cold sizing chaser. AR 332 The extent of cold sizing and cold forming expressed as 314 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| / Db tility and toughness meeting the requirements of the base mate- where rial. AR 316 Welds containing defects may be locally repaired by Da is the outside diameter after sizing welding. 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 within 317 Arc stops during welding shall be repaired according to the range 0.003 < sr ≤ 0.015. Expansion shall not introduce a 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 by shall 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 weld 319 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 not certificate type 2.2 is sufficient for SAW Flux. AR exceed 0.015 unless the entire pipe ends are subsequently 320 Handling of welding consumables and the execution and stress relieved. quality assurance of welding shall meet the requirements of in- Finish of pipe ends house quality procedures. AR 336 Unless otherwise agreed, pipe ends shall be cut square SAW pipe and be free from burrs. MR 321 Any lubricant and contamination on the weld bevel or 337 The internal weld bead shall be ground to a height of 0 the 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 Offshore Standard DNV-OS-F101, October 2010 Sec.7 – Page 69

Table 7-1 C-Mn steels, acceptable manufacturing routes Type of Starting Material Pipe forming Final heat treatment Delivery pipe 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 Q HFW 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 pipe SAW 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) Q Notes

1) 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-processing height 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 of pipe ends. The transition to the base material/pipe body shall QT or normalised pipe material, it is acceptable to conduct one be smooth and without a noticeable step. MR re-heat treatment cycle of the entire test unit. All mechanical 339 If agreed internal machining or grinding may be carried testing shall be repeated after re-heat treatment. AR out. In case of machining, the following requirements shall be Traceability adhered 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 criteria Table 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 ≤ 35 340 Jointers shall not be delivered unless otherwise agreed. mm. MR 341 If used, the jointer circumferential weld shall be quali- 403 For pipes with nominal wall thickness larger than the fied according to the requirements for pipeline girth welds limits indicated in B401 and B402, the chemical composition given 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 analysis plate end welds shall not be permitted unless otherwise agreed. for boron is less than 0.0005%, then it is not necessary for the MR product analysis to include boron, and the boron content may 343 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 2010 Page 70 – Sec.7 sis) carbon equivalents shall be determined using the CE for- 411 From the set of three Charpy V-notch specimens, only mula as given in Table 7-3. one is allowed to be below the specified average value and Tensile properties shall meet the minimum single value requirement. AR Flattening test 406 The tensile properties shall be as given in Table 7-5. 412 For HFW pipe with SMYS ≥ 415 MPa with wall 407 For transverse weld tensile testing, the fracture shall not thickness ≥ 12.7 mm, there shall be no opening of the weld be located in the weld metal. The ultimate tensile strength shall before the distance between the plates is less than 66% of the be at least equal to the SMTS. original outside diameter. For all other combinations of pipe Hardness grade and specified wall thickness, there shall be no opening of the weld before the distance between the plates is less than 408 The hardness in the Base Material (BM), Weld Metal 50% of the original outside diameter. (WM) and the Heat Affected Zone (HAZ) shall comply with Table 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 between CVN 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, of in 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, in general, be performed on test specimens 10 × 10 mm. Where Guided-bend test test 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 completely ison with the values in Table 7-5, the measured energy shall be — reveal any cracks or ruptures in the weld metal longer than converted to the impact energy (KV) in Joules using the for- 3.2 mm, regardless of depth, or mula: — 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 810× × KV specified wall thickness. KV = ------m (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 are AR 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.% Carbon SMYS equivalents 1) 1) 2) 3) 4) C Si Mn PSVNbTiOther CE Pcm 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 agreed Notes

1) 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 CE = C + + + 3) 6 5 15 4) Si Mn Cu Ni Cr Mo V P = C + + + + + + + + 5B cm 30 20 20 60 20 15 10 5) 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 Offshore Standard DNV-OS-F101, October 2010 Sec.7 – Page 71

Table 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 equivalent SMYS 1) 1) 2) 3) C Si Mn PSVNbTiOther Pcm 245 0.12 0.40 1.25 0.020 0.010 0.04 0.04 0.04 Note 4) 0.19 290 0.12 0.40 1.35 0.020 0.010 0.04 0.04 0.04 Note 4) 0.19 320 0.12 0.45 1.35 0.020 0.010 0.05 0.05 0.04 Note 4) 0.20 360 0.12 0.45 1.65 0.020 0.010 0.05 0.05 0.04 Notes 5,6) 0.20 390 0.12 0.45 1.65 0.020 0.010 0.06 0.08 0.04 Notes 5,6) 0.21 415 0.12 0.45 1.65 0.020 0.010 0.08 0.08 0.06 Notes 5,6) 0.21 450 0.12 0.45 1.65 0.020 0.010 0.10 0.08 0.06 Notes 5,6) 0.22 485 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) Notes

1) 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 V P = C + + + + + + + + 5B 3) cm 30 20 20 60 20 15 10 4) 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 1) Rt0,5 Rm Rt0,5/Rm 50.8 mm [HV10] energy (KVT) [MPa] [MPa] Af [J] [%] BM, WM HAZ SMYS min. max. min.2) max. max. min. max. average min. 245 245 450 3) 415 760 0.93 Note 4) 270 300 27 22 290 290 495 415 760 270 30 24 320 320 520 435 760 270 32 27 360 360 525 460 760 270 36 30 390 390 540 490 760 270 39 33 415 415 565 520 760 270 42 35 450 450 570 535 760 270 45 38 485 485 605 570 760 300 50 40 555 555 675 625 825 300 56 45 Notes

1) 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 A 0,2 the following equation: A = C XC where: f U 0,9

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 2010 Page 72 – Sec.7

Table 7-6 C-Mn steel linepipe, Charpy V-notch impact testing Inspection frequency temperatures T0 (°C) as a function of Tmin (°C) (Minimum 502 The inspection frequency during production shall be as Design 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 is Nominal wall Thickness (mm) PIPELINES and risers given in these tables. MR t ≤ 20 T = T 0 min 503 A test unit is a prescribed quantity of pipe that is made 20 < t ≤ 40 T0 = Tmin – 10 to the same specified outside diameter and specified wall t > 40 T0 = to be agreed in each case thickness, by the same pipe-manufacturing process, from the Fracture 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 in have 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 3183 Macro examination of weld seam Annex J. AR 416 The macro section shall show a sound weld merging 505 Sampling for mechanical and corrosion testing shall be smoothly 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 Table melting of tack welds shall be demonstrated. For MPQT welds 7-9. The samples shall not be prepared in a manner that may shall 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 large pipes shall be verified on the macro section, unless alternative diameter and heavy wall thickness pipe, where the test unit is methods 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 this 418 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 heats 419 It shall be verified that the entire HAZ has been appro- — in case of test failure, the test frequency shall revert to the priately 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-testing 420 The pipe shall withstand the hydrostatic test without 507 In order to accept or reject a particular test unit with an leakage through the weld seam or the pipe body. original test unit release failure, re-testing shall be conducted 421 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 from 422 For pipe classified as coiled tubing, the hydrostatic test two different pipes within the same test unit. Both re-tests shall of the finished coiled tubing shall be performed at a pressure meet the specified requirements. The test unit shall be rejected corresponding 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 than two hours. AR 509 The reason for the failure of any test shall be established and the appropriate corrective action to prevent re-occurrence Surface 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 may plate mill are given in Appendix D, Subsection G. Require- conduct individual testing of all the remaining pipes in the test ments for visual inspection of welds and pipe surfaces are unit. If the total rejection of all the pipes within one test unit given in Appendix D H500. MR and AR exceeds 25%, the test unit shall be rejected. In this situation the Dimensions, mass and tolerances Manufacturer shall investigate and report the reason for failure 424 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 pipe 425 If agreed, the Manufacturer shall supply weldability data fails due to low CVN values in the fusion line (HAZ) or weld or perform weldability tests. The details for carrying out the line in HFW pipe, testing of samples from the same pipe may tests 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 analysis 501 Compliance with the requirements of the purchase order shall 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. MR umentation shall be in accordance with the requirements in 514 If the value of any elements, or combination of elements Sec.12. fails to meet the requirements, two re-tests shall be performed

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.7 – Page 73 on samples taken from two different pipes from the same heat. with Subsection E. MR If one or both re-tests still fail to meet the requirements, the heat shall be rejected. MR Non-destructive testing Mechanical testing 518 NDT, including visual inspection, shall be carried out in accordance with Subsection F. AR and MR 515 All mechanical testing shall be performed according to Appendix B. MR Dimensional testing Metallurgical testing 519 Dimensional testing shall be performed according to 516 Macro examination and metallographic examination Subsection G. MR shall be performed in accordance with Appendix B. Treatment of surface imperfections and defects Hydrostatic test (mill pressure test) 520 Surface imperfections and defects shall be treated 517 Hydrostatic testing shall be performed in accordance according to Appendix D H300. MR

Table 7-7 Inspection frequency for C-Mn steel linepipe during production 1 ,2) Applicable Type of test Frequency of testing Acceptance criteria to: 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 B407 SAWH, 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) B416 SAWL, Guided-bend testing of the seam weld Once per test unit of not more than 50/1003) pipes with B414 SAWH 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) Notes 1) 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. where D = Specified outside diameter

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Table 7-8 Additional testing for Manufacturing Procedure Qualification Test for C-Mn steel pipe 1) Applicable to: Type of test Extent of testing Acceptance criteria All pipe All production tests as stated in Table 7-7 One test for each pipe pro- See Table 7-7 2, 3) vided for manufacturing SMLS pipe with t > CVN testing at ID of quenched and tempered seamless 4) Table 7-5 and Table 7-6 25 mm pipe with t > 25 mm AR procedure qualification Welded 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 7-5 Notes 1) 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.

where t = specified nominal wall thickness

Table 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 mm SMLS, not cold Pipe body Tensile 1L3) 1L 1L3) 1L expanded pipe CVN3T3T3T3T Hardness 1T 1T 1T 1T SMLS, cold expanded Pipe body Tensile 1L3) 1T4) 1L3) 1T4) pipe CVN3T3T3T3T Hardness 1T 1T 1T 1T HFW pipe Pipe body Tensile 1L903) 1T1804) 1L903) 1T1804) CVN3T903T903T903T90 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 3183 SAWL pipe Pipe body Tensile 1L903) 1T1804) 1L903) 1T1804) CVN3T903T903T903T90 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 1W SAWH pipe Pipe body Tensile 1L3) 1T4) 1L3) 1T4) CVN3T3T3T3T 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 1W Notes 1) 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 in accordance 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).

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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 to welded and seamless linepipe in duplex stainless steel and C 400 Acceptance criteria seamless martensitic 13Cr stainless steel. Chemical composition 102 Austenitic stainless steel and nickel based CRA linepipe 401 The chemical composition of duplex stainless steel and shall be supplied in accordance with a recognised standard that martensitic 13Cr stainless steel parent materials shall be defines 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 properties C 200 Pipe designation 402 Requirements for tensile, hardness and Charpy V-notch 201 CRA linepipe to be used to this standard shall be desig- properties are given in Table 7-11. Weldment shall meet the nated 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 mm, there shall be no opening of the weld, including the HAZ, ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- until the distance between the plates is less than 66% of the original outside diameter. For pipe with wall thickness C 300 Manufacture < 12.7 mm there shall be no opening of the weld, including the Starting 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 with the processes given in A302 using the raw materials stated in 405 For pipe with a D/t2 > 10, there shall be no cracks or the 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 seam be described in the MPS. 406 The macro examination of weld seam shall meet the 302 All steels shall be made by an electric or one of the basic requirements in B416 and B417. oxygen processes. Microstructure of duplex stainless steel Requirements 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 solution the following requirements given for C-Mn steel pipe are also heat treatment. Essentially free implies that occasional strings applicable 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 steel the 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.

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Table 7-10 Duplex- and martensitic stainless steel linepipe, chemical composition Element 1) Product analysis, wt.% Grade Grade Grade Grade 22Cr duplex 25Cr duplex 13Cr - 2 Mo 13Cr - 2.5 Mo C 0.030 max 0.030 max 0.015 max 0.015 max Mn 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 max S 0.020 max 0.020 max 0.003 max 0.003 max Ni 4.50 - 6.50 6.00 – 8.00 4.50 min 6.00 min Cr 21.0 - 23.0 24.0 – 26.0 12.0 min 12.0 min Mo 2.50 – 3.50 3.00 – 4.00 2.00 min 2.50 min N 0.14 – 0.20 0.20 – 0.34 - - PRE - min. 40 2) -- Notes

1) 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 properties Grade 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 R / R 2) (HV10) Af duplex, and according to Table 7-6 for t0.5 m [%] martensitic 13Cr

BM WM Mean Single HAZ 22Cr 450 620 0.92 290 350 Note 3) 45 35 25Cr 550 750 0.92 330 350 45 35 13Cr-2 Mo 550 700 0.92 300 na 60 45 13Cr-2.5 Mo 550 700 0.92 300 na 60 45 Notes

1) 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 Retesting 501 Compliance with the requirements of the purchase order 508 Requirements for retesting shall be according to B508 to shall be checked by specific inspection in accordance with EN B512. 10204. Records from the qualification of the MPS and other Heat and product analysis documentation shall be in accordance with the requirements in Sec.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/ standard 502 The inspection frequency during production and MPQT shall be determined and reported. Other elements added for shall be as given in Table 7-12 and Table 7-13, respectively. controlling the material properties may be added, subject to Reference to the relevant acceptance criteria is given in the agreement. tables. 511 If the value of any elements, or combination of elements 503 A test unit is a prescribed quantity of pipe that is made fails to meet the requirements, two re-tests shall be performed to 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 heat same heat, and under the same pipe-manufacturing conditions. shall be rejected. 504 Sampling for mechanical and corrosion testing shall be Mechanical testing performed 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 to ence their mechanical properties. Refer to B506 for reduced Appendix B. frequency of testing in case of large quantities of pipe. Metallurgical testing 505 The number and orientation of the samples for SMLS 513 Macro examination and metallographic examination and 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 steels the 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 with ples shall be as for SAWL pipe in Table 7-9. Appendix B B200.

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Hydrostatic test (mill pressure test) Dimensional testing 515 Hydrostatic testing shall be performed in accordance 517 Dimensional testing shall be performed according to with Subsection E. Subsection G. Non-destructive testing Treatment of surface imperfections and defects 516 NDT, including visual inspection, shall be in accordance 518 Surface imperfections and defects shall be treated with 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 criteria All pipe All tests in Table 7-7 applicable to “All As given in Table 7-7 Table 7-10 and pipe” Table 7-11 SAWL 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 C405 Duplex stainless steel pipe Metallographic examination Once per test unit of not more than 50/100 3) C407 and C408 25Cr duplex stainless steel pipe Pitting corrosion test (ASTM G48) Once per test unit of not more than 50/100 3) C409 Notes 1) 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. where D = Specified outside diameter

Table 7-13 Additional testing for Manufacturing Procedure Qualification Test of CRA linepipe 1) Applicable to Type of test Frequency of testing Acceptance criteria All pipe All production tests as stated above One test for each pipe provided for Subsection C manufacturing procedure qualification Welded pipe (all types) All weld tensile test3) Table 7-11 Fracture toughness (CTOD) test of weld metal 2) B415 Notes 1) 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 pipe 101 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 internal CRA 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 Specification shall be according to A303 to A305. MPS for clad linepipe 105 Cladding and liner materials shall be specified according to 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 of 106 The cladding/liner material thickness shall not be less cladding alloy and backing material prior to sandwich than 2.5 mm, unless otherwise agreed. assembly — method used to assemble the sandwich or one-sided-open D 200 Pipe designation package, as applicable, prior to reheating and rolling 201 In addition to the designation of the backing material — package (sandwich or one-side-open) reheating tempera-

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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 oxides MPS 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 electrodes the 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-Mn 303 The following additional essential variable applies to the steel pipe after both pipes have been carefully cleaned, dried qualification 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 at CRA with carbon steel shall be avoided. Direct contact of the least 5°C above the dewpoint temperature. Temperature and CRA 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 be providing subsequent pickling is performed. expanded by a suitable method to ensure adequate gripping. The carbon steel pipe shall not under any circumstances 402 All work shall be undertaken in clean areas and control- receive a sizing ratio, sr , exceeding 0.015 during the expansion led 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 shall 404 The welding consumables for seam welds and liner seal be machined at each end and further fixed to the backing pipe welds shall be selected taking into consideration the reduction by a seal weld (clad or fillet weld, respectively) to ensure that of 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 B307 General requirements to manufacture of clad linepipe to B331, the following requirements shall apply for welding of 405 The cladding alloy shall be produced from plate, and lined linepipe: shall be supplied in a solution or soft annealed condition, as applicable. — the corrosion properties of the CRA weld consumable (e.g. fillet or clad weld) shall be equal or superior to the liner 406 The steel backing material and the cladding alloy shall material be cleaned, dried and inspected to ensure that the level of — the weld shall be purged with welding grade inert gas and humidity 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 criteria 407 Unless otherwise agreed, the mating plate surfaces shall as a minimum be blast cleaned to a surface cleanliness of ISO Properties of the backing material 8501 Sa2. 501 The backing material of the manufactured clad or lined 408 A pre-clad rolling assembly procedure shall be part of linepipe shall comply with the requirements for C-Mn steel the MPS. This procedure shall include details of all surface given in Subsection B. Sour service requirements according to preparation to be performed just prior to the sandwich assem- I100 shall not apply to the backing material unless required bly (if applicable). according to I115. 409 The sandwich or one-side-open packages, as applicable, 502 The cladding/liner material shall be removed from the shall 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. Hardness 410 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 meet heat treatment (e.g. quench and tempering). the relevant requirements of this standard.

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Bonding 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 to tion on the edges of the specimens. B512. 505 After longitudinal weld root bend testing in accordance Heat and product analysis with 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 CRA specimen edge may be disregarded if not associated with obvi- liner or cladding, respectively. ous defects. Mechanical testing 506 The minimum shear strength shall be 140 MPa. 607 All mechanical testing of clad pipe and the backing steel Properties 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 API 507 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 performed Chemical 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 in exposed to the pipe fluid), shall be analysed during MPQT. Appendix B. Unless otherwise agreed the composition of the deposited weld Corrosion testing metal as analysed on the exposed surface shall meet the requirements of the base material specification. 609 Unless otherwise agreed, corrosion testing of roll bonded clad pipes or any longitudinal weld seams is not Unless otherwise agreed the calculated PRE (see Table 7-10, required. note no. 2) for alloy 625 weld metal shall not be less than for the clad pipe base material or liner material. Metallurgical testing Microstructure 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 clad pipe seam welds, any pipe end clad welds and the seal welds of Liner collapse test lined pipe shall be essentially free from grain boundary car- 611 To check for the presence of moisture in the annulus bides, nitrides and intermetallic phases. between the liner and the backing material, one finished pipe Gripping force of lined linepipe or a section thereof (minimum length of 6 m) shall be heated to 200°C for 15 minutes and air cooled. This pipe shall be within 510 Acceptance criteria for gripping force production testing the first 10 pipes produced. shall be agreed based on project specific requirements (see Sec.6 B400) and/or test results obtained during MPQT. Gripping force test Liner collapse 612 Gripping force of lined pipe shall be measured in 511 After the test for presence of moisture in the annulus accordance with API 5LD. Equivalent tests may be applied between 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 the pipe 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 accordance 601 Compliance with the requirements of the purchase order with Subsection E. shall be checked by specific inspection in accordance with EN 10204. Records from the qualification of the MPS and other docu- Non-destructive testing mentation shall be in accordance with the requirements in Sec.12. 614 NDT, including visual inspection, shall be in accordance Inspection frequency with Subsection F. 602 The inspection frequency during production and MPQT Dimensional testing shall be as given in Table 7-14 and Table 7-15, respectively. 615 Dimensional testing shall be performed according to 603 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 defects 604 For lined pipe, the number and orientation of the sam- 616 Surface imperfections and defects shall be treated ples 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 linepipe Applicable to Type of test Extent of testing Acceptance criteria All pipe All tests in Table 7-7 applicable to “All pipe” See Table 7-7 and D600 D501 Clad 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 D507 CRA material of According to reference standard (see D508 clad pipe Liner 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 2010 Page 80 – Sec.7

Table 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 criteria All pipe All production tests in Table 7-14 One test for each pipe See Table 7-14 Corrosion testing of welds, if agreed, see D609provided 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 D505 Lined pipe Chemical composition of seal or clad welds 2) D508 Metallographic examination of seal welds D509 Liner collapse test D511 Notes 1) 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 pressure E 100 Mill pressure test may be significantly higher than the incidental pressure. For 101 Each length of linepipe shall be hydrostatically tested, such conditions and where the mill pressure test capacity is unless 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 seal is made on the inside or the outside of the linepipe surface, be 106 The test configuration shall permit bleeding of trapped conducted 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 ⋅ t be recorded together with the identification of the pipe tested. min (7.2) ph = ------⋅⋅min[SMYS 0.96;0.84SMTS ⋅ ] The equipment shall be capable of registering a pressure drop Dt– min of minimum 2% of the applied pressure. The holding time at test pressure shall be minimum 10 seconds. Calibration records 103 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 end caps, and the linepipe is exposed to axial stresses, the test pres- 107 Subject to agreement, the hydrostatic testing may be sure 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;0.84SMTS ⋅ ] — ensure that the pipe material stress-strain curve is linear up based on the minimum pipe wall thickness t . to a stress corresponding to E102 min — 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. s e = 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 ⋅ ()Dt– h min be recorded for each pipe. s h = ------2 ⋅ tmin

N = True pipe wall force which depend on the test set up end restraints. F. Non-destructive Testing F 100 Visual inspection s = -----N l A 101 Visual inspection shall be in accordance with Appendix s D H500. 102 If visual inspection for detection of surface imperfec- (tmin is equivalent to t1 in Sec.5) 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 Appendix 104 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 testing Sec.5 B200. 201 Requirements for Non-Destructive Testing (NDT) of 105 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 Offshore Standard DNV-OS-F101, October 2010 Sec.7 – Page 81 are 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 to lamination 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 at

Table 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 H600 Pipe ends of all Laminar imperfections pipe ends 4) UT 100% H700 pipe 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% H900 and LBW Laminar imperfections in area adjacent to weld UT 100% Longitudinal imperfections in weld UT 100% SAWL, Laminar imperfections in pipe body UT 100% H1300 SAWH 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% H1000 Lined 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% Notes 1) 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 the 101 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 length 201 The diameter and out-of-roundness shall be within the of pipe shall be 12.1 m, and the tolerances for length according tolerances given in Table 7-17. However, in areas where to Table 7-19.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 82 – Sec.7

Tolerances for the weld seam 306 The pipe body out-of-roundness shall be determined as 205 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 of G 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 each to Table 7-17 to Table 7-19. pipe end. External measurement shall be taken where indicated by visual 302 Suitable methods shall be used for the verification of conformance with the dimensional and geometrical tolerances. inspection. MR (the requirement is modified compared to ISO Unless 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 1 facturer. and Figure 2 in ISO 3183. 303 All test equipment shall be calibrated. Dimensional test- 310 Out-of squareness at pipe ends shall be measured ing 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 be be within acceptable limits. weighed individually. For pipe with D < 141.3 mm, the lengths 304 Unless a specific method is specified in the purchase of pipe shall be weighed either individually or in convenient order, 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 r = t(D-t) · C (7.4) slotted or notched to permit passage of the gauge over the weld l 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. r is the mass per unit length, in kg/m l ---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 mm 305 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 or circumferential 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 thickness smallest inside diameter, as measured in the same cross-sec- and the diameter of pipe ends and maximum out-of-roundness tional 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 length to ISO 3183). 100% of the actual measurement results shall be recorded.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.7 – Page 83

Table 7-17 Tolerances for diameter and out-of-roundness D [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 m m o r ± 0.5 mm or ± 0.5 mm Included in the diameter tolerance 4) ≥ 60.3 ≤ 610test unit ± 0.0075 D, ± 0.0075 D, 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 agreed where D = Specified outside diameter t = specified nominal wall thickness. Notes

1) 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. MR

Table 7-18 Tolerances for wall thickness Type 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 t SMLS 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 mm 100% HFW, EBW, LBW and MWP 2) 6.0 < t ≤ 15.0 ± 0.7 mm t > 15.0 ± 1.0 mm t ≤ 6.0 ± 0.5 mm 6.0 < t ≤ 10.0 ± 0.7 mm SAW 3) 10.0 < t ≤ 20.0 ± 1.0 mm t > 20.0 + 1.5 mm - 1.0 mm where t = specified nominal wall thickness. Notes

1) 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 7-18 Characteristic to be tested Frequency of inspection Tolerances Geometric deviations (peaking and flats) 1) 10% 2) 0.005 D or 2.5 mm, whichever is less Straightness, max. for full length of pipe 5% 2) ≤ 0.0015 L Straightness, max. deviation for pipe end region 3) 3 mm Out-of squareness at pipe ends ≤ 1.6 mm from true 90° Length 100% min. 11.70 m and max. 12.70 m Weight of each single pipe / pipe bundle -3.5% / +10% of nominal weight Tolerances for the pipe weld seam and dents see G205 and G206 where L = actual length of pipe

Notes

1) Applicable to welded pipes only 2) 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 2010 Page 84 – Sec.7

H. Marking, Delivery Condition and strain based design. Any restrictions for maximum allowable Documentation strain during operation are beyond the scope of this standard.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- H 100 Marking C-Mn steel 101 All marking shall be easily identifiable and durable in order to withstand pipe loading, shipping, and normal installa- 103 C-Mn steel linepipe for sour service shall conform to tion activities. Subsection B, and to the modified and additional requirements below, which conform to the requirements in ISO 3183 Annex 102 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 subject to agreement. 104 The chemical compositions given in Table 7-3 and Table 7-4 shall be modified according to Table 7-20 and Table 103 Each linepipe shall be marked with a unique number. 7-21, respectively. The marking shall reflect the correlation between the product and the respective inspection document. Table 7-20 Chemical composition for SMLS and welded C-Mn steel pipe with delivery condition N or Q for Supplementary H 200 Delivery condition requirement, sour service 201 The delivery condition of C-Mn steel pipe shall be Product analysis, maximum. weight % according to Table 7-1. SMYS 202 The internal surface of CRA pipes shall be pickled in C 1) Mn 1) S 2) VOther 3,4) accordance with the purchase order. If agreed the external sur- Pipe with delivery condition N - according to Table 7-1 face of CRA pipes shall be cleaned. 245 - - 0.003 - - 290 - - 0.003 - - H 300 Handling and storage 320 - - 0.003 - - 301 On customer's request, each linepipe shall be protected 360 - - 0.003 - - until taken into use. Pipe with delivery condition Q - according to Table 7-1 302 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 5,6,7) agreement between the Purchaser and the manufacturer. 485 0.16 1.65 0.003 0.09 Notes Notes 403 The Inspection Certificate shall identify the products represented 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 is number, 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 SMLS type of pipe, and the delivery condition shall be stated. and ≤ 0.006% for welded pipe, and in such cases lower Ca/S may be 404 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 pipe weld seam shall be stated. Ca ≤ 0.006%. 5) If agreed Mo ≤ 0.35%. 405 Records from the qualification of the MPS and other documentation shall be in accordance with the requirements in 6) If agreed Cr ≤ 0.45% and Ni ≤ 0.50%. Sec.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 I. Supplementary Requirements with delivery condition M for Supplementary requirement, sour service I 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 requirements below. 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 apply, in combination with the additional requirements of this 320 0.10 - 0.002 - - standard. 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- 5,6) ble “to the qualification and selection of materials for equipment 450 0.10 1.60 0.002 - Notes 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 Offshore Standard DNV-OS-F101, October 2010 Sec.7 – Page 85

105 Vacuum degassing or alternative processes to reduce the Clad or lined steel linepipe gas 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 additional 107 The requirements for mechanical properties in B400 requirements below. shall apply, except for the hardness. 115 Materials selection for cladding/liner, the associated 108 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 internal If 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 for the weld cap area. 116 During qualification of welding procedures and produc- tion, hardness measurements shall be performed as outlined in 109 Any hard spot larger than 50 mm in any direction, see Appendix B. The hardness in the internal heat-affected zone Table 7-7, shall be classified as a defect if its hardness, based and in the fused zone of the cladding/lining shall comply with upon 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 with Pipes 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 one 110 The acceptance criteria for the HIC test shall be the fol- randomly selected pipe from each of the three (3) first heats, or lowing, with each ratio being the maximum permissible aver- until three consecutive heats have shown acceptable test age 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 heat Appendix 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 show 111 By examination of the tension surface of the SSC speci- acceptable results, the ten heats are acceptable. However, if men 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 tested demonstrated that these are not the result of sulphide stress until the test results from three consecutive heats have been cracking. found acceptable. After three consecutive heats have shown CRA linepipe acceptable test results, the testing frequency may again be 112 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 test 113 Linepipe grades, associated hardness criteria, and 120 If specified in the purchase order SSC testing shall be requirements 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 tests

Type of pipe Type of test Extent of testing Acceptance criteria Welded C-Mn steel pipe HIC test In accordance with I118 and I119 I110

Tests for Manufacturing Procedure Qualification Test Type of pipe Type of test Extent of testing Acceptance criteria Welded C-Mn steel pipe HIC test If agreed, one test (3 test pieces) for each pipe provided I110 All pipe (only if agreed, see SSC test for manufacturing procedure qualification I111 Sec. 6 B202) Notes 1) 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 established properties (F) for the linepipe base material. The Charpy V-notch energy 201 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 specimens usage factor, up to a pressure of 15 MPa, 30 mm wall thickness shall be tested at different temperatures, including Tmin, and and 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 2010 Page 86 – Sec.7

203 This paragraph does not apply to linepipes delivered formed on welded linepipe with outer diameter > 500 mm, wall with a final heat treatment (e.g. normalising or quench and thickness > 8 mm and SMYS > 360 MPa. A DWTT transition tempering). 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 specimens introduced during manufacturing (no additional straining is taken from the same test coupon. The test shall be performed required). The samples shall be aged for 1 hour at 250°C. Five in accordance with Appendix B. The specimens tested at the sets of specimens shall be tested at different temperatures, minimum design temperature shall as a minimum, meet an including 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 in given in Table 7-23 in the aged condition. Values obtained at I100 are specified for linepipe material with SMYS ≥ 450 MPa other test temperatures are for information. the acceptance criteria stated in I204 (average and minimum 204 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) Notes SMYS ≤ 610 ≤ 820 ≤ 1120 1) Minimum individual results to exceed 75% of 245 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 agreement 485 82 100 124 (see Sec. 5 D1100) 555 103 126 155

Table 7-24 Applicable testing for Supplementary requirement F Type of pipe Type of test Extent of testing Acceptance criteria All 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- 1) Welded pipe CVN impact testing of the pipe body for establishment of transition curve, cedure qualification Table 7-23 except CRA pipe aged condition 2) Notes

1) 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 I203

I 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 MPa 301 Supplementary requirement (P) is applicable to linepipe — the YS/TS ratio shall not exceed 0.90 unless otherwise when 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 to single event strains below 5%. Guidance note: A higher yield to tensile ratio may be specified in case the local 302 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- gitudinal direction using proportional type specimens in ah = 1 - 0.2 · eF · gc ·1.2/ec accordance with Appendix B, in order to meet the require- Buckling of the pipeline during on-reeling is primarily caused by ments 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 stress according to Table 7-9 is not required. Transverse tensile test- along the pipeline. The strain hardening capability combined ing 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 does 303 The finished pipe (for C-Mn steel the requirements are not prevent buckles, evaluations of the loading scenario is also applicable up to X65, otherwise subject to agreement) shall meet necessary. the following requirements to tensile properties in longitudinal direction (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---

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Table 7-25 Additional testing for Supplementary requirement P 1)

Production tests Type of pipe Type of test Extent of testing Acceptance criteria All 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 criteria All 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 testing Welded pipe Tensile testing of weld metal (all weld test) I308 CVN impact testing of the seam weld Hardness testing of the seam weld Notes 1) 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 test pipe 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 straining I306 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 scale straining the test specimens, which shall represent the strain — SMYS, SMTS and hardness shall be according to Table history 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 be The 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 for turer. 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 tolerances 307 The following testing shall be performed of the longitu- on the subsequent fabrication/installation activities and the dinal weld seam after straining and ageing: welding facilities to be used.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 88 – Sec.7

Table 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 inspection All 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 mm SMLS 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 mm SAW 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 ends where D = specified nominal outside diameter t = specified nominal wall thickness. Notes 1) 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 quenched and tempered condition testing may be conducted in the longi- If one or both of the confirmatory tests fall below SMYS, the tudinal direction. re-test program given in I508 shall apply. 502 The test regime given in this sub-section intends to Re-testing ensure that the average yield stress is at least two standard 507 If the result from the mandatory testing falls below deviations above SMYS. The testing scheme applies to pro- SMYS, four (4) re-tests taken from four (4) different pipes (a duction in excess of 50 test units. Alternative ways of docu- total of 4 tests), within the same test unit, shall be tested. If the menting the same based upon earlier test results in the same four re-tests meet SMYS, the test unit is acceptable. If one of production 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 sample 503 The testing frequency shall comply with Table 7-7 or shall be replaced by a correctly prepared sample from the same Table 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 and requirement SMYS × 1.03, no further testing is required in I508 above), the Manufacturer may conduct re-heat treatment order 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 one 505 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 and 506 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 required different pipes (a total of two tests) within the same test unit if the agreed allowed variation of any parameter is exceeded.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 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 construction of 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 assurance A 200 Application 301 Requirements for quality assurance are given in Sec.2 201 This Section is applicable to pressure containing compo- B500. Corresponding requirements for the material processing nents (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 components Components Requirements for manufacture and testing Reference code and applicable class or designation 1) given in this section Bends B300 ISO 15590-1, Class C for non-sour and Class CS for sour service Fittings2) B400 ISO 15590-2, Class C for non-sour and Class CS for sour service Flanges B500 ISO 15590-3, Designation (L) for non-sour and desig- nation (LS) for sour service Valves B600 ISO 14723 Mechanical connectors B700 not covered by specific reference code CP Insulating joints B800 Anchor flanges B900 Buckle and fracture arrestors B1000 Pig traps B1100 Repair clamps and repair couplings B1200 Notes

1) 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 the B 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 additional Components 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 modified Table 8-1 and the additional and modified requirements given requirements to ISO 15590-1 in 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 (minimum Components 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 them standard (see B201), shall comply with the general require- — the centering tolerances for the coil ments 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 carbon Subsection 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 2010 Page 90 – Sec.8 steel 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 extrados, the neutral axis, and the bend intrados. Surface hard- 390 0.43 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 welds rials shall meet the applicable requirements for the relevant — H700 or H800, for UT of welds in C-Mn steel material type and grade given in Sec.7. However, the supple- — H200, for UT of welds in duplex stainless steel mentary requirements F, P, D or U are not applicable to bends. — H800, for DP of welds in duplex stainless steel, and Mother 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 the pipe. 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 the apply. 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 CRA's. 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 is 307 (8.5) Heat treatment equipment and procedures shall be recommended that the bars transverse to the flow direction are in accordance with D500. welded to a pup piece, and that the bars parallel to the flow 308 (9.4.4.2) For C-Mn steel bends intended for sour-serv- direction are welded to the transverse bars only. If this is ice, hardness values up to 275 HV10 are acceptable in the out- impractical, alternative designs shall be considered in order to side 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 Offshore Standard DNV-OS-F101, October 2010 Sec.8 – Page 91

The MPS should specify the following items, as applicable: — 25Cr duplex stainless steel fittings shall be corrosion tested as required in Table 8-4, and a) 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 unit For “one-off” fittings designed and manufactured for a specific — HIC testing shall be performed for qualification of the purpose, the following additional information shall be pro- MPS for fittings in Class CS manufactured from rolled vided: 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 at an 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% magnetic with 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 to method 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 performed in accordance with qualified procedures meeting the require- — C400, for visual inspection ments in Appendix C. — D200, for C-Mn/low alloy steel forgings 408 (8.3.3) Heat treatment equipment and procedures shall — D300, for duplex stainless steel forgings be in accordance with D500. — C206 through 213, for UT of a 50 mm wide band inside ends/bevels 409 (9.2) Test pieces shall be taken according to E101 and — C221, for MT of ends/bevels E103. Location of test specimens shall be in accordance with — C222, for PT of ends/bevels E100. — B200, for RT of welds 410 (Table 2) Inspection, testing and acceptance criteria — B300, for UT of welds in C-Mn/low alloy steel shall be in accordance with Class C with the following addi- — B400, for UT of welds in duplex stainless steel tional 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 2010 Page 92 – Sec.8 vided: 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 to qualified welding procedures meeting the requirements of method and acceptance criteria may be applied. Appendix C. Acceptance criteria for forgings shall be in accordance with the 504 (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 connections accordance 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 be 508 (Table 5) The impact test temperature for C-Mn steel provided: and low alloy flanges shall be 10°C below the minimum design temperature for all thicknesses and categories. — design standard 509 Hardness indentation locations shall be according to — required design life Table 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, and acceptance criteria according to Sec.7 C400. — weld overlay, corrosion resistant and/or wear resistant. 511 (9.4.6 & 9.4.7) Manufacturing procedure specification Corrosion testing of duplex stainless steel shall be according to Table 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 the trant 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 temperature of 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 are found during the testing of the first 10 flanges of each type and 607 (8) Welding shall be performed according to qualified size 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 Offshore Standard DNV-OS-F101, October 2010 Sec.8 – Page 93 alloy steels shall be in accordance with ISO 14723, Annex E, B 800 CP Insulating joints QL 2 requirements. 801 These requirements apply to manufacture and testing of The extent and type of NDT of duplex stainless steels shall be boltless, monolithic coupling type of insulating joints for in 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- ings ance with ISO 14723, Annex E, QL 2 requirements. the 803 Insulating joints shall be protected from electrical high method shall be according to Appendix D. current high voltage from welding and lightening etc. in the Acceptance 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 fitted For UT 2, VT 2 and VT 3 the acceptance criteria shall be in with a temporary short-circuit cable clearly tagged with the accordance 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 the 610 (10.2) Hydrostatic shell tests shall be performed in design, manufacture and testing of insulating joints, one joint accordance 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 the guish 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 moment qualified by applicable fire tests. Refer to API 6FA and BS — Tension to maximum design tension 6755 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 of end connections such as hub and clamp connections connect- Before and after testing the resistance and electrical leakage ing 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 longitudinally 703 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 (if 704 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 (as applicable): 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 the Acceptance criteria shall be according to the corresponding combined pressure-bending test / electrical leakage tests shall requirements 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 be formed according to G100. performed with a test pressure 1.5 times the design pressure,

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 94 – Sec.8 unless otherwise specified, and to the specified holding time in — B200, for RT of welds general accordance with G100. — B300, for UT of welds in C-Mn/low alloy steel 809 Hydraulic fatigue of each insulating joint shall be per- — B400, for UT of welds in duplex stainless steel formed. The test shall consist of 40 consecutive cycles with the — B500, for MT of welds in C-Mn/low alloy steel pressure changed from 10 barg to 85 percent of the hydrostatic — B600, for DP of welds in duplex stainless steel test pressure. At the completion of the test cycles the pressure — D400, for visual inspection of forgings shall be increased to the hydrostatic test pressure and main- — B800, for visual inspection of welds, and tained 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 corresponding 810 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 arrestors pressure 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 with pressure effect) longitudinal stress of 90% of SMYS in the Subsec.E or Sec.7. adjoining pup pieces. The test duration shall be 2 hours. The acceptance criteria are no water leakage or permanent distor- B 1100 Pig traps tion. 1101 Materials shall comply with the requirements of the 811 After hydrostatic testing, all isolating joints shall be leak design code or with the requirements of this section, if more tested with air or nitrogen. The joints shall be leak tested at 10 stringent. barg for 10 minutes. The tightness shall be checked by immersion or 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 the 812 The FAT shall be performed according to the accepted design code or with the requirements of Appendix C, if more FAT 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 in 813 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 NDT relative 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 B100 sinusoidal 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 requirements value not exceeding 1.2kV increasing to 5.0kV in a time not of the design code longer than 10 seconds and shall be maintained at peak value for 60 seconds. The test is acceptable if no breakdown of the B 1200 Repair clamps and repair couplings insulation or surface arcing occurs during the test and a maxi- Repair clamps and repair couplings to be installed according to mum 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 any changes which may take place within a joint after hydrostatic C. Materials for Components testing, hydraulic fatigue test and the combined pressure-bend- ing test. No significant changes in electrical leakage shall be C 100 General accepted. 101 The materials used shall comply with internationally B 900 Anchor flanges recognised standards, provided that such standards have acceptable equivalence to the requirements given in Sec.7 and 901 Anchor flanges shall be forged. this section. Modification of the chemical composition given 902 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 low NDT shall be performed in accordance with Appendix D (as alloy steel forgings and castings with SMYS ≤ 555 MPa. Use applicable): 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 Offshore Standard DNV-OS-F101, October 2010 Sec.8 – Page 95 international standards. The chemical composition shall be 102 Components shall be manufactured in accordance with a selected to ensure an acceptable balance between sufficient documented and approved MPS. hardenability and weldability. 103 The MPS shall demonstrate how the fabrication will be 204 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 quality mechanical properties are met. and reliability of production. All main fabrication steps from 205 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 materials 207 Forgings shall be delivered in normalised or quenched — manufacturer and tempered condition. Minimum tempering temperature — steel making process shall be 610°C when PWHT will be applied, unless otherwise — steel grade specified. — product form, delivery condition 208 Castings shall be delivered in homogenised, normalised — chemical composition and 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 — Manufacturing quenched and tempered condition, the tempering temperature shall be sufficiently high to allow effective post weld heat — supply of material and subcontracts treatment during later manufacture / installation (if applica- — manufacturing processes including process- and proc- ble). ess control procedures — welding procedures C 300 Duplex stainless steel, forgings and castings — heat treatment procedures 301 All requirements with regard to chemical composition — NDT procedures for 22Cr and 25Cr duplex stainless steel shall be in accordance — list of specified mechanical and corrosion testing with Sec.7 C400. — hydrostatic test procedures 302 Acceptance criteria for tensile, hardness, Charpy V- — functional test procedures notch impact properties and corrosion tests are given in E300. — dimensional control procedures — FAT procedures 303 Duplex stainless steel castings and forgings shall be — marking, coating and protection procedures delivered in the solution annealed and water quenched condi- — handling, loading and shipping procedures tion. — at-site installation recommendations. C 400 Pipe and plate material For “one-off” components and other components designed and 401 Pipe and plate material shall meet the requirements in manufactured for a specific purpose, the following additional Sec.7. information shall be provided: 402 For welded pipe it shall be assured that the mechanical — Plan and process flow description/diagram properties of the material and longitudinal welds will not be — Order specific quality plan including supply of material affected by any heat treatment performed during manufacture and subcontracts of components. — Manufacturing processes including process- and process 403 In case post weld heat treatment is required, the mechan- control procedures. ical testing should be conducted after simulated heat treatment. D 200 Forging C 500 Sour Service 201 Forging shall be performed in compliance with the 501 For components in pipeline systems to be used for fluids accepted MPS. Each forged product shall be hot worked as far containing hydrogen sulphide and defined as “sour service” as practicable, to the final size with a minimum reduction ratio according 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 the procedures 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 the ings 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 temperature nents 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 Casting induction bends and fittings that shall be manufactured in 301 Casting shall be performed in general compliance with accordance with B300 and B400 ASTM A352.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 96 – Sec.8

302 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 attached 303 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 final thickness 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 castings repaired by welding. The maximum extent of repair welding prior to heat treatment should take into account the requirements should 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 being D 400 Hot forming immersed in the quenchant shall not exceed 90 seconds for low 401 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, including extrusion of branches, shall be performed below 1050°C. The temperature shall be monitored. The component shall be allowed to cool in still air. E. Mechanical and Corrosion Testing of Hot 403 For duplex stainless steel material, the hot forming shall Formed, Cast and Forged Components be conducted between 1000 and 1150°C. E 100 General testing requirements D 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 one shall 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 be 502 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 least once a year in order to ensure acceptable temperature stability 107 A sketch indicating the final shape of the component and and uniformity. The uniformity test shall be conducted in the location of all specimens for mechanical testing shall be accordance 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 Offshore Standard DNV-OS-F101, October 2010 Sec.8 – Page 97 according to ASTM G48 shall be performed in order to con- shall meet the requirements for linepipe with equal SMYS as firm 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-sour with Appendix B, at 50°C. The test period shall be 24 hours. service shall not exceed 300 HV10. For components intended for sour service the hardness shall according to Sec.7 I100. E 200 Acceptance criteria for C-Mn and low alloy steels 201 Tensile, hardness and Charpy V-notch impact properties

Table 8-4 Number, orientation, and location of test specimens per tested component Type 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 the gential 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 surface section of the component for section thickness ≥ 25 mm 5,6) Metallographic sample 3 As for the CVN impact testing sets Hardness testing 7) 3 As for the CVN impact testing sets HIC and SSC test 8) 1 In accordance with ISO 15156 ASTM G48 9) 1 See E108 Notes

1) 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 component's 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 1 Location of tensile and CVN specimens, component with section thickness ≥ 25 mm

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 98 – Sec.8

203 Specimens for hardness testing shall be examined, prior 305 Due consideration shall be given to the access and time to testing, at a magnification of not less than x100. Grain-size required for adequate inspection and testing as fabrication pro- measurement shall be performed in accordance with ASTM ceeds. E112. The type of microstructure and actual grain size shall be recorded on the materials testing report. 306 Due consideration during fabrication shall be given to the control of weight and buoyancy distribution of pipe strings E 300 Acceptance criteria for duplex stainless steels for towing. 301 Tensile, hardness and Charpy V-notch impact properties 307 The procedures prepared by the fabricator shall be sub- shall meet the requirements for linepipe as given in Sec.7, C400. mitted for acceptance prior to start of fabrication. 302 The metallographic samples shall comply with the F 400 Material receipt, identification and tracking requirements of Sec.7 C400. 401 All material shall be inspected for damage upon arrival. 303 For ASTM G48 testing the acceptance criteria is: maxi- 2 Quantities and identification of the material shall be verified. mum allowable weight loss 4.0 g/m . Damaged items shall be clearly marked, segregated and dis- posed of properly. 402 Pipes shall be inspected for loose material, debris, and F. 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 materials 101 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 during 102 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 records cedures, 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 and prior to start of production. repair numbers. The system shall be capable of detecting duplicate records. F 200 Materials for risers, expansion loops, pipe strings for reeling and towing 405 The individual pipes of pipe strings shall be marked in accordance with the established pipe tracking system using a 201 Linepipe shall comply with the requirements, including suitable marine paint. The location, size and colour of the supplementary requirements (as applicable) given in Sec.7. 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 string requirements 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 heat 302 The MPS shall demonstrate how the fabrication will be treatment performed and verified through the proposed fabrication steps. 501 The Contractor shall be capable of producing welded The MPS shall address all factors which influence the quality and joints of the required quality. This may include welding of reliability of production. All main fabrication steps from control girth welds, other welds, overlay welding and post weld heat of received material to shipment of the finished product(s), treatment. Relevant documentation of the Contractor's capabil- including all examination and check points, shall be covered in ities shall be available if requested by the Purchaser. detail. References to the procedures and acceptance criteria estab- lished for the execution of all steps shall be included. 502 Attention shall be paid to local effects on material prop- erties and carbon contamination by thermal cutting. Preheating 303 The MPS shall, as a minimum, contain the following of the area to be cut may be required. Carbon contamination information: shall be removed by grinding off the affected material. — plan(s) and process flow description/diagram 503 Forming of material shall be according to agreed proce- — project specific quality plan including supply of material dures specifying the successive steps. and subcontracts — fabrication processes used 504 The fabrication and welding sequence shall be such that — supply of material, i.e. manufacturer and manufacturing the amount of shrinkage, distortion and residual stress is mini- location of material mised. — fabrication processes 505 Members to be welded shall be brought into correct — fabrication process procedures alignment and held in position by clamps, other suitable — fabrication process control procedures devices, or tack welds, until welding has progressed to a stage — welding procedures where the holding devices or tack welds can be removed with- — heat treatment procedures out danger of distortion, shrinkage or cracking. Suitable allow- — NDT procedures ances shall be made for distortion and shrinkage where — pressure test procedures appropriate. — list of specified mechanical and corrosion testing 506 Welding shall meet the requirements given in — dimensional control procedures Appendix C. — marking, coating and protection procedures and — handling, loading and shipping procedures. F 600 Hydrostatic testing 304 The MPS shall be submitted for acceptance prior to start 601 Hydrostatic testing shall be performed to established of fabrication procedures meeting the requirements of G100.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.8 – Page 99

F 700 NDT and visual examination — Testers shall have a range of minimum 1.25 times the 701 All welds shall be subject to 100% visual inspection. specified test pressure, with an accuracy better than ± 0.1 bar and a sensitivity better than 0.05 bar. 702 Welds where the acceptance criteria are based on the — Temperature-measuring instruments and recorders shall acceptance criteria in Appendix D shall be subject to 100% have an accuracy better than ± 1.0°C, and radiographic or ultrasonic testing based on the requirements to — Pressure and temperature recorders are to be used to pro- applicable and preferred NDT methods is given in vide a graphical record of the pressure test for the total Appendix D. duration of the test. 703 For welds where allowable defect sizes are based on an ECA, ultrasonic testing shall supplement radiographic testing, 109 Where the test acceptance is to be based on observation unless automated ultrasonic testing is performed of pressure variations calculations showing the effect of tem- perature changes on the test pressure shall be developed prior 704 Requirements to automated ultrasonic testing systems to starting the test. Temperature measuring devices, if used, are given in Appendix E. shall be positioned close to the test object and the distance 705 All NDT shall be performed after completion of all cold between the devices shall be based on temperature gradients forming and heat treatment. along the test object. 706 Requirements for personnel, methods, equipment, proce- 110 The test medium should be fresh water or adequately dures, and acceptance criteria for NDT are given in Appendix D. treated sea water, as applicable. Filling procedure shall ensure minimum air pockets. F 800 Dimensional verification 111 Pressurisation shall be performed as a controlled opera- 801 Dimensional verification should be performed in order tion with consideration for maximum allowable velocities in to establish conformance with the required dimensions and tol- the inlet piping up to 95% of the test pressure. The final 5% up erances. to the test pressure shall be raised at a reduced rate to ensure 802 Dimensional verification of pipe strings for towing shall that the test pressure is not exceeded. Time shall be allowed for include weight, and the distribution of weight and buoyancy. confirmation of temperature and pressure stabilisation before the test hold period begins. F 900 Corrosion protection 112 The test pressure shall be according to the specified 901 Application of coatings and installation of anodes shall requirement. meet the requirements of Sec.9. 113 Where the test acceptance is to be based on 100% visual inspection the holding time at test pressure shall be until 100% visual inspection is complete or 2 hours, whichever is longer. Where the test acceptance is to be based on pressure observation G. Hydrostatic Testing the holding time at test pressure shall be not less than 2 hours. G 100 Hydrostatic testing 114 During testing, all welds, flanges, mechanical connec- 101 Prior to the performance of the pressure test the test tors etc. under pressure shall be visually inspected for leaks. object shall be cleaned and gauged. 115 The pressure test shall be acceptable if: 102 The extent of the section to be tested shall be shown on — During a 100% visual inspection there are no observed drawings or sketches. The limits of the test, temporary blind leaks and the pressure has at no time during the hold period flanges, end closures and the location and elevation of test instru- fallen below 99% of the test pressure. 100% visual inspec- ments and equipment shall be shown. The elevation of the test tion shall only be acceptable where there is no risk that a instruments shall serve as a reference for the test pressure. leak may go undetected due to prevailing environmental 103 End closures and other temporary testing equipment conditions, or shall be designed, fabricated, and tested to withstand the max- — The test pressure profile over the test hold period is con- imum test pressure, and in accordance with a recognised code. sistent with the predicted pressure profile taking into 104 Testing should not be performed against in-line valves, account variations in temperatures and other environmen- unless possible leakage and damage to the valve is considered, tal changes. and the valve is designed and tested for the pressure test con- 116 Documentation produced in connection with the pres- dition. Blocking off or removal of small-bore branches and sure testing shall, where relevant, include: instrument tappings should be considered in order to avoid possible contamination. — Test drawings or sketches Considerations shall be given to pre-filling valve body cavities — pressure and temperature recorder charts with an inert liquid unless the valves have provisions for pres- — log of pressure and temperatures sure equalisation across the valve seats. — calibration certificates for instruments and test equipment 105 Welds shall not be coated, painted or covered. Thin — calculation of pressure and temperature relationship and primer coatings may be used where agreed. justification for acceptance. 106 Instruments and test equipment used for measurement of G 200 Alternative test pressures pressure, volume, and temperature shall be calibrated for accu- racy, repeatability, and sensitivity. All instruments and test 201 For components fitted with pup pieces of material iden- equipment shall possess valid calibration certificates with tical to the adjoining pipeline, the test pressure can be reduced traceability to reference standards within the 6 months preced- to a pressure that produce an equivalent stress of 96% of ing the test. If the instruments and test equipment have been in SMYS in the pup piece. frequent use, they should be calibrated specifically for the test. 202 If the alternative test pressure in G201 can not be used 107 Gauges and recorders shall be checked for correct func- and the strength of the pup piece is not sufficient: tion immediately before each test. All test equipment shall be — Testing shall be performed prior to welding of pup pieces. located in a safe position outside the test boundary area. The weld between component and pup piece is regarded a 108 The following requirements apply for instruments and pipeline weld and will be tested during pipeline system test equipment: testing.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 100 – Sec.8

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, as 101 All base material, fittings and, flanges, etc. shall be delivered with Inspection Certificate 3.1 according to Euro- a minimum, provide correlation of the product with the related pean 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 Offshore Standard DNV-OS-F101, October 2010 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 separate document. The purchaser may specify that the above — manufacture (application) of concrete weight coatings documentation shall be submitted for approval prior to the start — manufacture of galvanic anodes of production and any PQT (see B202). — installation of galvanic anodes. 202 A coating pre-production qualification test (PQT; also referred to as an “application procedure qualification test”, 102 The objectives are to ensure that the external corrosion “procedure qualification trial” or “pre-production trial”) control system and any weight coating are manufactured and should be executed and accepted by the purchaser before start- installed to provide their function for the design life of the sys- ing the coating work, especially for coating systems which rely tems. As to the last item above, it is a further objective to on a curing process to achieve the specified properties. The ensure that the fastening does not impose any damage or haz- purpose of the qualification is to confirm, prior to the start of ards affecting the integrity of the pipeline system. regular production, that the coating manufacturing procedure specification (MPS), coating materials, tools/equipment and A 200 Application personnel to be used for production are adequate to achieve the 201 This section is applicable to the preparation of specifica- specified properties of the coating. tions for manufacture and installation of external corrosion control systems and for the manufacture of concrete weight 203 An inspection and testing plan (ITP; sometimes referred coating during the construction phase. Such specifications to as an “inspection plan” or “quality plan”) shall be prepared shall define the requirements to properties of the coatings and and submitted to the purchaser for acceptance. The ITP shall anodes, and to the associated quality control. refer to the individual manufacturing and inspection/testing activities in consecutive order, define methods/standards, fre- 202 Manufacture and installation of any impressed current quency of inspection/testing, checking/calibrations, and CP systems for landfalls is not covered by this standard. The acceptance criteria. Reference shall be made to applicable pro- requirements in ISO 15589-1 shall then apply. cedures for inspection, testing and calibrations. 204 Inspection and testing data, essential process parame- ters, repairs and checking/calibrations of equipment for quality B. External Corrosion Protective Coatings control shall be recorded in a “daily log” that shall be updated on a daily basis and be available to the purchaser on request at B 100 General any time during coating production. 101 Properties of the coating (as-applied) and requirements to quality control during manufacture shall be defined in a pur- chase specification. DNV-RP-F106 and DNV-RP-F102 give C. Concrete Weight Coating detailed requirements and recommendations to the manufac- ture of linepipe coatings and field joint coating, respectively, C 100 General with emphasis on quality control procedures. DNV-RP-F102 also covers field repairs of linepipe coating. These documents 101 The objectives of a concrete weight coating are to pro- are applicable to the preparation of coating specifications and vide negative buoyancy to the pipeline, and to provide can also be used as a purchase document if amended to include mechanical protection of the corrosion coating during installa- project and any owner specific requirements. tion and throughout the pipeline's operational life. 102 The design and quality control during manufacture of 102 Requirements to raw materials (cement, aggregates, field joint coatings is essential to the integrity of pipelines in water, additives, reinforcement), and coating properties (func- HISC susceptible materials, including ferritic-austenitic tional requirements) shall be defined in a purchase specifica- (duplex) and martensitic stainless steel. Compliance with tion. The following coating properties may be specified as DNV-RP-F102 is recommended. applicable: B 200 Coating materials, surface preparation, coating — submerged weight/negative buoyancy application and inspection/testing of coating — thickness 201 All coating work shall be carried out according to a — concrete density project specific “manufacturing procedure specification” — compressive strength (MPS, also referred to as “application procedure specifica- — water absorption tion”). The following items shall be described in the procedure — impact resistance (e.g. over-trawling capability) specification: — flexibility (bending resistance), and —cutbacks. — receipt, handling and storage of coating materials — surface preparation and inspection Recommended minimum requirements to some of the above — coating application and monitoring of essential process properties are given in C202 below. Some general require- parameters ments to steel reinforcement are recommended in C203 and — inspection and testing of coating C204. Project specific requirements to quality control (includ- — coating repairs and stripping of defect coating ing pipe tracking and documentation) and marking shall also — preparation of cut-backs (for linepipe coating) be described in the purchase documentation.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 102 – Sec.9

C 200 Concrete materials and coating manufacture and submitted to the purchaser for acceptance in due time prior 201 All coating work shall be carried out according to a man- to start of production. The plan shall define the methods and ufacturing procedure specification (MPS). The following frequency of inspection, testing and calibrations, acceptance items shall be described: criteria and requirements to documentation. Reference shall be made to applicable specifications and procedures for inspec- — coating materials, including receipt, handling and storage tion, testing and calibration. Handling of non-conforming coat- — reinforcement design and installation ing materials and as-applied coating shall be described. — coating application and curing 302 Inspection shall include weighing and measurements of — inspection and testing, including calibrations of equipment outside concrete diameter for each individual pipe. The pur- — coating repairs (see F209) chaser may further specify seawater adsorption tests after com- — pipe tracking, marking and coating documentation pleted curing and compression tests of core samples from — handling and storage of coated pipes. applied coatings. Acceptance criteria for all inspection and testing shall be subject to agreement. The purchaser may specify that the MPS shall be subject to approval prior to start of production and any PQT. 303 Inspection and testing data, repairs, essential process parameters and calibrations of equipment for quality control Before starting coating production, the coating manufacturer shall be recorded in a “daily log” that shall be updated on a shall document that the materials, procedures and equipment to daily basis and be available to the purchaser on request at any be used are capable of producing a coating of specified prop- time during coating production. erties. The purchaser may specify a pre-production qualifica- tion test for documentation of certain properties such as impact resistance and flexibility (bending strength). 202 The concrete constituents and manufacturing method D. Manufacture of Galvanic Anodes shall provide the following recommended minimum require- ments to as-applied coating properties: D 100 Anode manufacture 101 Requirements to anode manufacture shall be detailed in — minimum thickness: 40 mm a purchase specification (‘anode manufacturing specifica- — minimum compressive strength (i.e. average of 3 core tion’). A manufacturing specification for pipeline bracelet specimens per pipe): 40 MPa (ASTM C39) anodes shall cover all requirements in ISO 15589-2. DNV-RP- — maximum water absorption: 8% (by volume), (testing of F103 refers to this document for anode manufacture and gives coated pipe according to agreed method), and 3 some additional requirements and guidance, primarily for pro- — minimum density: 1900 kg/m (ASTM C642). cedures and documentation associated with quality control. 203 The concrete coating shall be reinforced by steel bars The manufacturer of bracelet anodes shall prepare a ‘manufac- welded to cages or by wire mesh steel. The following recom- turing procedure specification’ (MPS) describing anode alloy mendations apply: For welded cages, the spacing between cir- (e.g. limits for alloying and impurity elements) and anode core cumferential bars should be maximum 120 mm. Steel bars materials, anode core preparations, anode casting, inspection should have a diameter of 6 mm minimum. The average per- and testing, coating of bracelet anode surfaces facing the pipe centage of steel to concrete surface area in circumferential surface, marking and handling of anodes, and documentation. direction and longitudinal direction sections should be mini- mum 0.5% and 0.08%, respectively. 102 An “Inspection and Testing Plan” (ITP) for manufacture of bracelet anodes, shall be prepared and submitted to the pur- 204 When a single layer of reinforcement is used, it shall be chaser for acceptance. It is further recommended that the located within the middle third of the concrete coating. The inspection and testing results are compiled in a ‘daily log’. recommended minimum distance from the corrosion protec- Requirements and guidance for preparation of these docu- tive coating is 15 mm, whilst the recommended minimum cov- ments and to a ‘pre-production qualification test’ are given in erage is 15 mm and 20 mm for coatings with specified DNV-RP-F103. For manufacturing of other types of anodes minimum thickness ≤ 50 mm and > 50 mm respectively. Over- than pipeline bracelet anodes, reference is made to DNV-RP- lap for wire mesh reinforcement should be minimum 25 mm. B401. Electrical contact with anodes for CP shall be avoided. Guidance note: 205 The concrete may be applied according to one of the fol- The requirement for an ITP is an amendment to ISO 15589-2. lowing methods: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — impingement application — compression coating 103 For each anode type/size, the manufacturer shall prepare — slip forming. a detailed drawing showing location and dimensions of anode inserts, anode gross weight and other details as specified in a 206 Rebound or recycled concrete may be used provided it is purchase document documented that specified properties are met and the purchaser 104 A procedure for electrochemical testing of anode material has accepted. performance during anode manufacturing is given in Appendix 207 The curing method shall take into account any adverse A of DNV-RP-B401 and in Annex D of ISO 15589-2. climatic conditions. The curing process should ensure no sig- 105 Marking of anodes shall ensure traceability to heat nificant moisture loss for 7 days and/or a minimum compres- number. Anodes should be delivered according to ISO 10474, sive strength of 15 MPa. Inspection Certificate 3.1.B or EN 10204, Inspection Certifi- 208 Procedures for repair of uncured / cured coatings and cate 3.1. detailed criteria for repairs (e.g. max repair areas for different types of coating damage) shall be subject to agreement. As a minimum, all areas with exposed reinforcement shall be repaired. Pipes with deficient coating exceeding 10% of the E. Installation of Galvanic Anodes total coating surface shall be recoated, unless otherwise agreed. E 100 Anode installation C 300 Inspection and testing 101 Installation of anodes shall meet the requirements in ISO 301 An inspection and testing plan (ITP) shall be prepared 15589-2. DNV RP-F103 gives some additional requirements

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.9 – Page 103 and guidelines, primarily for quality control. pipeline (see Sec.6 D500). For installation of anodes on such structures, reference is made to DNV-RP-B401. 102 For martensitic and ferritic-austenitic (duplex) stainless steels and for other steels with SMYS > 450 MPa, no welding ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- for anode fastening (including installation of doubling plates) shall be carried out on linepipe or other pressure containing 103 All welding or brazing of anode fastening devices and components, unless specified by or agreed with the pipeline connector cables shall be carried out according to a qualified owner. procedure (see Appendix C of this standard) to demonstrate Guidance note: that the requirements in ISO 13847 to maximum hardness Guidance note: The requirement above is an amendment to ISO (welding/brazing) and copper penetration (brazing including 15589-2. Most CP related HISC damage to pipeline components ‘aluminothermic welding’) are met. in CRA’s have occurred at welded connections of galvanic 104 For linepipe to be concrete weight coated, electrical con- anodes to the pipe walls. To secure adequate fastening of pipeline bracelet anodes for compatibility with the applicable installation tact between concrete reinforcement and the anodes shall be techniques, forced clamping of anodes is applicable in combina- avoided. The gaps between the anode half shells may be filled tion with electrical cables attached to anodes and pipeline by with asphalt mastic, polyurethane or similar. Any spillage of brazing. However, for many applications, CP can be provided by filling compound on the external anode surfaces shall be anodes attached to other structures electrically connected to the removed.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 104 – Sec.10

SECTION 10 CONSTRUCTION - INSTALLATION

A. General and reliability of the installation work, including normal and contingency situations, and shall address all installation steps, A 100 Objective including examinations and check points. The manual shall 101 This section provides requirements as to which analyses, reflect the results of the FMEA analysis or HAZOP studies, studies and documentation shall be prepared and agreed for the and shall state requirements for the parameters to be controlled installation, and further to provide requirements for the instal- and the allowable range of parameter variation during the lation and testing of the complete pipeline system which are installation. not covered elsewhere in the standard. The following shall, as a minimum, be covered: A 200 Application — quality system manual — mobilisation manual 201 This section is applicable to installation and testing of — construction manual pipelines and rigid risers designed and manufactured accord- — health, safety and environment manual ing to this standard. — emergency preparedness manual. A 300 Failure Mode Effect Analysis (FMEA) and Haz- The manuals should include: ard and Operability (HAZOP) studies 301 Systematic analyses of equipment and installation oper- — interface description ations shall be performed in order to identify possible critical — organisation, responsibilities and communication items or activities which could cause or aggravate a hazardous — description of and commissioning procedures for the condition, and to ensure that effective remedial measures are equipment and systems involved in the operation taken. Reference is given to DNV-RP-H101 Risk Management — limitations and conditions imposed by structural strength in Marine and Subsea Operations. in accordance with the design — limitations on operations imposed by environmental con- 302 The extent of analysis shall reflect the criticality of the ditions operations and the extent of experience available from previ- — references to the established operational and contingency ous similar operations. The systematic analyses should be car- procedures. ried out as a failure mode effect analysis (FMEA) and hazard and operability studies (HAZOP). For FMEA, reference is 503 The Contractor shall prepare procedures covering nor- made to DNV Rules for Classification of High Speed, and mal and contingency situations. The procedures shall describe: Light Craft and Naval Surface Craft, Pt.0 Ch.4 Sec.2. 303 Special attention shall be given to sections of the pipe- — purpose and scope of the activity line route close to other installations or shore approaches — responsibilities where there is greater risk of interference from shipping, — materials, equipment and documents to be used anchoring etc. For critical operations, procedural HAZOP — how the activity is performed in order to meet specified studies shall be performed. requirements — how the activity is controlled and documented. A 400 Installation and testing specifications and draw- ings 504 The installation manual shall be updated/revised as needed as installation proceeds. 401 Specifications and drawings shall be prepared covering installation and testing of pipeline systems, risers, protective 505 The installation manuals are subject to agreement structures etc. through: 402 The specifications and drawings shall describe, in suffi- — review of methods, procedures and calculations cient detail, requirements to installation methods and the proc- — review and qualification of procedures esses to be employed and to the final result of the operations. — qualification of vessels and equipment 403 The requirements shall reflect the basis for, and the — review of personnel qualifications. results of, the design activities. The type and extent of verifi- 506 Requirements to the installation manual and acceptance cation, testing, acceptance criteria and associated documenta- are given in the various subsections. The results of the FMEA tion required to verify that the properties and integrity of the analysis or HAZOP studies (see A300) shall also be used in pipeline system meet the requirements of this standard, as well determining the extent and depth of verification of equipment as the extent and type of documentation, records and certifica- and procedures. tion required, shall be stated. 507 In cases where variations in manner of performance of 404 Requirements to the installation manual and the extent an activity may give undesirable results, the essential variables of tests, investigations and acceptance criteria required for and their acceptable limits shall be established. qualification of the installation manual shall be included. A 600 Quality assurance A 500 Installation manuals 601 The installation Contractor shall as a minimum have an 501 Installation manuals shall be prepared by the various implemented quality assurance system meeting the require- Contractors. ments of ISO 9001 Quality management systems – Require- 502 The installation manual is a collection of the manuals ments or equivalent. Further requirements for quality and procedures relevant to the specific work to be performed. assurance are given in Sec.2 B500. It is prepared in order to demonstrate that the methods and equipment used by the Contractor will meet the specified A 700 Welding requirements, and that the results can be verified. The installa- 701 Requirements for welding processes, welding procedure tion manual shall include all factors that influence the quality qualification, execution of welding and welding personnel are

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 105 given in Appendix C. of the defects have been established and rectified. 702 Requirements for mechanical and corrosion testing for 807 For "Golden Welds" (critical welds e.g. tie-in welds that qualification of welding procedures are given in Appendix B. will not be subject to pressure testing, etc.) 100% ultrasonic 703 The mechanical properties and corrosion resistance of testing, 100% radiographic testing, and 100% magnetic parti- weldments shall at least meet the requirements given in the cle testing or 100% liquid penetrant testing of non- ferromag- installation and testing specifications. netic materials shall be performed. If the ultrasonic testing is performed as automated ultrasonic testing, see Appendix E, 704 For weld repair at weld repair stations where the pipeline the radiographic and magnetic particle/liquid penetrant testing section under repair is subjected to tensile and bending may be omitted subject to agreement. stresses, a weld repair analysis shall be performed. The analy- sis shall determine the maximum excavation length and depth 808 Magnetic particle testing or liquid penetrant testing of combinations that may be performed, taking into account all non-ferromagnetic materials shall be performed to verify com- stresses acting at the area of the repair. The analysis shall be plete removal of defects before commencing weld repairs, and performed in accordance with Appendix A. for 100% lamination checks at re-bevelled ends of cut pipe. The analysis shall consider the reduction of yield and tensile 809 Visual Examination shall include: strength in the material due to the heat input from defect exca- — 100% examination of completed welds for surface flaws, vation, preheating, and welding and also dynamic amplifica- shape and dimensions tion due to weather conditions and reduced stiffness effect at — 100% examination of the visible pipe surface, prior to field field joints. joint coating 705 The weld repair analysis shall be subject to agreement. — 100% examination of completed field joint coating. 706 The root and the first filler pass shall, as a minimum, be A 900 Production tests completed at the first welding station before moving the pipe. Moving the pipe at an earlier stage may be permitted if an anal- 901 One production test is required for each Welding Proce- ysis is performed showing that this can be performed without dure Specification (WPS) used for welding of the pipeline any risk of introducing damage to the deposited weld material. girth welds. This analysis shall consider the maximum misalignment 902 Production tests should not be required for welding pro- allowed, the height of the deposited weld metal, the possible cedures qualified specifically for tie-in welds, flange welds, presence of flaws, support conditions for the pipe and any Tee-piece welds etc. dynamic effects. 903 Production tests may, subject to agreement, be omitted A 800 Non-destructive testing and visual examination in cases where fracture toughness testing during welding pro- cedure qualification is not required by this standard, or for C- 801 Requirements for methods, equipment, procedures, Mn steel linepipe with SMYS < 450 MPa. acceptance criteria and the qualification and certification of personnel for visual examination and non-destructive testing 904 The extent of production tests shall be expanded if: (NDT) are given in Appendix D. Selection of non-destructive methods shall consider the requirements in Appendix D, A400. — the Contractor has limited previous experience with the welding equipment and welding methods used 802 Requirements to automated ultrasonic testing (AUT) are — the welding inspection performed is found to be inade- given in Appendix E. quate 803 The extent of NDT for installation girth welds shall be — severe defects occur repeatedly 100% ultrasonic or radiographic testing. Radiographic testing — any other incident indicates inadequate welding perform- should be supplemented with ultrasonic testing in order to ance enhance the probability of detection and/or characterisation/ — the installed pipeline is not subjected to system pressure sizing of defects. testing, see Sec.5 B203. 804 For wall thickness > 25 mm, automated ultrasonic test- 905 The extent of production testing shall be consistent with ing should be used. the inspection and test regime and philosophy of the pipeline 805 Ultrasonic testing (UT) shall be used in the following project. cases: 906 Production tests shall be subject to the non-destructive, all weld tensile, Charpy V-notch fracture toughness (when — UT or automated ultrasonic testing (AUT) shall be per- applicable) and corrosion testing as required in Appendix C for formed whenever sizing of flaw height and/or determina- Welding Procedure Qualification Testing (WPQT). tion of the flaw depth is required — 100% testing of the first 10 welds for welding processes 907 If production tests show unacceptable results, appropri- with high potential for non-fusion type defects, when start- ate corrective and preventative actions shall be initiated and ing installation or when resuming production after suspen- the extent of production testing shall be increased. sion of welding and when radiographic testing is the primary NDT method. For wall thickness above 25 mm additional random local spot checks during installation are recommended B. Pipeline Route, Survey and Preparation — testing to supplement radiographic testing for wall thick- ness above 25 mm, to aid in characterising and sizing of B 100 Pre-installation route survey ambiguous indications 101 A pre-installation survey of the pipeline route may be — testing to supplement radiographic testing for unfavoura- required in addition to the route survey required for design pur- ble groove configurations, to aid in detection of defects poses covered by Sec.3 if: — 100% lamination checks of a 50 mm wide band at ends of cut pipe. — the time elapsed since the previous survey is significant — a change in seabed conditions is likely to have occurred 806 If ultrasonic testing reveals defects not discovered by — the route is in areas with heavy marine activity radiography, the extent of ultrasonic testing shall be 100% for — new installations are present in the area the next 10 welds. If the results of this extended testing are — seabed preparation work is performed within the route cor- unsatisfactory, the welding shall be suspended until the causes ridor after previous survey.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 106 – Sec.10

102 The pre-installation survey, if required, shall determine: C. Marine Operations — potential new/previously not identified hazards to the C 100 General pipeline and the installation operations — location of wrecks, submarine installations and other 101 These requirements are applicable for vessels perform- obstructions such as mines, debris, rocks and boulders that ing pipeline and riser installation and supporting operations. might interfere with, or impose restrictions on, the instal- The requirements are applicable for the marine operations dur- lation operations ing installation work only. Specific requirements for installa- — that the present seabed conditions confirm those of the sur- tion equipment onboard vessels performing installation vey required in Sec.3 operations are given in the relevant subsections. — any other potential hazards due to the nature of the suc- 102 The organisation of key personnel with defined respon- ceeding operations. sibilities and lines of communication shall be established prior to start of the operations. Interfaces with other parties shall be 103 The extent of, and the requirements for, the pre-installa- defined. tion route survey shall be specified. 103 All personnel shall be qualified for their assigned work. B 200 Seabed preparation Key personnel shall have sufficient verbal communication 201 Seabed preparation may be required to: skills in the common language used during operations. 104 Manning level should comply with IMO's Principles of — remove obstacles and potential hazards interfering with Safe Manning (IMO 23rd Session 2003 (Res. 936-965))"Prin- the installation operations ciples of Safe Manning". Non-propelled vessels shall have — prevent loads or strains that occur as a result of seabed similar manning and organisation as required for propelled conditions such as unstable slopes, sand waves, deep val- units of same type and size. leys and possible erosion and scour from exceeding the design criteria C 200 Vessels — prepare for pipeline and cable crossings 201 All vessels shall have valid class with a recognised clas- — infill depressions and remove high-spots to prevent unac- sification society. The valid class shall cover all systems of ceptable free spans importance for the safety of the operation. Further require- — carry out any other preparation due to the nature of the suc- ments to vessels shall be given in a specification stating ceeding operations. requirements for: 202 Where trench excavation is required before pipelaying, — anchors, anchor lines and anchor winches the trench cross-section shall be specified and the trench shall — anchoring systems be excavated to a sufficiently smooth profile to minimise the possibility of damages to the pipeline, coating and anodes. — positioning and survey equipment — dynamic positioning equipment and reference system 203 The extent of, and the requirements for, seabed prepara- — alarm systems, including remote alarms when required tion shall be specified. The laying tolerances shall be consid- — general seaworthiness of the vessel for the region ered when the extent of seabed preparation is determined. — cranes and lifting appliances B 300 Pipeline and cable crossings — pipeline installation equipment (see. D) — any other requirement due to the nature of the operations. 301 Preparations for crossing of pipelines and cables shall be carried out according to a specification detailing the measures 202 Vessels shall have a documented maintenance pro- adopted to avoid damage to both installations. The operations gramme covering all systems vital for the safety and opera- should be monitored by ROV to confirm proper placement and tional performance of the vessel, related to the operation to be configuration of the supports. Support and profile over the exist- performed. The maintenance programme shall be presented in ing installation shall be in accordance with the accepted design. a maintenance manual or similar document. 302 The specification shall state requirements concerning: 203 Status reports for any recommendations or requirements given by National Authorities and/or classification societies, — minimum separation between existing installation and the and status of all maintenance completed in relation to the main- pipeline tenance planned for a relevant period, shall be available for — co-ordinates of crossing review. — marking of existing installation — confirmation of position and orientation of existing instal- 204 An inspection or survey shall be performed prior to lations on both sides of the crossing mobilisation of the vessels to confirm that the vessels and their — lay-out and profile of crossing principal equipment meet the specified requirements and are — vessel anchoring suitable for the intended work. — installation of supporting structures or gravel beds C 300 Anchoring systems, anchor patterns and anchor — methods to prevent scour and erosion around supports positioning — monitoring and inspection methods — tolerance requirements 301 Anchoring systems for vessels kept in position by — any other requirements. anchors (with or without thruster assistance) while performing marine operations shall meet the following requirements: B 400 Preparations for shore approach 401 The location of any other pipelines, cables or outfalls in — instruments for reading anchor line tension and length of the area of the shore approach shall be identified and clearly anchor lines shall be fitted in the operations control room marked. or on the bridge, and also at the winch station — remotely operated winches shall be monitored from the 402 Obstructions such as debris, rocks and boulders that control room or bridge, by means of cameras or equiva- might interfere with or restrict the installation operations shall lent. be removed. The seabed and shore area shall be prepared to the state assumed in the design such that over-stressing in the pipe- 302 Anchor patterns shall be predetermined for each vessel line during the installation and damage to coating or anodes is using anchors to maintain position. Different configurations avoided. for anchor patterns may be required for various sections of the

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 107 pipeline, especially in the vicinity of fixed installations and — Class 2 for operations < 500 m away from existing other subsea installations or other pipelines or cables. installations and for tie-in/riser installation operations 303 Anchor patterns shall be according to the results of a — Class 3 for manned subsea operations or other opera- mooring analysis, using an agreed computer program, and tions where a sudden horizontal displacement of the shall be verified to have the required capacity for the proposed vessel may have fatal consequences for personnel. location, time of year and duration of operation. Distance to other installations and the possibility to leave the site in an 502 Subject to agreement and on a case by case basis, vessels emergency situation shall be considered. with displacement > 5 000 t performing operations < 500 m away from existing installations or performing tie-in/riser 304 Station-keeping systems based on anchoring shall have installation operations may have Class 2 provided that the con- adequate redundancy or back-up systems in order to ensure sequences of fire or flooding will not seriously affect the safety that other vessels and installations are not endangered by par- of the installation or the integrity of the pipeline. tial failure. 305 Each anchor pattern shall be clearly shown on a chart of C 600 Cranes and lifting equipment adequate scale. Care shall be taken in correlating different 601 Cranes and lifting equipment including lifting gear, lift- chart datum, if used. ing appliances, slings, grommets, shackles and pad-eyes, shall 306 Minimum clearances are to be specified between an meet applicable statutory requirements. Certificates for the anchor, its cable and any existing fixed or subsea installations equipment, valid for the operations and conditions under or other pipelines or cables, both for normal operations and which they will be used, shall be available on board for review. emergency conditions. C 700 Anchor handling and tug management C 400 Positioning systems 701 Anchor handling vessels shall be equipped with: 401 Requirements for the positioning system and its accu- racy for each type of vessel and application shall be specified. — a surface positioning system of sufficient accuracy for anchor drops in areas within 500 m of existing installa- 402 The accuracy of horizontal surface positioning systems tions and pipelines shall be consistent with the accuracy required for the operation — computing and interfacing facilities for interfacing with and sufficient to perform survey work, placing of the pipeline, lay vessel, trenching vessel or other anchored vessels. supporting structures or anchors within the specified tolerances, and to establish reference points for local positioning systems. 702 Procedures for the anchor handling shall be established, 403 Installation in congested areas and work requiring precise ensuring that: relative location may require local systems of greater accuracy, such as acoustic transponder array systems. Use of ROV's to — anchor locations are in compliance with the anchor pattern monitor and assist the operations should be considered. for the location — requirements of owners of other installations and pipelines 404 The positioning system shall provide information relat- for anchor handling in the vicinity of the installation are ing to: known, and communication lines established — position relative to the grid reference system used — position prior to anchor drop is confirmed — geographical position — anchor positions are monitored at all times, particularly in — offsets from given positions the vicinity of other installations and pipelines — offsets from antenna position — any other requirement due to the nature of the operations — vertical reference datum(s). is fulfilled. 405 Positioning systems shall have minimum 100% redun- 703 All anchors transported over subsea installations shall be dancy to allow for system errors or breakdown. secured on deck of the anchor handling vessel. 406 Documentation showing that positioning systems are 704 During anchor running, attention shall be paid to the calibrated and capable of operating within the specified limits anchor cable and the catenary of the cable, to maintain mini- of accuracy shall be available for review prior to start of the mum clearance between the anchor cable and any subsea installation operations. installations or obstacles. C 500 Dynamic positioning C 800 Contingency procedures 501 Vessels using dynamic positioning systems for station 801 Contingency procedures shall be established for the keeping and location purposes shall be designed, equipped and marine operations relating to: operated in accordance with IMO MSC/Circ.645 (Guidelines for Vessels with Dynamic Positioning Systems), or with earlier — work site abandonment including emergency departure of NMD requirements for consequence class, and shall have cor- the work location and when anchors cannot be recovered responding class notations from a recognised classification — mooring systems failure society as follows: — any other requirement due to the nature of the operations. a) Vessels > 5 000 t displacement: — Class 1 for operations > 500 m away from existing installations D. Pipeline Installation — Class 3 for operations < 500 m away from existing installations and for tie-in/riser installation operations D 100 General — Class 3 for manned subsea operations or other opera- 101 The requirements of this subsection are generally appli- tions where a sudden horizontal displacement of the cable to pipeline installation, regardless of installation method. vessel may have fatal consequences for personnel. Additional requirements pertaining to specific installation methods are given in the following subsections. b) Vessels < 5 000 t displacement: 102 Interfaces shall be established with other parties that — Class 1 for operations > 500 m away from existing may be affected by the operations. The responsibilities of all installations, parties and lines of communication shall be established.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 108 – Sec.10

D 200 Installation manual — other calculations made as part of the installation scope. 201 The laying Contractor shall prepare an installation man- 302 Review and qualification of procedures shall as a mini- ual. As a minimum, the installation manual shall include all mum include: documentation required to perform the installation, and shall demonstrate that the pipeline can be safely installed and com- — welding procedures for production and repair welding (see pleted to the specified requirements by use of the dedicated Appendix C) spread. — non-destructive testing procedures and automated NDT 202 The installation manual shall cover all applicable equipment (see Appendix D, Appendix E) aspects such as: — field joint coating and field joint coating repair procedures — internal and external coating repair procedures. — spread, including modifications and upgrading, if any — supervisory personnel, inspectors, welders and NDT per- 303 Qualification of vessels and equipment prior to start of sonnel work shall include: — communications and reporting — navigation and positioning — dynamic positioning system test — anchor handling, anchor patterns and catenary curves (if — combined review and dynamic positioning system/ten- applicable) sioner system tests (simulate vessel pull and tensioner fail- — dynamic positioning system (if applicable) ures and redundancy tests during pull) — stress/strain and configuration monitoring, control, and — tensioner system review test (test combinations of tension- recording during all phases of installation activities ers, testing of single tensioner failure when running two or — operating limit conditions three tensioners, test redundancy of single tensioners, sim- — normal pipe-lay ulate main power loss and loss of signal power) — anode installation (where applicable) — abandonment and recovery winch test (fail safe actions, — piggyback pipeline saddle installation (where applicable) simulate main power loss and loss of signal power) — piggyback pipeline installation (where applicable) — friction clamp test (fail safe actions and test clamps during — pipe-lay in areas of particular concern, e.g. shipping lanes, vessel pull) platforms, subsea installations, shore approach — remote operated buckle detector — vessel pull management system — pipeline support geometry — abandonment and recovery — stinger configuration and control devices — start-up and lay-down — review of calibration records of critical/essential equip- — method of buckle detection ment, including welding machines and automated NDT — installation of in-line assemblies and equipment equipment — pipe handling, hauling, stacking and storage — review of maintenance records for critical/essential equip- — maintaining pipeline cleanliness during construction ment, including welding machines and automated NDT — pipe tracking equipment — repair of damaged pipe coating — maintenance/calibration records of critical/essential — internal coating repair equipment on support vessels. — internal cleaning of pipe before and after welding — welder qualification 304 Review of personnel qualifications shall include: — welding equipment, line-up clamps, bevelling procedures, welding procedures, production welding, weld repair, — welders qualification/certification records, welding production tests — welding inspectors and QC personnel qualification/ certi- — NDT equipment, visual examination and NDT proce- fication records, dures, visual examination and NDT of welds — NDT operators qualification/certification records, — weld repair analysis extent of weld repair at repair station, — Lay barge survey party chief, and determined by ECA (see A700) — Field coating personnel. — field joint coating and field joint coating repair — touchdown point monitoring 305 Records from vessel qualification, testing and calibra- — pipeline repair in case of wet or dry buckle tion shall be kept onboard and be available for review. —crossings 306 Essential variables shall as minimum be established for: — provisions for winter laying, prevention of ice build-up, removal of ice, low temperature reservoirs in steel and — Allowable variations in stress/strain and configuration concrete coating, etc. control parameters where variations beyond established — vessel emergency bridging document describing co-ordi- limits may cause critical conditions during installation nation of safety management systems between the vessel — variations in equipment settings/performance that can contractor and the pipeline operator/licensee. cause or aggravate critical conditions — changes in welding joint design and process parameters 203 The installation manual shall be supported by calcula- beyond that allowed in Appendix C tions and procedures, including contingency procedures, to an — changes in NDT method, NDT equipment and NDT extent that adequately covers the work to be performed. equipment calibration beyond that allowed in Appendix D and Appendix E D 300 Review and qualification of the installation man- — weld repair lengths/depths in areas where the pipe is sub- ual, essential variables and validity ject to bending moments/axial stress. The maximum 301 The review of methods, procedures and calculations length/depth of excavation shall be determined by ECA shall include: calculations (see A.704) — changes in field joint coating procedure — Failure mode effect analysis, — operating limit conditions — HAZOP studies, — any other requirement due to the nature of the operations. — installation procedures, — contingency procedures, 307 The validity of the installation manual is limited to the — engineering critical assessments for girth welds, lay-vessel/spread where the qualification was performed and — engineering critical assessments for weld repair lengths, to the pipeline or section of pipeline in question.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 109

D 400 Operating limit conditions — ROV breakdown 401 The installation operation shall be classified as weather — breakdown of positioning system restricted operation or temporary condition, see Sec.4 C600. — other critical or emergency situations identified in FMEA analysis or HAZOP studies. 402 For weather restricted operations, operating limit condi- tions shall be established and agreed. D 700 Layvessel arrangement, laying equipment and 403 The operating limit conditions shall be based on stress instrumentation and strain calculations, vessel station keeping capability, 701 The tensioners shall operate in a fail-safe mode and shall FMEA analysis or HAZOP study data, and shall refer to objec- have adequate pulling force, holding force, braking capacity tive, critical values indicated by measuring devices. The oper- and squeeze pressure to maintain the pipe under controlled ten- ating limit conditions shall be referred to in the procedure for sion. The forces applied shall be controlled such that no dam- stress/strain and configuration control. Continuous monitoring age to the pipeline or coating will occur. and recording of the measuring devices required for control of the operating limit conditions shall be performed during all 702 The installation vessel tensioning system arrangement phases of installation activities. shall therefore be such that: 404 If a systematic deviation between the monitored — the tensioners, brakes and holding clamps shall be able to response and predicted response from a seastate is found this hold the pipeline throughout an accidental flooding, unless should be accounted for. it can be demonstrated that the flooded pipe can be 405 Start of weather restricted operations is conditional to an released safely and without damage to the laying vessel acceptable weather forecast. and the risk of such a release is found acceptable — the tensioning system shall have sufficient redundancy to 406 For weather restricted operations, planning of operation prevent simultaneous breakdown of tensioners shall be based on an operational reference period. Further, the — the tensioner capacity shall have sufficient redundancy to operational criteria shall account for uncertainties in both allow failure of individual tensioners, without compromis- weather forecasts and monitoring of environmental conditions. ing the pipeline integrity Regular weather forecasts from a recognised meteorological — in case of tensioner failure or failure in the tensioner sys- centre shall be available onboard the lay vessel, and shall be tem, the pipeline installation shall not re-start before the supplemented by historical environmental data. Reference is made to DNV-OS-H101 Marine Operations (1). system has been repaired. (1) This standard is not yet issued. Until issue, refer to: 703 When applicable for the laying method, the pipeline shall be fully supported along the length of the vessel and on — DNV Rules for planning and execution of marine Opera- to the stinger by rollers, tracks or guides that allow the pipe to tions, Pt. 1, Ch. 2, paragraph 3.1. move axially. Supports shall prevent damage to coating, field joint coatings, anodes and in-line assemblies, and rollers shall 407 If the critical values are about to be exceeded, prepara- move freely. The vertical and horizontal adjustment of the sup- tions for lay-down shall commence. If the critical condition is ports shall ensure a smooth transition from the vessel onto the weather dependent only, and if weather forecasts indicate that stinger, to maintain the loading on the pipeline within the spec- the weather condition will subside, the lay-down may be post- ified limits. The support heights and spacing shall be related to poned subject to agreement. a clear and easily identifiable datum. The pipeline support geometry shall be verified prior to laying, and the accepted 408 Decision to recover the pipeline shall be based on com- height and spacing of supports shall be permanently marked or parison of the actual seastate with the limiting seastate, otherwise indicated. together with weather forecasts. 704 Stingers shall be adjusted to the correct configuration to D 500 Installation procedures ensure a smooth transition from the vessel to the outboard 501 Installation procedures meeting the requirements of this stinger end, and to maintain the loading on the pipeline within standard, including all requirements of the installation and testing the specified limits. The geometry shall be verified prior to lay- specifications, shall be prepared by the Contractor for agreement. ing. If the stinger can be adjusted during laying operations, it shall be possible to determine the stinger position and config- D 600 Contingency procedures uration by reference to position markings or indicators. Buoy- ant stingers shall be equipped with indication devices showing 601 Contingency procedures meeting the requirements of the position of the rollers relative to the water surface. this standard, including all requirements of the installation and testing specifications, shall be prepared by the Contractor for 705 Buckle detection should normally be used continuously agreement. The contingency procedures shall at least cover: during laying. The intention of the buckle detection is to iden- tify a buckle at an early stage. By adopting a higher safety class — failure of dynamic positioning system during installation, the probability of a buckle event will be — failure of tensioner system reduced, and subject to agreement, the guidance provided in — failure of anchors and anchor lines Table 10-1below may be used.

Table 10-1 Safety class during installation Buckle detection requirement Additional requirements Low Buckle detection required (e.g. by buckle detector or equip- ment providing similar degree of detection) Medium Buckle detection not required Good control of installation parameters required (e.g. lay tension, touch down point etc.) and consequence of possible buckle is found acceptable High Buckle detection not required Consequence of possible buckle is found acceptable Guidance note: Guidance note: The above implies, subject to agreement, that if buckle detection The buckle detector (or equipment providing same degree of is not used during laying a higher safety class may be applied. detect ability) shall be positioned in such a way that critical areas monitored (normally a distance after the touch down point). If a ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- buckle detector is used the diameter of the disc shall be chosen

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 110 – Sec.10

with regard to the pipeline diameter and tolerances on ovality, under the seastates expected for the operation in question. wall thickness, misalignment and internal weld bead.

709 Other measuring and recording systems or equipment ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- shall be required if they are essential for the installation oper- ation. 706 The abandonment and recovery (A & R) winch should be able to recover the pipeline when waterfilled, or alternative D 800 Requirements for installation methods for recovering the pipeline should be available. 801 Handling and storage of materials on supply and laying 707 A sufficient amount of instrumentation and measuring vessels shall ensure that damage to pipe, coatings, assemblies devices shall be installed to ensure that monitoring of essential and accessories are avoided. Slings and other equipment used equipment and all relevant parameters required for stress/strain shall be designed to prevent damage. Storage of pipes shall be and configuration control and control of the operating limit in racks and suitable shoring shall be used. Maximum stacking conditions can be performed. heights shall be determined to avoid excessive loads on the The following instrumentation is required: pipe, coating or anodes. All material shipped for installation shall be recorded. Tensioners: 802 All material shall be inspected for damage, quantity and — total pipeline tension recorders identification upon arrival. Damaged items shall be quaran- — tension at each tensioner tined, repaired or clearly marked and returned onshore. — tensioner setting and variance to set point (dead band), and 803 Pipes and in-line assemblies shall be inspected for loose — indication of applied pulling, holding and squeeze pres- material, debris and other contamination and cleaned inter- sure. nally before being added to the line. The cleaning method shall Stinger: not cause damage to any internal coating. 804 A pipe tracking system shall be used to maintain records — underwater camera(s) and video recorders for monitoring of weld numbers, pipe numbers, NDT, pipe lengths, cumula- pipeline position with respect to the last roller on the tive length, anode installation, in-line assemblies and repair stinger (if restricted underwater visibility is expected, a numbers. The system shall be capable of detecting duplicate sonar is required for monitoring pipeline position with records. respect to the rollers on the stinger) — reaction load indicators (vertical and horizontal) on the 805 The individual pipes of the pipeline shall be marked in first roller on the stinger accordance with the established pipe tracking system, using a — for installations that rely on a maximum force on the last suitable quick-curing marine paint. The location, size and col- roller on the stinger this shall be monitored by reaction our of the marking shall be suitable for reading by ROV during load indicators or documented by other means installation and subsequent surveys. It may be necessary to — stinger configuration and tip depth for articulated stingers. mark a band on top of the pipeline to quantify any rotation that may have occurred during installation. If damaged pipes are Buckle detector: replaced, any sequential marking shall be maintained. 806 Pipes shall be bevelled to the correct configuration, — pulling wire tension and length recorder, when applicable. checked to be within tolerance, and inspected for damage. Internal line-up clamps shall be used, unless use of such Winches: clamps is demonstrated to be impracticable. Acceptable align- — abandonment and recovery winches shall be equipped ment, root gap and staggering of longitudinal welds shall be with wire tension and length recorder confirmed prior to welding. — anchor winches shall meet the requirements given in 807 In-line assemblies shall be installed and inspected as C300. required by the specification, and shall be protected against damage during passage through the tensioners and over pipe Vessel: supports. — vessel position 808 Field joint coating and inspection shall meet the require- — vessel movements such as roll, pitch, sway, heave ments given in Sec.9. — water depth 809 The parameters to be controlled by measuring devices, — vessel draft and trim and the allowable range of parameter variation during installa- — current strength and direction tion, shall be established in a procedure for configuration con- — wind strength and direction trol, pipeline tension and stress monitoring. The function of — direct or indirect indication of sagbend curvature and essential measuring devices shall be verified at regular inter- strain. vals and defective or non-conforming devices shall repaired or replaced. All measuring equipment shall be calibrated and adequate doc- umentation of calibration shall be available onboard the vessel 810 The buckle detector load chart, if a buckle detector is prior to start of work. All measuring equipment used shall be used (see 705) shall be checked at regular intervals. The buckle provided with an adequate amount of spares to ensure uninter- detector shall be retrieved and inspected if there is reason to rupted operation. believe that buckling can have occurred. If the inspection shows indications of buckling or water ingress, the situation Essential equipment shall be provided with back-up. shall be investigated and remedial action performed. Direct reading and processing of records from all required 811 The position of pipeline start up and lay-down shall be essential instrumentation and measuring devices, shall be pos- verified as within their respective target areas prior to depar- sible at the vessels bridge. ture of the lay vessel from site, and adequate protection of Correlation of recorded data and pipe numbers shall be possible. pipeline and lay-down head shall be provided. 708 Pipeline lay down point shall be monitored as well as 812 Pipelaying in congested areas, in the vicinity of existing other operations that are critical to the integrity of the pipeline installations and at pipeline and cable crossings, shall be car- or represent a risk for fixed installations or other subsea instal- ried out using local positioning systems with specified accu- lations and pipelines. ROVs shall be capable of operating racy and appropriate anchor patterns (if used). Measures shall

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 111 be taken to protect existing installations, cables and pipelines requirements of A500 and applicable requirements of D200, it from damage. Such operations and the pipeline touch down shall include: point shall be monitored continuously by ROV. — the amount of displacement controlled strain, both accu- 813 Other critical operations such as laying in short radii mulated and maximum for each single strain cycle curves, areas with steep slopes, use of very high or low pulling — method for control of, and allowable variation in, curva- tension values etc. shall be identified and special procedures ture of the pipe between the point of departure from the for the operation shall be prepared. reel and entry into the straighteners 814 In the event of buckling a survey of the pipeline shall be — description of straighteners performed before repair to establish the extent of damage and — proposed procedure for qualification of the installation feasibility of the repair procedure. After completion of the method by fracture mechanics assessment and validation repair, a survey shall be performed of the pipeline over a length testing. sufficient to ensure that no further damage has occurred. E 300 Qualification of the installation manual 815 If loss or major damage to weight and corrosion coating or anodes and their cables/connectors are observed, repair shall be 301 In addition to the applicable requirements of D300, qual- performed and inspected according to established procedures. ification of the installation manual shall include: 816 Prior to abandonment of the pipeline, all internal equip- — qualification of welding procedures according to the spe- ment except the buckle detector shall be removed and all cific requirements given in Appendix C, including δ-R or welds, including the abandonment and recovery head welds, J-R testing shall be filled to a level that the pipe can be safely abandoned — engineering critical assessments to determine the maxi- on and retrieved from the seabed. In the event that the cable mum allowable weld defects will have to be released from the vessel, a buoy and pennant — validation of engineering critical assessment by testing, if wire should be attached to the abandonment and recovery relevant, see Appendix A head. The buoy shall be large enough to remain on the surface — testing of pipe coating durability when exposed to the weight of the pennant wire, as well as any — testing of straighteners and resulting pipe straightness. hydrodynamic loads from waves and current. Alternatively, seabed abandonment with a ROV friendly hook- 302 A fracture assessment including testing shall be per- ing loop may be used. Winch tension and cable lengths shall be formed as specified in Appendix A. monitored, and the specified values shall not be exceeded dur- 303 Bending tests on pipe coating shall be performed to ing the abandonment and recovery operation. demonstrate that successive bending and straightening will not Before recovery the pipeline shall be surveyed over a length impair the pipe coating and field coating. No degradation of away from the abandonment and recovery head, sufficient to the coating properties shall occur. For this test the coating test ensure that no damage has occurred. may be carried out on plates. Alternatively, previous test results may be used as documentation given that it is the same 817 An as-laid survey shall be performed either by continu- manufacturer, chemical composition and strain level. ous touch down point monitoring or by a dedicated vessel, and shall, as a minimum, include the requirements given in J. 304 The straighteners shall be qualified using pipe which is delivered to the pipeline and bent corresponding to the mini- mum curvature fed into the straighteners. It shall be demon- strated that the strain resulting from the straightening is within E. Additional Requirements for Pipeline the assumptions made for the validation testing, and that the specified straightness is achieved. The straightening shall not Installation Methods Introducing Plastic cause damage to coating. The maximum deformation used dur- Deformations ing straightening to the specified straightness shall be recorded and regarded as an essential variable during installation. E 100 General 101 The additional requirements of this subsection are appli- E 400 Installation procedures cable to pipeline installation by methods which give total sin- 401 In addition to the relevant applicable procedures of this gle event nominal strain ≥ 1.0% or accumulated nominal subsection, the following procedures are required as applica- plastic strain ≥ 2.0%. ble: 102 The specific problems associated with these installation — loadout/spooling of pipe onto reel methods shall be addressed in the installation and testing spec- — pipe straightening ifications. — anode and anode double plate installation 103 Pipes used for such installation methods shall meet the — installation, welding and NDT of additional pipe strings supplementary requirement, pipe for plastic deformation (P), — any other procedure needed due to the nature of the oper- see Sec.7 I300. ations. 104 For installation welding, the sequence of pipes included E 500 Requirements for installation in the pipe string shall be controlled such that variations in stiffness on both sides of welds are maintained within the 501 Adequate support of the pipestring shall be provided assumptions made in the design. This may be achieved by when loading the reel. Tension shall be applied and monitored matching, as closely as possible, wall thickness/diameter of the during reeling in order to ensure that the successive layers on pipes and the actual yield stress on both sides of the weld. the reel are sufficiently tightly packed to prevent slippage between the layers. Adequate measures shall be taken to pro- 105 100% automated ultrasonic testing (AUT) according to tect the coating during reeling. the requirements given in Appendix E or manual ultrasonic testing according to the requirements given in Appendix D 502 If the reel is used for control of the pipeline tension dur- shall be performed. ing installation it shall be demonstrated that such use will give acceptable redundancy and will not induce excessive stresses E 200 Installation manual or have other detrimental effects. 201 An installation manual shall be prepared by the Contrac- 503 The curvature of the pipe, peaking and sagging, between tor for acceptance by the Purchaser and in addition to the the point of departure from the reel and entry into the straight-

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 112 – Sec.10 eners shall not exceed the maximum values assumed in design — ballast control during installation and ECA and validated in the material testing of the girth — installation and joining of additional pipestrings. welded pipes. F 600 Contingency procedures 504 Anodes should be installed after the pipe has passed through the straightener and tensioner. The electrical connec- 601 In addition to the applicable procedures of D600, contin- tion between anodes and pipe shall meet the specified require- gency procedures are required for: ments and shall be verified at regular intervals, see Sec.9. — weather conditions in excess of the operating limit condi- tions — ballast system breakdown or partial failure F. Pipeline Installation by Towing — loss of towing tension — excessive towing tension F 100 General — pre-designation of temporary mooring area(s) along the 101 The specific problems associated with pipeline towing tow route operations are to be addressed in the installation and testing — third party marine activities. specifications. The weight and buoyancy distribution control during fabrication, launching of the pipestring, tow, ballast F 700 Arrangement, equipment and instrumentation control, environmental loads and contingencies shall be 701 Vessels shall be equipped with: addressed when the requirements are specified. 102 Tows may be performed as: — measuring equipment that continuously displays and records the towing speed and tensions — surface or near-surface tows, with the pipestring supported — measuring equipment that continuously displays and mon- by surface buoys itors the depth of the pipestring and its distance from the — mid-depth tows, where the pipestring is towed well clear seabed away from the seabed — measuring equipment that continuously display the posi- — bottom tows, where the pipestring is towed in contact tion of any ballast valves. The flow rates during any bal- with, or close to, the seabed. lasting and de-ballasting are to be displayed. 103 For surface tows, all aspects pertaining to the tow are 702 All measuring equipment shall be continuously moni- subject to agreement in each case. tored during the tow and installation. 104 For bottom or near bottom tows, the pipeline route shall 703 Installation of strain gauges to monitor the stresses in the be surveyed prior to the tow and the route shall avoid rough pipestring during tow and installation shall be considered. seabed, boulders, rock outcrops and other obstacles that may cause damage to the pipeline, coating or anodes during the tow F 800 Pipestring tow and installation and installation. During bottom and near bottom tows, ade- 801 Launching of pipestrings shall be performed such that quate monitoring with ROVs and of the pipeline position at over-stressing of the pipestring and damage to the coating and critical phases is required. Satisfactory abrasion resistance of anodes are avoided. If pipestrings are moored inshore awaiting the pipeline coating shall be demonstrated. All aspects pertain- the tow, adequate precautions shall be taken to avoid marine ing to bottom tows are subject to agreement in each case. growth influencing pipestring buoyancy, weight and drag. 105 For mid-depth tows, the requirements in F200 through 802 Notification of the tow shall be given to the relevant F800 are generally applicable. authorities, owners of subsea installations crossed by the tow- ing route and users of the sea. F 200 Installation manual 803 Towing shall not commence unless an acceptable 201 An installation manual shall be prepared by the Contrac- weather window for the tow is available. During the tow a tor and, in addition to the requirements of A500 and applicable standby vessel shall be present to prevent interference with the requirements of D200, it shall include: tow by third party vessels. — description of towing vessel(s) including capacities, 804 Tension in the towing line and the towing depth shall be equipment and instrumentation kept within the specified limits during the tow. If required, bal- — description of pipestring instrumentation. lasting or de-ballasting shall be performed to adjust the towing depth to the specified values. F 300 Qualification of installation manual 805 Installation shall be performed by careful ballasting and de- 301 Qualification of the installation manual shall include the ballasting. Care shall be exercised to prevent over-stressing of the applicable requirements of D300. pipestring. The use of drag chains during the installation is recom- mended. The installation operation shall be monitored by ROV. F 400 Operating limit conditions 401 Operating limit conditions with regard to weather win- dow for the tow, the seastate and current and allowed strain gauge values (if installed) shall be established. G. Other Installation Methods F 500 Installation procedures G 100 General 501 Installation procedures meeting the requirements of this 101 Other installation methods may be suitable in special standard and the installation specifications shall be prepared cases. A thorough study shall be performed to establish the fea- and agreed. In addition to the applicable procedures of D500, sibility of the installation method and the loads imposed during procedures are required for, but not limited to: installation. Such methods are subject to agreement in each case. 102 Installation of flexible pipelines, bundles and multiple — control of weight- and buoyancy distribution pipelines shall be performed after a thorough study to establish the — launching of the pipestring feasibility of the installation method and the loads imposed during — ballast control during tow installation. The installation is subject to agreement in each case.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 113

H. Shore Pull terrupted operation shall be provided. 704 ROVs shall, if used, be equipped with video cameras, H 100 General sonars, a bathymetric system, altimeter, adequate tooling such 101 The requirements of this subsection are applicable to the as wire cutters or manipulator, transponders, responders etc. as execution, inspection and testing of shore pull when pipes- needed. It shall be documented that ROVs are able to operate trings are pulled either from a vessel onto the shore, or vice under the seastate expected for the operation in question. versa. 705 Other measuring and recording systems or equipment, 102 Detailed requirements for the execution, inspection and such as strain gauges, should be provided if they are essential testing of shore pull shall be specified, considering the nature for the installation operation or the integrity of the pipeline. of the particular installation site. The specific problems associ- ated with shore pull shall be addressed in the installation and H 800 Requirements for installation testing specifications. 801 If necessary the seabed shall be prepared as required in H 200 Installation manual B. 201 An installation manual shall be prepared by the Contrac- 802 Satisfactory abrasion resistance of the pipeline coating tor and, in addition to the requirements of A500 and D200, shall be demonstrated for the installation conditions. shall cover,: 803 Installation of the pulling head shall be made in a man- ner that prevents over-stressing of the pipeline and provides a — description of offshore plant arrangement, equipment and secure connection. instrumentation — description of onshore plant arrangement, equipment and 804 Buoyancy aids should be used if required to keep pulling instrumentation tension within acceptable limits. — special operations. 805 During the operation, continuous monitoring of cable tension and pulling force is required. Monitoring with ROVs H 300 Qualification of installation manual may be needed. 301 Qualification of the installation manual shall include the applicable requirements of D300. H 400 Operating limit conditions I. Tie-in Operations 401 Operating limit conditions with regard to the seastate and current shall be established if relevant. I 100 General 101 The requirements of this subsection are applicable to tie- H 500 Installation procedures in operations using welding or mechanical connectors. The 501 Installation procedures meeting the requirements of this operations can be performed onboard a laying vessel (in which standard and the installation specifications, shall be prepared case welding is the preferred method) or underwater. The spe- and agreed. In addition to the applicable procedures of D500, cific problems associated with tie-in operations shall be procedures are required for, but not limited to: addressed in the installation and testing specifications. — installation of pulling head 102 Tie-in operations, by means of hot or cold taps, are sub- — tension control ject to special consideration and agreement. — twisting control I 200 Installation manual — ROV monitoring where applicable — other critical operations 201 An installation manual shall be prepared by the Contrac- — site preparation and winch set-up tor and shall, in addition to the requirements of Subsection — buoyancy aids, where applicable A500 and Subsection D200, cover: — position control in trench, tunnels, etc., as applicable. — description of diving plant arrangement, equipment and H 600 Contingency procedures instrumentation 601 Contingency procedures meeting the requirements of — special operations. this standard and the installation and testing specification shall I 300 Qualification of installation manual be prepared. 301 Qualification of the installation manual shall include the 602 The contingency procedures shall cover: applicable requirements of Subsection D300. — cable tension exceeding acceptable limits I 400 Operating limit conditions — excessive twisting of the pipestring — ROV breakdown 401 Operating limit conditions with regard to the seastate, — other critical or emergency situations. current and vessel movements shall be established. H 700 Arrangement, equipment and instrumentation I 500 Tie-in procedures 701 Cables, pulling heads and other equipment shall be 501 Tie-in procedures meeting the requirements of this dimensioned for the forces to be applied, including any over- standard and the installation specifications shall be prepared loading, friction and dynamic effects that may occur. and agreed. In addition to the applicable procedures of Subsec- 702 Winches shall have adequate pulling force to ensure that tion D500, the following procedures are required: the pipe is maintained under controlled tension within the — lifting and deployment of the pipeline/riser section allowed stress/strain limits. The forces applied shall be con- — configuration and alignment control trolled such that no damage to the pipeline anodes or coating will occur. — mechanical connector installation. 703 The winches shall be equipped with wire tension and If underwater methods are used, additional procedures are length indicators and recorders. All measuring equipment shall required to cover the safety and operational aspects of the be calibrated, and an adequate amount of spares to ensure unin- underwater operations.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 114 – Sec.10

I 600 Contingency procedures requirements to survey vessel, survey equipment, the extent of 601 In addition to the requirements of Subsection D600, the survey, tolerances for the as-laid pipe line, and the maximum following contingency procedure is required: acceptable length and gap height of spans at various locations. The extent of procedures to be prepared and qualified shall be — weather conditions in excess of the operating limit condi- specified. tions before completion of tie-in J 300 As-laid survey — If underwater methods are used, additional contingency procedures are required to cover the safety and operational 301 The as-laid survey should include and not limited to the aspects of the underwater operations. following: I 700 Tie-in operations above water — determination of the position and depth profile of the entire pipeline 701 The position of the tie-in shall be verified prior to start — identification and quantification of any spans with speci- of operations. A survey shall be performed to establish that the fied accuracy to length and gap height location is free of obstructions and that the seabed conditions — determination of position of start-up and lay down heads, will permit the tie-in to be performed as specified. — determination of the presence of debris 702 To avoid overstressing during lifting and lowering of the — as laid-video documentation of the pipeline to the extent pipeline sections, the winch tension shall be monitored contin- specified. Where video coverage cannot be obtained at any uously and shall not exceed the specified for operation. Lifting time due to environmental reasons, alternate methodolo- arrangements and equipment shall be designed, and lifting gies should be utilised to ensure 100% coverage. points attached, in a manner that prevents any over-stressing of the pipeline section during lifting and lowering into final posi- J 400 As-laid survey of corrosion protection systems tion. 401 Prior to any pipeline protection operations, a video sur- 703 ROV/diver monitoring of the operation should be per- vey of the corrosion protection system shall be carried out formed to confirm correct configuration of the pipeline sec- along the full length of the pipeline, including risers. Signifi- tions from the seabed and onto the vessel. cant damage to the coating and sacrificial anodes shall be doc- umented. 704 The alignment and position of the tie-in ends shall be within the specified tolerances before completing the tie-in. 402 In the case of extensive damage to coating or sacrificial galvanic anodes, consequences for long-term performance 705 Installation of mechanical connectors shall be per- shall be considered. Potential measurements at any bare sur- formed in accordance with the Manufacturer's procedure. For faces should be carried out to confirm adequate protection. flanged connections hydraulic bolt tension equipment shall be Corrective actions may include retrofitting of anodes and coat- used. During all handling, lifting and lowering into the final ing repairs, including risers. Satisfactory level of protection position, open flange faces shall be protected against mechan- shall be documented after the corrective action has been per- ical damage. formed. 706 A leak test to an internal pressure not less than the local incidental pressure should be performed for all mechanical connections whenever possible. K. Span Rectification and Pipeline Protection 707 Corrosion protection of the tie-in area shall be per- formed and inspected in accordance with accepted procedures. K 100 General 708 After completion of the tie-in, a survey of the pipeline on 101 The requirements of this subsection are applicable to both sides of the tie-in, and over a length sufficient to ensure span rectification and the protection of pipelines, e.g. by that no damage has occurred, should be performed trenching and backfilling, gravel dumping, grout bags, con- 709 It shall be verified that the position of the tie-in is within crete mattresses etc. the target area prior to departure of the vessel from site. The 102 A specific survey of the work area should be required in pipeline stability shall be ensured and adequate protection of addition to, or supplementing, the as-laid survey if: pipeline provided. — significant time has elapsed since the as-laid survey I 800 Tie-in operations below water — a change in seabed conditions is likely 801 In addition to the requirements in Subsection I700, the — heavy marine activity is present in the area requirements in 802 and 803 are valid for tie-in operations — new installations are present in the area involving underwater activities. — the as-laid survey does not provide sufficient information. 802 Diving and underwater operations shall be performed in 103 The survey of the work area, if required, shall as a min- accordance with agreed procedures for normal and contin- imum include: gency situations covering applicable requirements. 803 Requirements for underwater hyperbaric dry welding — a video inspection of the pipeline to identify any areas of are given in Appendix C. damage to pipeline, coating and anodes — cross profiles of the pipeline and adjacent seabed at regu- lar intervals — depth profiles along the pipeline and the seabed at both J. As-Laid Survey sides of the pipeline — any existing subsea installations. J 100 General The undisturbed seabed level shall be included in the cross pro- 101 These requirements are applicable to as-laid surveys files. performed by ROV either by continuous touch down point monitoring from the lay vessel or by a dedicated vessel. K 200 Span rectification and protection specification 201 The requirements applicable to the specific methods of J 200 Specification of as-laid survey span rectification and protection regarding execution, monitor- 201 The installation and testing specification shall contain ing and acceptance. Requirements for vessels, survey equip-

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 115 ment etc. shall be addressed in the installation and testing K 500 Post-installation gravel dumping specifications. The extent of procedures to be prepared and qualified shall be specified. 501 Material used for gravel dumping shall meet the speci- fied requirements for specific gravity, composition and grad- K 300 Span rectification ing. 301 Span rectification is required for all spans exceeding the 502 Gravel dumping shall be performed in a continuous and specified acceptable length or height for the specific location. controlled manner, such that the required material is deposited Rectification of other spans shall be considered if scour or sea- over and under the pipeline, supports, subsea assemblies, etc. bed settlement could enlarge the span length and gap height without disturbing their vertical or lateral position, and over above maximum acceptable dimensions before the first the adjacent seabed. planned pipeline inspection. 503 The gravel dumping operation shall ensure rectification 302 Adequate rectification of spans shall be documented by of all spans to meet the specified requirements. Stabilisation of a video survey. All rectified spans shall be identified and the free spans should be carried out in a continuous operation, length, gap and height shall be within the requirements. where the distance between spans to be stabilised is not too large, so as to avoid scouring and formation of free spans K 400 Trenching between gravel dumps. 401 Where trench excavation is performed after pipelaying, 504 If the fall pipe technique is used for gravel dumping, the trenching equipment shall be of a type that does not place minimum clearances shall be specified such that the fall pipe significant loads on the pipeline and minimises the possibility cannot touch the pipeline, any other subsea installation or the of damage to the pipeline. seabed. Deployment operations shall be performed well away from the pipeline or any other subsea installation. Before the 402 Trenching equipment shall be equipped with sufficient fall pipe is moved to the dumping location, the clearance instrumentation to ensure that damage and excessive pipe con- beneath the fall pipe shall be verified. The clearance shall be tact is avoided. continuously monitored during dumping. 403 Special care shall be taken during trenching operations 505 The completed gravel dump shall leave a mound on the of piggy back / bundle pipelines, so that strapping arrange- seabed with a smooth contour and profile and a slope not ments will not be disturbed / damaged during trenching. For steeper than specified. If the gravel dumping is performed over small pipelines without any weight coating, trenching shall not cable and pipeline crossings, the gravel mound shall provide damage / dismantle the anodes. the specified depth of cover over both the raised and the crossed pipeline. During the dumping operations inspections 404 Where mechanical backfilling is required, it shall be car- shall be performed with a sonar survey system, or when visi- ried out in a manner that minimises the possibility of damage bility is restored, a video camera, to determine the complete- or disturbance to the pipeline. ness and adequacy of the dumping. 405 The trenching equipment monitoring system shall be 506 Upon completion of the gravel dumping, a survey shall calibrated and include: be performed to confirm compliance with the specified requirements. The survey shall, as a minimum, include: — devices to measure depth of pipe — a monitoring system and control system preventing hori- — a video inspection of the pipeline length covered zontal loads on the pipeline or devices to measure and — cross profiles of the mound and adjacent undisturbed sea- record all vertical and horizontal forces imposed on the bed at regular intervals pipeline by trenching equipment, and devices to measure — length profiles of the mound the proximity of the trenching equipment to the pipeline, horizontally and vertically relative to the pipeline — confirmation that minimum required buried depth is achieved — underwater monitoring systems enabling the trenching equipment operator to view the pipeline and seabed profile — any existing installations and their vicinity in order to forward and aft of the trenching equipment ensure that the installation(s) have not suffered damage. — measuring and recording devices for trenching equipment K 600 Grout bags and concrete mattresses tow force — devices monitoring pitch, roll, depth, height and speed of 601 Concrete mattresses and grout bags shall meet the spec- the trenching equipment. ification with regard to size, shape and flexibility of the mate- rial, location of filling points, and the specific gravity, 406 Jet sleds shall have a control and monitoring system for composition and grading of grout. the position of the jetting arms and the overhead frame, hori- 602 Placing of grout bags and concrete mattresses shall be zontally and vertically relative to the pipeline. The location of performed in a controlled manner, such that the bags or mat- the sled shall not be controlled by the force between sled and tresses are placed as required. Restrictions on vessel move- pipeline. Devices indicating tension in the tow line and show- ments during the operation shall be given. ing the depth of the trench, shall be installed. 603 During the placing operations, inspections shall be per- 407 The trench depth shall be referenced to the undisturbed formed with a ROV-mounted video camera to determine the seabed adjacent to the pipeline and to the top of the pipeline. completeness and adequacy of the installation. 408 An allowable range of values, indicated by the measur- 604 Upon completion of the placing operation, a survey shall ing devices of the trenching equipment, shall be established. be performed to confirm compliance with the specified The possibility of damage to coating shall be considered. Dur- requirements. The survey shall as a minimum include: ing trenching operations the measuring devices shall be contin- uously monitored. — a video inspection of the completed work 409 A post-trenching survey shall be performed immediately — cross profiles of the placed bags or mattresses and adjacent or as agreed after the trenching, in order to determine if the undisturbed seabed at regular intervals required depth of lowering has been achieved and if any reme- — length profiles of the placed bags or mattresses and the dial work is required. seabed at both sides of the area.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 116 – Sec.10

L. Installation of Protective and Anchoring ual examination and non-destructive testing shall be estab- Structures lished in accordance with Appendix D and Appendix E as applicable. L 100 General 602 Transportation, storage and handling of riser pipe and 101 Installation of protective and anchoring structures shall appurtenances shall prevent any damage to coating and paint. be performed according to specifications and procedures meet- In addition, special precautions shall be taken to protect flange ing the requirements of the applicable design code. faces and other specially prepared surfaces from damage. 603 All tolerances and measurements required in order to install the riser in accordance with drawings and specifications shall be verified in the field before installation commences. M. Installation of Risers Diameter, roundness and cleanness of J-tubes shall be checked M 100 General by gauging pigs, pulling a test pipe or similar to prevent the pulling head and riser from jamming. 101 The installation and testing specification shall cover the riser installation operations and address the specific problems 604 Adequate control shall be performed to ensure that the associated with these operations. Diving and underwater oper- angularity and straightness of risers, the distance between ris- ations shall be performed in accordance with agreed proce- ers and bracing, the spacing between adjacent risers and other dures covering applicable requirements. critical dimensions meet the specified requirements. 102 The following methods may be used: 605 Tie-ins between riser and pipeline shall be performed in accordance with I. — integral installation by surface vessel, where the riser and 606 Prior to pull-in of risers into J-tubes, it shall be verified pipeline are welded on deck of the vessel and the pipeline that the bellmouth is clear of debris and obstructions, that the and riser lowered to the seabed. The riser is then posi- bellmouth height above the seabed is within design limits, and tioned in clamps installed on the structure that no damage to the bellmouth, J-tube or J-tube clamps (if — installation by J-tube method, where the riser is pulled applicable) has occurred. Entry of the pipeline into the bell- through a pre-installed J-shaped conduit on the structure, mouth shall be monitored by ROV, and the tension in the pull- — installation of prefabricated risers, where the riser is in cable shall be monitored by calibrated load cells and shall installed in clamps fitted on the structure by a surface ves- not exceed the specified maximum. Proper sealing as specified sel. Hyperbaric welding or mechanical connector are then shall be ensured at the bell-mouth for a riser in a J-tube in case used to connect the riser and pipeline, the corrosion protection system is designed with for a non-cor- — stalk-on risers installed by a installation vessel, and rosive fluid in the annulus. — flexible, free-hanging risers. 607 All clamps, protection frames, anchor flanges etc., shall M 200 Installation manual be installed in accordance with specification and drawings, using appropriate bolt torque and to the specified tolerances. 201 The installation manual should, in addition to the require- ments given in Subsection A500 and Subsection D200, cover: 608 Repair of damage to coating and paint shall be per- formed in accordance with accepted procedures. — communication line and interface procedure with the plat- form where the riser is installed 609 Upon completion of the installation, a ROV or diver sur- — description of offshore plant arrangement, equipment and vey shall be performed to confirm the position of the riser rel- instrumentation ative to the platform, the position of any expansion loops, — procedures for offshore riser fabrication supports, etc., and the results of any trenching and protection — procedures for measurement and control of cut-off length operations. on the pipeline, riser bottom bend section, spool piece etc. 610 In case the riser has not been tested according to Sec.7 G, — anchor pattern for installation vessel cleaning, gauging and system pressure testing shall be performed — diving and/or underwater operations procedures. in general accordance with the requirements in O, except that wire line pigs may be used, the holding time shall be at least 2 M 300 Qualification of the installation manual hours and the pressure variation shall not exceed ± 0.4% unless 301 The installation manual shall be qualified. The qualifica- the variation can be related to temperature variations during the tion shall, as a minimum, include the requirements of Subsec- test period. Visual inspection of welds and flanged connections tion D300. shall be performed whenever possible. M 400 Operating limit conditions 401 Operating limit conditions with regard to the seastate and current shall be established such that any over-stressing of N. As-Built Survey the pipe material and weldments is avoided. When adverse weather conditions require shut-down of the installation work, N 100 General the vessel shall move away from the platform. 101 All work on the pipeline, including crossings, trenching, gravel dumping, artificial backfill, subsea assemblies, riser M 500 Contingency procedures installation, final testing etc., should be completed before the 501 Contingency procedures shall be prepared for accept- as-built survey is performed. The as-built survey of the ance, covering dynamic positioning system breakdown, installed and completed pipeline system is performed to verify anchor dragging and anchor line failure. If underwater meth- that the completed installation work meets the specified ods are used, additional contingency procedures are required to requirements, and to document any deviations from the origi- cover the safety and operational aspects of the underwater nal design. operations. N 200 Specification of as-built survey M 600 Requirements for installation 201 The specification shall contain requirements to survey 601 Offshore installation welding shall be performed in vessel, survey equipment and the extent of survey. The extent accordance with Appendix C, and acceptance criteria for vis- of procedures to be prepared and qualified shall be specified.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 117

N 300 As-built survey requirements 402 Appropriate measures shall be taken to ensure that any 301 The as-built survey shall as a minimum include: suspended and dissolved substances in the fluid used for this operation are compatible with the pipe material and internal — detailed plot of the position of the pipeline, including loca- coating (if applied), and that deposits are not formed within the tion of in-line assemblies, anchoring and protective struc- pipeline. tures, tie-ins, supports etc. 403 Water to be used for flooding should have a minimum — out of straightness measurements as applicable quality corresponding to filtration through be filtered to — depth of cover or trench depth as applicable remove suspended particles larger than a 50μm and filter, and — quantification of span lengths and heights, including should have an average content of suspended matters not length and height reporting tolerances exceeding 20 g/m3. — location of areas of damage to pipeline, coating and 404 If water quality or the water source is unknown, water anodes samples shall be analysed and suitable actions shall be taken to — location of any areas with observed scour or erosion along remove and/or inhibit harmful substances. pipeline and adjacent seabed — verification that the condition of weight coating (or 405 If water is to remain in the pipeline for an extended anchoring systems that provide for on-bottom stability) is period of time, consideration shall be given to control of bac- in accordance with the specification terial growth and internal corrosion by chemical treatment (see — description of wreckage, debris or other objects which Sec.6 D302). may affect the cathodic protection system or otherwise 406 Added corrosion inhibitors, any chemical additives like impair the pipeline oxygen scavengers, biocides, dyes, etc. shall be considered for — as-built video for the entire pipeline. possible harmful interactions selected to ensure full compati- bility and their impact on the environment during and after dis- N 400 Inspection of impressed current cathodic corro- posal of the test watershall be considered. sion protection system 407 The pipeline cleaning concept shall consider: 401 Impressed current cathodic corrosion protection systems shall be inspected, including cables, conduits, anodes and rec- — protection of pipeline components and facilities (e.g. tifiers. Readings from the corrosion monitoring system shall be valves) from damage by cleaning fluids and pigs verified by independent potential measurements, and adequate — testing devices such as isolation spheres etc. electrical insulation from other installations (if applicable) — removal of substances that may contaminate the product to shall be confirmed installed and commissioned according to be transported ISO 15589-2 Petroleum and natural gas industries - Cathodic — particles and residue from testing and mill scale protection of pipeline transportation systems - Part 2: Off- — organisms and residue resulting from test fluids shore pipelines... — chemical residue and gels If the required protection level is not attained, the causes shall — removal of metallic particles that may affect future inspec- be identified and adequate corrective actions performed. Satis- tion activities. factory performance shall be documented after the corrective action. 408 The main purpose of gauging a pipeline system is to establish an internal diameter which is less than the minimum internal diameter of the system in order to provide a basis for any future operational pigging activities. Selection of an O. Final Testing and Preparation for Operation appropriate gauging concept/method shall therefore be based on a review of the operational pigging requirements. O 100 General a) As a minimum pipelines with a constant nominal internal 101 All work on the subsea pipeline system, including cross- diameter should normally be gauged using a metallic ings, trenching, gravel dumping, artificial backfill, subsea gauge plate with a diameter that is 95% of the nominal assemblies, riser installation, as-built survey etc., should be internal diameter. Alternatively the gauging plate may completed before the final testing commences. have a diameter that is 97% of the minimum internal diam- 102 Disposal of cleaning and test fluids shall be performed eter, taking into account the manufacturing tolerances for in a manner minimising danger to the environment. Any dis- all system components and weld penetrations. posal of fluids shall be in compliance with requirements from b) As a minimum pipelines with variations in the nominal National Authorities. internal diameter should normally either be gauged in sec- tions in accordance with a) above or be gauged by use of O 200 Specification of final testing and preparation for an “intelligent” gauging tool. In cases where this is consid- operation ered impractical or unnecessary, based on a review of 201 The installation and testing specification shall contain operational pigging requirements, the system should be requirements for equipment, the extent of testing and prepara- gauged in accordance with a) above based on the smallest tion for operation, performance of tests and preparation for diameter section. operation and associated acceptance criteria. The extent of pro- cedures to be prepared and qualified shall be specified. Guidance note: The minimum internal diameter including uncertainties can be O 300 Procedures for final testing and preparation for established as: operation Dmin,tot = Dmin(1-f0/2)-2tmax-2hbead 301 All operations and tests shall be performed in accord- Where hbead also allows for possible misalignment

ance with agreed procedures. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- O 400 Cleaning and gauging 409 Cleaning and gauging train design, number and type of 401 Cleaning and gauging may be combined with the initial pigs, need for chemical cleaning, train velocity etc., shall be flooding of the pipeline, be run as a separate operation, or be decided based on type and length of pipeline, steep gradients combined with the weld sphere removal after completion of along the pipeline route, type of service, construction method, hyperbaric tie-in. downstream process etc.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 118 – Sec.10

410 If cleaning and gauging are performed on separate sec- ter than 0.1°C tions of the pipeline prior to tie-in, a minimum of one cleaning — pressure recorders and temperature recorders when and gauging pig should be run through the completed pipeline included shall be used to provide a graphical record of the system prior to, or during, product filling. pressure test continuously for the total duration of the test. O 500 System pressure testing If a pressure transducer is used instead of a dead weight tester, 501 A pipeline system pressure test shall be performed based the transducer shall have a range of minimum 1.1 times the upon the system test pressure determined according to Sec.5 specified test pressure, and the accuracy shall be better than ±± B 203 unless the test is waived as allowed by Sec.5 B204. The 0.2% of test pressure. Sensitivity shall be better than 0.1%. extent of the test should normally be from pigtrap to pigtrap, 510 A correlation that shows the effect of temperature including all components and connections within the pipeline changes on the test pressure where relevant, shall be developed system. The pressure test is normally performed as a leak test. and accepted prior to starting the test. Temperature measuring 502 The system may be tested as separate sections provided devices, if used, shall be positioned close to the pipeline, and that the tie-in welds between sections have been subject to the distance between the devices shall be based on temperature 100% radiographic, ultrasonic and magnetic particle testing, or gradients along the pipeline route. by a combination of other methods which provide the same or 511 The test medium should be water meeting the require- improved verification of acceptable weld quality. ments given in O400. 503 The pipeline section under test shall be isolated from 512 The air content of the test water shall be assessed by con- other pipelines and facilities. Pressure testing should not be structing a plot of the pressure against volume during the initial performed against in-line valves, unless possible leakage and filling and pressurisation, until a definite linear relationship is damage to the valve is considered, and the valve is designed apparent, see Figure1. This should be done at 35% of test pres- and tested for the pressure test condition. Blocking off or sure. The assessed air content should not exceed 0.2% of the removal of small-bore branches and instrument tappings, calculated total volume of the pipeline under test. If the limit is should be considered to avoid possible contamination. exceeded, it shall be documented that the amount of air, not will influence the accuracy of the test significantly. 504 End closures, temporary pigtraps, manifolds and other temporary testing equipment, shall be designed and fabricated according to a recognised code and with design pressure equal to the pipeline's design pressure. Such items shall be individu- ally pressure tested to at least the same test pressure as the pipeline. 505 Filling of the pipeline with test water should be per- formed in a controlled manner, using water behind one or more pigs. The pig(s) shall be capable of providing a positive air/ water interface. Considerations shall be given to pre-filling valve body cavities with an inert liquid, unless the valves have provision for pressure equalisation across the valve seats. All valves shall be fully open during line filling. A pig tracking system and the use of back-pressure to control the travel speed of the pig shall be considered if steep gradients occur along the pipeline route. 506 Instruments and test equipment used for the measure- ment of pressure, volume and temperature shall be calibrated for accuracy, repeatability and sensitivity. All instruments and test equipment shall possess valid calibration certificates, with traceability to reference standards within the 6 months preced- Figure 1 ing the test. If the instruments and test equipment have been in Determination of volume of air frequent use, calibration specifically for the test should be required. 507 Gauges and recorders shall be checked for correct func- 513 Pressurisation of the pipeline shall be performed as a tion immediately before each test. All test equipment shall be controlled operation with consideration for maximum allowa- located in a safe position outside the test boundary area. ble velocities in the inlet piping. The last 5% up to the test pres- sure shall be raised at a reduced rate to ensure that the test 508 The test pressure should be measured using a dead pressure is not exceeded. Time shall be allowed for confirma- weight tester. Dead weight testers shall not be used before a tion of temperature and pressure stabilisation before the test stable condition is confirmed. When pressure testing is per- hold period begins. formed from a vessel, where a dead weight tester can not be utilised due to the vessel movements, the test pressure shall be 514 The pressure level requirement for the system pressure measured by using one high accuracy pressure transducer in test is given in Sec.5 B203. addition to a high accuracy large diameter pressure gauge. 515 The test pressure hold period after stabilisation shall be 509 The following requirements apply for instruments and held for a minimum 24 hours. test equipment: 516 Subject to agreement shorter pressure hold periods may be accepted for pipelines with test volumes less than 5 000 m3. — dead weight testers shall have a range of minimum 1.25 In these cases the principles of Sec.7 G shall normally apply. times the specified test pressure, and shall have an accuracy better than ±0.1 bar and a sensitivity better than 0.05 bar 517 The pressure and temperatures where relevant, shall be — the volume of water added or subtracted during a pressure continuously recorded during the pressurisation, stabilisation test shall be measured with equipment having accuracy and test hold periods. better than ± 1.0% and sensitivity better than 0.1% 518 If possible, flanges, mechanical connectors etc. under — temperature measuring instruments and recorders shall pressure shall be visually inspected for leaks during the pres- have an accuracy better than ±1.0°C, and a sensitivity bet- sure test, either directly or by monitors.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.10 – Page 119

519 The pressure test is acceptable if the pipeline is free from icals shall include consideration of any effect on valve and seal leaks, and the pressure variation is within ± ± 0.2% of the test materials, any internal coating and trapping of fluids in valve pressure. A pressure variation up to an additional ±0.2% of the cavities, branch piping, instruments etc. test pressure is normally acceptable if the total variation (i.e. ± 0.4%) can be documented to be caused by temperature fluctu- O 700 Systems testing ations or otherwise accounted for. If pressure variations greater 701 Prior to fluid product filling, safety and monitoring sys- than ± 0.4% of the test pressure are observed, the holding tems shall be tested in accordance with accepted procedures. period shall be extended until a hold period with acceptable This includes testing of: pressure variations has occurred. 520 De-pressurisation of the pipeline shall be performed as a — corrosion monitoring systems controlled operation with consideration for maximum allowa- — alarm and shutdown systems ble velocities in the pipeline and the discharge piping. — safety systems such and pig trap interlocks, pressure pro- tection systems etc. O 600 De-watering and drying — pressure monitoring systems and other monitoring and 601 De-watering is required before introducing the product control systems fluid into the pipeline. Drying may be required in order to pre- — operation of pipeline valves. vent an increase in the corrosion potential or hydrate forma- tion, or if omission of drying is deemed to have an adverse effect on the product transported. P. Documentation 602 Introduction of the fluid may be accepted in special cases. The separation pig train between the test medium and P 100 General the fluid will then require special qualification in order to avoid 101 The installation and testing of the pipeline system shall contact between the residual test water and the product. be documented. The documentation shall, as a minimum, 603 Selection of de-watering and drying methods and chem- include that given in Sec.12.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 120 – Sec.11

SECTION 11 OPERATIONS AND ABANDONMENT

A. General which takes into account probability of failure and conse- quence of failure, should be applied. A 100 Objective 101 The purpose of this section is to provide minimum requirements for the safe and reliable operation of submarine pipeline systems (see Sec.11 A500) for the whole service life B. Commissioning with main focus on pipeline integrity management (PIM). B 100 General A 200 Scope and application 101 Commissioning is activities associated with the initial 201 This section covers the submarine pipeline system filling of the pipeline system with the fluid to be transported, phases operations and abandonment. Operations consist of and is part of the operational phase. Documentation and proce- commissioning, operation and de-commissioning. dures for commissioning are specified in Sec.12 E. 202 Pipeline integrity is the ability of the submarine pipeline B 200 Fluid filling system to operate safely and withstand the loads imposed dur- 201 During fluid filling, care shall be taken to prevent explo- ing the pipeline lifecycle. sive mixtures and, in the case of gas or condensate, to avoid 203 The pipeline integrity management process is the com- hydrate formation. The injection rate shall be controlled so that bined process of threat identification, risk assessments, plan- pressure and temperature do not exceed allowable limits for ning, monitoring, inspection, maintenance etc. to maintain the pipeline material or dewpoint conditions. pipeline integrity. B 300 Operational verification 204 The equipment scope limits include pipeline and compo- nents according to the definition of a submarine pipeline sys- 301 After stable production has been reached it shall be ver- tem in Sec.1 C335. The PIM principles and methodology are ified that the operational limits are within design conditions. applicable to pipeline systems in general. Important issues can be: A 300 Responsibilities — flow parameters (pressure, temperature, etc.) —CP-system 301 Pipeline integrity management is the responsibility of — expansion the operator. The operator needs to ensure that the integrity of — movement the pipeline is not compromised. — lateral snaking 302 At all times during the operational life of the pipeline — free span and exposure system, responsibilities must be clearly defined and allocated. 302 Scheduling of the first inspection of the wall thickness A 400 Authority and company requirements shall be evaluated based on the corrosivity of the fluid, 401 The relevant national requirements shall be identified expected operational parameters, robustness of the internal and ensured that they are complied with. corrosion protection system (inhibitor system), the corrosion allowance used in the design, the effectiveness of the QA/QC 402 The relevant company requirements should be complied system applied during fabrication and construction, and the with when planning and performing pipeline integrity management. defect sizing capabilities of the inspection tool that will be used during operation of the pipeline. A 500 Safety philosophy 501 The safety philosophy adopted in design and consistent with Sec.2 shall apply. 502 Operating safely is interpreted as operating to meet the C. Integrity Management System acceptance criteria as established in design and updated C 100 General through the project phases and service life. 101 The operator shall establish and maintain an integrity 503 Design and operating premises and requirements shall be management system which as a minimum includes the follow- identified prior to start of operation and updated during the serv- ing elements: ice life. These premises and requirements may be linked to: — company policy — pressure, temperature and flow rate — organisation and personnel — fluid composition (content of water, CO2, H2S etc.) — condition evaluation and assessment methods —sand — planning and execution of activities — cover depths — management of change — free spans length and height — operational controls and procedures — pipeline configuration (e.g. snaking) — contingency plans —others. — reporting and communication A change in design basis will in general require a re-qualifica- — audit and review tion, see Sec.11 E. — information management. 504 It must be verified that design and operating premises The activity plans are the result of the integrity management and requirements are fulfilled. If this is not the case, appropri- process by use of recognised assessment methods, see Sec.11 D. ate actions shall be taken to bring the pipeline system back to The core of the integrity management system is the integrity a safe condition. management process as illustrated in Figure 1. The other ele- 505 A risk based pipeline integrity management philosophy, ments mainly support this core process.

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— corrosion control Integrity management system — monitoring Company Integrity management process Management — safety equipment and pressure control system. policy of change - Condition evaluation and 702 Measures shall be in place to ensure that critical fluid assessment methods parameters are kept within the specified design limits. As a - Planning and execution of Contingency minimum, the following parameters should be controlled or activities plans Organisation monitored: and - Evaluation of threats personnel — pressure and temperature at inlet and outlet of the pipeline - Inspection and monitoring Audit and - Integrity assessment review — dew point for gas lines - Mitigation, intervention and repairs — fluid composition, flow rate, density and viscosity. Reporting and communication Operational controls Information 703 All safety equipment in the pipeline system, including and procedures management pressure control and over-pressure protection devices, emer- gency shutdown systems and automatic showdown valves, Figure 1 shall be periodically tested and inspected. The inspection shall Pipeline integrity management system verify that the integrity of the safety equipment is intact and that the equipment can perform the safety function as speci- fied. 102 Specification of work processes should be the basis for 704 Safety equipment in connecting piping systems shall be definition of procedures. Documents and procedures for the subject to regular testing and inspection. operational phase are specified in detail in Sec.12 H. 705 For pressure control during normal operations, see Sec.3 103 The detailed procedures for operation, inspections and B300. repairs shall be established prior to start-up of operation. 706 Operational control shall ensure that design temperature 104 Procedures covering non-routine or special activities, limits are not exceeded. If the design is based on a constant shall be prepared as required, e.g. in case of major repairs, temperature along the whole route, control of inlet temperature modifications etc. will be sufficient. If the design is based on a temperature pro- file for the pipeline, additional measures may be required. C 200 Company policy 201 The company policy for pipeline integrity management C 800 Contingency plans should set the values and beliefs that the company holds, and 801 Plans and procedures for emergency situations shall be guide people in how they are to be realized. established and maintained based on a systematic evaluation of possible scenarios. C 300 Organisation and personnel 301 The roles and responsibilities of personnel involved in C 900 Reporting and communication integrity management of the pipeline system shall be clearly 901 A plan for reporting and communication to employees, defined. management, authorities, customers, public and others shall be 302 Training needs shall be identified and training shall be established and maintained. This covers both regular reporting provided for relevant personnel in relation to management of and communication, and reporting in connection with changes, pipeline integrity. special findings, emergencies etc.

C 400 Condition evaluation and assessment methods C 1000 Audit and review 401 The condition evaluation of the pipeline system shall use 1001 Audits and reviews of the pipeline integrity manage- recognised methods and be based on design data and opera- ment system shall be conducted regularly. tional experience. 1002 The focus in reviews should be on: C 500 Planning and execution of activities — effectiveness and suitability of the system 501 This covers planning and execution of inspections, anal- — improvements to be implemented. yses, studies, interventions, repairs and other activities. 1003 The focus in audits should be on: C 600 Management of change — compliance with regulatory and company requirements 601 Modifications of the pipeline system shall be subject to — rectifications to be implemented. a management of change procedure that must address the con- tinuing safe operation of the pipeline system. Documentation C 1100 Information management of changes and communication to those who need to know is essential. 1101 A system for collection of historical data, an in-service file, shall be established and maintained for the whole service 602 If the operating conditions are changed relative to the life, see Sec.12 A103 and Sec.12 F201. The in-service file will design premises, a re-qualification of the pipeline system typically consist of documents, data files and data bases. according to Sec.11 E shall be carried out. 1102 The in-service file, together with the DFI-resume, shall C 700 Operational controls and procedures be the basis for future inspection planning. 701 Relevant operational controls and procedures are: 1103 The in-service file and the DFI-resume shall be easily retrievable in case of an emergency situation. — start-up and shutdown procedures 1104 The documents, data and information shall be managed — cleaning and other maintenance, e.g. pigging as described in Sec.12F and 12I.

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D. Integrity Management Process first inspection, the need of additional inspections should be considered. D 100 General 303 A long term inspection programme reflecting the overall 101 The integrity management process consists of the fol- safety objective for the pipeline shall be established, and shall lowing steps: be maintained/updated on a regular basis. The following should be considered: a) Evaluation of threats and the condition of the pipeline system. — operation conditions of the pipeline b) Plan and conduct activities including inspection and mon- itoring. — consequences of failure — likelihood of failure c) Integrity assessment based on inspection and monitoring — inspection methods results and other relevant information. — design and function of the pipeline. d) Assess need for, and conduct if needed, intervention and The long term program shall state the philosophy used for repair activities and other mitigating actions. maintaining the integrity of the pipeline system and will form This process shall be performed periodically within regular the basis for the detailed inspection program in terms of intervals. inspection methods and intervals. 102 The requirements for corrosion inspection and monitor- 304 The long term inspection program shall include the ing, and the capability of optional techniques, shall be evalu- entire pipeline system. The following items, at minimum, ated at an early stage of pipeline system design. should be considered: Guidance note: — pipeline Pipelines and risers manufactured from Corrosion Resistant — risers and their supports Alloys (CRA) do not normally require inspection and monitoring —valves of internal corrosion. This must be evaluated in each particular — Tee and Y connections case. — mechanical connectors

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- —flanges — anchors 103 An inspection and monitoring philosophy shall be estab- —clamps lished, and shall form the basis for the detailed inspection and — protecting structures monitoring program. The philosophy shall be evaluated every — anodes 5 to 10 years. — coating. 104 All inspection and monitoring requirements identified 305 A detailed inspection program including specifications during the design phase as affecting safety and reliability dur- for the inspections shall be prepared for each survey. The ing operation shall be covered in the inspection and monitoring detailed inspection program should be updated based on previ- program, see Sec.3 B200 and Sec.5 B300. ous inspections as required. 105 A special investigation shall be performed in case of any 306 Pipeline systems that are temporarily out of service shall event which impairs the safety, reliability, strength or stability also be subject to periodical survey. of the pipeline system. This investigation may initiate further inspections. 307 Inspection shall be carried out to ensure that the design requirements remain fulfilled and that no damage has 106 If mechanical damage or other abnormalities are occurred. The inspection program should, as a minimum, detected during the periodic inspection, a proper evaluation of address: the damage shall be performed, which may include additional inspections. — exposure and burial depth of buried or covered lines, if required by design, regulations or other specific require- D 200 Evaluation of threats and condition ments 201 Threats shall be systematically identified, assessed and — free spans including mapping of length, height and end- documented throughout the operational lifetime. This shall be support conditions done for each section along the pipeline and for components. — condition of artificial supports installed to reduce free span Examples of typical threats are: — local seabed scour affecting the pipeline integrity or attached structures — internal corrosion — sand wave movements affecting the pipeline integrity — external corrosion — excessive pipe movements including expansion effects — free spans — identification of areas where upheaval buckling or exces- — buckles sive lateral buckling has taken place — impact damage. — integrity of mechanical connections and flanges — integrity of sub-sea valves including protective structure 202 The condition assessment shall include an evaluation of — Y- and Tee connections including protective structure relevant risks by using qualitative and/or quantitative methods. — pipeline settlement in case of exposed pipeline, particu- Data from design and operation is the basis for the condition larly at the valve/Tee locations assessment. — the integrity of pipeline protection covers (e.g. mattresses, covers, sand bags, gravel slopes, etc.) D 300 External inspection — mechanical damage to pipe, coatings and anodes Pipeline configuration survey — major debris on, or close to, the pipeline that may cause 301 A pipeline configuration survey is a survey to determine damage to the pipeline or the external corrosion protection the position, configuration and condition of the pipeline and its system components. — leakage. 302 The start-up inspections should be completed within one 308 The risers shall be part of the long-term inspection pro- year from start of production, see Sec.11 B300. In case of sig- gramme for the pipeline system. In addition to the generally nificant increase in temperature, pressure or flowrate after this applicable requirements for pipeline inspection, special attention

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.11 – Page 123 shall be given to the following elements for riser inspections: 319 A survey of the external corrosion protection system, should be carried out within one year of installation. — riser displacement due to pipeline expansion or foundation settlement D 400 In-line inspection — coating damage 401 In-line inspection is carried out in order to confirm the — technique for corrosion control of any risers in closed con- integrity of the pipeline system, primarily by means of in situ duits or J-tubes wall thickness measurements. — extent of marine growth — extent of any previous damage due to corrosion Guidance note: — integrity and functionality of riser supports and guides Un-piggable pipelines are subject to separate evaluations and — integrity and functionality of protecting structure. alternative methods.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 309 The frequency of future external inspections shall be determined based upon an assessment of: 402 In-line inspection should be carried out with a carrier tool ("inspection pig") capable of inspecting the internal and — authority and company requirements external surface of the pipeline along its full circumference and — degradation mechanisms and failure modes length, or a critical part thereof. — likelihood and consequences of failure — results from previous inspections 403 The technique for detection of internal and/or external corrosion shall be selected based on considerations of fluid, — changes in the operational parameters linepipe material, diameter and wall thickness, expected form — re-qualification activity and results of damage, and requirements to detection limits and defect siz- — repair and modifications ing capability. The latter shall be determined based on pipeline — subsequent pipelay operation in the vicinity. design and operational parameters. 310 Critical sections of the pipeline system vulnerable to 404 Candidate operators of inspection tools should be damage or subject to major changes in the seabed conditions required to document the capability of their systems with i.e. support and/or burial of the pipeline, shall be inspected at respect to detection limits and sizing of relevant corrosion short intervals, normally on an annual basis. The remaining defects (including localised corrosion at girth welds) for the sections should also be inspected, ensuring a full coverage of pipe dimensions considered. the entire pipeline system within a suitable period, normally 405 The frequency of in-line inspections shall be determined not more than 5 years. based on factors such as: 311 For risers contained in J-tubes filled with non-corrosive fluid inspection of external corrosion may not be required if — authority and company requirements adequate properties of the fluid is verified by periodic testing. — likelihood and consequences of failure — potential corrosivity of fluid Risers in the splash zone and the atmospheric zone — potential for development of external corrosion at hot-spots 312 In the splash zone and in the atmospheric zone, damaged such as riser(s) and landfall/onshore pipeline sections and/or disbonded coatings can cause severe corrosion damage. — detection limits and accuracy of inspection system Risers carrying hot fluids are most vulnerable to such damage. — results from previous surveys and monitoring 313 In the splash and atmospheric zones, visual examination — changes in pipeline operational parameters, etc. of the coating should be performed in order to assess the needs See also Sec.11 B300. for preventive maintenance. Besides visual indications of direct damage to the coating, effects such as rust discoloration 406 Inspection by special internal tools may be used to detect and bulging or cracking of the coating are indicative of under- external corrosion of risers and pipelines in all three zones (see rusting. Coating systems which prevent close inspection of D200) including risers contained in J-tubes, if required. under-coating corrosion shall require special consideration. D 500 Corrosion monitoring 314 The frequency of the external inspection in the splash zone of risers shall be determined based on the fluid category, 501 The objective of monitoring internal corrosion is to con- the line pipe material, coating properties and any corrosion firm that the fluid remains non-corrosive or, more often, to assess allowance. the efficiency of any corrosion preventive measures, and accord- ingly to identify requirements for inspection of corrosion. Pipelines and risers in the submerged zone 502 Corrosion monitoring as defined above does not nor- 315 In the submerged zone, coating malfunctions are not mally give any quantitative information of critical loss of wall critical unless they are combined with deficiency in the thickness. Although monitoring may be carried out as actual cathodic protection system. wall thickness measurements in a selected area, it cannot 316 To a large extent, inspection of external corrosion pro- replace pipeline inspection schemes that cover the pipeline tection of pipelines and risers with sacrificial anodes can be system, or section thereof, in its full length and circumference. limited to inspection of the condition of anodes. Excessive On the other hand, inspection techniques for internal corrosion anode consumption is indicative of coating deficiencies, are not normally sensitive enough to replace monitoring. except close to platforms, templates and other structures where 503 The following major principles of corrosion monitoring current drain may lead to premature consumption of adjacent may be applied: pipe anodes. — fluid analyses; i.e. monitoring of fluid physical parameters 317 Potential measurements on anodes, and at any coating and sampling of fluid for chemical analysis of corrosive damage exposing bare pipe metal, may be carried out to verify components, corrosion retarding additions or corrosion adequate protection. Electric field gradient measurements in products the vicinity of anodes may be used for semi-quantitative — corrosion probes; i.e. weight loss coupons or other retriev- assessments of anode current outputs. able probes for periodic or on-line determination of corro- 318 For pipelines with impressed current cathodic protection sion rates systems, measurements of protection potentials shall, at mini- — in-situ wall thickness measurements, i.e. repeated meas- mum, be carried out at locations closest to, and most remote urements of wall thickness at defined locations using port- from, the anode(s). able or permanently installed equipment.

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504 Techniques and equipment for corrosion monitoring grind repair shall be checked for capacity. For guidance, refer- shall be selected based upon: ence is made to DNV-RP-F101, Corroded Pipelines. — monitoring objectives, including requirements for accu- Dents racy and sensitivity 609 A dent is defined as a depression which produces a gross — fluid corrosivity and the corrosion preventive measures to disturbance in the curvature of the pipe wall. For dent accept- be applied ance criteria, see Sec.5 E503. — potential corrosion mechanisms. 610 A dent affecting a weld can result in cracks, and removal of the damaged portion of the pipe should be considered. The 505 A typical major objective of corrosion monitoring is to damaged part can be cut out as a cylinder, or repaired by detect changes in either intrinsic corrosivity of the fluid, or in installing a full encirclement welded split sleeve or bolted the efficiency of the corrosion prevention measures. For pipe- clamp which is designed to take the full internal operating lines carrying dry (i.e. fully processed) gas, inspection of inter- pressure. nal corrosion may be postponed provided that monitoring demonstrates that no corrosive liquids have entered the pipe- D 700 Mitigation, intervention and repairs line, or been formed by condensation downstream of the inlet. 701 Examples of mitigation, intervention and repairs are: D 600 Integrity assessment a) mitigation: 601 Pipeline systems with unacceptable defects may be operated temporarily under the design conditions or reduced — restrictions in operational parameters (pressure, tem- operational conditions until the defect has been removed or perature, flow rate, fluid composition etc.) repair has been carried out. It must, however, be documented — use of chemical injections. that the pipeline integrity and the specified safety level is main- tained, which may include reduced operational conditions and/ b) intervention: or temporary precautions. — rock dumps 602 When a defect is observed, an evaluation shall be per- — pipeline protections formed including: — trenching. — quantify details of the defect c) repairs: — identify cause of defect — evaluate accuracy and uncertainties in the inspection — local reinforcement (clamps etc.) results. — replacement of pipeline parts. If the defect is not acceptable, then further evaluations include: All mitigation, intervention and repairs shall be documented. 702 Repair and modification shall not impair the safety level — options for continued operation of the pipeline system of the pipeline system below the specified safety level. — repair methods. 703 All repairs shall be carried out by qualified personnel in 603 In each case a thorough evaluation of the defect and the accordance with agreed specifications and procedures, and up impact on safety and reliability for the operation of the pipeline to the standard defined for the pipeline. shall be performed. The requirements given in the following If the repair involves welding, the personnel, method, and sections regarding required actions, e.g. grinding or replace- equipment shall be agreed upon according to Appendix C. ment, may be waived if it can be documented that the specified safety level for the pipeline system is not impaired. For other types of repair the requirements for personnel, method and necessary equipment to carry out the work shall be 604 Defects that affect the safety or reliability of the pipeline agreed upon in each case. shall either be removed by cutting out the damaged section of the pipe or repaired by local reinforcement. Alternatively, the 704 All repairs shall be tested and inspected by experienced pipeline may be permanently re-qualified to lower operational and qualified personnel in accordance with agreed procedures. conditions see Sec.11 E and Sec.5, e.g. reduced pressure, NDT personnel, equipment, methods, and acceptance criteria which may allow for omitting repair. shall be agreed upon in accordance with Appendix D. Free spans 705 Depending upon the condition of the damage, a tempo- rary repair may be accepted until the permanent repair can be 605 For guidance, reference is made to DNV-RP-F105, Free carried out. If a temporary repair is carried out, it shall be doc- Spanning Pipelines. umented that the pipeline integrity and safety level is main- Global buckling tained either by the temporary repair itself and/or in combination with other precautions. 606 If the design is based on controlled global buckling including plastic strains, the pipeline should be verified based Repair of leaks on established design limits and conditions (curvatures, 706 Prior to carrying out a permanent repair of any leak, the strains, bending moment). If unexpected global buckling cause of the leak shall be established. occurs, utilisation of the pipeline should be evaluated based on relevant failure modes. For guidance, reference is made to 707 The most suitable method for repairing a leak in the pipe DNV-RP-F110, Global Buckling of Submarine Pipelines. depends upon e.g. the pipe material, pipe dimensions, location of leak, load conditions, pressure, and temperature. The fol- Grooves, gouges, cracks and notches lowing repair methods may be used: 607 Sharp defects like grooves, gouges, and notches should a) The damaged portion is cut out of the pipe as a cylinder preferably be removed by grinding or other agreed repair and a new pipe spool is installed either by welding or by methods. For ground defects where all sharp edges are con- an mechanical connector. For guidance, reference is made firmed as removed, the defect can be regarded as a smooth to DNV-RP-F113 Pipeline Subsea Repair. metal loss defect, see D608. b) Clamps are installed, and tightness is obtained by either Metal loss defects welding, filler material, friction or other qualified mechan- 608 Metal loss defects caused by e.g. corrosion, erosion, or ical means.

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708 Leaking flanges and couplings may be sealed by install- —dents ing a seal clamp covering the leaking flange or coupling, — damage to pipeline protection increasing the bolt pre-load, or replacing gaskets and seals. — weld defects Prior to increasing the pre-load in bolts, it shall be documented — corrosion related defects by calculation that no over-stressing occurs in bolts, flange or — damage to anodes. gasket/seals. In case the pre-load in the bolts is removed, e.g. due to changing of gasket, new bolts shall be used for the E 200 Application flange connection. 201 Within the original design life, and without essential 709 All repair clamps, sleeves, pipe spools, and mechanical changes in the manner of employment (repair etc.), the stand- connectors shall be qualified prior to installation and leak ard under which the pipeline was built may apply when consid- tested after installation. For guidance, reference is made to ering incidents, minor modifications or rectification of design DNV-RP-F113 Pipeline Subsea Repair. parameters exceeded during operation. This standard and asso- Repair by welding ciated DNV codes may alternatively be used. 710 Repair welding procedures and welders shall be quali- For major modifications or other instances not covered by the fied as described in Appendix C. above paragraph this standard shall apply. Guidance note: 711 Repair welding above water shall be carried out as described in Appendix C. The same safety level shall apply for lifetime extensions of an existing pipeline as would apply for the design of a new pipeline. 712 Underwater welding shall be carried out in a dry habitat, The reason for requiring use of this standard is in case the origi- see Appendix C. nal standard used for design is less stringent than necessary to meet the target safety levels specified in this standard. 713 Repair welding may, in special cases, be carried out on pipelines while operating, depending on pipe material, pipe ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- wall thickness, fluid type, pressure and temperature. It shall be documented that safety for carrying out the repair is accepta- E 300 Safety level ble, and a safety procedure shall be established. 301 A target safety level as defined in Sec.2 C500 shall apply 714 All repair welds shall be subject to visual and non- for a re-qualification assessment. destructive testing, see Appendix D. Following the repair, 302 Operational experience, e.g. change of operational con- pressure testing may be required for the repaired section. ditions, inspection records and modifications, shall be consid- ered in a re-qualification assessment. E 400 System pressure test E. Re-qualification 401 System pressure testing may be required when: E 100 General — the original mill pressure test or system pressure test does 101 The purpose of this section is to define re-qualification not satisfy requirements according to this standard at the and to give requirements for re-qualification of pipeline sys- new design pressure tems. — a significant part of the pipeline has not been system pres- sure tested e.g. new pipeline section. (for omission of sys- 102 Re-qualification is a re-assessment of the design under tem pressure test, see Sec.5 B204). changed design conditions. 103 A re-qualification may be triggered by a change in the E 500 Deterioration original design basis, by not fulfilling the design basis, or by 501 All relevant deterioration and damage mechanisms shall mistakes or shortcomings having been discovered during nor- be evaluated. Typical mechanisms are: mal or abnormal operation. Possible causes may be: a) corrosion: a) preference to use this standard, e.g. due to requirements for higher utilisation for existing pipelines — external corrosion b) change of the premises: — internal corrosion. b) erosion — environmental loads — deformations c) accidental loads —scour. d) development of free spans c) change of operational parameters: e) fatigue f) settlement. — pressure or temperature — corrosivity of the medium. 502 Sufficient reliability or safety measures shall be applied to account for the accuracy and uncertainties in the inspection d) deterioration mechanisms having exceeded the original results. assumptions: 503 Accumulated damage experienced prior to the re-quali- fication shall be included in the evaluation. — corrosion rate, either internal or external — dynamic responses, contributing to fatigue, which E 600 Design criteria may be caused by lacking supports etc. 601 The parameters that trigger the re-qualification and the e) extended design life. implication of changes in these parameters on different design conditions shall be clearly identified and documented. For re- f) discovered damage: design of these design conditions, reference is made to Sec.5.

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F. De-commissioning G. Abandonment F 100 General G 100 General 101 Pipeline de-commissioning shall be planned and pre- 101 Pipeline abandonment shall be planned and prepared. pared. 102 Pipeline abandonment evaluation shall include the fol- 102 De-commissioning shall be conducted and documented lowing aspects: in such a way that the pipeline can be re-commissioned and put into service again. — relevant national regulations — health and safety of personnel, if the pipeline is to be 103 De-commisioning evaluation shall include the following removed aspects: — environment, especially pollution — relevant national regulations — obstruction for ship traffic — environment, especially pollution — obstruction for fishing activities — obstruction for ship traffic — corrosion impact on other structures. — obstruction for fishing activities — corrosion impact on other structures. 104 De-commissioned pipelines shall be preserved to reduce effect from degradation mechanisms.

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SECTION 12 DOCUMENTATION

A. General — corrosion control philosophy — second and third party activities. A 100 Objective 102 The purpose of the design documentation is to ensure a 101 This section specifies the minimum requirements to doc- reliable pipeline system. The design shall be adequately docu- umentation needed for design, manufacturing / fabrication, mented to enable second and/or third party verification. As a installation, operation and abandonment of a pipeline system. minimum, the following items shall be addressed: The pipeline system phases are further described in Sec.3 A 200. — pipeline routing 102 A Design Fabrication Installation (DFI) resumé, as — physical and chemical characteristics of fluid described in H, shall be established with the main objective — materials selection being to provide the operations organisation with a concen- — temperature/pressure profile and pipeline expansion trated summary of the most relevant data from the design, fab- — strength analyses for riser and riser supports rication and installation (incl. pre-commissioning) phase (see — all relevant strength and in-place stability analyses for B, C and D). pipeline 103 An in-service file containing all relevant data achieved — relevant pipeline installation analysis during the operational phase of the pipeline system and with — risk analysis as applicable the main objective to systemise information needed for integ- — systematic review of threats in order to identify and eval- rity management and assessment of the pipeline system shall uate the consequences of single failures and series of fail- be established and maintained for the whole service life (see ures (see Sec.2 B300) F200). — corrosion control (internal and external) — piggability 104 For the design, fabrication and installation phase, all — installation and commissioning. required documentation shall be reflected in a master docu- ment register (MDR). 103 Drawings shall be provided for the fabrication and 105 The required documentation for all phases of the pipe- installation of the pipeline system, including but not limited to: line system’s lifetime shall be submitted to the relevant parties — pipeline route drawings including information on, e.g. sea- for acceptance or information as agreed. bed properties and topology, existing and future platforms, pipelines/cables, subsea well heads, ship lanes, etc. — alignment sheets — detailed pipeline crossing drawings B. Design — platform layout drawings with risers, riser protection sys- B 100 Structural tems, loading zones, boat landing areas, rescue areas, etc. as applicable 101 A design basis for the pipeline system shall be estab- — spool fabrication drawing lished, including, but not limited to: — other components within the pipeline system (connectors, pigging loops etc.) — safety objective — pipeline protection drawings — pipeline system description incl. location, general arrange- — riser and riser clamp fabrication drawings ments, battery limits, inlet and outlet conditions — land ownership details. — functional requirements including field development restrictions, e.g. safety barriers and subsea valves B 200 Linepipe and pipeline components (including — requirements to repair and replacement of pipeline sec- welding) tions, valves, actuators and fittings — project plans and schedule, including planned period of 201 The following documentation shall be established: the year for installation — material manufacturing specifications — design life including specification of start of design life, — welding and NDT specifications e.g. installation, final commissioning, etc. — transport capacity and pipeline sizing data — material take off/data sheets. — attention to possible code breaks in the pipeline system B 300 Corrosion control systems and weight coating — geometrical restrictions such as specifications of constant internal diameter, requirement for fittings, valves, flanges 301 The following documentation shall be established, as and the use of flexible pipe or risers applicable: — pigging requirements such as bend radius, pipe ovality and distances between various fittings affecting design for pig- — cathodic protection design report ging applications — anode manufacturing and installation specifications — relevant pigging scenarios (inspection and cleaning) — anode drawings — pigging fluids to be used and handling of pigging fluids in — coating manufacturing specifications both end of pipeline including impact on process systems — field joint coating specification(s) — topographical and bathymetrical conditions along the — corrosion monitoring system specification intended pipeline route — material take off/data sheets. — geotechnical conditions Guidance note: — environmental conditions The cathodic protection design report shall pay attention to the — operational conditions such as pressure, temperature, fluid landfall section (if any) and possible interaction with the relevant composition, flow rate, sand production etc. including onshore CP-system. possible changes during the pipeline system's design life — principles for strength and in-place analysis ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---

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B 400 Installation — consumable batch numbers 401 The following documentation shall be established: — welder certificates — heat treatment records — Failure Mode Effect Analysis (FMEA) and HAZOP stud- — NDT procedures and records ies (see Sec.10) — NDT operator certificates — installation and testing specifications and drawings — dimensional reports — Welding Procedure Qualification (WPQ) records. — equipment calibration certificates/reports — storage procedures B 500 Operation — release certificates 501 Decisions and parameters having an impact on the oper- — pipe tally sheet ational phase of the pipeline system such as: — complete statistics of chemical composition, mechanical properties and dimensions for the quantity delivered. — operation envelope — external and internal inspection strategies incl. piggability, C 200 Corrosion control system and weight coating ROV surveys 201 The documentation to be submitted for review prior to — measuring points for in-situ wall thickness measurements, start of manufacturing shall include, but not be limited to: ER-probes, weight loss coupons, fluid monitoring etc. — manufacturing procedures, including inspection/test shall be emphasised and documented in design. requirements and acceptance criteria, repairs, documenta- tion, etc. 502 As a minimum, the following documentation shall be established: — documentation of materials and concrete mix design — Manufacturing Procedure Qualification Tests (MPQT) — pipeline integrity management strategy covering strategies results for corrosion control, inspection and maintenance — quality plan with referenced procedures for inspection, — emergency response strategy testing and calibrations — emergency repair contingency strategy. — outline drawing of anodes. B 600 DFI-Resumé 202 The as built documentation to be submitted after manu- facturing shall include, but not be limited to: 601 The Design part of the DFI-resumé shall be established and in accordance with the requirements given in H. — manufacturing procedures, including test requirements and acceptance criteria, repairs, personnel qualification records, etc. — material certificates C. Construction - Manufacturing — production test records and Fabrication — complete statistics of coating dimensions, weight and neg- ative buoyancy for the each joint delivered C 100 Linepipe and pipeline component — repair log 101 The documentation to be submitted for review prior to — electrical resistance test log. start or during start-up of manufacturing shall include, but not C 300 DFI-resumé be limited to: 301 The Manufacturing / Fabrication part of the DFI-resumé — Quality Plan (QP) shall be established and in accordance with the requirements — Manufacturing Procedure Specifications (MPS) including given in H. test requirements and acceptance criteria — Manufacturing Procedure Qualification Test (MPQT) results — manufacturing procedures (e.g. hydrostatic testing, D. Construction - Installation dimensional measurements, mechanical and corrosion and Pre-Commissioning testing etc.) — Welding Procedure Specifications (WPS), including pro- D 100 General cedures for repair welding 101 The documentation to be submitted for review prior to — Welding Procedure Qualification (WPQ) records start of installation shall include, but not be limited to: — Non Destructive Testing (NDT) procedures — Personnel qualification records (e.g. for welders and NDT — installation procedures for pipelines, risers, spools and operators) components including acceptance criteria, test certificates — manufacturer's/fabricator's quality system manual. for equipment, qualification records for personnel (e.g. welding, coating), etc. 102 The as built documentation to be submitted after manu- — installation procedures for protective structures (as mat- facturing shall include, but not be limited to: tresses etc.) and pipeline anchoring structures — Quality Control (QC) procedures — Installation Manuals (IM) procedures — trenching specification — Inspection and Test Plan (ITP) — intervention procedure — traceability procedure — survey procedure — material certificates — hydrotest procedures — Manufacturing Procedure Specifications (MPS) including — pre-commissioning procedure, incl. procedures for dewa- test requirements and acceptance criteria tering, cleaning, drying, flooding, mothballing,etc.:and —results from MPQT — filling of fluid procedures — test procedures (e.g. hydrostatic testing, dimensional measurements, mechanical and corrosion testing etc.) 102 Documentation produced in connection with the pres- — mechanical test reports sure testing of the pipeline system shall include: — hydrostatic testing report — weld log records — pressure and temperature record charts

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— log of pressure and temperatures that might impair the safety, reliability, strength and stability — calibration certificates for instruments and test equipment of the pipeline system, the following documentation shall, but — calculation of air content not be limited to, be prepared prior to start-up of the pipeline: — calculation of pressure and temperature relationship and justification for acceptance — description of the damage to the pipeline, its systems or — endorsed test acceptance certificate. components with due reference to location, type, extent of damage and temporary measures, if any 103 The as built documentation to be submitted after installa- — plans and full particulars of repairs, modifications and tion and pre-commissioning shall include, but not be limited to: replacements, including contingency measures — further documentation with respect to particular repair, — survey reports modification and replacement, as agreed upon in line with — updated drawings those for the construction or installation phase. — intervention reports — pre-commissioning reports. 103 In case of re-qualification of the pipeline system (see Sec.11 E), all information related to the re-assessment process 104 Records and documentations should include authorisa- of the original design shall be documented. tions and permits to operate. F 200 In-Service file D 200 DFI-Resumé 201 The in-service file, as defined in Sec.11 C1100 shall as 201 The Installation (incl. pre-commissioning) part of the a minimum contain documentation regarding: DFI-resumé shall be established and in accordance with the requirements given in H. — results and conclusions from the in-service inspections — accidental events and damages to the pipeline system — intervention, repair, and modifications — operational data (fluid composition, flow rate, pressure, E. Operation - Commissioning temperature etc.) affecting corrosion and other deteriora- E 100 General tion mechanisms. 101 As a part of the commissioning (see Sec.11 B) the doc- umentation made available shall include, but not be limited to: G. Abandonment a) procedure and results from fluid filling operations with special emphasis on design parameters having an impact G 100 General on the integrity of the pipeline system such as temperature, pressure and dew points 101 Records of abandoned pipelines shall be available and shall include but not be limited to: b) procedures and results from operational verification activ- ities (i.e. start-up inspection). Important parameters to — details of abandoned pipelines on land including route document are typically: maps, the size of the pipeline depth of burial and its loca- tion relative to surface features — expansion — details of abandoned offshore pipelines, including naviga- — movement tion charts showing the pipeline route. — global buckling — wall thickness/metal loss. c) inspection plans covering the future external and internal inspections of the pipeline system. H. DFI Resumé H 100 General 101 A Design Fabrication Installation (DFI) Resumé shall be F. Operation prepared to provide information for operation of the pipeline system. The DFI resumé shall clearly show the limits of the F 100 General pipeline system, which shall be in accordance with Sec.1 C335 101 In order to maintain the integrity of the pipeline system, or otherwise as agreed between Contractor and Pipeline the documentation made available during the operational Owner. phase shall include, but not be limited to: 102 The DFI Resumé shall reflect the as-built status of the pipeline system and shall provide information for preparation — organisation chart showing the functions responsible for of plans for inspection and maintenance planning. the operation of the pipeline system — personnel training and qualifications records 103 The DFI Resumé shall specify design and operating — history of pipeline system operation with reference to premises and requirements. events which may have significance to design and safety 104 The DFI Resumé shall contain all documentation — installation condition data as necessary for understanding required for normal operation, inspections and maintenance pipeline system design and configuration, e.g. previous and provide references to the documentation needed for any survey reports, as-laid / as-built installation drawings and repair, modification or re-qualification of the pipeline system. test reports — physical and chemical characteristics of transported media 105 The preparation of the DFI Resumé shall be carried out including sand data in parallel, and as an integrated part, of the design, fabrication — inspection and maintenance schedules and their records and installation phase of the project. — inspection procedure and results covering the inspection H 200 DFI resumé content aspects described in Sec.11, including supporting records. 201 As a minimum, the DFI Resumé shall contain the below 102 In case of mechanical damage or other abnormalities listed items:

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System description description of possible impact on the operational phase. 202 Shall include a description of the pipeline system includ- Certificate and Authority Approval ing: 209 Shall include a hierarchical overview of issued certifi- — final dimensions cates, release notes and authority approvals with reference to — final operational parameters items and nature of any conditional approvals. The certificates, — a table, for planning of future pigging operations, listing release notes and authority approvals shall show unambiguous all components in the system from pigtrap to pigtrap. Key reference to applicable standards and documents, items cov- data like inner diameter (ID), bend radius and wall thick- ered, accepted deviations, certification activities and condition ness (WT) should be included, as well as references to for certificates. additional documentation / drawings. Surveys Document filing system 210 Shall give all engineering assumptions and assessments drawn from the route and site surveys in addition to all appli- 203 Shall give an overview of as-built documentation cable as-installed route drawings. including description of filing system and method. Inspection, Maintenance and Repair Design Basis 211 Shall include an overview of: 204 Shall give a summary of the final design basis, on which engineering, fabrication and installation is based. Design — identified areas deemed to require special attention during parameters of key importance for the operation of the pipeline normal operation of the pipeline system system should be emphasised. The following parameters are — operational constraints considered important for the operation of the pipeline system: Deviations and Non-Conformances — design life and limitations — design standards, 212 Shall include a complete list of waivers, deviations and — environmental conditions non-conformances with special emphasis on identified areas — tabulated geotechnical parameters as used in design deemed to require special attention during normal operation of — design pressure and temperature the pipeline system. — flow rate Selected Drawings — fluid composition 213 Shall include a complete as-built drawing list, including — corrosion allowance drawings from sub-vendors and contractors, with reference to — depth of cover the as-built filing system. Selected drawings from the design, — material specifications, covering pressure containing fabrication and installation phase, as: equipment and structure — CP-system (i.e. anode details) — drawings of special components — fatigue design assumptions incl. free span criteria — alignment sheets — incidental pressure relief system — as-installed route drawings — flow control techniques and requirements. shall be included. Design 205 Shall include a design activity resumé, all engineering assumptions and assessments not listed in the design basis in addition to applicable deviations and non-conformances I. Filing of Documentation including a description of possible impact on the operational phase. I 100 General Fabrication 101 Maintenance of complete files of all relevant documen- tation during the life of the pipeline system is the responsibility 206 Shall include a manufacturing / fabrication activity of the Owner, or for the operational phase the Operator. resumé, reference to specifications, drawings etc., discussion of problem areas and any deviations from specifications and 102 The DFI-resumé (see H200) and all documentation drawings of importance for the operational phase. referred to in the DFI Resumé shall by filed for the lifetime of the system. This includes also documentation from possible Installation major repair or re-construction of the pipeline system. 207 Shall include an installation activity resumé, reference 103 The engineering documentation not mentioned in I102 to specifications, drawings etc., discussion of problem areas shall be filed by the Owner or by the engineering Contractor and any deviations from specifications and drawings of impor- for a minimum of 10 years. tance for the operational phase. 104 Files to be kept from the operational phase of the pipe- Pre-commissioning line system shall as a minimum include final in-service (F200) 208 Shall include a pre-commissioning activity resumé and inspection reports from start-up, periodical and special inspec- any results from the pre-commissioning phase. All applicable tions, condition monitoring records, and final reports of main- deviations and non-conformances shall be listed including a tenance and repair.

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SECTION 13 COMMENTARY (INFORMATIVE)

A. General — give guidance reflecting good engineering practice. A 100 Objective The section is informative only, and some of the recommenda- The objective of this section is to: tions may not be founded on thorough work but engineering judgement only. — give an overview of the standard by giving cross refer- ences to subjects covered in different sections — give background information to the requirements in the standard B. Cross References

Table 13-1 Index and cross references Key word Reference Comment or aspect Crossing Sec.2 B302 Evaluation of risks Sec.3 C204 Survey Sec.5 B105 Minimum vertical distance Sec.10 B300 Specification Golden weld Sec.10 A807 Requirements Installation Sec.2 C400 Safety class Sec.5 H102 Design criteria Sec.5 H200 Pipe straightness Sec.9 Installation Material strength Sec.5 C302 fc Table 5-6 Relation to supplementary requirement U Figure 2 in Sec.5 Proposed (conservative) de-rating stresses Table 5-7 Reduction due to the UO/UOE process Mill pressure test Sec.1 C200 Definition Sec.5 B200 Link between mill pressure test and design Sec.5 D201 Reduced mill test pressure implication on pressure containment capacity Sec.7 E100 Basic Requirement Sec.7 E105 Maximum test pressure Sec.7 E107 Waiving of mill test – UOE-pipes, conditions Minimum wall thickness Table 5-3 Minimum 12 mm and when it applies Table 5-2 When to use minimum wall thickness, relation to nominal thickness and corrosion allowance Ovality Eq. (5.13) Minimum allowed ovality for collapse

Sec.5 D901 Maximum allowed ovality, as installed Table 7-17 and Table 7-26 Maximum allowed ovality (Out-of roundness), line pipe specification

Pressure - general Sec.1 C200 Definitions Sec.3 B300 Pressure protection system Table 4-1 Pressure terms Table 4-3 Characteristic values

Pressure – incidental Sec.13 E500 Benefit of lower incidental pressure Sec.3 B300 Pressure protection system Table 3-1 Incidental to design pressure ratios Reeling Table 5-10 Fracture assessment – when supplementary requirement P comes into force Appendix A Engineering critical assessment Eq. (5.31) Capacity formula Table 4-5 Condition factor Sec.7 I300 Supplementary requirement P Sec.7 I400 Supplementary requirement D Sec.10 E Testing Spiral welded Sec.5 A205 Requirements

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Table 13-1 Index and cross references (Continued) Key word Reference Comment or aspect Strain hardening Eq. 5.30, Eq. 5.31 In capacity formula; strain Eq. 5.19 (through Eq. 5.22) Capacity formula SMYS/SMTS - (in αc) Table 7-5 and Table 7-11 SMYS and SMTS Table 7-5 and Table 7-11 αh (YS/UTS) System pressure test Sec.1 C200 Definition Sec.5 B200 Link to design Sec.5 B203 Requirements Table 5-1 Waiving of system pressure test Sec.5 B205 Safety class during system pressure test Sec.5 D200 Limit state check - pressure containment Sec.5 D300 Limit state check - local buckling Sec.10 O500 Execution of the test (filling, holding time etc.) Weld onto pipe Sec.5 B108 Requirements for doubler plates etc.

Table 13-2 Characteristic material properties for design Symbol Description Reference Pressure Local buckling containment Collapse Load Displacement Propagating Controlled Controlled buckling

Elastic properties E Young’s modulus X ν Poisson’s ratio X α Temperature expansion, as X function of the temperature (within the actual temperature range) Plastic properties SMYS Specified minimum yield stress Table 7-5 and Table XXXXX 7-11 fy, temp Yield stress temperature derat- Figure 2 XXXXX ing value in Sec.5 SMTS Specified minimum tensile Table 7-5 and Table X-X - - strength 7-11 fu, temp Tensile strength temperature Sec.5 C304 GN X - X - - derating value α fab Fabrication factor Table 5-7 - X (X) (X) X Plastic properties depending on additional requirements αu(U) increased utilisation Table 5-6 X X X X X αh(P) Strain hardening value Table 7-5 and -- - X - Table 7-11 αc(U) Flow stress parameter Eq 5.22 - - X - -

C. Design Philosophy ure during installation, normally considered as safety class low, will have a significantly smaller consequence than a fail- C 100 Safety Class discussion ure during a shut-down period of the pipeline, where both pol- lution and time for repair are significantly more expensive and Safety class shall be specified for each part of the pipeline and time consuming. for each phase. The classification shall be based on the require- ments in Sec.2. However, the total safety may not always be increased by spec- ifying a higher safety class. This may be the case when the The safety class concept allows the owner some flexibility in most probable cause of failure would be draught of vessel, terms of risk which is both a reasonable and rational approach, where the emphasis should be put on operating procedures and e.g. this allows the owner to differentiate between the design back-up. During such circumstances, it may not be required conservatism for a flow line with a 5 year design life and a with a higher safety class. trunk line with 40 years design life. The above clearly illustrates that Table 2-4 is for “Nor- The main aspect when determining the safety class is the con- mal”classification only, as stated. sequence, typically to people, environment and cost. Note that this consequence not necessarily is limited to failure of the C 200 Structural reliability analyses considered pipeline itself, but also to its impact on the total Structural reliability methods consider structural analysis exploration. One such example may be reduction in production models in conjunction with available information regarding if a water injection line or a system for waste water fails which the involved variables and their associated uncertainties. The from an isolated point of view could be defined as safety class reliability as assessed by reliability methods is not an objective low. physical property of the pipeline itself in the given operational Another example is differentiation of temporary phases. A fail- and environmental condition, but rather a nominal measure of

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.13 – Page 133 the reliability given a particular physical and probabilistic based on pressure having an annual probability of exceedance modelling and analysis procedure applied. less than 10-2. This pressure shall then be defined as the inci- Structural reliability analysis is only one part of a total safety dental pressure in the pipeline system. Determination of design concept as gross errors are not included. A gross error is pressure shall then be made based on the above principles. defined as a human mistake during the design, construction, For pipeline systems with a two peak annual extreme pressure installation or operation of the pipeline that may lead to a distribution, special considerations are required. Reference is safety level far below what is normally aimed for by use of a given to E600. partial safety factor design format or specific reliability analy- sis. In the following only natural variability are discussed and the corresponding probabilities are referred to as Nominal throughout this standard. E. Design Criteria Nominal target reliabilities have to be met in design in order to ensure that certain safety levels are achieved. A probabilistic E 100 General design check can be performed using the following design for- The basis for most of the given limit states were developed mat: within the joint industry project SUPERB and the reports may Pf,calculated < Pf,,T be bought from Sintef, Norway. Some results have been pub- lished, e.g. Jiao et al (1996) and Mørk et al (1997). Pf,calculated is the calculated nominal probability of failure evaluated by a recognised (accepted) reliability method and The SUPERB results were incorporated in DNV Rules for pf,T is a nominal target value that should be fulfilled for a Submarine Pipeline Systems, 1996 (DNV'96) and modified in design to be accepted. order to allow for additional aspects, not necessarily to be con- Acceptable nominal failure probabilities depend in general on sidered in a research project. Hence, all limit states may not the consequence and nature of failure, the risk of human injury, have identical partial factors as in the SUPERB reports. economic losses, social (political) inconvenience and the In the 2000 revision of this standard, the LRFD format was expense and effort required to reduce the failure probability. modified on the resistance side as described in Sec.2 and the Failure statistics may be used as guidance on relative failure limit states from DNV'96 modified correspondingly. The local probability levels but only limited information about specific buckling formulation included some results from the Hotpipe failure probability for SLS, ULS and FLS can be deduced from project, allowing a higher utilisation of pressurised pipes. See failure statistics. Structural (nominal) failure probability from e.g. Vitali et al (1999). In this revision, this has been further a SRA is a nominal value and cannot be interpreted as an improved to allow for higher utilisation for pressurised pipes. expected frequency of failure. The characteristic pressure is now incidental pressure for all limit states. C 300 Characteristic values A table specifying the combinations of characteristic loads In a LRFD format, so called characteristic values are used. have been included in Sec.4. This is not intended to be differ- These are often lower fractiles for strength and resistance, not ent from the 2000 revision (with exception of use of the inci- always however, and upper fractiles for loads. Typical exam- dental pressure and that interference loads is a separate load ples of these may be SMYS for the yield stress and 100-year category), only a interpretation given explicitly. waves for loads. The characteristic value in the resistance formulas is a lower E 200 Condition load effect factors fractile and the expected yield stress is typically in the order of The load condition factor γC = 1.07, pipeline resting on uneven 8% higher. On commonly overlooked implication of this is seabed refers to the load effect uncertainty due to variation in that it is not allowed to replace the fy based upon a certificate weight, stiffness, span length or heights. This implies that it is or test. Such a replacement requires a thorough evaluation by not applicable for the sag bend evaluation during installation a reliability specialist. on uneven seabed.

A γC lower than unity is e.g. used in DNV-RP-F110 Global Buckling of Submarine Pipelines – Structural Design due to D. Loads High Temperature/High Pressure, to represent the degree of displacement control and uncertainties in, primarily, the pipe- D 100 Conversion of pressures soil properties. The governing pressure for design is the incidental pressure. E 300 Calculation of nominal thickness The incidental pressure is normally defined as the pressure with an annual probability of exceedance of 10-2 The negative fabrication tolerance is normally given as a per- centage of the nominal thickness for seamless pipes, and as an If the design pressure is given, the incidental pressure shall be absolute measure for welded pipes. determined based on the pressure control system and the pres- sure safety system tolerances and capabilities to ensure that the The pressure containment criterion gives a minimum required local incidental pressure meets the given annual probability of minimum wall thickness, t1. Depending on the fabrication tol- exceedance above. erance format, the implication of the corrosion allowance will be different. For a fabrication tolerance given as a percentage, If the pressure not can exceed the design pressure, e.g. full % t , Eq. (13.1) applies. shut-in pressure is used, the incidental pressure may be fab reduced to the design pressure, see Table 3-1. It is expected that the operating pressure of a well stream designed for the t1 + tcorr t = ------(13.1) shut-in pressure is at least 5% less than the shut-in pressure. i.e. 1%t– only incidental operations are expected to be in the upper 5% fab of the incidental pressure. Correspondingly, the nominal thickness based on an absolute Different systems may have different definitions of design fabrication tolerance, t , is given by Eq. (13.2). pressure and incidental pressure, e.g. between topside and a fab pipeline system. When converting the defined pressures in one system to pressure in another system, the conversion shall be t = t1 ++tcorr tfab (13.2)

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E 400 Pressure containment - equivalent format reduced on purpose by a choke in order to enable a lower pres- The format of the pressure containment resistance in Sec.5 is sure pipeline downstream. This reduced pressure is dependent given in a LRFD format. This corresponds to the traditional on a constant flow and will increase to the shut-in pressure in format, which usually is expressed in terms of allowable hoop case of blockage downstream. stress, is given in Eq. (13.3). A High Integrity Pressure Protection System (HIPPS) serve the purpose to protect the downstream pipeline from the shut- D − t 2⋅α in pressure by stopping the flow in case a pressure increase is 1 U experience (due to some blocking down-stream). The closer ( pli − pe ) ≤ ⋅(SMYS − f y,temp ) (13.3) 2⋅t1 3 ⋅γ ⋅γ this blockage is to the HIPPS, the faster will the pressure m SC increase occur. Hence, the speed of this HIPPS will determine The differential pressure is here given as a function of the local how long part of the pipeline downstream that not can be pro- incidental pressure. Introducing a load factor, γinc, reflecting tected but designed for the full shut-in pressure. This part is the ratio between the incidental pressure and the design pres- referred to as the fortified zone. sure, the formula can be rearranged for the reference point In case of failure of this HIPP system, the downstream pipeline above water, as given in Eq. (13.4). will experience the full shut-in pressure. In order to take advantage of a HIPP system, the annual probability of this to happen must be less than 10-2. D − t1 2⋅α U pd ≤ ⋅(SMYS − f y,temp ) (13.4) 2⋅t 3 ⋅γ ⋅γ ⋅γ The resulting annual extreme pressure distribution will then be 1 m SC inc similar to Figure 1, a two peak distribution where the right Introducing a usage factor as given in (13.5), the criteria can be peak describes the pressure distribution in case of failure of the given as in Eq. (13.6) and Eq. (13.7). HIPPS.

2⋅α η = U (13.5) 3 ⋅γ m ⋅γ SC ⋅γ inc

D − t1 pd ≤η ⋅ (SMYS − f y,temp ) (13.6) 2 ⋅ t1

D − t1 η pd ≤ ⋅(SMTS − f u,temp ) (13.7) 2⋅t1 1.15

The corresponding usage factors for γinc = 1.10 (10% inciden- Probability Density tal pressure) are given in Table 13-3.

Table 13-3 "Usage factors" η for pressure containment Utilisation Safety Class Pressure factor,α test U Low Medium High 01234 1.00 0.8473 0.802 0.6981 0.96 (0.843) Normalised pressure 3 2 0.96 0.813 0.77 0.67 0.96 Figure 1 (0.838) 1) In location class 1, 0.802 may be used 2) In location class 1, 0.77 may be used 3) Effectively this factor since the pressure test is governing From the example in the figure, it is evident that the over pres- sure scenario will burst the pipeline (a factor 2.5 times the inci- E 500 Pressure containment criterion, dental pressure). incidental pressure less than 10% above the design pres- For a failure probability less than 10-2 this over-pressure may sure. be considered as an accidental limit state and the methodology The governing pressure when determining the wall thickness is in Sec.5 D1200 may be used. The wall thickness will then be the local incidental pressure. The pipeline system shall have a the larger of the pressure containment criterion based: pressure safety system which ensures that there is a low life- time probability for exceeding the local incidental pressure at — on the choke pressure and any point in the system. If this is achieved for an incidental — the accidental scenario of the shut-in pressure. pressure which is 10% above the design pressure, this gives one wall thickness. With the example in Figure 1 the accidental scenario will gov- ern the wall thickness design. If the over pressure would have However, a better control system which can guarantee the been less than 20-30% above the incidental pressure, the choke same probability for an incidental pressure 5% above the pressure may govern the design. design pressure, a correspondingly smaller wall thickness is The accidental criterion is: required. This is reflected by a lower γinc in (13.5) and will typ- ically apply to hydraulicly “softer” systems like gas trunk lines. (13.8) ∑ p f |Di ⋅ PDi ≤ p f ,T E 600 HIPPS and similar systems where p is the failure probability given that the scenario A pipeline will always have an operating pressure lower than f|Di happens and PDi is the probability of the scenario to happen. In the design pressure due to the pressure drop caused by the flow the following, it is assumed that the over pressure scenario will of the fluid. be the overall contributing accidental scenario and the summa- For high pressure wells, this downstream pressure may be tion sign is neglected.

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For the HIPPS scenario outlined above, the probability of the E 900 Local buckling - Moment scenario, PDi, will be equal to the probability of a blockage to The given formula is valid for 15 < D/t < 60 for yielding and happen times the on-demand-failure of the HIPPS. 2 ovalisation failure modes. Up to D/t2 equal to 45, these failure modes will occur prior to other failure modes, e.g. elastic buck- PDi = Pblockage · Pfailure on demand(HIPPS) (13.9) ling, and hence do not need to be checked.

The resulting wall thickness for the accidental scenario will Over D/t2 45, elastic buckling has to be checked separately, then be the wall thickness giving the failure probability typically through FE analysis, with D/t2 a sufficient "safety required in accordance with 13.8 margin" above the actual D/t2 in order to account for both Note that the target failure probability in accordance with uncertainty as well as natural thickness variations. Sec.2 primarily shall be equal to similar limit states. The fail- In addition to check for elastic buckling, a thinner pipe ure probability of the pressure containment criterion is at least becomes more susceptible to imperfections. Special consider- one order of magnitude less than the target values in Table 2-5. ations shall be made to E 700 Local buckling - Collapse — girth welds and mismatch at girth welds, and The collapse pressure, pc, is a function of the: — point loads, e.g. point supports. — elastic capacity If both the elastic buckling has been documented to occur — plastic capacity beyond the valid range and the implications of imperfections — the ovality. has found to be acceptable, the criteria may be extended to D/t2 =60. The formulation adopted in this standard is identical as in BS8010, apart from the safety margin. The formula is given in E 1000 Local buckling - Girth weld factor Eq. (13.10) with the defined elastic and plastic capacities in Research on buckling of pipes including girth welds has shown Eq. (13.11) and Eq. (13.12). that the girth weld has a significant impact on the compressive strain capacity, see Ghodsi et al (1994). A reduction in the

2 2 D order of 40% was found for D/t2 = 60. There are no other (pc ()t − pel ()t )⋅ ()pc ()t − p p ()t = pc ()t ⋅ pel ()t ⋅ p p ()t ⋅ f 0 ⋅ (13.10) known experiments on the impact from girth welds for lower t D/t2. 3 ⎛ t ⎞ It is assumed that the detrimental effect is due to on-set of 2 ⋅ E ⋅⎜ ⎟ D (13.11) buckling due to imperfections at the weld on the compressive ⎝ ⎠ side. If this is true, this effect will be more pronounced for pel ()t = 2 1−ν higher D/t2's. The girth weld factor should be established by test and/or FE-calculations. 2⋅t p ()t = f ⋅α ⋅ (13.12) If no other information exists and given that the reduction is p y fab D due to the misalignment on the compressive side, the reduction is expected to negligible at D/t2 = 20. A linear interpolation is This third degree polynomial has the following analytical solu- then proposed up to D/t = 60. tion: 2 If no other information exists then the following girth weld fac- tor is proposed. 1 p = y – ---b (13.13) c 3 where: b = − pel ()t

2 d = pel (t) p p (t) 1 1 2 u = ---⎛⎞----b + c 3⎝⎠3 Figure 2 Proposed girth weld factors 1 2 3 1 v = ---⎛⎞------b – ---bc+ d 2⎝⎠27 3 E 1100 Ovalisation Pipe ovalisation is mentioned in three different places within –1⎛⎞–v Φ = cos ⎜⎟------this standard: ⎝⎠3 –u Sec.5 D900, where the maximum allowable ovalisation f0 = ⎛ Φ 60π ⎞ 3%. This applies for the pipeline as installed condition. This y = −2 − u cos⎜ + ⎟ limitation is due to the given resistance formulations which not ⎝ 3 180 ⎠ includes the ovality explicitly, as well as other functional aspects as stated in the paragraph. E 800 Buckle arrestor Sec.5 D401, where the minimum ovalisation f0 = 0.5% to be The buckle arrestor formula in Sec.5 is taken from Torselletti accounted for in the system collapse check; and the combined et al. loading. The collapse formula includes the ovality explicitly giving a lower resistance for a larger ovality, hence a minimum ovality is prescribed.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 136 – Sec.13

Table 7-17, dimensional requirements, where the maximum G 200 J-tubes allowable out of roundness to be delivered from Manufacturer The J-tube system is to be designed to perform satisfactorily is specified. during its entire planned life. It is to be designed against rele- The ovality of a pipe exposed to bending strain may be esti- vant failure modes. mated by Eq. (13.14). This is a characteristic formula without The routing is to be based on the following considerations: any safety factors. — platform configuration and topsides layout — space requirements D D 2 f + 0.030⎛⎞ 1 + ------⎛⎞2ε ---- — movements of the J-tube 0 ⎝⎠120t ⎝⎠c t — cable/Pipeline approach f ′ = ------(13.14) 0 P — J-tube protection 1 – -----e — in-service inspection and maintenance Pc — Installation considerations. For further information, reference is made to Murphey (1985) The J-tube spools are normally to be joined by welding. For J-tubes, loads during Installation include: — load-out F. API Material Grades — transportation F 100 API material grades — lifting — launching The API requirements to the Grades X42 through X80 are listed — upending in Table 13-4. For full details see the API Specification for Line — docking Pipe (API Specification 5L). The SMYS and SMTS values — pressure testing given in MPa in the table below are converted from the API specification (in ksi), and differ slightly from the mechanical — temporary supporting. properties in Sec.7 Table 7-5, which apply for this standard. The effect of deflections due to a connected Pipeline's thermal expansion or contraction is to be taken into account. Table 13-4 API Material Grades API SMYS SMTS Loads caused by deflections of the J-tube, or the structure to which the support is attached, are to be considered. Grade ksi MPa ksi MPa X42 42 289 60 413 Loads on the J-tube and supports as a result of foundation set- tlements are to be considered. Accidental loads are loads to X46 46 317 63 434 which the J-tube and support system may be subjected in con- X52 52 358 66 455 nection with incorrect operation or technical failure such as X56 56 386 71 489 fire, explosions and impact loads. The relevant accidental X60 60 413 75 517 loads and their magnitude are to be determined on the basis of X65 65 448 77 530 a risk analysis. X70 70 482 82 565 The effect of impact by vessels is to be considered for the J- X80 80 551 90 620 tube and support system within the splash zone. Normally the ksi = 6.895 MPa; 1 MPa = 0.145 ksi; ksi = 1000 psi (lb f/in2) J-tubes and supports are to be routed inside the structure to avoid vessel impact. Consideration is to be given to accidental loads caused by fall- ing objects such as: G. Components and Assemblies — falling cargo from lifting gear G 100 Riser Supports — falling lifting gear Riser Supports are to be designed to ensure a smooth transition — unintentionally swinging objects. of forces between Riser and support. Inspection/control methods are to be specified so that proper Installation is ensured, in accordance with the design assump- H. Installation tions. Where the Riser Support relies on friction to transfer load, H 100 Safety class definition appropriate analytical methods or experimental test results are Installation of pipeline and pipeline components is normally to be used to demonstrate that adequate load transfer will be defined as safety class Low. However, if the installation activ- developed and maintained during the life of the structure. The ity impose a higher risk to personnel, environment or the design of the studbolts is to be such that it is possible to moni- assets, a higher "safety class" should be used. Such activities tor the remaining bolt tension during the design life time. This may typically be repair, where the system is shut down, but the can be done by utilising mechanical bolt load indicators in production medium is still within the system, modifications to some of the studbolts in each connection. existing system or installation operations where failure may The minimum remaining pretension level in the studbolts at lead to extensive economic loss. which pre-tensioning must be performed is to be determined during the design phase. H 200 Coating The design is to be such that all the studbolts in one connection In case no other data is available the following criterion should can be pre-tensioned simultaneously by means of bolt tension- be used. The mean overbend strain: ing jacks. D All relevant loads are to be considered when calculating the εmean = –------+ εaxial (13.15) fatigue life of the Riser Supports. 2R

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.13 – Page 137 should satisfy: Calculation requirements The following requirements to the lay analysis apply both γccεmean ≥ εcc (13.16) when using Limit State Criteria and Simplified Criteria: where — The analysis shall be conducted using a realistic non-linear stress-strain (or moment-curvature) representation of the D = outer steel diameter material (or cross-section). R = stinger radius — For calculation of strain concentration at field joints, non- εmean = calculated mean overbend strain linear material properties of the steel, the concrete and the εaxial = axial strain contribution corrosion coating shall be considered. γcc = 1.05 safety factor for concrete crushing — The characteristic environmental load during installation εcc = limit mean strain giving crushing of the concrete. is to be taken as the most probable largest value for the Positive strain denotes tensile strain. sea-state (Hs, Tp) considered with appropriate current and wind conditions. The sea-state duration considered is not The mean overbend strain at which concrete crushing first to be less than 3 hrs. occurs depends on the pipe stiffness, the concrete strength and thickness, the axial force and the shear resistance of the corro- — If the dynamic lay analysis is based on regular waves, it sion coating. Crushing occurs at lower mean overbend strains shall be documented that the choice of wave heights and for lower concrete strength, lower axial force, higher pipe stiff- periods conservatively represents the irregular sea-state ness and higher shear resistance. If no other information is (Hs, Tp). available, concrete crushing may be assumed to occur when H 400 Reeling the strain in the concrete (at the compressive fibre in the mid- dle of the concrete thickness) reaches 0.2%. A pipeline that is reeled onto a spool will be subjected to large plastic strains. When two abutting pipe joints have dissimilar For concrete coating of 40 mm thickness or more, together tangential stiffness, e.g. due to different wall thickness or var- with asphalt corrosion coating, a conservative estimate of εcc ying material properties, a discontinuity will occur. The result is 0.22% for 42" pipelines and 0.24% for 16" pipelines, with of this is a concentration of compressive strains in the softer linear interpolation in between. joint in an area close to the weld. Experience has shown that Reference is made to Endal (1995) or Ness (1995). variations in properties (within fabrication tolerances) may cause the pipe to buckle. H 300 Simplified laying criteria Figure 4 and Figure 5 attempt to illustrate the reeling situation This simplified laying criteria may be used as a preliminary from two different points of view. It is recognised that these simplified criterion of the local buckling check during early illustrations, and the description below, are simplified and only design stages. It does not supersede any of the failure mode take into account global effects. checks as given in the normative part of the standard. In Figure 4 the sudden increased curvature is visualised by In addition to the simplified stress criteria given below, the looking at the moment curvature relationship for the two abut- limit states for Concrete Crushing (K200), Fatigue (Sec.5 ting joints. It is seen that the required moment equilibrium D700) and Rotation (Sec.5 H203) shall be satisfied. Reference across the weld will lead to an increase in curvature in the is further made to Endal et. al. (1995) for guidance on the Rota- weaker pipe. This figure also shows clearly that an increased tion limit state. stiffness difference will increase the sudden increase in curva- Overbend ture in the weaker joint. For static loading the calculated strain shall satisfy Criterion I in Table 13-5. The strain shall include effects of bending, axial force and local roller loads. Effects due to varying stiffness (e.g. strain concentration at field joints or buckle arrestors) need not be included. For static plus dynamic loading the calculated strain shall sat- isfy Criterion II in Table 13-5. The strain shall include all effects, including varying stiffness due to field joints or buckle arrestors.

Table 13-5 Simplified criteria, overbend Criterion X70 X65 X60 X52 I 0.270% 0.250% 0.230% 0.205% II 0.325% 0.305% 0.290% 0.260%

Sagbend Figure 3 Moment curvature relationship for plastic bending of pipes with For combined static and dynamic loads the equivalent stress in different stiffness. the sagbend and at the stinger tip shall be less than

σeq < 0.87 times fy (13.17) Figure 3 provides a different illustration: The distribution of moment and corresponding tangential stiffness is schemati- with all load effect factors set to unity. cally plotted along the pipeline. Effects due to varying stiffness or residual strain from the over- At the left hand side of the figure the pipe is assumed to lie bend may be ignored. tight onto the reel with a constant bending moment well into For the sagbend in deeper water, where collapse is a potential the plastic regime. From the point where the pipe first touches problem, the normative buckling criteria in the standard shall the reel, to the point at the right hand side where back tension also be satisfied. is applied, the moment is assumed to decay linearly to zero.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 138 – Sec.13

(Note that this moment will not vanish if the caterpillars, The lower part of this figure shows the tangential stiffness through which the back tension is applied, restrain rotation.) along the pipeline. Attention should be paid to the sudden drop Furthermore, Figure 4 illustrates the scenario where a field in stiffness at the weld. It is obvious that this loss of stiffness joint approaches the reel and a weak/soft joint follows a will attract deformations, i.e. increased curvature in the weaker stronger/stiffer one. pipe close to the weld.

Moment moment at reel curvature weld

elastic moment for softer pipe elastic moment for stiffer pipe

on reel plastified elastic plastified elastic

Stiffness

on reel plastified elastic plastified elastic

Pipe axis

Figure 4 Schematic illustration of bending moment and stiffness along the pipe

FE analyses have shown that the most important parameters, cross section's tendency to buckle. Obviously a high D/t2 ratio with respect to stiffness variations are variations, in yield stress will have a similar effect. and wall thickness. Under disadvantageous circumstances, variations within normal fabrication tolerances may lead to During reeling, application of a high back tension is the major buckling of the pipe cross section. remedy available for reducing the possibility for pipe buckling, and both practical experience and FE analyses have shown that Over-matching (girth) weld materials are often used in pipes. this is a viable and mitigating measure in this context. These will introduce stiffness variations, however the effect of these are not normally significant from a buckling point of view. Hence: in order to reduce the probability of buckling during reeling, one should: If a thick and relatively stiff coating is applied with gaps across field joints, stress concentrations due to variations in yield — specify a low thickness fabrication tolerance, stress and wall thickness will be amplified. — specify a low variation in yield stress, Analyses have also shown that accurate non-linear material — specify a low yield stress to ultimate stress ratio modelling is essential for the accuracy of FE analyses. Espe- — apply a high and steady back tension during reeling. cially important in this respect is the tangential material stiff- ness, often defined through the yield stress to ultimate stress For further information, reference is made to Crome (1999), ratio, SMYS/SMTS. High ratios increase significantly the Brown et al (2004).

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Sec.13 – Page 139

I. References Murphey D.E. and Langner C. G. "Ultimate pipe strength under bending collapse and fatigue", Offshore Mechanics and Brown G., Tkaczyk T., Howard B. “Reliability based assess- Arctic Engineering symposium, New Orleans 1985. ment of minimum reelable wall thicknesss for reeling” Pro- Mørk. K, Spiten J., Torselletti E., Ness O. B., and Verley R.; ceedings of IPC04-0733, IPC Calgary, Alberta, Canada 2004 "The SUPERB Project and DNV'96: Buckling and Collapse Crome, Tim; "Reeling of Pipelines with Thick Insulating Coat- Limit State", Proceedings of OMAE'97 conference, Yoko- ing, Finite Element Analyses of Local Buckling", OTC, Hou- hama, Japan ston, 1999. Ness O. B. and Verley R.; "Strain Concentrations in Pipelines Endal G., Ness O. B., Verley R., Holthe K. and Ramseth S; with Concrete Coating: An Analytical Model", Proceedings of "Behaviour of Offshore Pipelines Subjected to Residual Cur- OMAE'95 conference, Copenhagen, Denmark vature During Laying", Proceedings of OMAE'95 conference, Sriskandarajah T. and Mamendran, I. K.; "Parametric consid- Copenhagen, Denmark erations of design and installation of deepwater pipelins", Off- Ghodsi Nader Yoosef-, Kulak G. L. and Murray D. W.; shore Oil and Gas Pipeline Technology, London, 1987 "Behaviour of Girth Welded Line-pipe", University of Alberta Torseletti E., Bruschi R., Marchesani F., Vitali L. “Buckle department of Civil Engineering, Structural Engineering Propagation and its Arrest: Buckle Arrestor Design Versus Report No. 23, 1994 Numerical Analyses and Experiments” OMAE2003-37220 Jiao G., Sotberg T., Bruschi R., Verley R. and Mørk K; "The Vitali L., Bruschi R., Mørk K., Verley R.(1999); "Hotpipe SUPERB Project: Wall Thickness Design Guideline for Pres- project - Capacity of pipes subjected to internal pressure, axial sure Containment of Offshore Pipelines", Proceedings of force and bending moment", Proc. 9th Int. Offshore and Polar OMAE'96 conference, Florence, Italy Engineering Conference, Brest 1999.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 140 – App.A

APPENDIX A STRUCTURAL INTEGRITY OF GIRTH WELDS IN OFFSHORE PIPELINES

A. General can be demonstrated to be conservative. G106 shows a con- servative way of estimating the corresponding CTOD fracture A 100 Objective toughness from a J fracture toughness test. 101 The objective of this Appendix is to: 205 The fatigue assessment procedure described in this Provide detailed procedures and recommendations for evalua- Appendix (Subsection F) is supplementary to the fatigue tion of the integrity of girth welds considering weld disconti- design guidance described in the main body of this document nuities during installation and operation (the S-N approach). Assessment of the fatigue life should sat- isfy the requirement listed here and described in Sec.5 D800. Referenced Standards A 300 Application 102 The following standards are referred to in this appendix: 301 The ECA procedures described in this Appendix are BS 7448 only applicable to C-Mn steels with SMYS up to 555 MPa, BS 7910 13Cr martensitic stainless steel, 22Cr and 25Cr duplex stain- DNV-RP-C203 less steels. Special advice must be sought if any other type of pipeline materials is used. DNV-RP-F108 302 In general, procedures for assessing girth welds under A 200 Introduction load- and strain-based conditions are described. The proce- dures are also applicable for assessing flaws in parent pipe. 201 The purpose of the structural integrity evaluation of welds in pipelines is to avoid failure during the installation and 303 This Appendix is not applicable to flexible pipes or operation stages by determining the criticality of flaws. The dynamic or compliant risers. procedures described are based on fracture mechanics and the 304 The integrity of welds in lined and clad pipelines may be term “Engineering Critical Assessment” (ECA) is used. Both evaluated according to the procedures described in this appen- static and dynamic strains (fatigue) are considered as relevant. dix, but special considerations apply, see C105, D103, E206, Typically the assessments are used to: F108, H101 and Appendix B. a) Derive flaw acceptance criteria from the ECA results 305 Some materials are sensitive to environmentally induced (where applicable) in line with Appendix D and embrittlement, e.g. due to hydrogen from sour service or Appendix E. cathodic protection. In such cases the choice of toughness and fatigue properties shall reflect the actual environment. See also b) Perform fitness-for-purpose evaluations, e.g.: G105. — to avoid failures during installation and/or operation 306 This Appendix is not applicable where the yield and/or — to assess the effect of changed operational conditions tensile stress of the weld is under-matched with respect to the (temperature, strain level, lifetime extension etc.) parent pipe material. In such cases specialist advice shall be — to assess the significance of weld flaws or damage sought. incurred after installation. 307 It is possible to estimate KIC from Charpy V-notch test 202 For girth welds, it is the pipeline longitudinal stress- results using correlation formulas. The results are however strain condition that is of relevance during installation. All considered to be less reliable and it is not acceptable to assess strain requirements/limitations for girth welds are defined as the integrity of pipeline girth welds in accordance with this Appendix based on Charpy V-notch testing only. Such assess- the total nominal strain (elastic plus plastic), εl,nom in the pipe longitudinal direction. The total nominal strain may be inclu- ments are only considered as indications. sive of global stiffness disruption effects such as concrete coat- 308 The fracture toughness properties will normally be ing discontinuity (if applicable) at the field joint. However, any determined from a fracture toughness test programme using other local effects, such as wall thickness mismatch and joint single edge notched tensile (SENT) specimens in accordance misalignment effects, etc., shall be considered/analysed with with Subsection G, Appendix B and DNV-RP-F108. However, the methodology presented herein. For assessments of the other fracture toughness test methods and specimen operational stage, the effect of circumferential stresses also geometries may be used provided that it can be demonstrated need to be considered, see B103, C104, D103 and E206. that these test techniques are conservative in relation to their 203 Failures are assumed to be avoided if: application. Guidance note: — the maximum longitudinal strain, εl,nom is not larger than The ECA procedures described in this Appendix requires that 0.4% fracture toughness testing is performed. Hence, the pipe dimen- — the maximum size of weld defects is in accordance with sions which may be assessed according to this Appendix depend Appendix D on the limitations with respect to the fracture toughness testing. — the material is in accordance with Sec.6 and 7 It is recommended that the dimensions of SENT specimens are — the girth welds have acceptable fatigue capacity according not less than W = 8 mm and B shall be at least equal to W, see Figure 1. It is possible that B = 2W and the specimens shall be as to Sec.5 D800, or large as possible, see DNV-RP-F108 for further details. Hence, it — an ECA is performed as specified in this Appendix and is normally not possible to perform ECA of pipelines with nom- acceptance criteria are determined in accordance with inal wall thickness less than about 10 mm. Appendix D and Appendix E as relevant. If fracture toughness testing is not possible and the εl,nom exceeds 0.4%, full scale testing or pipe segment testing shall be per- 204 The fracture toughness requirements specified in this formed to prove the integrity of the girth welds including worst Appendix is expressed in terms of the J value. However, the case weld defects. The testing shall reflect the worst case loading ECA may be expressed in terms of the crack tip opening dis- condition, relevant temperature, unfavourable material proper- placement (CTOD) provided that the assessment procedure ties and unfavourable girth weld geometry.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.A – Page 141

and based on well proven engineering principles e.g. 3D FE frac- ture mechanics analysis.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 104 The assessment temperature is defined as the tempera- ture representative for the stress-strain condition considered. It may be ambient (typically installation), elevated (e.g. lateral buckling) or sub-zero (e.g. shut-down). All testing shall nor- mally be performed at the assessment temperature, see Subsec- tion G and 109. Figure 1 If other test temperatures are chosen it must be substantiated SENT geometry that the testing gives conservative results as compared to test- ing at the assessment temperature.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 105 Depending on the level of monotonic and cyclic defor- mations, the assessment procedure and required testing is divided in categories as follows:

a) Maximum longitudinal strain, εl,nom, less than 0.4%. Max- B. Assessment Categories imum number of strain cycles limited to 10, suffix ECA static - low. ECA static – low, may further be “generic” or B 100 General “full”: 101 Pipeline systems shall have adequate resistance against — generic ECA, see Subsection C, requires less testing failure during the whole of its design life. This shall be and assessments are not required as maximum allow- achieved by selecting materials and welds with adequate frac- able flaw sizes are extracted from tables. Generic ture toughness, tensile properties and weld defect acceptance ECA is only applicable if specified requirements are criteria. fulfilled — full ECA, see Subsection E, requires more testing and 102 The various assessment procedures provided in this assessments. Full ECA is performed if generic ECA is Appendix are based on BS 7910. Hence the recommendations not acceptable because all requirements are not ful- and requirements are only applicable if BS 7910 is the basis for filled or if larger maximum allowable flaw sizes are the assessment with amendments and adjustments as described required. in this Appendix. b) Maximum longitudinal strain, εl,nom, equal to or larger It is acceptable to base the integrity of welds on finite element than 0.4%. Maximum number of strain cycles limited to (FE) analyses or other suitable standards, but in such cases the 10, suffix ECA static - high. ECA static – high, may fur- assessment procedure must be thoroughly described and docu- ther be “generic” (see Subsection D) or “full” (see Subsec- mented. Such procedures shall be compared with the proce- tion E) as specified above. dures described in this standard. c) More than 10 strain cycles with Δσl,nom larger than 103 The ECA procedures described in this standard gener- 200 MPa or more than 10 000 stress cycles suffix ECA ally consider uni-axial loading conditions. However, the oper- fatigue, see Subsection F. ation of pipelines normally involves both internal pressure and axial strain, i.e. a bi-axial stress-strain state. ECA of the oper- However, if A203 is fulfilled, no further assessments are ational stage under biaxial stresses is described in E206 (last required. part). 106 A pipeline may either be defined according to “ECA Guidance note: static - low”, “ECA static – high”, “ECA fatigue” or as a com- bination of “static” and “fatigue”. All phases during manufac- Recent full-scale testing has indicated that the fracture capacity turing, fabrication, installation and operation shall be for circumferentially aligned defects (such as those at girth evaluated and included in the assessment of maximum allow- welds) subject to an applied longitudinal strain is reduced if the able flaw sizes. If the size of weld defects indicates potential pipeline is pressurized. This phenomenon is mainly caused by increased crack driving force. Assessment procedures consider- failures during installation or operation based on ECA, the ing internal overpressure combined with longitudinal tensile allowable weld defect sizes shall be reduced. A typical ECA strains are under development, but are not implemented in this process is illustrated in Figure 2. The actual assessment proce- standard. Analysis for such situations must be well documented dures for girth welds are illustrated in Figure 3.

Figure 2 Illustration of a typical ECA process

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 142 – App.A

Figure 3 Flowchart of girth weld integrity assessment

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.A – Page 143

107 It shall be evaluated if the loading mode in consideration dimensions for given material properties and loading condi- is displacement controlled or load controlled and the assess- tions in a conservative way. The derivation of flaw acceptance ment methodology shall reflect this. Normally offshore sub- criteria for UT/AUT can be based upon the critical flaw dimen- marine pipelines are displacement controlled during sions obtained from the ECA in accordance with the recom- installation (e.g. bending controlled by curvature.) and it is mendations and limitations of Appendix D and Appendix E. acceptable to follow the displacement controlled (strain-based) 103 The generic ECA is performed based on Level 2B procedure which is presented in this standard. according to BS 7910 with amendments and adjustments as Where the pipeline is load-controlled (e.g. some operational described in this Appendix. It is recommended that the J frac- conditions or whilst in the lay catenary) the special considera- ture toughness parameter is established by testing of SENT tions specified in 108 apply. specimens. The specimens shall be tested to maximum load 108 If the loading mode is load controlled and it is natural to and the J value shall be judged either as Jm, Jc or Ju according specify the applied load as a tension stress, the assessment to BS 7448: Part 1 and Part 2. The characteristic fracture methodology specified in this Appendix can be used with the toughness value shall be defined according to E211. following changes: 104 If the ECA is performed for the operational phase con- sidering a combination of internal overpressure and longitudi- — if pre-straining is relevant (see Subsection G), the final nal loading, the fracture toughness testing shall be performed strain cycle applied to the test specimen blanks shall end on SENB specimens. in compression. Tensile test results and fracture toughness results from this material shall be used in the assessment 105 This “generic ECA” is not applicable for the following — if pre-straining is not relevant, as-received material used situations: for testing shall as far as possible have documented “lower-bound” tensile properties. For the assessments — clad or lined pipelines (special advice must be sought) either a “lower-bound” stress-strain curve shall be con- — where the girth welds have under-matching strength com- structed or a tensile stress-strain curve shall be established pared to the parent pipe, see E108 from testing which shall represent “lower-bound” proper- — if the girth welds are not tested according to Table A-1, ties Subsection G and Appendix B —L (L cut-off), see E208, shall be defined as: — if the linepipes have not been tested and designed accord- r,max r ing to Sec.6 and Sec.7 YS +UTS L = — if experimentally determined values of J do not meet the r,max 2YS requirements specified in Table A-2 to Table A-4 — the geometry, applied strain and misalignment is not within the limitations specified in Table A-2 to Table A-4 where UTS is the engineering tensile strength and YS is — if the stress-strain curve exhibit a Lüder plateau (yield dis- the engineering yield stress of the parent pipe. continuity in the stress-strain curve) and the maximum 109 The effect of plastic deformation, possible ageing and length of the plateau seen during production tensile testing the assessment temperature shall be taken into account when and tensile testing according to Table A-1 exceeds 2% fracture toughness testing and tensile testing is performed, see — if significant pop-ins, see BS 7448: Part 2, or unstable Subsection G. fracture occur prior to maximum load during fracture 110 The maximum defect size resulting from the ECA shall toughness testing be adjusted for the probability of detection, flaw sizing error — if the material testing does not satisfy the requirements and potential flaw interaction relevant to the specific NDT specified in Subsection G and Appendix B equipment used for inspection see Appendix D and E (Note the — if the following YS/UTS ratios are not met during the pro- probability of detection and sizing error is normally specific to duction qualification tests for the line pipe according to the NDT method, pipe material, geometry and welding proce- Table A-1: dures) YS/UTS ≤ 0.90 for C-Mn with SMYS ≤ 555 MPa YS/UTS ≤ 0.85 for 13Cr — if the following Lr cut-off values determined from the C. Generic ECA for Girth Welds SENT testing according to C208 are not met: Subject to Strains Less than 0.4% Lr cut-off ≥ 1.20 for C-Mn with SMYS ≤ 450 MPa Assessed According to ECA Static – Low Lr cut-off ≥ 1.15 for C-Mn with 450 < SMYS ≤ 485 MPa C 100 General Lr cut-off ≥ 1.10 for C-Mn with 485 < SMYS ≤ 555 MPa 101 If larger weld defect acceptance criteria than specified in Lr cut-off ≥ 1.20 for 13Cr. Appendix D, are requested, the maximum allowable flaws 106 If not all the requirements in 105 are fulfilled either a full specified in Table A-2 to A-4, suitably adjusted to account for ECA shall be performed or the acceptance criteria shall be in sizing accuracy, may be used for the final weld defect accept- accordance with Appendix D and Appendix E. ance criteria. This is only acceptable if all requirements speci- 107 Where the linepipe is subjected to fatigue during opera- fied in A300 and 104 are fulfilled. tion or installation the maximum allowable flaw sizes deter- 102 The ECA does not provide acceptance criteria for UT/ mined from Tables A2 to A4 should be adjusted to account for AUT. The intention of an ECA is to provide critical flaw possible fatigue crack growth in accordance with Subsection F.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 144 – App.A

Table A-1 Testing required for use of “generic ECA” for strain conditions less than 0.4% 1), 2) Type of test Location Test quantity Transverse all weld tensile testing 4), 5) Transverse girth weld 3 Tensile testing 4), 5) Parent pipe, longitudinal 3 J testing of SENT specimens 5) 6) Main line 3 specimens for each notch position, see Appendix B J testing of SENT specimens 5) 6) Double joint 3 specimens for each notch position, see Appendix B J testing of SENT specimens 5) 6) Through thickness repair (TTR) 3 specimens for each notch position, see Appendix B J testing of SENT specimens 5) 6) Partial repair 3) 3 specimens for each notch position, see Appendix B 1) All weld procedures which have different essential variables according to Appendix C, Table C-2 shall be tested 2) The test temperatures and material condition to be tested shall be as specified in Subsection G 3) If the welding procedure and heat input is equal to the through thickness repair procedure, this testing may be omitted 4) If production tensile testing is performed at the assessment temperature and full stress-strain curves are established, additional tensile testing is not required 5) The specimen geometry and test requirements are specified in Appendix B 6) The blunting shall be included in the tearing length

Table A-2 Characteristic J requirements for different maximum allowable flaw sizes 1) [N/mm = kJ/m2] Max allowable flaw, Nominal outer diameter, 8” ≤ OD ≤ 12”, WT = nominal wall thickness 2) a × 2c [mm] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 3 × 50 440 310 480 340 530 460 250 250 4 × 50 750 450 Full 500 Full 570 440 250 5 × 50 Full 640 Full 700 Full 780 Full 300 3 × 100 730 430 790 470 Full 680 480 250 4 × 100 Full 720 Full 790 Full Full Full 400 3 × 200 Full 650 Full 710 Full Full Full 420 4 × 200 Full Full Full Full Full Full Full Full δmax [mm], see E206 1.8 2.5 1.8 2.5 1.8 2.5 1.8 2.5 a > 5 mm Full ECA required 2c > 200 mm Full ECA required WT < 15 mm Full ECA required WT < 10 mm See A308 1) Only acceptable if testing as specified in Table A-1 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

Table A-3 Characteristic J requirements for different maximum allowable flaw sizes 1) [N/mm = kJ/m2] Max allowable flaw, Nominal outer diameter, 12” < OD ≤ 16”, WT = nominal wall thickness 2) a × 2c [mm] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 3 × 50 370 250 400 250 460 250 250 250 4 × 50 600 410 660 440 740 500 310 250 5 × 50 Full 540 Full 590 Full 670 550 250 3 × 100 560 350 610 390 680 440 310 250 4 × 100 Full 570 Full 620 Full 690 740 270 3 × 200 Full 510 Full 550 Full 610 Full 270 4 × 200 Full Full Full Full Full Full Full 580 δmax [mm], see E206 1.8 2.5 1.8 2.5 1.8 2.5 1.8 2.5 a > 5 mm Full ECA required 2c > 200 mm Full ECA required WT < 15 mm Full ECA required WT ≤ 10 mm See A308 1) Only acceptable if testing as specified in Table A-1 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

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Table A-4 Characteristic J requirements for different maximum allowable flaw sizes 1) [N/mm = kJ/m2] Max allowable flaw, Nominal outer diameter, OD > 16”, WT = nominal wall thickness 2) a × 2c [mm] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 3 × 50 350 250 380 250 430 250 250 250 4 × 50 540 280 590 370 670 370 260 250 5 × 50 Full 510 Full 550 Full 630 450 250 3 × 100 490 330 540 360 600 410 250 250 4 × 100 Full 510 Full 560 Full 630 580 250 3 × 200 800 440 Full 490 Full 540 Full 250 4 × 200 Full 770 Full Full Full Full Full 440 δmax [mm], see E206 1.0 1.5 1.0 1.5 1.0 1.5 1.0 1.5 a > 5 mm Full ECA required 2c > 200 mm Full ECA required WT < 15 mm Full ECA required WT ≤ 10 mm See A308 1) Only acceptable if testing as specified in Table A-1 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

D. Generic ECA for Girth Welds — if experimentally determined values of J do not meet the Subjected to Strains Equal to or Larger than requirements specified in Table A-6 to Table A-9 (see Figure 4) — if significant pop-ins, see BS 7448: Part 1 and 4, or unsta- 0.4% but Less Than 2.25% Assessed ble fracture occur prior to maximum load during fracture According to ECA Static – High toughness testing D 100 General — if geometry, applied strain, fracture toughness and maxi- mum misalignment are not within the limitations specified 101 The maximum allowable flaws specified in Table A-6 to A- in Table A-6 to Table A-9 9, suitably adjusted to account for sizing accuracy, may be used — if the following YS/UTS ratios are not met during the pro- for the final weld defect acceptance criteria. This is only accepta- duction qualification tests or the parent pipe tensile testing ble if all requirements specified in A300 and 103 are fulfilled. specified in Table A-5: 102 The generic ECA is based on Level 3B (fracture resist- YS/UTS ≤ 0.90 for C-Mn with SMYS ≤ 450 MPa ance curve needed) according to BS 7910 with amendments YS/UTS ≤ 0.90 for C-Mn with 450 < SMYS ≤ 485 MPa and adjustments as described in this Appendix. The ductile YS/UTS 0.90for C-Mn with 485 < SMYS 555 MPa tearing including blunting, Δa, shall be measured for all the ≤ ≤ SENT tests. For each set (3 specimens) one test shall be tested YS/UTS ≤ 0. 85 for 13Cr beyond maximum load (notch opening displacement (V) at maximum load multiplied by 1.1), one test shall be tested to — if the following Lr cut-off values determined from the maximum load and one test shall be unloaded before maxi- SENT testing according to E208 are not met: mum load. Lr cut-off ≥ 1.20 for C-Mn with SMYS ≤ 450 MPa 103 This generic ECA is not applicable for the following sit- Lr cut-off ≥ 1.15 for C-Mn with 450 < SMYS ≤ 485 MPa uations: Lr cut-off ≥ 1.10 for C-Mn with 485 < SMYS ≤ 555 MPa L cut-off ≥ 1.20 for 13Cr. — clad or lined pipelines (special advice must be sought) r — pipelines subjected to a combination of internal overpres- 104 If any of the requirements specified in 103 are not met, sure and εl,nom> 0.4%, see E206 (last part) a full ECA shall be performed according to Subsections E. — where the girth welds have under-matching strength com- 105 Where the linepipe is subject fatigue during operation or pared to the parent pipe, see E108 installation the maximum allowable flaw sizes determined — if more than 5 tensile strain cycles are applied (e.g. one from Tables A6 to A9 should be adjusted to account for possi- contingency operation during reeling installation is ble fatigue crack growth in accordance with Subsection F. acceptable) — if the girth welds are not tested in accordance with Table 106 If ECA is performed for the operational phase based on A-5, Subsection G and Appendix B generic ECA for the installation phase, the crack height shall — if the linepipes have not been tested and designed accord- be increased by 0.5 mm if 0.4% < εl,nom ≤ 1.0% during instal- ing to Sec.6 and Sec.7 lation. If εl,nom exceeded 1% during installation the crack — if the difference in yield stress between adjacent linepipes height shall be increased by 1.0 mm. exceeds 100 MPa

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Figure 4 No J Δa test results shall end-up inside the area indicated

Table A-5 Testing required for use of “generic ECA” for strain conditions equal to or larger than 0.4% 1), 2) Type of test Location Test quantity Transverse all weld tensile testing 4), 5) Transverse girth weld 3 Tensile testing 4), 5) Parent pipe, longitudinal 5 J R testing of SENT specimens 5), 6) Main line 3 specimens for each notch position, see Appendix B J R testing of SENT specimens 5), 6) Double joint 3 specimens for each notch position, see Appendix B J R testing of SENT specimens 5), 6) Through thickness repair (TTR) 3 specimens for each notch position, see Appendix B J R testing of SENT specimens 5), 6) Partial repair 3) 3 specimens for each notch position, see Appendix B 1) All weld procedures which have different essential variables according to Appendix C, Table C-2 shall be tested 2) The test temperatures and material condition to be tested shall be as specified in Subsection G 3) If the welding procedure and heat input is equal to the through thickness repair procedure, this testing may be omitted 4) If production tensile testing is performed at the assessment temperature and full stress-strain curves are established, additional tensile testing is not required 5) The specimen geometry and test requirements are specified in Appendix B 6) The blunting shall be included in the tearing length

1), 2) Table A-6 Maximum allowable flaw sizes, a × 2c [mm], maximum strain, 0.4% ≤ εl,nom < 1% J Nominal outer diameter, 8” ≤ OD ≤ 12”, WT = nominal wall thickness 2 [N/mm = kJ/m ] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr; SMYS = 550 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 J0.5 = 400 3 × 25 3 × 55 3 × 25 3 × 40 3 × 20 3 × 30 3 × 30 3 × 60 and 4 × 20 4 × 25 4 × 15 4 × 25 4 × 15 4 × 20 4 × 20 4 × 35 J1.0 = 600 5 × 15 5 × 20 5 × 15 5 × 20 5 × 10 5 × 15 5 × 15 4 × 25 J0.5 = 600 3 × 50 3 × 100 3 × 45 3 × 90 3 × 35 3 × 80 3 × 45 3 × 95 and 4 × 30 4 × 50 4 × 25 4 × 45 4 × 20 4 × 40 4 × 25 4 × 55 J1.0 = 800 5 × 20 5 × 35 5 × 20 5 × 30 5 × 15 5 × 25 5 × 20 5 × 40 J0.5 = 800 3 × 70 3 × 150 3 × 65 3 × 145 3 × 55 3 × 115 3 × 50 3 × 100 and 4 × 40 4 × 80 4 × 35 4 × 70 4 × 30 4 × 60 4 × 30 4 × 70 J1.0 = 1000 5 × 25 5 × 50 5 × 25 5 × 45 5 × 20 5 × 40 5 × 25 5 × 50 δmax [mm], 1.8 2.5 1.8 2.5 1.8 2.5 1.8 2.5 see E206 2c ≥ 100 mm Full ECA required WT < 15 mm Full ECA required WT ≤ 10 mm See A308 1) Only acceptable if testing as specified in Table A-5 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

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1), 2) Table A-7 Maximum allowable flaw sizes, a × 2c [mm], maximum strain, 0.4% ≤ εl,nom < 1% J Nominal outer diameter, 12” < OD ≤ 16”, WT = nominal wall thickness [N/mm = kJ/m2] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr; SMYS = 550 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 J0.5 = 400 3 × 35 3 × 75 3 × 30 3 × 55 3 × 25 3 × 40 3 × 40 3 × 90 and 4 × 20 4 × 30 4 × 20 4 × 30 4 × 15 4 × 25 4 × 25 4 × 45 J1.0 = 600 5 × 15 5 × 25 5 × 15 5 × 20 5 × 15 5 × 20 5 × 20 5 × 30 J0.5 = 600 3 × 65 3 × 150 3 × 60 3 × 135 3 × 50 3 × 115 3 × 65 3 × 145 and 4 × 35 4 × 75 4 × 30 4 × 65 4 × 25 4 × 50 4 × 35 4 × 80 J1.0 = 800 5 × 25 5 × 45 5 × 20 5 × 40 5 × 20 5 × 30 5 × 25 5 × 50 J0.5 = 800 3 × 95 3 × 150 3 × 85 3 × 150 3 × 80 3 × 150 3 × 75 3 × 150 and 4 × 50 4 × 115 4 × 45 4 × 100 4 × 40 4 × 85 4 × 45 4 × 105 J1.0 = 1000 5 × 35 5 × 70 5 × 30 5 × 60 5 × 25 5 × 50 5 × 30 5 × 70 δmax [mm], 1.82.51.82.51.82.51.82.5 see E206 2c ≥ 100 mm Full ECA required WT < 15 mm Full ECA required WT ≤ 10 mm See A308 1) Only acceptable if testing as specified in Table A-5 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

1), 2) Table A-8 Maximum allowable flaw sizes, a × 2c [mm], maximum strain, 0.4% ≤ εl,nom < 1% J Nominal outer diameter, OD > 16”, WT = nominal wall thickness 2 [N/mm = kJ/m ] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr; SMYS = 550 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 J0.5 = 400 3 × 40 3 × 90 3 × 30 3 × 70 3 × 25 3 × 50 3 × 50 3 × 125 and 4 × 20 4 × 35 4 × 20 4 × 35 4 × 15 4 × 30 4 × 30 4 × 60 J1.0 = 600 5 × 15 5 × 25 5 × 15 5 × 25 5 × 15 5 × 25 5 × 20 5 × 40 J0.5 = 600 3 × 80 3 × 150 3 × 70 3 × 150 3 × 60 3 × 140 3 × 85 3 × 150 and 4 × 40 4 × 90 4 × 35 4 × 75 4 × 30 4 × 60 4 × 45 4 × 105 J1.0 = 800 5 × 25 5 × 50 5 × 25 5 × 45 5 × 20 5 × 35 5 × 20 5 × 65 J0.5 = 800 3 × 120 3 × 150 3 × 105 3 × 150 3 × 95 3 × 150 3 × 100 3 × 150 and 4 × 60 4 × 145 4 × 50 4 × 125 4 × 45 4 × 105 4 × 60 4 × 145 J1.0 = 1000 5 × 35 5 × 80 5 × 35 5 × 70 5 × 30 5 × 60 5 × 40 5 × 90 δmax [mm], 1.5 2.0 1.5 2.0 1.5 2.0 1.5 2.0 see E206 2c ≥ 100 mm Full ECA required WT < 15 mm Full ECA required WT ≤ 10 mm See A308 1) Only acceptable if testing as specified in Table A-5 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

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1), 2) Table A-9 Maximum allowable flaw sizes, a × 2c [mm], maximum strain, 1.0% < εl,nom < 2.25% J Nominal outer diameter, 8” ≤ OD ≤ 16”, WT = nominal wall thickness 2 [N/mm = kJ/m ] C-Mn; SMYS ≤ 450 C-Mn; SMYS = 485 C-Mn; SMYS = 555 13Cr; SMYS = 550 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 15 ≤ WT < 25 WT ≥ 25 J0.5 = 400 3 × 20 3 × 35 3 × 20 3 × 30 3 × 15 3 × 25 3 × 15 3 × 25 and 4 × 15 4 × 20 4 × 15 4 × 20 4 × 10 4 × 15 4 × 10 4 × 20 J1.0 = 600 5 × 10 5 × 15 5 × 10 5 × 15 4 × 10 5 × 10 5 × 15 J0.5 = 600 3 × 35 3 × 85 3 × 35 3 × 75 3 × 30 3 × 60 3 × 30 3 × 60 and 4 × 20 4 × 40 4 × 20 4 × 35 4 × 20 4 × 30 4 × 20 4 × 30 J1.0 = 800 5 × 15 5 × 30 5 × 15 5 × 25 5 × 15 5 × 20 5 × 15 5 × 25 J0.5 = 800 3 × 45 3 × 95 3 × 45 3 × 95 3 × 45 3 × 95 3 × 35 3 × 75 and 4 × 30 4 × 65 4 × 30 4 × 60 4 × 25 4 × 50 4 × 25 4 × 50 J1.0 = 1000 5 × 20 5 × 40 5 × 20 5 × 40 5 × 20 5 × 30 5 × 15 5 × 30 δmax [mm], 1.5 2.0 1.5 2.0 1.5 2.0 1.5 2.0 see E206 2c ≥ 100 mm Full ECA required WT < 15 mm Full ECA required WT ≤ 10 mm See A308 1) Only acceptable if testing as specified in Table A-5 has been performed 2) Maximum allowable flaw size, a × 2c refers to height and length respectively of both surface breaking and embedded flaws. If the embedded flaw is located close to the surface (ligament height less than half the flaw height) the ligament height between the flaw and the surface shall be included in the flaw height. The UT/AUT flaw sizing error must be subtracted from the maximum allowable flaw height to establish the UT/AUT weld defect acceptance criteria, see Appendix D and Appendix E WT = nominal wall thickness

E. Girth Welds under Strain-based Loading 105 The ECA static – full procedure is only acceptable if Assessed According to ECA Static - Full limitations specified in A300 applies. E 100 General 106 Full ECA requires more testing than the generic ECA, see Table A-1 and Table A-5. Tests already performed for a 101 For load-controlled conditions, this procedure may be generic ECA may be used when constructing the J R-curves followed provided B108 is followed. required for the full ECA. 102 If the generic ECA is not applicable a full ECA static shall be performed. If the maximum allowable flaw sizes 107 The crack growth including blunting (total a minus a0) assessed by ECA generic are not as required/desirable a full shall be measured for all the SENT tests. A minimum of 6 ECA shall be performed which may improve the results. SENT specimens are normally required to construct a J R- 103 The ECA does not provide acceptance criteria for UT/ curve for each weld procedure considered. It is suggested that AUT. For determination of acceptance criteria, see Appendix one specimen is tested beyond maximum load (notch opening D and Appendix E. displacement (V) at maximum load multiplied by 1.1), that two 104 The linepipes shall be tested and designed according to specimens are tested to maximum load and that the remaining Sec.6 and Sec.7 and the girth welds shall be tested according 3 specimens are unloaded prior to maximum load at different to Table A-10, Subsection G and Appendix B. V values.

Table A-10 Testing required for girth welds in pipelines with category ECA static – Full ECA1), 2) Type of test Location Test quantity Transverse all weld tensile testing 4), 5) Girth weld 3 Tensile testing 4), 5) Parent pipe, longitudinal 5 J-R testing of SENT specimens 5), 6) Main line One J R-curve (minimum 6 SENT) for each notch posi- tion, see Appendix B J-R testing of SENT specimens 5), 6) Double joint One J R-curve (minimum 6 SENT) for each notch posi- tion, see Appendix B J-R testing of SENT specimens 5), 6) Through thickness repair (TTR) One J R-curve (minimum 6 SENT) for each notch posi- tion, see Appendix B J-R testing of SENT specimens 5), 6) Partial repair 3) One J R-curve (minimum 6 SENT) for each notch posi- tion, see Appendix B 1) All weld procedures which have different essential variables according to Appendix C, Table C-2 shall be tested 2) The test temperatures and material condition to be tested shall be as specified in Subsection G 3) If the welding procedure and heat input is equal to the through thickness repair procedure, this testing may be omitted 4) If production tensile testing is performed at the assessment temperature and full stress-strain curves are established, additional tensile testing is not required 5) The specimen geometry and test requirements are specified in Appendix B 6) The blunting shall be included in the tearing length

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108 The parent pipe tensile properties and the weld metal — A suitable corrosion allowance shall be included in the tensile properties shall be assumed to be even-matching in the assessments during the operational life of the pipeline. At assessment, i.e. the stress-strain curve of the parent pipe mate- the end of design life the whole corrosion allowance shall rial shall be used. Because of the assumption of even-match- be subtracted. ing, it is assumed that the primary stresses are equal for defects In case of fitness-for-purpose evaluations it is acceptable located at the Fusion Line (FL) border and for defects located within the weld metal, see A307. to base the thickness on inspected values. — The assessments shall be thoroughly defined and pre- If weld metal strength overmatch is not obtained for all mate- sented such that the assessment results are reproducible by rial conditions, the procedure for determination of applied a 3rd. party. stresses specified in E206 is not acceptable and special advice must be sought. Girth welds with less thickness than the parent — The sensitivity of different input parameters and the con- pipe wall thickness is not acceptable (counter-boring is not servatism of the results should be evaluated and discussed. acceptable). 204 Required inputs for an assessment according to a full A strength overmatching weld is obtained if the tensile stress- ECA as specified in this Appendix: strain curves for the weld metal are higher than the tensile stress-strain curve of the parent pipe for all material conditions — pipe dimensions, weld dimensions and dimensional toler- and strain levels under consideration. ances (e.g. high lows acceptable for manufacture) 109 Weld residual stresses shall in general be assumed to be — tensile properties in the form of complete engineering uniform and equal to the yield stress of the parent pipe. Relax- stress-strain curves for the parent pipe material and evi- ation according to BS 7910 is acceptable. If the weld residual dence that the weld metal stress-strain curve over-matches stress distribution is documented by sufficient simulations, it is the parent pipe in the region of interest, see E108 acceptable to define the stress distribution more accurately. — fracture toughness data for specimens with notches located both within the weld metal and at or near the fusion 110 Where the linepipe is subjected to fatigue loading during installation or operation the maximum allowable flaw sizes boundary as specified in this Appendix and Appendix B determined from the ECA shall be adjusted to account for pos- —the Lr cut-off value (see E208) sible fatigue crack growth in accordance with Subsection F. — maximum acceptable tearing (stable crack extension/ growth) (see E209) E 200 Assessment methodology — applied strain history during the installation phase and sec- ondary stresses (e.g. residual stresses from the welding or 201 Strain based assessments with εl,nom exceeding 0.4% during installation shall be carried out in accordance with BS installation processes) 7910 at assessment Level 3B with amendments and adjust- — applied maximum design stress (tensile) applicable to the ments as described in this Appendix. However, for assessment operational life of critical flaw size at the end of design life with εl,nom equal — cyclic stress history applicable to the pipeline whilst it is to or less than 1% Level 2B in accordance with this Appendix in the lay catenary configuration and during the opera- is acceptable. Both assessments based on the Level 2B and 3B tional life. procedures require that material specific stress-strain curves are established. Fracture resistance curves (J R- or CTOD R- 205 Determination of tensile properties and stress-strain curve) is further required for assessments according to Level curve shall be performed as follows: 3B while single parameter fracture toughness is required for Level 2B (CTOD or J). — tensile testing performed during production or qualifica- It is recommended that the fracture resistance curves are pre- tion shall be issued to the ECA contractor and the results sented as J R-curves established from SENT testing according shall be considered when the material specific stress-strain to DNV-RP-F108, and Appendix B (see also Subsection G for curve is constructed further details). This is to ensure that a possible weld defect — the tensile properties used in the ECA shall describe an will not lead to failure due to ductile tearing. Further, an upper-bound stress-strain curve with low strain hardening assessment at Level 3B for the installation phase provides — assumptions of local displacement control involving information about the defect size after installation which is relaxation of the stress level due to crack growth are not needed for assessing possible fatigue crack growth and frac- acceptable ture during operation. — for load controlled conditions see 101 and B108. However, for the operational phase considering a combination of internal overpressure and longitudinal loading the fracture 206 Determination of the applied stresses shall follow the toughness testing shall be performed by testing of SENB spec- following procedure: imens, see also last part of 206. — For uniaxial loading the nominal stress shall be deter- 202 Assessment procedures, other than specified in this mined from the nominal strain from the actual engineering Appendix may be acceptable, but must be justified, well “upper-bound” stress-strain curve. This stress is defined as described, documented and accepted by all parties. the primary membrane stress, Pm, according to BS 7910. 203 If an ECA is performed, the following requirements and For operational cases considering combined internal over- recommendations are applicable: pressure and longitudinal strain see the instructions at the end of this paragraph. — The nominal wall thickness minus the manufacturing tol- erance of the pipe shall be used in assessments considering — The nominal stress shall be increased because of an installation. assumed stress concentration factor (SCF) due to mis- If ECA is performed for only a limited amount of girth alignment at the girth weld. The Neuber approach may be welds it is acceptable to determine the wall thickness to be applied. The stress magnification is defined as a primary used in the ECA using probabilistic methods. bending stress, Pb, according to BS 7910.

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The SCF used in the ECA calculation may be calculated according to DNV-RP-C203: 6 ⋅δ 1 SCF = 1+ ⋅ ⋅ e−α t ⎛ 2.5 ⎞ ⎜ ⎛ T ⎞ ⎟ 1+ ⎜ ⎟ ⎜ ⎜ t ⎟ ⎟ ⎝ ⎝ ⎠ ⎠ where

1.82L 1 α = ⋅ 2.5 Dt ⎛ ⎛ T ⎞ ⎞ ⎜1+ ⎜ ⎟ ⎟ ⎜ ⎟ ⎝ ⎝ t ⎠ ⎠ and: Figure 5 Illustration of how the maximum SCF may be assumed T and t = Wall thickness of the pipes on each side of the girth weld, T > t The Neuber method was originally developed to assess δ = Eccentricities (wall thickness differ- strains at notches. It has been extensively used for pipeline ences, out-of-roundness, centre girth welds subjected to plastic strains with good experi- eccentricities etc.) ence and has been adopted for use in this Appendix. L = Length of weld cap The Neuber method is defined by the following equation: D = Outside diameter of pipe 2 σ 2 ⋅ε 2 = σ 1 ⋅ε 1 × SCF It is acceptable to calculate the SCF with the following as- sumptions, see Figure 5: where

hi / lo + hi / lo δ = ROOT CAP SCF = elastic stress concentration factor 2 σ1 = nominal stress (excluding SCF) ε1 = nominal strain (excluding SCF) The hi/lo shall in general be less than 0.15tnom and maxi- mum 3 mm, see Appendix D, Table D-3. However, weld σ2 = actual stress (including SCF) contractors often specify a maximum value of hi/loROOT ε2 = actual strain (including SCF) which is smaller than the allowable hi/lo. This is accepta- ble but must be documented. Note that hi/loROOT may be An illustration of the Neuber rule is shown in Figure 6. less than the misalignment.

Figure 6 vided the applied stress is defined according to the Illustration of the Neuber rule procedure specified above. If actual surface breaking defects with a height less than — Normally, the local stress intensity magnification factor 10% of the wall thickness must be expected, the criticality of surface breaking flaws shall be assessed and an appro- Mk is applied to welded connections. This increases the stress intensity factor to account for the presence of the priate Mk shall be applied. weld toe. It is normally acceptable to exclude the Mk fac- — If the difference in yield stress between adjacent pipes tor for pipeline girth welds if εl,nom is exceeding 0.4% pro- exceeds 100 MPa, see Sec.7, I303, or the wall thickness

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tolerances specified in Sec.7, Table 7-17 to Table 7-19, are limit (referred as Lr cut-off or Lr,max) for the Lr (Lr = σref/YS) not fulfilled, non-linear FE analyses shall be performed, axis must be defined. either to determine correct applied stresses or to perform a In cases with large plastic strain, the maximum allowable flaw Level 3C (3D FE fracture mechanics) assessment. sizes are often strongly dependant on the Lr cut-off value. — The relation between strains, concentrations, residual Hence, this value should be chosen carefully. stresses and applied stresses is complex. Hence, the applied stress in the ECA may alternatively be calculated It is recommended that the Lr cut-off is calculated directly by non-linear FE analysis (without a crack) considering from the SENT tests for the correct material condition. the nominal design strain, relevant geometry and material The Lr cut-off value, corresponding to the recorded maximum properties. The stress distribution across the girth weld is loads and the net-section area is as follows: defined as accurately as possible using the combination of P Pm and Pb, see BS 7910. In such cases, identical material L = max tensile properties shall be applied to the FE analyses and r.max YS⋅B(W −a ) to the ECA’s. 0 — For lined and clad pipelines, the applied stresses shall be where defined based on such FE analysis. Alternatively a Level 3 assessment may be performed or other well documented Pmax = minimum value of the maximum load from procedures agreed by all parties. the SENT test programme — Weld residual stresses shall be assumed for girth welds in B, W and a0 = dimensions associated with the relevant the as-welded condition. Normally the weld residual stress SENT specimen (see Figure 1). a0 is the shall be defined as a uniform secondary membrane stress, original crack height Qm, equal to the lowest yield stress of the weld metal and the parent pipe material. In case of PWHT or high applied Alternatively, if SENT test data is not available, it is acceptable strain it is acceptable to reduce the weld residual stress for strain-based assessment to define the Lr cut-off value as according to BS 7910. UTS/YS, where UTS is the engineering tensile stress and YS is the yield stress of the parent pipe for the correct material Recent research has shown that the combination of internal condition, see Subsection G. over-pressure and longitudinal loading may be more onerous than longitudinal loading alone. However, there is currently no 209 The J R-curves (or CTOD R-curves) to be used in a validated and generally accepted procedure for assessing the Level 3B assessment according to this Appendix shall be a combined loading and each case shall be evaluated separately lower bound to all J-Δa test data. It is not acceptable for exper- and the procedure accepted by all parties. imentally derived J-Δa points to be lower than the J R-curve applied in the assessment. The research results indicate that the reduction in strain capac- ity is caused by and increase in the crack driving force (applied 210 The maximum tearing permitted during the whole instal- J or applied CTOD) but that the material fracture toughness is lation process should not exceed 1 mm. However, the tearing not influenced. This means that if the crack driving force is must not exceed the maximum tearing measured in the SENT determined from dedicated 3D FEA or well documented and specimens. validated research results it is acceptable to use SENT testing 211 If a Level 2B assessment is performed (no fracture to determine the fracture resistance also for the combination of toughness resistance curve), the critical J (or CTOD) shall be internal over-pressure and longitudinal loading. chosen according to BS 7910, Annex K, K.2.3.2:

For assessments of situations with longitudinal strains, εl,nom, equal to or less than 0.4% under internal over-pressure is it Number of fracture Equivalent fracture acceptable to apply the procedure specified above to determine toughness results toughness value applied stresses. However, in such cases fracture toughness 3 to 5 Lowest testing shall be performed on SENB specimens to compensate 6 to 10 Second lowest for the under-estimated crack driving force. 11 to 15 Third lowest 207 Determination of the reference stress, σref: All test results shall represent one homogeneous group (iden- It is recommended that the Kastner, see BS 7910 (P.12), solu- tical microstructure and testing conditions etc.) and the tion is used to determine the reference stress (σref) for the requirements of BS 7910 Annex K.2.3 shall be satisfied. The assessment of surface flaws. equivalent fracture toughness values are valid for both SENB For the assessment of embedded flaws, BS 7910 uses a refer- and SENT testing. ence stress solution developed for a flat plate. This is however considered to be too conservative where the critical defect height of the embedded flaw may be predicted to be less than that of a surface breaking flaw of a corresponding length. Nor- F. Girth Welds Assessed mal practice is to assess the critical flaw height of a surface According to ECA Fatigue breaking flaw and to regard the results as valid for embedded flaws of the same length, i.e. the height 2a of an embedded F 100 General flaw is equal to the height a of the equivalent surface breaking flaw. 101 If A203 is fulfilled, no further assessments are required. If the embedded flaw is located close to the surface (ligament 102 If allowable defect sizes are determined by ECA in accordance with Subsections C, D or E, or for any other reason height less than half the flaw height) the ligament height are larger than specified in Appendix D, the fatigue life assess- between the flaw and the surface shall be included in the flaw height. ment shall be based on S-N curves validated for the allowable defect sizes (see Sec.5 D808) or assessed based on fracture The use of other, less conservative, reference stress solutions, mechanics in accordance with this Subsection. whether for embedded or surface defects, must be justified and As crack initiation is not included in the fracture mechanics documented. approach, shorter fatigue lives are normally derived from frac- 208 The Failure Assessment Diagram (FAD) cannot be ture mechanics than by S-N data. However, a well defined and extended to arbitrarily large plastic deformations and a cut-off validated procedure for including a possible initiation period in

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 152 – App.A the fracture mechanics fatigue approach does currently not For embedded defects it is acceptable to use air data until the exist, see also 204. crack extends through the ligament and becomes a surface 103 Possible stable crack growth (ductile tearing) and crack when the relevant environmental data shall be used. fatigue crack growth shall be considered in the assessment. Residual stresses shall be included by applying the fatigue The assessment shall confirm that the largest weld defects crack growth curves for R≥0.5. expected to remain after NDT and repair will not increase dur- 203 Fatigue crack growth from possible flaws at the weld ing pipe laying to an extent such that fracture or fatigue failure cap toe shall include an allowance for the increase in stress will occur during operation of the pipeline. intensity factor due to the weld cap geometry as well as any 104 The critical flaw size shall be determined according to local increase of bending due to girth weld misalignment. Subsection D and E as relevant and considered when the For the weld cap stress concentration it is acceptable to fatigue life is determined. The fatigue assessment shall be per- increase the stress intensity factor by the Mk factor according formed using the relevant fatigue loading and fatigue crack to BS 7910 or to use other well documented relevant stress growth law to determine the fatigue life from the initial defect intensity factor solutions. size and until the critical defect size is reached. Guidance note: If satisfactory fatigue life can not be demonstrated or there is a Large surface breaking defects normally do not occur in modern risk of unstable fracture before or at the end of the operational high quality pipeline girth welds. If it can be substantiated that life, either the weld defect acceptance criteria shall be reduced surface breaking defects are not present it is acceptable to assume or actions to reduce the fatigue loading shall be taken. Where the defects to be embedded with ligament height of 3 mm in the fatigue crack growth is predicted to be less than 0.2 mm, it can fracture mechanics based fatigue assessment. be assumed to be negligible. If the actual defect location can be determined it is acceptable to 105 The fatigue assessment shall consider all loading rele- base the integrity assessment on the actual location.

vant to the design case, e.g. vortex induced vibration (VIV), ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- bending stresses due to spanning, and varying longitudinal stresses due to thermal expansion and contraction. 204 If the NDT probability of detection (PoD) and sizing Due to possible residual stresses from welding or plastic defor- error is in accordance with Appendix D and E it is acceptable mation during installation or operation the compressive part of to increase the fatigue damage ratio for the fracture mechanics cyclic stresses may contribute to the fatigue crack growth and based fatigue assessment in accordance with this Subsection to the whole stress range shall be considered in the assessment. double that of an S-N based fatigue assessment as described in Sec.5 D810. 106 It is acceptable to define the fatigue stress distribution through the wall thickness based on FE analyses provided that F 300 Low-cycle fatigue the analyses are well documented. 301 Possible low-cycle fatigue shall be assessed. However, 107 The thickness of the pipe wall shall be defined according there does currently not exist any well defined, validated and to E203, first and second bullet points. In case of life extension generally accepted procedure for the assessment of low-cycle assessments the wall thickness of the pipe shall be reduced by fatigue in pipeline girth welds. the full corrosion allowance. If reliable wall thickness meas- Any method used for assessing low-cycle fatigue shall there- urements are available it is acceptable to base the assessment fore be justified, well documented and agreed by all parties. on such measurements. Guidance note: 108 For lined or clad pipelines, the fatigue life shall be Low-cycle loading is normally understood to be cycles less than assumed equal to the time necessary to grow through the clad/ around 1000 and stress/strain ranges in the elastic-plastic regime. liner thickness. Possible initial weld defects shall be assumed as relevant. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 109 If the NDT probability of detection (PoD) and sizing error is in accordance with Appendix D and E it is acceptable to increase the fatigue damage ratio for the fracture mechanics G. Testing Requirements based fatigue assessment in accordance with this Subsection to double that of an S-N based fatigue assessment as described in G 100 General Sec.5 D810. 101 Fracture toughness testing shall be performed on the F 200 High-cycle fatigue materials and material conditions specified in Table A-11. 201 Fracture mechanics based fatigue assessments in the 102 Tensile testing shall be performed on the materials and high-cycle regime shall be based on BS 7910 or equivalent the material conditions specified in Table A-12. procedures. 103 Mechanical testing, fracture mechanics testing and pre- Guidance note: straining shall be performed according to this Subsection and High-cycle loading is normally understood to be cycles of more Appendix B. than around 1000 and stress ranges in the elastic regime. 104 The extent of fracture mechanics testing and tensile test-

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- ing for the different ECA categories shall be as specified in Table A-1, Table A-5 and Table A-10 respectively. All notch 202 Mean plus two standard deviation fatigue crack growth positions specified in Appendix B shall normally be tested and curves representing the relevant environment shall be used. exceptions must be thoroughly evaluated and documented.

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Table A-11 Required material condition and test temperature fracture toughness testing ECA Category Material condition to be Test temperatures tested ABC

ECA Static - low, εl,nom < 0.4% during both installation and operation As-received Tmin RT Tmax 1) ECA Static - high, εl,nom ≥ 0.4% during installation As-received Tmin RT Tmax 2) ECA Static – high, εl,nom ≥ 0.4% during operation Pre-strained and aged Tmin RT Tmax Assessment temperatures in consideration:

o A Minimum temperature, Tmin < 0 C o o B Minimum temperature, 0 C ≤ Tmin ≤ 50 C for C-Mn and 13Cr pipelines o o B Minimum temperature, 0 C ≤ Tmin ≤ 20 C for 22Cr and 25Cr pipelines C Maximum temperature, Tmax > 50 for C-Mn and 13Cr pipelines C Maximum temperature, Tmax > 20 for 22Cr and 25Cr pipelines 1) If pipelines are installed as illustrated in Figure 9 b), it is acceptable to pre-compress all material prior to testing 2) See G204

Table A-12 Required material condition and test temperature for tensile testing ECA Category Material condition to be Test temperatures tested ABC ECA Static - low, εl,nom < 0.4% during both installation and operation As-received Tmin RT Tmax 1) ECA Static - high, εl,nom ≥ 0.4% during installation As-received Tmin RT Tmax ECA Static – high, εl,nom ≥ 0.4% during operation Pre-strained and aged Tmin RT Tmax Assessment temperatures in consideration: o A Minimum temperature, Tmin < 0 C o o B Minimum temperature, 0 C ≤ Tmin ≤ 50 C for C-Mn and 13Cr pipelines o o B Minimum temperature, 0 C ≤ Tmin ≤ 20 C for 22Cr and 25Cr pipelines C Maximum temperature, Tmax > 50 for C-Mn and 13Cr pipelines C Maximum temperature, Tmax > 20 for 22Cr and 25Cr pipelines 1) If pipelines are installed as illustrated in Figure 9 b), it is acceptable to pre-compress all material prior to testing

Guidance note: where The tensile properties and the shape of the stress-strain curve are important and have a strong effect on the critical flaw dimen- YS = The engineering yield stress at test temperature sions. Experience shows that for strain based assessments the tensile properties are sensitive to test temperature and pre-strain- UTS = The tensile strength at the test temperature ing and ageing history. Conservative values of the critical flaw m = Constraint parameter according to ASTM dimensions are determined using higher yield strengths and low E1290-02 strain hardening. n = The strain-hardening parameter according

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- a = The original crack size 105 For pipeline materials susceptible to environmentally W = The specimen width induced embrittlement the mechanical, fracture toughness and fatigue properties shall reflect the actual environment, see also This is a conservative way of calculating CTOD from J and, A306. If tensile testing, fracture toughness testing and crack hence, it is not acceptable to use the formulas the other way growth testing is performed under representative environmen- around to calculate the J fracture toughness to be used in Sub- tal and loading condition, the assessment procedure described section C and D. in Subsection E and F are applicable. G 200 Straining and ageing 106 The corresponding CTOD fracture toughness can con- servatively be estimated from the J fracture toughness accord- 201 For strain-based ECAs, upper-bound tensile properties ing to the following formulas: with low strain hardening shall be assessed and tested. For stress-based ECAs, lower-bound tensile properties shall be assessed and tested. To achieve this it may be necessary to pre- J strain and age the material prior to testing. Pre-straining and δ = ageing is normally not required for ECA Static considering ⎛ YS +UTS ⎞ m⎜ ⎟ installation, see also 204. ⎝ 2 ⎠ If aging is relevant, artificial ageing at 250°C for one hour shall a a be performed prior to any tensile testing. The ageing shall be m = 1.221+ 0.793 + 2.751n −1.418n W W performed after the pre-straining but before the tests are per- formed. 2 3 ⎛ YS ⎞ ⎛ YS ⎞ ⎛ YS ⎞ n = 1.724 − 6.098⎜ ⎟ + 8.326⎜ ⎟ − 3.965⎜ ⎟ 202 There are three important material mechanisms that ⎝UTS ⎠ ⎝UTS ⎠ ⎝UTS ⎠ must be considered when the pre-straining and aging proce- dure is established. These are:

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 154 – App.A

— The “Bauschinger effect”, as illustrated in Figure 7 ics testing, e.g. the strain increment marked in Figure 9 b). In — Strain hardening, as illustrated in Figure 8 such cases ageing is not required. — Aging. 204 If the ECA includes situations where the pipeline has already been subject to plastic strains, the tensile testing and σ fracture mechanics testing shall be performed on material rep- resenting strained material with ageing if relevant. If it can be documented based on earlier experience that the fracture toughness properties are not reduced because of pre-straining and aging it is acceptable to perform fracture toughness testing in the as-received condition. If the loading situation to be evaluated takes place more than one week after the material was plastically deformed during ε installation or operation, the tensile testing shall be performed on pre-strained and aged material. If the load condition is strain-based, the pre-straining cycling shall end in tension because this will give upper-bound tensile properties and little strain hardening. Figure 7 If the load condition is stress-based, the pre-straining cycling The Baushinger effect is a phenomenon which occurs when mate- shall end in compression because this will give lower-bound rials are strained into the non-linear stress-strain area in one di- tensile properties. rection followed by straining in the opposite direction. The effect of such cycling is that the reversed yield stress is decreased 205 The pre-straining shall simulate one complete strain his- tory (i.e. the whole installation sequence, but not contingency etc.) if ECAs are required for the operational phase. σ H. ECA Validation Testing H 100 General 101 Segment specimen testing or full scale testing shall be performed for the following situations where “ECA static” is ε applicable and more than one strain increments are applied: — Clad or lined pipelines. — C-Mn linepipe materials with SMYS larger than 450 MPa and εl,nom > 1.5%. — 13Cr martensitic steels and εl,nom > 1.5%. Figure 8 — 22Cr and 25Cr duplex stainless steels if ε > 1.5%. Cyclic strain hardening is the effect seen if a material is strained l,nom in one direction followed by unloading before the material is — If maximum total strain, εl,nom exceeds 2.25%. strained in the same direction once more, see Figure 7. The effect of such cycling is that the yield stress is increased and that the 102 The segment testing shall be performed based on the strain-hardening is decreased procedure described in DNV-RP-F108 and Appendix B. The amount of testing and the strain cycles applied shall be agreed. 103 It is recommended that where a segment test is required 203 Figure 9 illustrates the moment/curvature cycles for two the dimensions of the starter flaw should be determined by an different installation methods introducing large plastic strains. ECA tailored to the segment test prior to testing and based on For reeling installation, Figure 9 a), the most critical situation the lower bound fracture toughness curve. The tip of the starter is theoretically reeling-on at 12 o’clock because the tensile flaw should be in the lowest toughness material consistent with properties are represented by the highest stress-strain curve the ECA. The dimensions of the starter flaw should be such with little strain hardening. However, the strain increment may that approximately 0.5 mm of tearing (or as agreed) at the be larger at the 6 o’clock location in the straightener and this deepest point is predicted. Upper bound values of tensile situation shall also be considered. strength consistent with the values used in ECA should be used. If less tearing than estimated in the ECA is measured in For other installation methods, it is important that the whole the segment specimens and the stress capacity is at least as installation sequence is evaluated in order to determine the large as estimated by ECA, the ECA is considered validated. largest strain increment. In some cases it may be acceptable to pre-compress the material prior to tensile and fracture mechan-

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Crack driving force 600 12 o'clock Crack driving force 6 o'clock 500 Aligner 400 300

200

100

0 Reel drum -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5 1.0 1.5 2.0 2.5 Moment -100 Straightener -200 -300

-400

-500

-600 Curvature a) Reeling installation

Crack driving force 12 o'clock over ramp

Crack driving force no. 1, 6 o'clock Crack driving force no. 2, 6 o'clock Aligner Moment Straightener

Bending on vessel

6 o'clock 12 o'clock Curvature b) Installation method introducing large plastic strain increment Figure 9 Examples of installation methods introducing large plastic strain increments

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APPENDIX B MECHANICAL TESTING AND CORROSION TESTING

A. Mechanical Testing and Chemical Analysis Samples and test pieces for welds not performed at pipe mills 207 For welds not performed as part of linepipe fabrication, A 100 General including girth welds, samples shall be taken in accordance 101 This appendix addresses methods for mechanical test- Appendix C Figure 1 and 2. ing, chemical analysis and corrosion testing of materials and products. A 300 Chemical analysis 102 Test laboratories shall meet the requirements of ISO 301 Samples for heat and product analyses shall be taken and 17025, General requirements for the competence of testing prepared in accordance with ISO 14284. Methods and proce- and calibration laboratories, or an accepted equivalent. dures for chemical analysis shall be according to recognised 103 The following standards are referred to in this Appen- industry standards, of acceptable uncertainty. Results from dix: chemical analyses shall be given with the same number of dig- its (or more) as given in the specification of the product and/or —API 5LD in this standard. —API RP 5L3 Guidance note: —ASTM A264 ISO/TR 9769 gives a list of available international standards pro- —ASTM A 956 viding chemical analysis methods, with information on the appli- — ASTM A 1038 cation and precision of the various methods. —ASTM E110 —ASTM E1820 ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- —ASTM G48 Chemical analysis of weld overlay — BS 7448 — BS 7910 302 The chemical composition of the weld overlay shall be — DNV-RP-F108 obtained at the surface of the overlay after machining of the — ISO 148 overlay such that the minimum distance from the surface to the — ISO 377 fusion line is either 3 mm or the minimum thickness specified — ISO 3183 for the finished component, whichever is the lesser. — ISO 4136 — ISO 5173 A 400 Tensile testing — ISO 5178 401 Tensile testing shall be carried out in accordance with — ISO 6507 the requirements in this appendix and ISO 6892 or ASTM — ISO 6892 A370. The test piece configuration and possible test piece flat- — ISO/TR 9769 tening shall be the same for all the delivered items. The exten- — ISO 14284 someter shall be attached to a machined surface. Double sided — ISO 15156 extensometers should be used. — ISO 17025 402 Base material tensile properties may be determined — NACE TM0284 using rectangular or round test pieces at the manufacturers dis- A 200 General requirements to selection and prepara- cretion, see A403 and A404, respectively. tion of samples and test pieces 403 Rectangular test pieces shall represent the full wall 201 Selection of samples and preparation of test pieces shall thickness. Longitudinal/axial test pieces shall not be flat- as far as applicable be in accordance with the general condi- tended. Transverse/tangential test pieces shall be flattened. tions of ISO 377. In addition the following requirements apply. Test piece grip ends may be flattened or machined to fit the test machine's grips. Weld beads may be ground flush and local 202 For any of the mechanical tests, any test piece that shows imperfections may be removed. defective preparation or material imperfections unrelated to the intent of the particular mechanical test, whether observed 404 Round test pieces shall be obtained from non-flattened before or after testing, may be discarded and replaced by samples. For longitudinal/axial tensile tests when t ≥ 19.0 mm, another test piece from the same pipe. such test pieces shall be 12.7 mm in diameter. For transverse or tangential tensile tests the diameter of such test pieces shall Samples and test pieces from linepipe be as given in Table 21 in ISO 3183, except that the next larger 203 For tensile tests, CVN impact tests, DWT tests, guided- diameter may be used at the option of the manufacturer. bend tests, and flattening tests, the samples shall be taken, and 405 For testing when D < 219.1 mm, full-section longitudi- the corresponding test pieces prepared, in accordance with the nal/axial test pieces may be used at the option of the manufac- applicable reference standard. turer. 204 Samples and test pieces for the various test types for 406 If agreed, ring expansion test pieces may be used for the linepipe shall be taken from alternating pipe ends in the loca- determination of transverse yield strength. tions as shown in Figure 5 and Figure 6 in ISO 3183 and as given in Sec.7 Table 7-9, and the details stated below. 407 All weld tensile tests shall be carried out using round test pieces. Samples and test pieces from components 205 Unless otherwise stated the location of samples and test 408 For pipes to be tested according to supplementary pieces from components shall be according to Sec.8 E100. requirement P specimens shall be of proportional type with gauge length of value 5.65 S0 , where S0 is the cross section 206 For induction bends and bolts the location of samples area of the specimen. and test pieces shall be according to the recognised standard or specification used for manufacture, as specified for the rele- Transverse weld (cross weld) tensile test vant component in Sec.8. 409 Test pieces shall be rectangular and in accordance with

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A403. The weld reinforcement shall be removed on the face pieces shall be sampled in the positions given in Figure 3 to and root sides by machining or grinding. The tensile strength Figure 8, with the notch positions as applicable. FL test pieces shall be determined (yield stress and elongation is not shall always be located such that 50% of weld metal and 50% required). of HAZ is sampled. 410 Transverse weld tensile test pieces of clad or lined line- 511 Impact testing of clad/lined pipes shall be performed in pipe shall be performed on the full thickness of the carbon the carbon steel portion of the material. steel, after removal of the CRA, taking care not to reduce the 512 When dissimilar materials are welded, both sides of the C-Mn steel wall thickness. weld shall be tested. All-weld tensile testing of load bearing weld overlay 513 For weld overlay material contributing to the transfer of 411 Test pieces shall be round with maximum obtainable load across the base material/weld overlay fusion line, impact diameter. The test pieces shall be machined from the weld testing of the weld overlay and HAZ shall be performed (i.e. overlay transverse to the welding direction. when the overlay is a part of a butt joint or acts as a transition Transverse all-weld tensile test for girth welds between a corrosion resistant alloy and a carbon steel). The longitudinal axis of the specimen shall be perpendicular to the 412 The geometry of the test pieces shall be according to fusion line and the notch parallel to the fusion line. Figure 13. The test requires that the width of the weld is at least 6 mm. The test pieces shall be round with maximum obtainable A 600 Bend testing diameter and be instrumented with strain gauges on the Guided-bend testing of the seam weld of welded pipe reduced section representing the weld metal. 601 The test pieces shall be prepared in accordance with ISO A 500 Charpy V-notch impact testing 7438 or ASTM A370, and Figure 8 in ISO 3183. 501 The test pieces shall be prepared in accordance with ISO 602 For pipe with t > 19.0 mm, the test pieces may be 148-1 without any prior flattening of the material. Testing machined to provide a rectangular cross-section having a according to ASTM A370 is acceptable if agreed. Each set thickness of 18.0 mm. For pipe with t ≤ 19.0 mm, the test shall consist of three specimens taken from the same test cou- pieces shall be full wall thickness curved-section test pieces. pon. Full size test pieces shall be used whenever possible. 603 For SAW pipes, the weld reinforcement shall be 502 The size, orientation, and source of the test pieces from removed from both faces. linepipe shall be as given in Table 22 in ISO 3183, except that the next smaller test piece size may be used if the absorbed 604 The guided-bend test shall be carried out in accordance energy is expected to exceed 80% of the full-scale capacity of with ISO 7438. The mandrel dimension shall not be larger than the impact testing machine. Additional sets of HAZ test pieces that determined using the following equation, with the result shall be sampled compared to ISO 3183, see Table 7-7 and rounded to the nearest 1 mm: Table 7-8 in Sec.7. The notch locations shall be according to 1.15(D − 2t) A508-513. A = − t gb D Guidance note: (e − 2e −1) It is not necessary to impact-test linepipe with combinations of t specified outside diameter and specified wall thickness not cov- ered by Table 22 in ISO 3183. where: Agb is the mandrel dimension, expressed in millimetres ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- (inches) 503 During MPQT, for seamless pipe with t > 25 mm and D is the specified outside diameter, expressed in millime- delivered in the quenched and tempered condition, one set of tres (inches) transverse direction CNV test pieces shall be sampled 2 mm t is the specified wall thickness, expressed in millimetres above the internal surface. (inches) e is the strain, as given in Table 23 of ISO 3183 504 The locations of test pieces taken from components shall 1.15 is the peaking factor. be according to Sec.8 E100. 605 Both test pieces shall be bent 180° in a jig as shown in 505 The locations of test pieces taken from girth welds shall Figure 9 in ISO 3183. One test piece shall have the root of the be according to Appendix C Figure 1 and Figure 2. weld directly in contact with the mandrel; the other test piece 506 The test pieces shall be sampled 2 mm below the exter- shall have the face of the weld directly in contact with the man- nal surface, except for testing of the root of double sided welds. drel. A smaller distance than 2 mm shall be used if necessary (due Bend testing of clad linepipe to the dimensions of the material) to make specimens with the largest possible cross section. The axis of the notch shall be 606 Weld clad or roll bonded clad pipe shall be subjected to perpendicular to the surface. bend testing (the longitudinal weldment shall not be included). Specimens shall be of full thickness, including the full thick- 507 For weld metal and HAZ tests, each test piece shall be ness of the clad layer. The width of the specimens shall be etched prior to notching in order to enable proper placement of approximately 25 mm. The edges may be rounded to a radius the notch. of 1/10 of the thickness. Notch positioning for weld metal test pieces The specimens shall be bent 180° around a former with a diam- 508 For production welds other than HFW pipe the axis of eter 5x the pipe wall thickness. the notch of the weld metal sample shall be located on, or as 607 Longitudinal weld root bend test shall include the corro- close as practical to, the centreline of the outside weld bead. sion resistant alloy. 509 For test pieces taken in the weld of HFW pipe, the axis of the notch shall be located on, or as close as practical to the — The longitudinal axis of the weld shall be parallel to the weld line. specimen, which is bent so that the root surface is in ten- sion. Notch positioning for HAZ test pieces — The width of the longitudinal root bend specimen shall be 510 The HAZ notch positions comprise the fusion line (FL) at least twice the width of the internal weld reinforcement test pieces, the FL+2 mm test pieces and the FL+5 mm Test or maximum 25 mm. The edges may be rounded to a

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 158 – App.B

radius of 1/10 of the thickness. 802 Full thickness specimens shall be used where possible. — The internal and external weld reinforcement shall be Reduced thickness specimens may be used subject to Pur- removed flush with the original surfaces. chaser agreement. If reduced thickness specimens are used, — The thickness of the specimen shall be equal to the base both surfaces shall be equally machined to the thickness of material thickness or a maximum of 10 mm, as shown in 19.0 mm. The testing temperature reduction given in API RP Figure 2. 5L3 shall apply. — The specimen shall be bent to an angle of 180° using a The specimens shall be taken transverse to the rolling direction former with diameter 90 mm. or pipe axis, with the notch perpendicular to the surface. Bend testing for WPQT according to Appendix C For high toughness steels ductile crack initiation from the notch tip shall be acceptable (contrary to API RP 5L3, 608 Bend testing shall be performed in accordance with ISO Clause 7.1). 5173. Bend test specimens shall have full wall thickness. The width of root and face bend specimens shall be approximately A 900 Fracture toughness testing 25 mm. The width of side bend specimens shall be 10 mm. The edges may be rounded to a radius of 1/10 of the thickness. 901 For qualification testing of linepipe weld metal, see 904 and 913 to 916: 609 Bend test of clad pipes shall be performed on full thick- ness of the pipe, including the corrosion resistant alloy. — for qualification testing of girth welds, see 917 to 920. 610 The weld reinforcement on both faces shall be removed 902 The fracture toughness testing applicable to this Stand- flush with the original surfaces, as shown in Figure 1. The weld ard is: shall be located in the centre of each specimen. 611 The specimens shall be bent to an angle of 180° using a — Fracture toughness testing, J or CTOD (δ), a minimum of former with diameter depending on the specified minimum 3 specimens is required for each notch position. yield stress SMYS for the parent material. For materials with — Fracture toughness resistance curve testing, J-Δa (J R- SMYS up to 360 MPa, the former diameter shall be 4x thick- curve) or δ-Δa (δ R-curve), a minimum of 6 specimens is ness of the test specimen. For materials with SMYS equal to or required for each notch position. exceeding 415 MPa, the former diameter shall be 5x thickness 903 Unless otherwise agreed fracture toughness testing shall of the test specimen. be performed using one of the following type of specimens: 612 If necessary, e.g. if one of the materials to be joined has a lower yield stress than the other, guided bend testing in — Single Edge Notched Tension (SENT), or accordance with ISO 5173 may be applied, using the same — Single Edge Notched Bend (SENB) specimen roller diameter as for the conventional bend testing. Pipeline walls are predominately loaded in tension independ- 613 After bending, the welded joint shall be completely ent of the loading mode. The recommended specimen for such within the tensioned region. conditions is the SENT specimen, as shown in Figure 12. Refer Bend testing of weld overlay also to DNV-RP-F108 for further guidance. 614 Side bend test specimens shall be used. The test speci- Guidance note: mens shall be sampled perpendicular to the welding direction. Commonly used testing standards, e.g. BS 7448 and ASTM E1820, describe methods for determining the fracture resistance — For pipes, the test specimens shall sample the full thick- from deeply notched SENB (Single Edge Notched Bend) or CT ness of the weld overlay and the base material. For heavy (Compact Tension) specimens. These specimens, both predomi- nantly loaded in bending, have high crack tip constraint and will section components, the thickness of the base material in hence give lower bound estimates for the fracture resistance that the specimen shall be at least equal to 5x the thickness of can be used for conservative fracture assessments for a large the overlay. range of engineering structures. The SENB specimen can also be — The thickness of side bend specimens shall be 10 mm. The used but this is likely to result in unnecessarily conservative frac- edges may be rounded to a radius of 1/10 of the thickness. ture toughness.

The central portion of the bend test specimen shall include ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- an overlap area. — The specimens shall be bent to an angle of 180°. For base 904 Fracture toughness testing as required in Sec.7 for weld materials with SMYS up to 415 MPa the former diameter metal shall be CTOD testing of SENB specimens. shall be 4x thickness of the test specimen. For base mate- rials with SMYS equal to or exceeding 415 MPa the 905 Other test specimen configurations may be used for former diameter shall be 5x thickness of the test specimen. deriving the fracture toughness for use in an ECA provided that the fracture toughness can be derived from experimental meas- A 700 Flattening test urement, e.g. load vs. clip gauge displacement and that it is jus- tified that the crack tip constraint of the test specimen is not 701 The test pieces shall be taken in accordance with ISO smaller than for the most severe pipeline weld defect assessed 8492, except that the length of each test piece shall be ≥ 60 in the ECA. mm. Minor surface imperfections may be removed by grind- ing. 906 Testing of SENB specimens shall be carried out in gen- eral compliance with the latest revisions of the relevant parts 702 The flattening test shall be carried out in accordance of BS 7448 or an equivalent standard. with ISO 8492. As shown in Figure 6 in ISO 3183, one of the two test pieces taken from both end-of-coil locations shall be All SENT testing shall be performed in accordance with DNV- tested with the weld at the 6 or 12 o’clock position, whereas the RP-F108. remaining two test pieces shall be tested at the 3 or 9 o’clock 907 Post-test metallography shall be applied to the speci- position. Test pieces taken from crop ends at weld stops shall mens designated for FL/HAZ testing in order to establish if the be tested at the 3 or 9 o’clock position only. crack tip has been successfully located in the target microstruc- ture. A 800 Drop weight tear test The specimen is considered qualified if: 801 Drop weight tear test shall be carried out in accordance with API RP 5L3. — the pre-crack tip is not more than 0.5 mm from fusion line

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.B – Page 159

— grain coarsened heat affected zone (GCHAZ) micro-struc- 915 The number of valid CTOD or J tests for each location ture is present within a region confined by a plane perpen- shall be minimum 3. The characteristic CTOD or critical J dicular to the crack plane through the crack tip and a value shall be taken as the lowest from 3 valid tests or selected parallel plane 0.5 mm ahead of the crack tip. in accordance with BS 7910. Only specimens that are qualified with respect to crack tip location by post-test metallographic Relevant for testing of SENB specimens examination shall be considered valid. 908 Testing of SENB specimens are acceptable, see 903, 916 If fracture toughness testing of the FL/HAZ of the seam also with reduced notch length. However, for use in an ECA weld is performed, surface notched specimens shall be tested. the specimen notch length shall not be chosen shorter than the It is acceptable to test SENT specimens. It is important that the height of the most severe weld defect assessed in the ECA. weld metal is not mechanically deformed during fabrication of The fracture toughness for SENB test specimens can be specimens. For SENB specimens the instructions specified in derived from the load vs. clip gauge displacement record BS 7448-2 shall be followed. For SENT specimens it is nor- according to the following formulae: mally required to cut out the seam weld and at least 10 mm of the parent pipe on each side of the seam weld. Extensions are butt welded until required specimen length before the speci- men is finally machined to a SENT specimen. Validation of the crack tip shall be performed, see A907. Qualification of girth welds (ECA) 917 The recommended specimen for fracture toughness test- ing of girth welds is the SENT (Single Edge Notched Tension) specimen. The calculation and performance of SENT testing where Ap is the area under the load vs. crack mouth displace- shall be according to DNV-RP-F108. ment (CMOD) curve. For definitions of the other parameters it 918 The SENT specimens shall be designed with a Surface is referred to BS 7448. Notch (SN), since this is the relevant orientation for defects in 909 If the total displacement, Vg, is measured at a distance the welds. The notch may be introduced either from the outer z ≤ 0.2a from the physical crack mouth then the CMOD can be surface or from the inner surface. calculated from: 919 The notch positions and welding procedures to be tested shall be agreed. Typically the main line procedure(s), the through thickness procedure(s) and the partial repair proce- dure(s) shall be tested as illustrated in Figure 9 and specified in Appendix A Tables A-1, A-5 and A-7 as relevant. Guidance note: It is recommended that the FL/HAZ is notched from the outer 910 The CTOD-value, δ, can be calculated from J according surface. Such notching is empirically more successful because Appendix A, G106. the crack growth tends to grow towards the base material. Hence, Reporting of fracture toughness testing: a crack tip at the FL boundary is typically growing through the HAZ if it is notched from the outer surface.

911 The following information shall be reported from J/ CTOD testing: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — load vs. crack mouth opening displacement curves of all tests 920 For situations involving plastic deformation and possi- bility of unstable fracture caused by tearing, crack resistance — crack measurements (a0) —j or δ results curve testing (preferably J R-curve) shall be performed of the — test temperature girth weld. If the SENT specimen is tested, which is recom- — material condition (possible pre-straining and aging his- mended, the testing shall be in accordance with DNV-RP- tory) F108. — welding procedure and weld metal designation 921 If segment testing is required, see Appendix A, H101, — parent pipe designation. testing shall be performed based on DNV-RP-F108. The amount of testing and test procedure shall be adjusted to the 912 The following information shall be reported from J R- loading considered. curve or δ R- curve testing: A 1000 Specific tests for clad and lined linepipe — load vs. crack mouth opening displacement curves of all tests 1001 Shear testing shall be performed in accordance with — crack measurements (a0 and Δa) —J-Δa or δ-Δa results ASTM A264 (Standard Specification for Stainless Chromium- — test temperature Nickel Steel-Clad Plate, Sheet and Strip). — material condition (possible pre-straining and aging history) 1002 Gripping force of lined pipe shall be measured by the — welding procedure and weld metal designation residual compressive stress test, in accordance with Clause 7.3 — parent pipe designation. b of API 5LD. Fracture toughness testing of linepipe A 1100 Metallographic examination and hardness testing 913 The following applies to fracture toughness testing of Macro examination linepipe as required during MPQT: 1101 Macro examination shall be performed at 5X to 10X δ fracture toughness testing of the weld metal shall be per- magnifications (for HFW the examination shall be performed formed using SENB specimens. at minimum 40X and be documented at least 20X magnifica- tion). Macro examination shall be conducted on specimens 914 Testing shall be conducted on through thickness notched given in Figures 10 and 11, as applicable. The macro section specimens with the specimen orientated transverse to the weld shall include the whole weld deposit and in addition include at direction (The corresponding notation used by BS 7448 is NP). least 15 mm of base material on each side measured from any The notch shall be located in the weld metal centre line. point of the fusion line. The macro-section shall be prepared by

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 160 – App.B grinding, polishing, and etched on one side to clearly reveal the A 1200 Straining and ageing fusion line and HAZ. Ageing test The macro examination of weld overlay shall be sampled 1201 This test is applicable if the cold forming during pipe transverse to the welding direction. The width of the macro manufacture of C-Mn and clad/lined steels exceeds 5% strain section shall be minimum 40 mm. The face exposed by sec- and for Supplementary requirement F. This test does not apply tioning shall be prepared by grinding, polishing and etched by to linepipe delivered with a final heat treatment (e.g. normalis- a suitable etchant to clearly reveal the weld and heat affected ing or quench and tempering). zone. A test coupon shall be machined from the pipe material and Microstructure examination aged at 250°C for one hour. Thereafter, the specified number 1102 Samples for optical metallography shall be prepared of Charpy V-notch specimens shall be machined from the mid- using standard procedures, and further etched using a suitable dle of the coupon. The orientation of the specimens shall be etchant in order to reveal the microstructure. longitudinal to the coupon centreline, with the notch perpen- dicular to the surface of the test coupon. Micro examination of duplex stainless steels shall be per- formed and documented at a minimum magnification of 400X. Pre-straining and ageing of materials 1202 Pre-straining is applicable to: The ferrite content of the base material and weld metal shall be measured according to ASTM E562. — Linepipe material to be qualified in accordance with Sup- Hardness testing plementary requirement P. — Girth welds to be qualified in accordance with 1103 Hardness testing of base material and weld cross-sec- Appendix A (ECA). tion samples shall be carried out using the Vickers HV10 method according to ISO 6507-1. 1203 Pre-straining can be carried out as full scale (reversed) bending of whole pipes sections or as tension/compression 1104 For pipe base material tests, individual hardness read- straining of material cut from the pipe wall. ings exceeding the applicable acceptance limit may be consid- ered acceptable if the average of a minimum of three and 1204 When full scale bending is applied whole pipes sec- maximum of six additional readings taken within close prox- tions they shall be instrumented with strain gauges on the out- imity does not exceed the applicable acceptance limit and if no side of the pipe wall in the 12 and 6 o'clock positions, see such individual reading exceeds the acceptance limit by more Figure 14 a). A sufficient number of strain gauges shall be fit- than 10 HV10 units. ted along the length of the test section to ensure an efficient monitoring of the strain along the whole test section. 1105 Hardness test locations for SMLS pipe shall be as shown in Figure 10 a), except that: 1205 When pre-straining cut material such material shall be fitted with strain gauges on each of the opposite sides with —when t < 4.0 mm, it is only necessary to carry out the mid- respect to the smallest measure on the cross section, see thickness traverse Figure 14 b). A sufficient number of strain gauges shall be fit- — for pipe with 4.0 mm ≤ t < 6 mm, it is only necessary to ted along the length of the test section to ensure an efficient carry out the inside and outside surface traverses. monitoring of the strain along the whole test section. If the test machine is not sufficiently rigid, strain gauges shall also be fit- 1106 Hardness testing of welds shall be performed on the ted either sides along the long cross section. specimens used for macro examination, and as shown in Fig- 1206 The strain gauges shall be logged with sufficient fre- ures 10 b) and c), and Figure 11. quency during the straining cycle to ensure efficient monitor- 1107 For SAW, HFW and MWP the following applies: ing of the cycle. 1207 The pre-straining shall be carried out in such a way that — for pipe with t < 4.0 mm, it is only necessary to carry out the characteristic strain (see below) does not deviate by more the mid-thickness traverse than ±0.10% of units of strain from the specified cycle when — for pipe with 4.0 mm ≤ t < 6 mm, it is only necessary to measured at the corners of the pre-straining cycle where the carry out the inside and outside surface traverses. strain rate changes sign. 1208 The characteristic strain shall for cut material be 1108 In the weld metal of SAW and MWP welds, a mini- defined as the mean value of the strains measured on the out- mum of 3 indentations equally spaced along each traverse shall side and inside of the pipe wall for pre-straining material be made. In the HAZ, indentations shall be made along the encompassing the full pipe wall thickness. See Figure 14 b). traverses for each 0.5 - 1.0 mm (as close as possible but pro- For pre-straining material not encompassing the full pipe wall vided indentation is made into unaffected material, and starting thickness the average strain shall be defined as the mean value as close to the fusion line as possible according to Figure 10 b). of the strains measured on the two opposite sides of the mate- 1109 Hardness testing of clad/lined pipes shall have one rial of the smallest thickness. For full scale bending of spool additional hardness traverse located in the thickness centre of pieces the characteristic strain is defined as the strain measured the CRA material. See Figure 11. on the outside of the pipe wall. 1110 For hardness testing of weld overlay hardness testing 1209 The difference between the average strain and each shall be performed at a minimum of 3 test locations: in the base strain gauge shall not exceed ±20% of the specified strain material, in the HAZ and in each layer of overlay up to a max- when measured at the corners of the pre-straining cycle where imum of 2 layers. the strain rate changes sign. If the difference is larger, the full straining cycle as measured on each strain gauge shall be Surface hardness testing reported and it shall be ensured that test pieces fabricated are 1111 Surface hardness testing, e.g. of suspected hard spots fabricated from pre-strained material that complies with the detected by visual inspection, shall be carried out in accord- requirement to the straining cycle. If this is not possible addi- ance with ISO 6506, ISO 6507, ISO 6508, or ASTM A370 tional material shall be pre-strained or acceptance from the cli- using portable hardness test equipment. Depending on the ent be obtained. method used the equipment shall comply with ASTM A956, 1210 After straining for Supplementary requirement P, the ASTM A1038 or ASTM E110. samples shall be artificially aged at 250°C for one hour before

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.B – Page 161 testing. Regarding artificial ageing for ECA, see Appendix A where one of the surfaces is representing the inside of the pipe. G200. 206 Rolled surfaces shall be tested "as-received", i.e. with- A 1300 Testing of pin brazings and aluminothermic out mechanical preparation. The root and the cap side of the welds welds are only to be prepared with the intention of removing "loose material" that will interfere with weighing prior to and Copper penetration after testing. Cut faces shall be ground (500 grid) and sharp 1301 2 test specimens shall the sectioned transverse to the edges smoothed off. The specimen shall subsequently be pick- anode lead and 2 test specimens parallel with the anode lead. led to reduce the susceptibility of cut surfaces to end-grain The specimens shall be prepared and etched for metallographic attack. For duplex stainless steels and austenitic grades with examination. The examination shall be performed at a magni- PRE > 30, 20% nitric acid + 5% hydrofluoric acid, 5 minutes fication of 50X. The fusion line of the weld/brazing shall at any at 60°C is adequate. point not be more than 1.0 mm below the base material surface. 207 The test solution shall be prepared according to the ref- Intergranular copper penetration of the base material shall not erenced standard. at any point extend beyond 0.5 mm from the fusion line. Corrosion testing of weld overlay Hardness 208 Specimens for corrosion testing of the weld overlay 1302 HV10 hardness tests shall be made on each of the spec- shall be machined from the base material side. The remaining imens for copper penetration measurements. A traverse shall surface of the specimen shall be representative for the weld be made across the weld/brazing zone. The traverse shall con- overlay at the minimum distance from the fusion line (equal to sist of minimum 6 indentations; two in the heat affected zone 3 mm or the minimum weld overlay thickness specified for the (HAZ) on each side of the weld/brazing, two in the HAZ under finished machined component, whichever is the lesser). The the weld/brazing and two in the base material on each side of opposite surface of the specimen shall be machined such that the weld/brazing. The HAZ indentations shall be made as close the thickness of the specimen is 2 mm. The size of the speci- to the fusion line as possible. men shall be 25 × 25 mm in length and width. 1303 The maximum hardness shall not exceed the limits given in Appendix C as applicable for the intended service and B 300 Hydrogen Induced Cracking test type of material. 301 Testing for Hydrogen Induced Cracking (HIC), also Pull test referred to as StepWise Cracking (SWC), as defined in ISO 15156 is applicable to rolled C-Mn steel linepipe and pipeline 1304 The test specimen shall be mounted in a tensile testing components. Testing shall be according to ISO 15156-2, B.5 machine and secured in the cable in one end and the base mate- (referring to NACE TM0284 "Evaluation of Pipeline Steels for rial in the other end. Force shall be applied until the specimen Resistance to Stepwise Cracking II). breaks. The specimen shall break in the cable. 302 Unless otherwise agreed tests shall be conducted in a medium complying with NACE TM0284, Solution A. If agreed, tests may be conducted: B. Corrosion Testing — in an alternative medium (see ISO 15156-2:2003, Table B 100 General B.3) including NACE TM 0284 Solution B 101 For certain material and fluid combinations where — with a partial pressure of H2S appropriate to the intended improper manufacture or fabrication can cause susceptibility application to corrosion related damage, the need for corrosion testing dur- — with acceptance criteria that are equal to or more stringent ing qualification and/or production of materials shall be than those specified in Sec.7 I110. assessed. Certain corrosion tests are further applicable to ver- ify adequate microstructure affecting toughness in addition to Values of crack length ratio, crack thickness ratio, and crack corrosion resistance. This subsection describes test require- sensitivity ratio shall be reported. If agreed, photographs of ments and methods for corrosion testing. any reportable crack shall be provided with the report. B 200 Pitting corrosion test B 400 Sulphide Stress Cracking test 201 This test is applicable to verify CRAs’ resistance to pit- Qualification of new materials ting and crevice corrosion by oxidising and chloride contain- 401 For qualification of new materials (i.e. not listed for sour ing fluids, e.g. raw seawater and other water containing fluids service in ISO 15156-2/3), testing shall be conducted on spec- (including treated seawater) with high residual contents of imens from at least 3 heats of material. Qualification testing oxygen and/or active chlorine. For duplex stainless steels, this shall include testing of simulated girth welds and for welded test is further applicable to verify adequate microstructure after pipe also seam welds, in addition to longitudinal samples of the manufacturing or fabrication (see B101). base material. Specimen preparation, testing procedures and 202 Testing shall be carried out according to ASTM G48 acceptance criteria shall comply with ISO 15156, using tripli- "Standard Test Methods for Pitting and Crevice Corrosion cate specimens for each testing condition (i.e. heat of material Resistance of Stainless steels and Related Alloys by the Use of and environment). Ferric Chloride solutions", Method A. 402 Materials listed for sour service in ISO 15156 but not 203 Location of specimens is given in Appendix C, Figures meeting the requirements in Sec.7 I100, (e.g. maximum hard- 1 and 2. ness or contents of alloying or impurity elements) may be qual- 204 The minimum recommended size of test specimens is 25 ified by testing for resistance to Sulphide Stress Cracking mm wide by 50 mm long by full material thickness (except as (SSC) as specified in B401, except that testing shall be carried allowed by 205). For welds, at least 15 mm of the base material out on material representing the worst case conditions to be on each side of the weld shall be included in the test specimen. qualified (e.g. max. hardness or max. sulphur content). 205 Test specimens from clad/lined pipe shall be machined Qualification of pipe manufacturing to remove the carbon steel portion and are to contain the full 403 As an option to Purchaser, SSC testing may be carried weld and any heat affected zone in the corrosion resistant out for qualification of pipe manufacturing. One longitudinal alloy. The specimen thickness shall as a minimum be 1 mm base material sample shall be taken from each test pipe.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 162 – App.B

404 For welded linepipe, testing shall include one additional sample transverse to the weld direction (samples W or WS according to Figure 5 in ISO 3183) and shall contain a section of the longitudinal or helical seam weld at its centre. 405 Three test pieces shall be taken from each sample. Unless otherwise agreed, test pieces for four-point bending SSC tests shall be ≥ 115 mm long × 15 mm wide × 5 mm thick. Samples may be flattened prior to machining test pieces from the inside surface of the pipe. 406 Unless otherwise agreed tests shall be performed in accordance with NACE TM0177, using Test Solution A. A four-point bend test piece in accordance with ISO 7539-2 shall be used and the test duration shall be 720 h. The test pieces shall be stressed to a fraction of SMYS appropriate for the pipeline design, see Table 13-3, however minimum 72% of the material SMYS.

— The "FL" specimen shall sample 50% WM and 50% HAZ W — The "FL+5 mm" sample is applicable to WPQT only. l ≥ 200 mm W Figure 3 t Charpy V-notch impact testing specimen positions for single sid- ed welds with t ≤ 25 mm t = Specimen thickness, t = 10 mm. r ≤ 0.1 t. max. 3.0 mm W = Width of specimen = Base material thickness (all edges) The weld reinforcement is to be machined / ground flush with the base material a) SIDE BEND TEST SPECIMEN (Pl./pipe mat. thickness t ≥ 20 mm.

t l ≥ 200 mm r ≤ 0.1 t. max. 3.0 mm (all edges)

W t t = Specimen thickness = Base material thickness. W = Width of specimen, W = 1.5 t, min. 20 mm The weld reinforcement is to be machined / ground flush with the base material

b) FACE/ROOT BEND TEST SPECIMEN (Pl./pipe mat. thickness t < 20 mm.

Figure 1 Bend test specimens

T t l ≥ 200 mm r ≤ 0.1 t. max. 3.0 mm (all edges) — The "FL" specimen shall sample 50% WM and 50% HAZ W — The "FL+ 5 mm" sample is applicable to WPQT only. t t = Specimen thickness = 10 mm Figure 4 W = Width of specimen = 30 mm Charpy V-notch impact test specimen positions for single sided T = Base material thickness The weld reinforcement is to be machined / ground welds with t > 25 mm flush with the base material Figure 2 Longitudinal root bend test specimens

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.B – Page 163

— The specimens indicated in the root area are only applica- ble when t > 25 mm) — The "FL" specimen shall sample 50% WM and 50% HAZ — The "FL+5 mm" samples are applicable to WPQT only — The "FL" specimen shall sample 50% WM and 50% HAZ (not at pipe mill). — The "FL+5 mm" sample is applicable to WPQT only. Figure 5 Figure 7 Charpy V-notch impact test specimen positions for double sided Charpy V-notch impact test specimen positions for full thickness welds repair welding of narrow gap welds

— The specimens indicated in the root area are only applica- ble when t > 25 mm). — The "FL" specimen shall sample 50% WM and 50% HAZ Figure 6 — The "FL+5 mm" sample is applicable to WPQT only. Charpy V-notch impact test specimen positions for HF welds Figure 8 Charpy V-notch impact test specimen positions for partial thick- ness repair welding

Figure 9 Illustration of typical notch positions for fracture toughness testing of girth welds

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 164 – App.B

P B

Gripped area

W

'Day-light' between grips, H H = 10W a

Gripped area

P

Figure 12 The clamped SENT (Single Edge Notched Tension) specimen Figure 10 Hardness locations in a) seamless pipes, b) HFW pipe, and c) fusion welded joints.

p

Figure 13 Tensile specimen for determination of stress/strain curves of weld p metals in the weld transverse direction

p = 1.5 mm ± 0.5 CENTRE OF CLAD Figure 11 Hardness locations clad materials Strain gauges

Strain gauges

a) b)

Figure 14 Instrumentation of pipe section of samples for pre-straining of materials

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.C – Page 165

APPENDIX C WELDING

A. Application A 300 Definitions 301 The following definitions are used in this appendix: A 100 General 101 This appendix applies to all fabrication involving shop- Welder: Person who performs the welding. , site- or field welding including post weld heat treatment. Manual Welder who holds and manipulates the elec- Welding of longitudinal welds in pipe mills is covered in welder: trode holder, welding gun, torch or blowpipe Sec.7. by hand. 102 The base materials covered by this appendix are: Welding Welder who operates welding equipment operator: with partly mechanised relative movement — C-Mn and low alloy steels between the electrode holder, welding gun, — corrosion resistant alloys (CRA) including ferritic auste- torch or blowpipe and the work piece. nitic (duplex) steel, austenitic stainless steels, martensitic Manual Welding where the welding parameters and stainless steels (13Cr), other stainless steels and nickel welding: torch guidance are controlled by the welder. based alloys Partly- Welding where the welding parameters and — clad/lined steel. mechanised torch guidance are controlled by the welder, welding: but where the equipment incorporates wire The base material requirements are specified in Sec.7 and feeding. Sec.8. Mechanised Welding where the welding parameters and welding: torch guidance are fully controlled mechani- A 200 Welding processes cally or electronically but where minor man- ual adjustments can be performed during 201 Welding may be performed with the following processes welding to maintain the required welding unless otherwise specified: conditions. — Shielded Metal Arc Welding, SMAW (Process ISO 4063- Automatic Welding where the welding parameters and 111) welding: torch guidance are fully controlled mechani- — Flux Cored Arc Welding with active gas shield, G-FCAW cally or electronically and where manual adjustment of welding variables during weld- (Process ISO 4063-136) ing is not possible and where the task of the — Flux Cored Arc Welding with inert gas shield, G-FCAW welding operator is limited to preset, start and (Process ISO 4063-137) stop the welding operation. — Gas Metal Arc Welding with inert gas shield, GMAW (Process ISO 4063-131) A 400 Quality assurance — Gas Metal Arc Welding with active gas shield, GMAW 401 Requirements for quality assurance are given in Sec.2 (Process ISO 4063-135) B500. — Tungsten Inert Gas Arc Welding, GTAW (Process ISO 4063-141) — Submerged Arc Welding, SAW (Process ISO 4063-12) — Plasma arc welding, PAW (Process ISO 4063-15) may be B. Welding Equipment, Tools and Personnel used for specific applications. B 100 Welding equipment and tools Guidance note: 101 Inspection of the workshop, site or vessel prior to start of GMAW and FCAW are regarded as methods with high potential welding shall be required. This shall include verification of for non-fusing type defects. calibration and testing of all tools and welding equipment used

during qualification/production welding. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 102 Welding equipment shall be of a capacity and type suit- 202 The following processes may be used for specific appli- able for the work. The equipment shall be calibrated and main- cations subject to agreement: tained in good working condition. 103 The control software for mechanised and automatic — Laser beam welding, LBW (Process ISO 4063-52) welding systems shall be documented. The name and unique — Electron beam welding, EBW(Process ISO 4063-51) version number of control software and the executable pro- — Electro slag welding gramme in use shall be clearly observable, e.g. on displays — Plasma transferred arc welding, PTA. and/or printouts. 104 All welding equipment shall have a unique marking for 203 Mechanised and automatic welding systems where pre- identification. vious experience is limited, or where the system will be used under new conditions, shall be subject to a more extensive pre- 105 Calibration status and the validity of welding, monitor- qualification programme or documentation before they may be ing and inspection equipment shall be summarised giving ref- used. The extent and the contents of a pre-qualification pro- erence to the type of equipment, calibration certificate and gramme for such mechanised welding systems shall be agreed expiry date. before start up. The Contractor shall prove and document that 106 Welding return cables shall have sufficient cross section the welding systems are reliable and that the process can be area to prevent concentration of current and shall be securely continuously monitored and controlled. attached to prevent arc burns.

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B 200 Personnel ification can be cancelled if the welder/welding operator show 201 All personnel involved in welding related tasks shall inadequate skill, knowledge and performance. have adequate qualifications and understanding of welding 214 When a qualification testing of recent date is transferred technology. The qualification level shall reflect the tasks and to a new project, the welding personnel shall be informed responsibilities of each person in order to obtain the specified about particular project requirements for which their welding quality level. performance will be especially important. Welding co-ordinator Identification of welders 202 The organisation responsible for welding shall nominate 215 Each qualified welder shall be assigned an identifying at least one authorised welding co-ordinator in accordance number, letter or symbol to identify the work of that welder. with ISO 14731 to be present at the location where welding is 216 Qualified welders shall be issued with and be carrying performed. The welding co-ordinator shall have comprehen- an ID card displaying the identifying number, letter or symbol. sive technical knowledge according to ISO 14731, paragraph 6.2. a. 217 The Welding Coordinator shall maintain a list of weld- ers ID stating the qualification range for each welder Welding operators and welders Thermal cutters and air-arc gougers 203 Through training and practise prior to qualification test- ing, the welding personnel shall have a understanding of (see 218 Personnel to perform air-arc gouging shall be trained Annex D of ISO 9606-1): and experienced with the actual equipment. Qualification test- ing may be required. — fundamental welding techniques Operators for pin brazing and aluminothermic welding — welding procedure specifications — relevant methods for non-destructive testing 219 Operators that have performed a qualified procedure test — acceptance criteria. are thereby qualified 220 Other operators shall each complete three test pieces 204 Welding operators performing automatic welding shall made in accordance with the procedure specification prior to be qualified according to EN 1418 or ISO14732. carrying out operation work. Each test piece shall pass the test 205 Welders performing manual, partly-mechanised weld- for electrical resistance and mechanical strength according to ing and mechanised welding shall be qualified for single side Table C-6. butt welds of pipes or plates in the required principal position B 300 Qualification and testing of welding personnel for in accordance with ISO 9606-1, EN 287-1 or other relevant hyperbaric dry welding and recognised standards, for the respective positions, material grades and welding processes. These requirements are also 301 Requirements for qualification and testing of welding applicable for welders performing temporary welds and tack personnel for hyperbaric dry welding are given in subsection I. welds. 206 Welders shall be qualified for single side butt welding of pipes in the required principal position. Welders may be qual- C. Welding Consumables ified for part of the weld, root, fillers or cap by agreement. Repair welders may be qualified for partial thickness repair on C 100 General a representative test configuration provided only such weld repairs are made. 101 Welding consumables shall be suitable for their intended application, giving a weld with the required properties and cor- 207 The qualification test shall be carried out with the same rosion resistance in the finally installed condition. or equivalent equipment to be used during production welding, and should be at the actual premises, i.e. work shop, yard, and 102 Welding consumables for arc welding shall be classified vessel. Use of other premises shall be specially agreed. according to recognised classification schemes. 208 Qualification NDT shall be 100% visual examination, 103 Welding consumables and welding processes shall give 100% radiographic or ultrasonic testing, and 100% magnetic a diffusible hydrogen content of maximum 5 ml/100g weld particle or liquid penetrant testing. Test requirements and metal unless other requirements are given for specific applica- acceptance criteria shall be in accordance with Appendix D, tions in this Appendix. Hydrogen testing shall be performed in subsection B. accordance with ISO 3690. 209 When using processes which have high potential for 104 For the FCAW welding processes it shall be docu- non-fusing type defects, including G-FCAW (Process ISO mented that the hydrogen content of the deposited weld metal 4063-137) bend testing shall be performed with the number of will be below 5 ml diffusible hydrogen per 100 g weld metal bend tests according to ISO 9606-1. under conditions that realistically can be expected for produc- tion welding. 210 A welder or welding operator who has produced a com- plete and acceptable welding procedure qualification is 105 Welding consumables for processes other than manual thereby qualified. or mechanised arc welding may require special consideration with respect to certification, handling and storage. Retesting 106 Depletion of alloying elements during welding per- 211 A welder may produce additional test pieces if it is dem- formed with shielding gases other than 99.99% argon shall be onstrated that the failure of a test piece is due to metallurgical considered. or other causes outside the control of the welder/ welding oper- 107 All welding consumables shall be individually marked ator. and supplied with an inspection certificate type 3.1 according 212 If it is determined that the failure of a test is due to to EN 10204 or equivalent. Certificate type 2.2 is sufficient for welder’s lack of skill, retesting shall only be performed after SAW flux. the welder has received further training. Cellulose coated electrodes Period of validity 108 Cellulose coated electrodes may be used only subject to 213 The period of validity of a welder qualification shall be agreement for welding of pipeline girth welds in C-Mn linepipe in accordance with the standard used for qualification. A qual- with SMYS ≤ 450 MPa. If used the delay between completion

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of the root pass and the deposition of the hot pass is simulated 303 For girth welds exposed to strain εl,nom≥ 0.4%, the yield during welding procedure qualification according to E108. stress (Rt0.5) of the weld metal requires special attention with 109 Use of cellulose coated electrodes is not permitted for: regard to straining and ageing and, when applicable, also to the properties at elevated temperatures. ECA shall be conducted — repair welding of pipeline girth welds for all girth welds exposed to a strain εl,nom ≥ 0.4% (see — welding of other than pipeline girth welds in C-Mn line- Appendix A). Further details regarding to the requirements for pipe with SMYS ≤ 450 MPa. weld metal tensile properties are given in Sec.6 B700. 304 Whenever an ECA is performed, the tensile properties of Data Sheet the weld metal shall be at least be equal to the properties used as 110 Each batch of welding consumables shall be delivered in input to the ECA. If the properties of the weld metal do not meet accordance with a Manufacturer’s data sheet, which shall state: these requirements, it shall be validated that the assumptions made during design and/or the ECA have not been jeopardised. — guaranteed maximum value for diffusible hydrogen in the 305 Whenever an ECA is performed and for steels with deposited weld metal SMYS ≥ 450 MPa, any batch intended for use in production — the guaranteed minimum and maximum levels of C, alloy- welding that was not qualified during welding procedure qual- ing elements and any other intentionally added elements ification, shall be qualified according to C400. — guaranteed mechanical properties (tensile and impact) — determined under defined reference conditions. The data 306 For girth welds, all batches of consumables used in pro- sheet shall, when relevant, also give recommendations for duction including possible wire / flux combinations should be handling/recycling of the welding consumables in order to qualified by testing during welding procedure qualification. meet the guaranteed maximum value for diffusible hydro- 307 Batch testing is not required for steels with gen in the deposited weld metal. SMYS < 450 MPa and when ECA is not performed if the ten- sile or impact properties stated on the Inspection Certificates Guidance note: are not less than 90% of the batch used for welding procedure The Contractor responsible for the welding and the welding con- qualification. sumable manufacturer should agree on the content and the spec- ified limits in the data sheets. Pipeline components

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 308 For welds in pipeline components the weld metal shall, as a minimum, have ductility and toughness meeting the require- C 200 Chemical composition ments of the base material and the actual yield stress (Rt0.5) of the deposited weld metal shall at least be 80 MPa above SMYS 201 All welding consumables shall be delivered in accord- of the base material. If two grades are joined, the requirement ance with Manufacturer's data sheets, which shall state the applies to the SMYS of the lower strength base material. minimum and maximum levels of C, Mn, Si, P, S, micro-alloy- ing elements and any other intentionally added elements. C 400 Batch testing of welding consumables for pipeline girth welds 202 For solid wire and metal powders, the chemical analysis shall represent the product itself. The analysis shall include all 401 A consumable batch is defined as the volume of product elements specified in the relevant classification standard and identified by the supplier under one unique batch/lot number, the relevant data sheet. manufactured in one continuous run from batch/lot controlled raw materials. 203 For coated electrodes and cored wires, the analysis shall represent the weld metal, deposited according to EN 26847 402 Batch testing shall be conducted to verify that consuma- (ISO 6847). The analysis shall include all elements specified in bles that were not tested during qualification of the welding the relevant classification standard and the relevant data sheet procedure will give a deposited weld metal nominally equiva- lent to those batches used for welding procedure qualification, 204 When sour service is specified, the chemical composi- with respect to chemistry and mechanical properties. tion of the deposited weld metal shall comply with ISO 15156. The Ni-content in welding consumables for girth welds in C- 403 The batch testing shall be performed for all welding con- Mn steel may be increased up to 2% Ni, provided that other sumables, including possible wire/flux combinations. requirements in ISO 15156 are fulfilled, and that the welding 404 Each individual product (brand name and dimensions) procedure has been tested for resistance to SSC. shall be tested once per batch/lot, except for solid wire origi- 205 The selection of welding consumables shall be given nating from the same heat, where one diameter may represent special attention in order to avoid any types of preferential all. SAW fluxes do not require individual testing but SAW weld corrosion. This applies particularly to material with wires shall be tested in combination with a selected, nominal enhanced corrosion properties, and for selection of welding batch of flux of the same classification as used for the welding consumable for the root pass in systems for seawater service. of the girth welds. 206 The chemical composition of the weld overlay materials Mechanical testing shall comply with the material requirements specified for the 405 The testing shall be performed on samples taken from applicable type of overlay material or with a project specifica- girth welds welded according to the welding procedure to be tion. used in production. Three samples shall be removed from the 12 and 6 o'clock position and from the 3 or 9 o'clock position. C 300 Mechanical properties The testing of each sample shall be performed as required in Pipeline girth welds Appendix B, and include: 301 Weld metal in pipeline girth welds shall, as a minimum — 1 transverse all weld metal tensile test. have strength, ductility and toughness meeting the require- — 1 macro section taken adjacent to the all-weld metal ten- ments of the base material. sile test. The macro section shall be hardness tested 302 For girth welds exposed to strain εl,nom< 0.4%, the yield (HV10) vertically through the weld centre line with inden- stress (Rt0.5) of the weld metal should be minimum 80 MPa tations spaced 1.5 mm apart above SMYS of the base material. If two grades are joined, the — 1 set of Charpy V-notch test at weld centre line in the same requirement applies to the SMYS of the lower strength base locations as tested during WPQT. Test temperature shall be the material, see Sec.6 B700. same as for qualification of the relevant welding procedure.

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406 If an ECA in not performed, the mechanical properties The moisture proof integrity of bags shall be verified upon shall meet the specified minimum requirements. delivery and when retrieving bags for use. The flux shall 407 If an ECA is used as basis for establishing acceptance only be taken from undamaged containers/bags directly criteria for pipeline girth welds (see Appendix A), fracture into a hopper or storage container toughness testing shall be performed with the same type of — the temperature ranges for heated hoppers, holding boxes specimens and test conditions as for qualification of the rele- and storage containers shall be in accordance with the flux vant welding procedure, whenever: manufacturer’s recommendations — whenever recycling of flux is applied, the recycling proc- — average impact test values are not within 80% of the aver- ess shall ensure a near constant ratio of new/recycled flux age value obtained during WPQT and the ratio of new/recycled flux shall be suitable to pre- — the transverse all weld metal yield stress is not within 90% vent any detrimental degradation of the flux operating of the value obtained during WPQT or the transverse all characteristics, e.g. moisture pick-up, excessive build-up weld metal yield stress results in undermatching weld of fines and change of grain size balance. metal strength — the relevant mechanical properties of the weld metal does not meet the properties used as input in the ECA. D. Welding Procedures Chemical analysis 408 For solid wire and metal powders the analysis shall rep- D 100 General resent the product itself. For coated electrodes and cored wires, 101 Detailed Welding Procedure Specifications shall be pre- the analysis shall represent the weld metal, deposited accord- pared for all welding covered by this Appendix. ing to EN 26847 (ISO 6847). The analysis shall include: 102 All welding shall be based on welding consumables, — all elements specified in the relevant classification stand- welding processes and welding techniques proven to be suita- ard and the relevant data sheet, see 201 ble for the type of material and type of fabrication in question. — the N content. D 200 Previously qualified welding procedures 409 The chemical analysis shall be in accordance with the General composition ranges stated in the Manufacturer's data sheets, see C201. 201 A qualified welding procedure of a particular manufac- turer is valid for welding only in workshops or sites under the C 500 Shielding, backing and plasma gases operational technical and quality control of that manufacturer. 501 The classification and designation and purity of shield- 202 For welding procedures developed qualified and kept on ing, backing and plasma gases shall be in compliance with EN file for contingency situations such as hyperbaric welding pro- 439. cedures intended for pipeline repair and other contingency sit- 502 Gases shall be delivered with a certificate stating the uations, the restrictions below shall not apply. classification, designation, purity and dewpoint of the deliv- Pipeline girth welds ered gas. 203 Previously qualified welding procedures shall not be 503 The gas supply/distribution system shall be designed used for: and maintained such that the purity and dewpoint is maintained up to the point of use. — welding of girth welds when the SMYS of C-Mn linepipe 504 Shielding, backing and plasma gases shall be stored in is > 450 MPa the containers in which they are supplied. Gases shall not be — welding of girth welds in clad or lined, duplex stainless intermixed in their containers. steel or 13Cr martensitic stainless steel linepipe. 505 If gas mixing unit systems are used, the delivered gas composition shall be verified and regularly checked. 204 Except as limited by 203 above, a WPS for new produc- tion may be based on a previously qualified WPQR. The type C 600 Handling and storage of welding consumables and extent of testing and test results for the previously quali- fied WPQR shall meet the requirements of this Appendix. A 601 A detailed procedure for storage, handling, recycling WPS for the new production shall be specified within the and re-baking of welding consumables to ensure that the essential variables of this Appendix. hydrogen diffusible content of weld metal is maintained at less than 5 ml per 100 g weld metal shall be prepared. The proce- 205 For WPQRs older than 5 years the validity shall be doc- dure shall, as a minimum, be in accordance with the Manufac- umented through production tests. turer's recommendations. The procedure shall be reviewed and Pipeline components agreed prior to start of the production. 206 Previously qualified welding procedures shall not be 602 The Manufacturer's recommendations may be adapted used for welding of steels with SMYS ≥ 450 MPa. A WPS for for conditions at the location of welding provided the follow- new production may otherwise be based on a previously qual- ing requirements are met: ified WPQR. The type and extent of testing and test results for — solid and flux cored wire shall be treated with care in order the previously qualified WPQR shall meet the requirements of to avoid contamination, moisture pick-up and rusting, and this Appendix and a WPS for the new production shall, based shall be stored under controlled dry conditions. Ranges of the previously qualified WPQR, be specified within the essen- temperature and relative humidity for storage shall be tial variables of this Appendix. stated 207 For a WPQR where the actual qualification is more than — if vacuum packed low hydrogen SMAW welding consum- 5 years old, it shall be documented through production tests ables are not used, low hydrogen SMAW consumables that a WPS based on the qualifying WPQR have been capable shall be stored, baked, handled and re-baked in accordance of producing welds of acceptable quality over a period of time. with the Manufacturer’s recommendation. Re-baking Alternatively a limited confirmation welding may be per- more than once should not be permitted formed to demonstrate that the WPS is workable and produc- — flux shall be delivered in moisture proof containers/bags. ing welds of acceptable quality.

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D 300 Preliminary welding procedure specification based on WPQRs for the type of weld repair to be applied. 301 A preliminary Welding Procedure Specification D 700 Contents of pWPS (pWPS) shall be prepared for each new welding procedure qualification. The pWPS shall contain the relevant information 701 The pWPS shall contain the relevant information required for making a weld for the intended application when required for the applicable welding processes, including any using the applicable welding processes, including tack welds. tack welds. A pWPS for production welding shall include the information given in Table C-1 and 702 through 705, as rele- D 400 Welding procedure qualification record vant for the welding to be performed. 401 The Welding Procedure Qualification Record (WPQR) Additional requirements to pWPS for mechanised welding of shall be a record of the materials, consumables, parameters and pipeline girth welds any heat treatment used during qualification welding and the 702 For mechanised welding of pipeline girth welds the fol- subsequent non-destructive, destructive and corrosion test lowing additional information shall be included in the pWPS: results. All essential variables used during qualification weld- ing that are relevant for the final application of the WPQR shall — control software (programme and/or software version) be documented and the welding parameters recorded in rele- — list of pre-set welding parameters that can not be adjusted vant positions for each pass. by the welder D 500 Welding procedure specification — list of welding parameters that can be adjusted by the welder. (“hot-key limits”) 501 A Welding Procedure Specification (WPS) is a specifi- — minimum number of welders for each pass. cation based on one or more accepted WPQRs. One or more WPSs may be prepared based on the data of one or more 703 A pWPS for mechanised GMAW welding shall in addi- WPQRs provided the essential variables are kept within the tion include: acceptable limits and other requirements of this Appendix are met. A WPS may include one or a combination of welding — wire feed processes, consumables or other variables. All limits and — oscillation width and frequency ranges for the applicable essential variables for the welding to — side wall dwell time. be performed shall be stated in the WPS. 704 A pWPS for mechanised GTAW/PAW welding shall in 502 The WPS shall be submitted together with the refer- addition include: enced supporting WPQR(s) for review and acceptance prior to start of production. — programmed arc voltage — wire feed including pulsing pattern and timing diagram D 600 Welding procedure specification for repair weld- — oscillation width and frequency ing — side wall dwell time 601 Repair welding procedure specifications shall be prepared, — shielding gas timing diagrams and pulse pattern.

Table C-1 Contents of pWPS Manufacturer Identification of manufacturer pWPS Identification of the pWPS Welding process Welding process and for multiple processes; the order of processes used Manual, partly-mechanised, mechanised and automatic welding Welding equipment Type and model of welding equipment. Number of wires Base materials Material grade(s), supply condition, chemical composition and manufacturing process. For steels with SMYS > 450 MPa; Steel supplier and For CRAs; UNS and PRE numbers. Material thickness and diam- Material thickness of test piece. Nominal ID of pipe eter Groove configuration Groove design/configuration; dimensions and tolerances of angles, root face, root gap and when applicable; diameters. Backing and backing material. Alignment and tack welding Tack welding (removal of tack welds or integration of tack welds in the weld) Type of line-up clamp. Stage for removal of line-up clamp Welding consumables Electrode or filler metal diameter or cross section area. Type, classification and trade name. Shielding, backing and Designation, classification and purity according to EN 439. Nominal composition of other gases and gas mix- plasma gases tures. Gas flow rate Electrical characteristics and Polarity. Type of current (AC, DC or pulsed current). Pulse welding details (machine settings and/or pro- pulsing data gramme selection) Arc Characteristics Spray arc, globular arc, pulsating arc or short circuiting arc Welding techniques Welding position according to ISO 6947. Welding direction. Stringer/weave beads. Sequence of deposition of different consumables. Number of passes to be completed before cooling to below preheats temperature. Accelerated weld cooling (method and medium). For double sided welding: Sequence of sides welded first and last and number of passes welded from each side. For cellulose coated electrodes: Time lapse between completion of root pass and start of hot pass and number of welders on each side. Preheating Method of preheat and minimum preheat temperature. Minimum initial temperature when preheat is not used. Interpass temperature Maximum and minimum interpass temperature Heat input Heat input range for each pass Post weld heat treatment Method, time and temperature for post heating for hydrogen release Method of post weld heat treatment (holding time and heating and cooling rates) Specific for the SMAW Run-out length of electrode or travel speed welding process

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Table C-1 Contents of pWPS (Continued) Specific for the SAW weld- Number and configuration of wire electrodes. Flux, designation, manufacturer and trade name. Additional ing process filler metal. Contact tip - work piece distance. Arc voltage range. Specific for the FCAW weld- Mode of metal transfer (short circuiting, spray or globular transfer) ing process Specific for the GMAW Shielding and backing gas flow rate. Additional filler metal. Contact tip - work piece distance. Arc voltage welding process range. Specific for the GTAW Shielding and backing gas flow rate. Nozzle diameter. Diameter and codification of tungsten electrode (EN welding process 26848). Hot or cold wire. Specific for the PAW weld- Shielding, backing and plasma gas flow rate. Nozzle diameter. Type of torch. Contact tip - work piece distance. ing process Hot or cold wire Additional requirements to pWPS for repair welding Multiple test pieces 705 A pWPS for repair welding shall in addition to the 806 A number of test pieces may be required for qualifying requirements applicable for a pWPS for production welding a pWPS where the size of the test piece will not allow extrac- include the following information: tion of test specimens in the correct locations according to Fig- ure 2. In such cases the maximum variation in heat input during — type of repair welding of the different test pieces shall be within 25% of the — method of removal of the defect, preparation and design of heat input of the test piece welded with the lowest heat input. the repair weld excavation This will qualify welding with a heat input range between the — minimum repair depth and length low and high heat input values, provided: — visual examination and NDT to be performed of the exca- vated area according to Appendix D, Subsection B to con- — hardness test specimens are taken from the test piece firm complete removal of defect before welding as well as welded with the lowest heat input visual examination and NDT of the final repaired weld. — impact test specimens are taken from the test piece welded — In cases when through thickness or partial thickness with the highest heat input. repeated repairs are permitted or agreed (see Table C-7) the location of additional Charpy V-notch tests, in addition 807 When it is intended to qualify a pWPS with a high and to the tests required by Table C-4, shall be shown on low heat input in order to allow welding within this heat input sketches in the pWPS. range, the maximum difference in heat input shall not exceed 30%. All required mechanical testing shall be performed on D 800 Essential variables for welding procedures test pieces welded with both high and low heat input. 801 A qualified welding procedure remains valid as long as 808 The minimum preheat or work piece temperature to be the essential variables are kept within the limits specified in stated in the WPS shall not be below that of the test piece with Table C-2. the recorded highest preheat. 802 For special welding processes as stated in A202 and 809 The maximum interpass temperature of any pass to be welding systems using these processes other essential parame- stated in the WPS shall not be higher than that of the test piece ters and acceptable variations need to be applied and shall be with the recorded lowest interpass temperature +25oC or the subject to agreement. recorded highest interpass temperature, whichever is the 803 The limits and ranges for essential variables for a WPS lower. shall be based on the on documented records in one or more Multiple filler metals WPQRs. 810 When multiple filler metals are used in a test joint, the 804 The essential variables given in Table C-2 shall, when qualified thickness for each deposited filler metal shall be applicable, be supplemented with the requirements in 805 between 0.75 to 1.5 times the deposited thickness of that filler through 814 below. material. Dissimilar material joint Number of welders 805 If two different materials are used in one test piece, the 811 If welders have been working on opposite sides of a test essential variables shall apply to each of the materials joined. piece, the maximum difference in heat input between the weld- A WPQR qualified for a dissimilar material joint will also ers shall not exceed 15%. The allowable variation in heat input qualify each material welded to itself, provided the applicable shall be based on the average of the heat inputs used by the essential variables are complied with. welders.

Table C-2 Essential variables for welding of pipeline girth welds Variable Changes requiring re-qualification 1 Manufacturer Manufacturer a Any change in responsibility for operational, technical and quality control 2 Welding process The process(es) used a Any change The order of processes used b Any change when multiple processes are used Manual, partly-mechanised, c Any change between manual, partly-mechanised, mechanised and automatic welding mechanised or automatic welding 3 Welding equipment Welding a Any change in make, type and model for partly-mechanised, mechanised and automatic welding Welding equipment b Any change in type for manual welding Number of wires c Change from single wire to multiple wire system and vice versa 4 Base materials Material grade a A change from a lower to a higher strength grade but not vice versa

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Table C-2 Essential variables for welding of pipeline girth welds (Continued) Variable Changes requiring re-qualification Supply condition b A change in the supply condition (TMCP, Q/T or normalised) Steel supplier c For SMYS ≥ 450 MPa; a change in base material origin (steel mill) (pipeline girth welds only) Chemical composition d An increase in Pcm of more than 0.020, CE of more than 0.030 and C content of more than 0.02% for C-Mn and low alloy steel Manufacturing process e A change in manufacturing process (rolled, seamless, forged, cast) UNS numbers. f A change in the UNS number for CRAs 5 Material thickness and diameter Material thickness (t = nominal a For non sour service: thickness of test joint.) — t < 25 mm: A change outside 0.75 t to 1.5 t — t > 25 mm: A change outside 0.75 t to 1.25 t For sour service: — A change outside the thickness interval 0.75 t to 1.25 t Nominal ID of pipe b A change of pipe ID outside the range 0.5 ID to 2 ID 6 Groove configuration Groove design/configuration. a Any change in groove dimensions outside the tolerances specified in the agreed WPS Backing and backing material. b Addition or deletion of backing or change of backing material 7 Alignment and tack welding Tack welding a Any change in removal of tack welds or integration of tack welds in the weld. Line-up clamp b Omission of a line-up clamp and a change between external and internal line-up clamp. Removal of line-up clamp c Any reduction in length of each section of root pass welded; the spacing of sections, number of sec- tions and percentage of circumference welded for external line-up clamp d Any change in number of completed passes and length of passes for internal line-up clamp Internal misalignment e Any increase for clad and lined pipe 8 Welding consumables Electrode or filler metal a Any change of diameter or cross section area b Any change of type classification and brand (brand not applicable for bare wire) c Any use of a non tested welding consumables batch when batch testing is required d Any use of a welding consumables batch with a reduction in tensile or impact properties of more than –10% from the batch used for WPQR when batch testing is not required Flux e Any change of type, classification and brand f Any increase in the ratio of recycled to new flux 9 Shielding, backing and plasma gases Gases according to EN 439 a Any change in designation, classification and purity according to EN 439 Other gases and gas mixtures b Any change in nominal composition, purity and dew point. Oxygen content of backing gas c Any increase Shielding gas flow rate d For processes 131, 135 136, 137 and 141: Any change in flow rate beyond ± 10% 10 Electrical characteristics and pulsing data Polarity a Any change in polarity AC, DC or pulsed current b Any change in type of current and a change from normal to pulsed current and vice versa. Pulse frequency range in pulsed c Any change in: Pulse frequency for background and peak current exceeding ± 10% and pulse duration manual welding range exceeding ± 10%. 11 Arc Characteristics Mode of metal transfer a A change from spray arc, globular arc or pulsating arc to short circuiting arc and vice versa 12 Welding techniques Angle of pipe axis to the a A change of more than ± 15°from the position welded. The L045 position qualifies for all positions horizontal provided all other essential variables are fulfilled Welding direction b A change from upwards to downwards welding and vice versa Stringer/weave c A change from stringer to weave of more than 3X electrode/wire diameter or vice versa Sequence of deposition of differ- d Any change in the sequence ent consumables Sequence of sides welded first e Any change in the sequence and last (double sided welds) Passes welded from each side f Change from single to multi pass welding and vice versa. Number of welders g Any decrease in number of welders for welding of root and hot pass for cellulose coated electrodes. Time lapse between completion h For cellulose coated electrodes: Any increase above maximum time qualified of root pass and start of hot pass Weld completion i Any reduction in the number of passes completed before cooling to below preheat temperature. Accelerated weld cooling j Any change in method and medium and any increase in maximum temperature of the weld at start of cooling.

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Table C-2 Essential variables for welding of pipeline girth welds (Continued) Variable Changes requiring re-qualification 13 Preheating Preheat temperature a Any reduction. Initial temperature when preheat b Any reduction. is not used 14 Interpass temperature Maximum and minimum inter- a Any increase above 25°C for C-Mn and low alloy steel. Any increase for CRAs. Any reduction below pass temperature the preheat temperature. 15 Heat input Heat input range for each pass a For C-Mn and low alloy steels with SMYS ≤ 450 MPa in non sour service: Any change exceeding ± 15% b For C-Mn and low alloy steels with SMYS > 450 MPa: Any change exceeding ± 10% c For CRAs: Any change exceeding ± 10% 16 Post weld heat treatment Post heating; hydrogen release a Any reduction in the time and temperature and deletion but not addition of post heating. Post weld heat treatment b Addition or deletion of post weld heat treatment. Any change in holding temperature exceeding ± 20°C. Any change in holding time and any change in heating and cooling rates outside ± 5% 17 Specific for the SAW welding process Wire electrode configuration. a Each variant of process 12 (121 to125) shall be qualified separately Flux b Any change of type, classification and brand. Arc voltage range. c Any change beyond ± 10% 18 Specific for the FCAW welding process Mode of metal transfer a A change from short circuiting transfer to spray or globular transfer. Qualification with spray or globular transfer qualifies both spray or globular transfer 19 Specific for the GMAW welding process Arc voltage range a Any change beyond ± 10% 20 Specific for the GTAW welding process Diameter and codification of a Any change tungsten electrode (EN 26848) Hot or cold wire. b A change from hot to cold wire and vice versa 21 Specific for the PAW welding process Hot or cold wire a A change from hot to cold wire and vice versa Additional essential variables for mechanised and automatic Post weld heat treatment welding of pipeline girth welds 814 If CRA or clad welds are subject to solution annealing 812 For mechanised and automatic welding of pipeline girth heat treatment after welding a slight variation in welding welds the following additional essential variables apply: parameters outside those in Table C-2, items 10 through 15 may be agreed. — any change of control software — any change of pre-set parameters (parameters that can not be adjusted by the welder) for automatic welding E. Qualification of Welding Procedures — any change in programmed parameters and their variation, except that necessary variation in oscillation width for E 100 General welding of thinner/ heavier wall than used during qualifi- 101 Qualification welding shall be performed based upon the cation shall be allowed for mechanised GMAW, GTAW accepted pWPS, using the type of welding equipment to be used and PAW. during production welding, and under conditions that are repre- — any change in limits for parameters that can be adjusted by sentative of the actual working environment for the work shop, the welder. (“hot-key limits”). site, or vessel where the production welding will be performed. Test joints Essential variables for repair welding 102 The number of test joints shall be sufficient to obtain the 813 For repair welding the following essential variables required number of specimens from the required locations apply: given in Figure 1 and Figure 2. Allowance for re-testing should be considered when deciding the number of test joints to be — the essential variables given in Table C-2 welded. — a change from internal to external repairs and vice versa 103 The test joints for qualification welding shall be of suf- for pipeline girth welds ficient size to give realistic restraint during welding. — a change from multi pass to single pass repairs and vice 104 The base material selected for the qualification testing versa should be representative of the upper range of the specified — a change from cold to thermal method for removal of the chemical composition for C-Mn and low alloy steels, and of defect but not vice versa the nominal range of the specified chemical composition for — any increase in the depth of excavation for partial thick- corrosion resistant alloys. ness repairs. 105 The material thickness shall be the same for both pipes/

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.C – Page 173 components/plates to be welded, except to qualify joining of — accelerated cooling of the weld shall be performed during two base materials with unequal thickness and for fillet end T- qualification welding if accelerated weld cooling, e.g. for joint test pieces. AUT will be performed in production. The cooling Qualification welding method and the weld temperature at the start of the cooling shall be recorded. 106 Certificates for materials and consumables, including shielding, backing and plasma gases, shall be verified, and Cellulose covered electrodes validity and traceability to the actual materials shall be estab- 108 If the use of cellulose covered electrodes has been lished prior to start of qualification welding. The records from agreed, the following additional requirements shall apply: qualification welding shall include all information needed to establish a WPS for the intended application within the essen- — preheat shall be minimum 100°C tial variables and their allowable ranges. — delay between completion of the root pass and the start of 107 The following requirements apply: depositing the hot pass shall be minimum 6 minutes — immediately upon completion of welding during welding — the welding qualification test shall be representative for procedure qualification the test pieces shall be water the production welding with respect to welding positions, quenched as soon as the temperature of the test piece is interpass temperature, application of preheat, heat conduc- below 300°C tion, time between each layer, etc. — non destructive testing of the test piece shall be by Auto- — if multiple welding arcs are combined in a single welding mated Ultrasonic Testing (AUT) or Radiographic testing head the parameters for each welding arc shall be recorded and Manual Ultrasonic Testing. — the direction of plate rolling (when relevant) and the 12 o’clock position (for fixed pipe positions) shall be marked E 200 Repair welding procedures on the test piece 201 Repair welding shall be qualified by a separate weld — when more than one welding process or filler metal is used repair qualification test. to weld a test piece, the parameters used and the approxi- mate thickness of the weld metal deposited shall be 202 Preheat for repair welding shall normally be minimum recorded for each welding process and filler metal 50°C above minimum specified preheat for production weld- — if tack welds are to be fused into the final joint during pro- ing. duction welding, they shall be included when welding the 203 When a heat treated pipe or component is repaired by test piece welding, a new suitable heat treatment may be required to be — heating of test pieces in addition to that generated by the included in the qualification of the weld repair procedure, welding is not permitted, with the exception of heating depending on the effect of the weld repair on the properties and required to obtain and maintain the minimum preheat tem- microstructure of the existing weld and base material. perature and post heating stated in the pWPS — backing gas oxygen content and the duration of backing 204 Qualification of repair welding procedures shall be gas application before, during and after welding shall be made by excavating a repair groove in an original weld welded recorded in accordance with a qualified welding procedure. — each test piece shall be uniquely identified by hard stamp- 205 The excavated groove shall be of sufficient length to ing or indelible marking adjacent to the weld and the obtain the required number of test specimens + 50 mm at each records made during test welding, non-destructive testing end. and mechanical testing shall be traceable to each test piece. Repeated repairs 206 Repeated weld repairs shall be qualified separately, if Pipeline girth welds repeated weld repairs are permitted or agreed. — the welding qualification test shall be representative for 207 In case of repeated repairs, the test piece shall contain a the production welding with respect to angle of pipe axis, repair weld of a qualified repaired original weld. For repeated interpass temperature, application of preheat, heat conduc- in-process root repair, single pass cap repair and/or single pass tion, time between each layer, etc. root sealing repairs the repair weld shall be removed prior to — for girth welds in welded pipe in all positions, except 1G re-repair. (PA) and 2G (PC), it is recommended that one of the pipes Qualification welding used for the welding procedure qualification test be fixed with the longitudinal weld in the 6 or 12 o'clock position 208 The qualification test shall be made in a manner realisti- — for welding of pipe with diameter ≥ 20” in fixed positions cally simulating the repair situation to be qualified. the weld circumference shall be divided in 90° sectors 209 Qualification welding shall be performed in accordance around the circumference, with one sector centred at the with E101 through E108. 12 o’clock position. The welding parameters shall be 210 For pipeline girth welds the repair qualification welding recorded for each pass in each sector and for each welding shall be performed in the overhead through vertical positions. arc. The heat input for each sector may be recorded as the average value in the sector 211 For roll welding the length of the repair weld may be — for welding of pipe with diameter < 20” the heat input centred at the 12 o’clock location for external repairs and at the shall be recorded as the average value for each pass 6 o’clock location for internal repairs, in which case repair — the release of external line-up clamps shall be simulated welding is qualified for repair welding in these locations only. during qualification welding. Clamps shall normally not be released until the completed sections of the root pass E 300 Qualification of longitudinal and girth butt welds covers a minimum of 50% of the circumference with even welding procedures spacing. The length of each section, the spacing of the sec- 301 Qualification of welding procedures for pipeline system tions, the number of sections welded and the percentage of girth welds and welds in pipeline components may be per- welded sections of the circumference shall be recorded formed by any of the arc welding processes specified in A200. — cooling of the test piece to below preheat temperature shall be simulated during qualification welding for at least one 302 The WPS shall be qualified prior to start of any produc- test piece. The number of passes completed before cooling tion welding. to below preheat temperature shall be recorded 303 The type and number of destructive tests for welding

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 174 – App.C procedure qualification are given in Table C-3, with methods weld metal in the strained and aged condition after deforma- and acceptance criteria as specified in subsection F below. tion cycles and also at elevated temperature. See Appendix A, 304 For pipeline girth welds exposed to strain ≥ 0.4% it may Subsection G. be required to perform testing to determine the properties of

Table C-3 Qualification of welding procedures for longitudinal and girth butt welds TEST JOINT MINIMUM NUMBER OF EACH SPECIFIED TEST Wall D Transverse Transver- All-weld Root Face Side- Charpy V- Macro and Other Fracture thickness (mm) weld Tensile seall-weld tensile 2) bend 10) bend 10) bend 10) notch sets hardness 11) tests12) toughness (mm) Tensile 1) 4,5,6,7) ≤ 25 ≤ 300 2 2 2 2 3) 2 3) 0 4 8) 2 13) 13) > 300 2 2 2 4 3) 4 3) 0 4 8) 2 13) 13) > 25 ≤ 300 2 2 2 0 0 4 6 8,9) 2 13) 13,14) > 300 2 2 2 0 0 4 6 8,9) 2 13) 13,14) Notes: 1) Transverse all weld tensile are required if an ECA is performed. 2) All weld tensile tests are not required for OD ≤ 200 mm and not if transverse all-weld tests are performed. 3) For welding processes GMAW and FCAW, side bend tests shall be performed instead of root and face bend tests. 4) Impact testing is not required for t < 6 mm. 5) Each Charpy V-notch set consists of 3 specimens. 6) The notch shall be located in the weld metal, the fusion line (FL) sampling 50% of HAZ, FL+2 mm and FL+5 mm, see Appendix B, Figure 3 through Figure 5. 7) For double sided welds on C-Mn and low alloy steels, four additional sets of Charpy V-notch test specimens shall be sampled from the weld metal, FL (sampling 50% of HAZ), FL+2 mm and FL+5 mm in the root area, see Appendix B Figure 5. 8) If several welding processes or welding consumables are used, impact testing shall be carried out in the corresponding weld regions, if the region tested cannot be considered representative for the complete weld. 9) When the wall thickness exceeds 25 mm for single sided welds, two additional sets of Charpy V-notch test specimens shall be sampled from the weld metal root and FL in the root area. 10) Bend tests on clad/lined pipes shall be performed as side bend tests. 11) For girth welds in welded pipe, one macro and hardness shall include an intersection between a longitudinal/girth weld. 12) Requirements for corrosion tests, chemical analysis and microstructure examination are specified in F. 13) Fracture toughness testing is only required when a generic or full ECA is performed for pipeline girth butt welds. Extent of testing shall be in accordance with Appendix A. 14) For nominal wall thickness above 50 mm in C-Mn and low alloy steels fracture toughness testing is required unless PWHT is performed. Qualification of repair welding procedures 308 The type and number of destructive tests for qualifica- tion or repair welding procedure are given in Table C-4, with 305 Qualification of repair welding procedures for pipeline methods and acceptance criteria as specified in subsection F system girth welds and welds in pipeline components may be below. performed by any of the arc welding processes specified in A200. Repeated repairs 306 The WPS for repair welding shall be qualified prior to 309 If it has been agreed to permit through thickness or par- start of any production welding. tial thickness repeated repairs (see Table C-7), and a HAZ is introduced in the weld metal from the first repair, then addi- 307 The following types of repairs shall be qualified to the tional Charpy V-notch sets (in addition to the tests required by extent that such repairs are applicable and for pipe, also if the Table C-4) shall be located in the re-repair weld metal and in type of repair is feasible for the size of pipe in question: FL, FL+2 mm and FL+5 mm of the weld metal from the first repair and/or the base material as applicable and as shown in — through thickness repair the accepted pWPS, see D705. — partial thickness repair 310 If it has been agreed to permit repeated in-process root — in-process root repair repair, single pass cap repair and/or single pass root sealing — single pass cap repair repair, see Table C-7, the extent of testing shall be as tests — single pass root sealing repair. required by Table C-4.

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Table C-4 Qualification of repair welding procedures for longitudinal and girth butt welds TEST JOINT MINIMUM NUMBER OF EACH SPECIFIED TEST Type of repair) Transverse Transverse All-weld Root Face Side Charpy V- Macro and Other Fracture weld Tensile all-weld Tensile 2) Bend Bend bend notch sets hardness tests toughness Tensile 1) Through thickness 1111 3) 1 3) 2 4) 4, 5, 6,7, 8) 1 9) 10,11) repair Partial thickness 1111 3) 1 3) 2 4) 4) 1 9) 10,11) repair In-process root 119) repair Single pass cap 119) repair Single pass root 119) sealing repair Notes: 1) Transverse all weld tensile are only required if an ECA is performed. 2) All weld tensile tests are not required for OD ≤ 200 mm and not if transverse all-weld tests are performed. 3) 1 root and 1 face bend test for t < 25 mm 4) For welding processes GMAW and FCAW, for clad/lined pipes and for all pipes when t > 25 mm, side bend tests shall be performed instead of root and face bend tests. 5) For partial penetration and through thickness repairs where a new HAZ is introduced in the original weld metal, Charpy V-notch sets of 3 specimens shall be located according to Appendix B, Figures 7 and 8. 6) The notch shall be located in the repair weld metal, the fusion line (FL) sampling 50% of HAZ, FL+2 mm and FL+5 mm of the base material. 7) If several welding processes or welding consumables are used, impact testing shall be carried out in the corresponding weld regions, if the region tested cannot be considered representative for the complete weld. 8) Requirements for corrosion tests, chemical analysis and microstructure examination are specified in Subsection F. 9) Fracture toughness testing is only required when a generic or full ECA is performed for pipeline girth butt welds. Extent of testing shall be in accordance with Appendix A. 10) For nominal wall thickness above 50 mm in C-Mn and low alloy steels fracture toughness testing is required unless PWHT is performed E 400 Qualification of welding procedures for corrosion 405 The test pieces used shall be relevant for the intended resistant overlay welding application of the weld overlay: Qualification of welding procedures — forging or casting for overlay welding of ring grooves 401 Qualification of welding procedures for corrosion resist- — pipe with the overlay welding performed externally or ant overlay welding shall be performed with GMAW or pulsed internally, or GTAW. Other methods may be used subject to agreement. — plate or pipe with a prepared welding groove for qualifica- tion of buttering and when the weld overlay strength is uti- 402 The chemical composition of test pieces shall be repre- lised in the design. sentative for the production conditions. 403 Qualification of weld overlay shall be performed on a 406 If a buffer layer will be used in production welding, it test sample which is representative for the size and thickness shall also be used in welding the test piece. of the production base material. The minimum weld overlay 407 The WPS shall be qualified prior to start of any produc- thickness used for the production welding shall be used for the tion welding. welding procedure qualification test. 408 The type and number of destructive tests for welding 404 The dimensions of, or the number of test pieces shall be procedure qualification are given in Table C-5 with methods sufficient to obtain all required tests. and acceptance criteria specified in F below.

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Table C-5 Qualification of corrosion resistant overlay welding procedures TEST JOINT MINIMUM NUMBER OF EACH SPECIFIED TEST Thickness of base Side bend Macro and hardness Chemical Analy- All-weld Ten- Charpy V-notch Other tests material tests sis sile Impact tests All 4 1) 112 2) 2,3,4,5) 6) Notes: 1) Side bend specimens shall be taken transverse to the welding direction. 2) Only required when the weld overlay strength is utilised in the design of the welded joint. 3) Only required when the weld overlay is load bearing across the overlay/base material fusion line. 4) Sets shall be tested with the notch in the overlay weld metal, Fl, and FL+2 mm and FL+5 mm in the base material. For t > 25 mm the weld metal root and FL shall also be tested. 5) If several welding processes or welding consumables are used, impact testing shall be carried out in the corresponding weld regions if the region otherwise required to be tested cannot be considered representative for the complete weld. 6) Requirements for corrosion tests and microstructure examination are specified in subsection F. Qualification of repair welding procedures 501 Attachment of anode leads shall be by pin brazing or alu- 409 Unless the production welding procedure can be minothermic welding methods. Other methods may be used applied, the repair welding procedure shall be qualified. Weld subject to agreement. Full details of the technique used and repair performed on weld overlay machined to the final thick- associated equipment shall be available prior to qualification ness shall be separately qualified. of procedures. 410 The type and number of destructive tests for qualifica- 502 The chemical composition of test pieces shall be repre- tion of repair welding procedure are given in Table C-5. In sentative for the production conditions and be selected in the cases when qualification is performed using a pipe, component upper range of the chemical composition. or plate with a prepared welding groove, and a new HAZ is introduced in the original weld metal, additional Charpy V- 503 Qualification for brazing/welding of anode leads shall notch sets shall be located according to Appendix B, Figures 7, be performed on test samples which is representative for the and 8. size and thickness of the production base material and the number of test pieces shall be minimum 4 and sufficient to E 500 Qualification of procedures for Pin Brazing and obtain all required tests. Aluminothermic welding of anode leads 504 The WPS shall be qualified prior to start of any produc- Qualification of procedures tion.

Table C-6 Qualification of Pin Brazing and Aluminothermic welding procedures TEST JOINT MINIMUM NUMBER OF EACH SPECIFIED TEST 1) Thickness of base Electrical resistance Mechanical strength Copper penetration 2) Hardness3) Pull test material All 4 4 4 4 4 Notes 1) The number of tests refer to the total number of tests from all pieces. 2) 2 test specimens shall the sectioned transverse to the anode lead and 2 test specimens parallel with the anode lead. 3) The hardness tests shall be made on the specimens for copper penetration measurements. 505 The type and number of destructive tests for procedure — transverse weld tensile qualification are given in Table C-6 with methods and accept- — Charpy V-notch impact testing ance criteria specified in F below. — macro and hardness testing, E 600 Qualification of welding procedures Fillet welds in doubler sleeves and anode pads for temporary and permanent attachments 605 The fillet weld qualification test shall comprise two test and branch welding fittings to linepipe pieces welded in the PD and PF plate positions to qualify the Qualification of welding procedures welding procedure for welding in all positions. 601 Qualification of welding procedures for temporary and 606 The extent of testing for each test piece shall be 3 macro permanent attachments and branch welding fittings to linepipe and hardness specimens taken from the start, end and middle may be performed by any of the arc welding processes speci- of each test weld with methods and acceptance criteria as spec- fied in A200, but use of cellulose coated electrodes is not per- ified in F. mitted. Branch welding fittings 602 The WPS shall be qualified prior to start of any produc- 607 The branch fitting qualification test welds shall be tion welding. welded in the PF or PD pipe positions to qualify welding in all 603 The type and number of destructive tests for welding positions. procedure qualification are given in 604 to 614 with methods 608 The extent of testing shall be 4 macro and hardness spec- and acceptance criteria as specified in subsection F. imens taken from the 12, 3, 6 and 9 o’clock locations of each Longitudinal welds in doubler sleeves test weld. 604 Longitudinal welds in doubler sleeves shall be made 609 Charpy V-notch impact testing with the notch in the with backing strips and qualified as required in E300 and Table weld metal, FL, FL+2 mm and FL+5 mm using full size or C-3, but with the extent of testing modified to: reduced size specimens shall always be performed whenever

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.C – Page 177 the material thickness allows. Charpy V-notch specimens shall whatever is applicable for the final product. be taken from both test welds. Visual examination and non-destructive testing Qualification of repair welding procedures for longitudinal welds in doubler sleeves 102 Visual examination and non-destructive testing shall be performed no earlier than 48 hours after the completion of 610 Repair welding procedures for longitudinal welds in welding of each test piece. doubler sleeves shall be qualified as required in E300 and Table C-4, but with the extent of testing modified according to 103 If a test piece does not meet the acceptance criteria for 604. visual examination and NDT one further test piece shall be welded and subjected to the same examination. If this addi- Qualification of repair welding procedures for fillet welds tional test piece does not meet the requirements, the WPQ is 611 Qualification welding shall be performed in the PD and not acceptable. PF plate positions. The extent of qualification of repair weld- Destructive testing ing procedures shall at as a minimum consist of: 104 The type and number of mechanical tests and micro- — through thickness repair structure evaluations for qualification tests are given in E300 — single pass repair against the pipe material to E700. — single pass repair against the sleeve material. 105 Test specimens shall be taken from the positions shown 612 Methods of testing and acceptance criteria shall be as in Figure 1 and Figure 2 for longitudinal welds and girth welds specified in F. respectively. Qualification of repair welding procedures for branch welding Re-testing fittings 106 A destructive test failing to meet the specified require- 613 Qualification welding shall be performed in the PD and ments may be re-tested. The reason for the failure shall be PF pipe positions. The extent of qualification of repair welding investigated and reported before any re-testing is performed. If procedures shall at as a minimum consist of: the investigation reveals that the test results are influenced by improper sampling, machining, preparation, treatment or test- — through thickness repair ing, then the test sample and specimen (as relevant) shall be — single pass cap repair against the fitting replaced by a correctly prepared sample or specimen and a new — single pass cap repair against the pipe. test performed. 614 Methods of testing and acceptance criteria shall be as 107 A destructive test failing to meet the specified require- specified in F. ments shall be rejected if the reason for failure can not be related to improper sampling, machining, preparation, treat- E 700 Qualification of welding procedures for struc- ment or testing of specimens. tural components 108 Re-testing of a test failing to meet the specified require- 701 Welding procedures for structural components, supplied ments should only be performed subject to agreement. This re- as a part of the pipeline systems, shall be qualified in accord- testing shall consist of at least two further test specimens/sets ance with ISO 15614-1. The requirements shall be appropriate of test specimens. If both re-tests meet the requirements, the for the structural categorisation of the members and stresses in test may be regarded as acceptable. All test results, including the structure. The extent of tensile, hardness and impact testing the failed tests, shall be reported. and the testing conditions should be in compliance with this Appendix. 109 If there are single hardness values in the different test zones (weld metal, HAZ, base material) that do not meet the E 800 Qualification of welding procedures for hyper- requirement, retesting shall be carried out on the reverse side baric dry welding of the tested specimen or after grinding and re-preparation of 801 Requirements for qualification of welding procedures the tested surface. None of these additional hardness values for hyperbaric dry welding are given in subsection I. shall exceed the maximum value. 110 Specific for Charpy V-notch impact testing the follow- ing requirements apply: F. Examination and Testing for Welding — if two out of three test specimens in any set fail or the aver- Procedure Qualification age requirement is not met, the WPQ is not acceptable. — if more than one set of specimens includes a failed speci- F 100 General men the WPQ is not acceptable. 101 All visual examination, non-destructive testing, — retest may, subject to agreement, be performed with two mechanical testing and corrosion testing of test pieces shall be test specimen sets. All re-tested specimens shall meet the performed in the as welded or post weld heat treated condition, specified minimum average toughness.

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F 200 Visual examination and non-destructive testing requirements 1 2 201 Each test weld shall undergo 100% visual examination and 100% ultrasonic and 100% radiographic testing and 100% 3 magnetic particle or liquid penetrant testing. Testing shall be in accordance with Appendix D, subsection B. 4 202 Acceptance criteria for visual examination and non- destructive testing shall be in accordance with Appendix D, B900 for welds exposed to strains < 0.4%. For welds exposed to strains ≥ 0.4%, the acceptance criteria shall be as for the pro- 5 duction welding or according to Appendix D, B900, whichever 6 is the more stringent.

7 203 Weld overlay shall be non-destructively tested accord- ing to Appendix D, C300 with acceptance criteria according to Appendix D, C600. The surface and weld thickness shall be 3 representative for the production welding, i.e. after machining of the overlay thickness or the thickness representative for the 5 thickness on the finished component. F 300 Testing of butt welds 301 All testing shall be performed in accordance with 5 Appendix B.

6 Transverse weld tensile testing 3 302 The fracture shall not be located in the weld metal. The 2 ultimate tensile strength shall be at least equal to the SMTS for the base material. When different material grades are joined, Figure 1 the ultimate tensile strength of the joint shall be at least equal Welding procedure qualification test - sampling of test specimens to the SMTS for the lower grade. for longitudinal butt welds. All-weld tensile testing 303 For longitudinal welds and girth welds exposed to strain Note: The indicated location of the test specimens are not required for qualifi- εl,nom <0.4% and where no ECA is performed, the upper yield cation of welding in the PA (1G) and PC (2G) positions, where sampling posi- or the Rt0.5 of the deposited weld metal should be at least be 80 tions are optional. MPa above SMYS of the base material and the elongation not less than 18%. If two grades are joined the requirement applies 2 5 1 to the lower strength material. 7 3 Transverse all-weld tensile testing 304 For pipeline girth welds where generic ECA acceptance 6 criteria. (see Appendix A) are applied, the upper yield or the Rt0.5 of the deposited weld metal shall at least match the upper maximum of the permitted yield stress of the base material. The elongation shall not be less than 18%.When different material grades are joined, the yield stress requirements applies to the lower grade.

8 4 305 For pipeline girth welds exposed to strain εl,nom ≥ 0.4% and where full ECA acceptance criteria shall be applied, the upper yield or the Rt0.5 of the deposited weld metal shall at least match the upper maximum of the permitted yield stress of 7 the base material or the assumptions made during design and/ 1 5 2 or the ECA. The elongation shall not be less than 18%. Bend testing 1: Cross weld tensile specimens 2: All weld tensile specimens 306 The end tests shall not disclose any open defects in any 3: Bend test specimens direction exceeding 3 mm. Minor ductile tears less than 6 mm, 4: Impact test specimens originating at the specimen edge may be disregarded if not 5: Macro and hardness test specimens associated with obvious defects. 6: Corrosion test specimens 7: Micro examination and chemical analysis Charpy V-notch impact testing 8: Fracture toughness specimens 307 The average and single Charpy V-notch toughness at Figure 2 each position shall not be less than specified for the base mate- Welding procedure qualification test - sampling of test specimens rial in the transverse direction (KVT values). Requirement for for girth butt welds. fracture arrest properties does not apply. C-Mn and low alloy steels shall meet the requirements given in Sec.7 B400. Note 1: For pipeline girth welds, if applicable, one macro and hardness speci- men shall include a pipe longitudinal seam weld. Duplex and martensitic stainless steels shall meet the require- ments given in Sec.7 C400. Note 2: The indicated location of the test specimens are not required for qual- ification of welding in the PA (1G rotated) where sampling positions are The C-Mn steel backing material in clad and lined linepipe optional. shall meet the requirements given in Sec.7 B400.

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308 When different steel grades are joined the required formed when acceptance criteria are established by an ECA. impact tests shall be performed on both sides of the weld. The The extent of testing shall be in accordance with Appendix A. weld metal shall meet the more stringent energy requirement. 319 For nominal wall thickness above 50 mm in C-Mn and Macro section low alloy steels fracture toughness testing is required unless 309 The macro section shall be documented by photographs PWHT is performed. (magnification of at least 5X). F 400 Testing of weld overlay 310 The macro section shall show a sound weld merging 401 When the weld overlay is not contributing to strength, smoothly into the base material and meeting Quality level C of tensile testing and Charpy V-notch testing of the weld overlay ISO 5817. material are not required. When the weld overlay strength is 311 For girth welds in welded pipe, one macro section shall considered as a part of the design, such mechanical testing of include a longitudinal weld. the weld overlay material is required. Hardness testing 402 The base material shall retain the minimum specified 312 The maximum hardness in the base material, HAZ and mechanical properties after any post weld heat treatment. The weld metal is: base material properties in the post weld heat treated condition shall then be documented by additional testing and recorded as — 325 HV10 for C-Mn and low alloy steels in non-sour serv- a part of the welding procedure qualification. ice 403 The testing in 404 through 408 shall, as a minimum, be — 250 HV10 for C-Mn and low alloy steels in sour service performed when the overlay material is not considered as part (for weld caps not exposed to the sour service media, max- of the design and when the base material has not been affected imum of hardness of 275 HV10 may be agreed for base by any post weld heat treatment. material thickness > 12 mm) — 325 HV10 for 13Cr martensitic stainless steels Bend testing of weld overlay — 350 HV10 for duplex stainless steels 404 The bend testing shall be performed in accordance with — 325 HV10 for clad or lined material in non-sour service. Appendix B, A614. The bend tests shall disclose no defects exceeding 1.6 mm. Minor ductile tears less than 3 mm, origi- For clad or lined materials in sour service special considera- nating at the specimen edge may be disregarded if not associ- tions are required, see ISO 15156. ated with obvious defects. 313 For girth welds in welded pipe, one hardness test speci- Macro examination of weld overlay men shall include a longitudinal weld. 405 The macro sections shall be documented by photographs Corrosion testing (magnification of at least 5X). The macro section shall show a 314 Sulphide stress cracking testing (SSC) is only required sound weld merging smoothly into the base material and meet- for C-Mn and low alloy steels with SMYS > 450 MPa, 13Cr ing Quality level C of ISO 5817. martensitic stainless steels and other materials not listed for Hardness testing of weld overlay sour service in ISO 15156. 406 The maximum hardness for base material and HAZ shall Acceptance criteria shall be according to ISO 15156. not exceed the limits given in F312 above as applicable for the 315 Pitting corrosion test according to ASTM G48 is only intended service and type of material. The maximum hardness required for 25Cr duplex stainless steel (see Sec.6 B302). The for the overlay material shall not exceed any limit given in ISO maximum weight loss shall be 4.0 g/m2 when tested at 40°C 15156 for sour service, unless otherwise agreed. for 24 hours. Chemical analysis of weld overlay Microstructure examination 407 The chemical composition shall be obtained in accord- 316 Welds in duplex stainless steel materials, CRA materials ance with Appendix B. Specimens for chemical analysis shall and clad/lined materials shall be subject to microstructure either be performed directly on the as welded or machined sur- examination. The material shall be essentially free from grain face or by taking specimen or filings/chips from: boundary carbides, nitrides and intermetallic phases. Essen- — the as welded surface tially free implies that occasional strings of detrimental phases — a machined surface along the centreline of the base material is acceptable given — from a horizontal drilled cavity. that the phase content within one field of vision (at 400X mag- nification) is < 1.0% (max. 0.5% intermetallic phases). The location for the chemical analysis shall be considered as For duplex steel the ferrite content of the weld metal and HAZ the minimum qualified thickness to be left after any machining shall be within the range 35-65%. of the corrosion resistant weld overlay. The ferrite content of austenitic stainless steel weld deposit 408 The chemical composition of overlay shall be shall be shall be within the range 5-13%. within the specification limits according to the UNS for the specified overlay material. The iron content of alloy UNS Micro cracking at the fusion line is not permitted. N06625 overlay shall be < 10%. Chemical analysis Microstructure examination of weld overlay 317 For welds in clad or lined materials a chemical analysis 409 The surface to be used for microstructure examination shall be performed. The analysis shall be representative of the shall be representative of a weld overlay thickness of 3 mm or CRA composition at a point at the centreline of the root pass the minimum overlay thickness specified for the finished 0.5 mm below the surface. The chemical composition shall be machined component, whichever is less. Microstructure exam- within the specification limits according to the UNS number ination shall be performed after any final heat treatment. for the specified cladding/lining material or, if the weld metal is of a different composition than the cladding/liner, within the 410 Metallographic examination at a magnification of 400X of limits of chemical composition specified for the welding con- the CRA weld metal HAZ and the base material shall be per- sumable. formed. Micro cracking at the CRA to the C-Mn/low alloy steel interface is not permitted. The material shall be essentially free Fracture toughness testing from grain boundary carbides, nitrides and inter-metallic phases 318 For girth welds fracture toughness testing shall per- in the final condition (as-welded or heat treated as applicable).

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 180 – App.C

411 The ferrite content of austenitic stainless steel weld G. Welding and PWHT Requirements overlay deposit shall be within the range 5-13%. The ferrite content of duplex stainless steel weld overlay in the weld metal G 100 General and HAZ shall be within the range 35-65%. 101 All welding shall be performed using the type of weld- All-weld tensile testing of load bearing weld overlay ing equipment and under the conditions that are representative 412 All-weld tensile testing shall be performed in accord- for the working environment during procedure qualification ance with Appendix B A400. welding. 413 The yield stress and ultimate tensile strength of the weld 102 Pre-qualification testing shall be performed for welding deposit shall be at least equal to the material tensile properties systems where the Contractor has limited previous experience, used in the design. or where the system will be used under new conditions. All welding equipment shall be maintained in good condition in Charpy V-notch impact testing of load bearing weld overlay order to ensure the quality of the weldment. 414 When the weld overlay material is designed to transfer 103 All welding shall be performed under controlled condi- the load across the base material/weld overlay fusion line, tions with adequate protection from detrimental environmental impact testing of the weld overlay and HAZ shall be performed influence such as humidity, dust, draught and large tempera- (i.e. when the overlay is a part of a butt joint or acts as a tran- ture variations. sition between a corrosion resistant alloy and a C-Mn/low alloy steel). 104 All instruments shall have valid calibration certificates and the adequacy of any control software shall be documented. 415 Testing shall be with the notch in the overlay weld metal, FL, FL+2 mm and FL+5 mm in the base material. For 105 Welding and welding supervision shall be carried out by t > 25 mm the weld metal root and FL shall also be tested. personnel qualified in accordance with the requirements given in B200. 416 Where several welding processes or welding consuma- bles are used, impact testing shall be carried out in the corre- G 200 Production welding, general requirements sponding weld regions if the region otherwise required to be 201 All welding shall be carried out strictly in accordance tested cannot be considered representative for the complete weld. with the accepted welding procedure specification and the requirements in this subsection. If any parameter is changed 417 The average and single Charpy V-notch toughness at each outside the limits of the essential variables, the welding proce- position shall not be less than specified for the base material. dure shall be re-specified and re-qualified. Essential variables When different steel grades are joined, a series of impact tests and variation limits are specified in D800. shall be considered in the HAZ on each side of the joint. The weld metal shall meet the more stringent energy requirement. 202 The preparation of bevel faces shall be performed by agreed methods. The final groove configuration shall be as Corrosion testing of weld overlay specified in the WPS and within the tolerances in the WPS. 418 Corrosion testing and microstructure examination of 203 After cutting of pipe or plate material for new bevel stainless steel and nickel base weld overlay materials shall be preparation, a new lamination check by ultrasonic and mag- considered. netic particle/dye penetrant testing is normally required. Pro- vided it can be demonstrated that the cut has been made inside F 500 Testing of pin brazing and aluminothermic welds a zone where a lamination check was performed at the plate/ Electrical resistance pipe mill the check may be omitted. Procedures for ultrasonic and magnetic particle/dye penetrant testing and acceptance cri- 501 The electrical resistance of each test weld/brazing shall teria shall be in accordance with Appendix D. not exceed 0.1 Ohm. 204 For welding processes using shielding, backing and Mechanical strength plasma gases, the gas classification moisture content and dew 502 Each test weld/brazing shall be securely fixed and tested point shall be checked prior to start of welding. Gases in dam- with a sharp blow from a 1.0 kg hammer. The weld/brazing aged containers or of questionable composition, purity and shall withstand the hammer blow and remain firmly attached dew point shall not be used. All gas supply lines shall be to the base material and show no sign of tearing or cracking. inspected for damage on a daily basis. All gas supply lines Copper penetration shall be purged before the welding is started. 503 2 test specimens shall the sectioned transverse to the 205 The weld bevel shall be free from moisture, oil, grease, anode lead and 2 test specimens parallel with the anode lead. rust, carbonised material, coating etc., which may affect the The fusion line of the weld/brazing shall at any point not be weld quality. more than 1.0 mm below the base material surface. Intergran- 206 The alignment of the abutting ends shall be adjusted to ular copper penetration of the base material shall not at any minimise misalignment. Misalignment shall not exceed the point extend beyond 0.5 mm from the fusion line. tolerances in the WPS. Hardness 207 The weld area shall be heated to the minimum preheat 504 HV10 hardness tests shall be made on each of the spec- temperature specified in the WPS. Pre-heating shall also be imens for copper penetration measurements. performed whenever moisture is present or may condense in the weld area and/or when the ambient temperature or material 505 The maximum hardness shall not exceed the limits given temperature is below 5°C. Welding below 20°C shall not be in F312 as applicable for the intended service and type of mate- performed unless otherwise agreed. rial. 208 If applicable pre-heating shall be applied prior to any Pull test welding, including tack welding. The pre-heating temperature 506 The specimen shall break in the cable. shall be measured at a distance of minimum 75 mm from the edges of the groove at the opposite side of the heating source F 600 Testing of welds for temporary and permanent when practically possible. If this is not possible, the adequacy attachments and branch outlet fittings to linepipe of the performed measurement shall be demonstrated. 601 Welds shall be tested to the extent required in E600 and 209 Tack welding shall only be performed if qualified during meet the relevant requirements given in F300 above. welding procedure qualification. The minimum tack weld

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.C – Page 181 length is 2t or 100 mm, whichever is larger. Temporary tack shall be removed by grinding and the weld visually inspected welds using bridging or bullets shall only be performed using prior to deposition of the next weld pass. materials equivalent to the base material and using a WPS based on a qualified welding procedure. All such tack welds 218 After weld completion, all spatter, scales, slag, porosity, and any spacer wedges shall be removed from the final weld- irregularities and extraneous matter on the weld and the adja- ment. Tack welds to be fused into the weld shall be made in the cent area shall be removed. The cleaned area shall be sufficient weld groove only and the ends of the tack welds shall have for the subsequent NDT. Peening is not permitted. their ends ground and feathered and examined for cracks by an 219 Welding shall not be interrupted before the joint has suf- adequate NDT method. Defective tack welds shall be removed ficient strength to avoid plastic yielding and cracking during or repaired prior to production welding. handling. Prior to restart after an interruption, preheating to the 210 Removal of tack welds shall be by grinding and cleaning minimum interpass temperature of the pass in question shall be followed by examination of the ground area by visual inspec- applied. tion. Where temporary tack welds are removed, the bevel con- 220 Welds shall only be left un-completed if unavoidable. figuration and root gaps specified in the WPS shall be Welding of fittings shall always be completed without inter- maintained for the subsequent pass and the groove visually ruption. If welding is interrupted due to production restraints, inspected prior to resuming welding of the root pass. the minimum number of passes specified in the WPS shall be 211 The interpass temperature shall be measured at the edge completed before stopping welding. If the WPS does not spec- of the groove immediately prior to starting the following pass. ify a minimum number of passes, at least 3 passes or half the thickness of the joint should be completed before the welding 212 Earth connections shall be securely attached to avoid arc is interrupted. When interruption of welding is imposed by burns and excessive resistance heating. Welding of earth con- production restraints interrupted welds shall be wrapped in dry nections to the work piece is not permitted. insulating material and allowed to cool in a slow and uniform 213 The number of welders and the weld sequence shall be manner. Before restarting welding of an interrupted weld the selected in order to cause minimum distortion of the pipeline joint shall be reheated to the interpass temperature recorded or the components. during qualification of the welding procedure. 214 Start and stop points shall be distributed over a length of 221 Maximum root gap for fillet welds should be 2 mm. weld and not "stacked" in the same area. Where the root gap is > 2 mm but ≤ 5 mm, this shall be com- pensated by increasing the throat thickness on the fillet weld by 215 Welding arcs shall be struck on the fusion faces only. 0.7 mm for each mm beyond 2 mm gap. Welding of fillet welds Weld repair of base material affected by stray arcs is not per- with root gap > 5 mm is subject to repair based on an agreed mitted. procedure. 216 Arc burns shall be repaired by mechanical removal of affected base material followed by NDT to verify absence of G 300 Repair welding, general requirements cracks and ultrasonic wall thickness measurements to verify 301 The allowable repairs and re-repairs are given in Table that the remaining material thickness is not below the mini- C-7 and are limited to one repair in the same area. Repeated mum allowed. repairs shall be subject to agreement and are limited to one 217 Surface slag clusters, surface porosity and high points repeated repair of a previously repaired area.

Table C-7 Types of weld repairs Type of repair Type of material C-Mn and low alloy 13Cr MSS Clad/lined CRA/Duplex SS 1) steel Through thickness repair Permitted Permitted If agreed If agreed Partial thickness repair Permitted Permitted Permitted Permitted In-process root repair Permitted Permitted Permitted Permitted Single pass cap repair Permitted Permitted Permitted Permitted Single pass root sealing repair If agreed If agreed If agreed If agreed Through thickness repeated repair If agreed Not permitted Not permitted Not permitted Partial thickness repeated repair If agreed Not permitted Not permitted Not permitted In-process root repeated repair Not permitted Not permitted Not permitted Not permitted Single pass cap repeated repair Not permitted Not permitted Not permitted Not permitted Single pass root sealing repeated repair Not permitted Not permitted Not permitted Not permitted Note 1) Provided solution annealing is performed after welding, all repairs are allowed. 302 Repair welding procedures shall be qualified to the 305 Defects in the base material shall be repaired by grinding extent that such repairs are feasible and applicable for the only. repair situation in question. Qualification of repair welding procedures denoted “if agreed“, need only be done if perform- 306 Defective welds that cannot be repaired with grinding ing such repairs is agreed and are feasible for the repair situa- only may be repaired locally by welding. Repair welding shall tion in question. be performed in accordance with a qualified repair welding procedure. For welding processes applying large weld pools, 303 Cellulosic coated electrodes shall not be used for repair e.g. multi-arc welding systems, any unintended arc-stops shall welding. be considered as defects. 304 Repair welding of cracks is not permitted unless the 307 Weld seams may only be repaired twice in the same cause of cracking by technical evaluation has been established area. Repeated repairs of the root in single sided welds are not not to be a systematic welding error (cracks in the weld is cause permitted, unless specifically qualified and accepted in each for rejection). case. Weld repairs shall be ground to merge smoothly into the

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 182 – App.C original weld contour. The holding time at temperature should be minimum 30 min- ° 308 Repairs of the root pass in a single-sided joint for mate- utes +2.5 minutes per mm thickness. Below 300 C the cooling rial meeting sour service requirements shall be carried out may take place in still air. under constant supervision. 409 The holding temperature for C-Mn low alloy steels shall normally be within 580°C to 620°C unless otherwise specified 309 A local weld repair shall be at least 50 mm long or 4 or recommended by the material/welding consumable sup- times the material thickness, whichever is longest. If the length plier. The maximum PWHT temperature for quenched and at the bottom of the excavation is 50 mm this may be ok if the tempered low alloy steels shall be 25°C less than the tempering taper required in 310 gives adequate access for welding. temperature of the material as stated in the material certificate. 310 The excavated portion of the weld shall be large enough 410 The heat treatment temperature cycle charts shall be to ensure complete removal of the defect, and the ends and available for verification if requested. sides of the excavation shall have a gradual taper from the bot- tom of the excavation to the surface. Defects can be removed 411 For materials other than C-Mn and low alloy steels the by grinding, machining or air-arc gouging. Air-arc gouging PWHT heating and cooling rates, temperature, and holding shall be controlled by a documented procedure including the time shall be as recommended by the material manufacturer. allowed variables according to AWS C5.3. If air-arc gouging is used, the last 3 mm through the root of the weld shall be G 500 Welding of pipeline girth welds removed by mechanical means and the whole excavated area Production welding shall be ground to remove any carbon enriched zones. The width and the profile of the excavation shall be sufficient to 501 These requirements apply to welding of girth welds in ensure adequate access for re-welding. Complete removal of pipelines regardless of whether the welds are made onboard a the defect shall be confirmed by magnetic particle testing, or laying vessel or at other locations, onshore or offshore. Girth by dye penetrant testing for non ferromagnetic materials. welds in expansion loops, pipe strings for reeling or towing Residuals from the NDT shall be removed prior to re-welding. and tie-in welds are considered as pipeline girth welds. 502 The type of welding equipment and the welding proce- 311 Weld repairs shall be ground to merge smoothly into the dure shall be qualified prior to installation welding. original weld contour. 503 In addition to the requirements given in G100 and G200 312 Repair by welding after final heat treatment is not per- the requirements below shall apply for production welding of mitted. pipeline girth welds. G 400 Post weld heat treatment 504 Bevels shall be prepared by machining. Bevelling by thermal cutting shall be performed only when bevelling by 401 Welds shall be subjected to PWHT as specified in the pWPS or WPS and to a documented procedure. machining is not feasible e.g. for tie-in and similar situations. Bevels prepared by thermal cutting shall be dressed to obtain 402 Post weld heat treatment shall be performed for welded the final configuration. The bevelling operator shall check the joints of C-Mn and low alloy steel having a nominal wall thick- bevel configuration for compliance with suitable tools or ness above 50 mm, unless fracture toughness testing shows gauges at regular intervals. acceptable values in the as welded condition. In cases where 505 When welds are to be examined by manual or automated the minimum design temperature is less than -10°C, the thick- ultrasonic testing, reference marking shall be made on both ness limit shall be specially determined. sides of the joint as a scribed line around the pipe circumfer- 403 If post weld heat treatment is used to obtain adequate ence. The reference marking shall be at a uniform and known resistance of welded joints against sulphide stress cracking, distance from the root face of the bevel preparation. The dis- this shall be performed for all thicknesses. tance from the root face and the tolerances shall be established, 404 Whenever possible, PWHT shall be carried out by plac- See also Appendix E, B108 and B1000. ing the welded assembly in an enclosed furnace. Requirements 506 All pipes shall be cleaned on the inside to remove any to PWHT in an enclosed furnace are given in Sec.8 D500. and all foreign matters and deposits in accordance with a doc- umented procedure. 405 If PWHT in an enclosed furnace is not practical, local PWHT shall be performed by means of electric resistance heat- 507 For S-lay welding, longitudinal welds shall be located in ing mats or other methods as agreed or specified. The PWHT the top quadrant. shall cover a band over the entire length of the weld. The band 508 The longitudinal welds shall be staggered at least 50 shall be centred on the weld and the width of the heated band mm. Girth welds shall be separated at least 1.5 pipe diameters shall not be less than 5 times the thickness of the thicker com- or 500 mm, whichever is larger. Whenever possible girth ponent in the assembly. welds shall be separated by the maximum possible distance. 406 Unless otherwise agreed temperatures shall be measured 509 Excessive misalignment may be corrected by hydraulic by thermocouples in effective contact with the material and at or screw type clamps. Hammering or heating for correction of a number of locations to monitor that the whole length of the misalignment is not permitted. Root gaps shall be even around weld is heated within the specified temperature range. In addi- the circumference. The final fit-up shall be checked with tion temperature measurements shall be made to confirm that spacer tools prior to engaging line-up clamps or tack welding. undesired temperature gradients do not occur. 510 Correction of angular misalignment of the pipe axis by 407 Insulation shall be provided if necessary to ensure that mitre welds is not permitted. the temperature of the weld and the HAZ is not less than the temperature specified in the pWPS or WPS. The width of the 511 Power operated internal line-up clamps shall be used insulation shall be sufficient to ensure that the material temper- whenever possible. ature at the edge of the insulation is less than 300°C. Internal line-up clamps shall not be released unless the pipe is 408 The rate of heating for C-Mn and low alloy steels above fully supported on each side of the joint. 300°C shall not exceed 5500/t °C · h1 and the rate of cooling External line-up clamps shall not be removed unless the pipe is while above 300°C shall not exceed 6875/t °C · h1 with t fully supported on each side of the joint and not before the com- expressed in mm. During heating and cooling at temperatures pleted parts of the root pass meet the requirements to length of above 300°C the temperature variation shall not exceed 35°C each section, the spacing of the sections, the number of sections in any weld length of 1000 mm. and the percentage of circumference required by the WPS.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.C – Page 183

512 Line-up clamps should not be removed before the first H. Material and Process Specific Requirements two passes are completed 513 If cables are present inside the pipeline, e.g. buckle H 100 Internally clad/lined carbon steel and duplex detector cables, and radiographic testing is used, the starts and stainless steel stops shall be made away from the six o’clock position to avoid WPS masking of starts and stops on radiographs. 101 In addition to the applicable data given in Table C-1 the 514 Copper contact tips and backing strips shall be checked WPS shall specify the following, as recorded during the weld- on a regular basis for damage that could introduce copper con- ing procedure qualification: tamination in welds. Damaged contact tips and backing strips shall be replaced. — the minimum time period of backing gas application prior to start of welding 515 Procedures shall be established for pre-cleaning, in — the minimum time period of backing gas application dur- process cleaning and post cleaning of welds. ing welding 516 If a pipe is to be cut for any reason, the cut shall be at a — the minimum time period of backing gas application after minimum distance of 25 mm from the weld toe. welding 517 The root and the first filler pass shall be completed at the — description of the back-purge dam type and method. first welding station before moving the pipe. Moving the pipe Essential variables at an earlier stage may be permitted if an analysis demonstrates that the pipe can be moved without any risk of introducing 102 The following essential variables shall apply in addition damage to the deposited weld metal. See Sec.10 A706. to those in Table C-2: Repair welding — any reduction of the time of backing gas application prior 518 In addition to the requirements given in G300 the below to start of welding requirements shall apply for repair welding of pipeline girth — any reduction in the number of passes completed before welds. stopping back-purging. 519 For through thickness repairs where the defects to be Welding consumables for clad/lined carbon steel repaired are less than 150 mm apart, they shall be considered and repaired as one continuous defect. 103 For single sided (field) joints, the same type of welding consumable should be used for all passes needed to complete 520 The location of repair of burn through and other in proc- the joint. Alternative welding consumables may be considered ess root repairs shall be marked on the outside of the pipe to for fill and capping passes after depositing a weld thickness not inform NDT personnel that a root repair has been made. less than 2 times thickness of the cladding/lining. The alterna- 521 If the pipe and the area of repair is not exposed to bend- tive welding consumables shall be documented to be compati- ing and/or axial stresses at the repair location the length of a ble with the welding consumables used for the root area, the repair excavation shall not exceed 30% of the pipe circumfer- base material and the applicable service conditions. Welding ence for partial penetration repairs and 20% of the pipe circum- consumables shall be segregated from consumables for C-Mn ference for through thickness repairs. steel. 522 Long defects may require repair in several steps to avoid Welding consumables for duplex steel yielding and cracking. The maximum length of allowable 104 Welding consumables with enhanced nickel and nitro- repair steps shall be calculated based on the maximum stresses gen content shall be used unless full heat treatment after weld- present in the joint during the repair operation, and shall not ing is performed. Sufficient addition of material from the exceed 80% of SMYS. welding consumables is essential for welding of the root pass 523 If the repair is performed at a location where the pipe and the two subsequent passes. Welding consumables shall be and the area of repair is exposed to bending and axial stresses segregated from consumables for C-Mn steel. the allowable length of the repair excavation shall be deter- Backing and shielding gases mined by calculations, see Sec.10 A704 and 705. 105 Backing and shielding gases shall not contain hydrogen 524 If repairs can not be executed according to the require- and shall have a dew point not higher than 30°C. The oxygen ments above, or are not performed successfully, the weld shall content of the backing gas shall be less than 0.1% during weld- be cut out. ing of the root pass. Backing gas shall be used for welding of 525 Full records of all repairs, including in-process root root pass and succeeding passes. (Exception from this require- repairs, shall be maintained. ment may be tie-in welds when stick electrodes are used for root bead welding, subject to agreement.) Production tests Production 526 Production tests (see Sec.10 A900) shall be performed in a manner which, as far as possible, reproduces the actual weld- 106 Welding of clad/lined carbon steel and duplex stainless ing, and covers the welding of a sufficient large pipe section in steel may be performed by the welding processes listed in the relevant position. Production welds cut out due to NDT A200. The welding shall be double sided whenever possible. failure may be used. Welding of the root pass in single sided joints will generally require welding with Gas Tungsten Arc Welding (GTAW / G 600 Welding and PWHT of pipeline components 141) or Gas Metal Arc Welding (GMAW / 135). 601 The Manufacturer shall be capable of producing pipeline 107 Onshore fabrication of clad/lined carbon steel and components of the required quality. duplex stainless steel shall be performed in a workshop, or part thereof, which is reserved exclusively for this type of material. 602 Welding and PWHT shall be performed in accordance During all stages of manufacturing, contamination of CRA and with G100 through G400 above. duplex steel with carbon steel and zinc shall be avoided. Direct 603 Production tests shall be performed in a manner which, contact of the CRA with carbon steel or galvanised handling as far as possible, reproduces the actual welding, and covers equipment (e.g. hooks, belts, rolls, etc.) shall be avoided. Tools the welding of a sufficient large test section in the relevant such as earthing clamps, brushes etc, shall be stainless steel position. Production welds cut out due to NDT failure may be suitable for working on type of material in question and not used. previously used for carbon steel. Contamination of weld bevels

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 184 – App.C and surrounding areas with iron and low melting point metals avoid carbon steel contamination of the corrosion resistant such as copper, zinc, etc. is not acceptable. The grinding material. Procedures for examination of surfaces and removal wheels shall not have previously been used for carbon steel. of any contamination shall be prepared. Parts of internal line-up clamps that come in contact with the material shall be non-metallic or of a similar alloy as the inter- H 200 13Cr martensitic stainless steel nal pipe surface. Thermal cutting shall be limited to plasma arc WPS and essential variables cutting. 201 The additional data for the WPS and the essential varia- 108 The weld bevel shall be prepared by milling or other bles given in H101 and 102 also applies to 13Cr martensitic agreed machining methods. The weld bevel and the internal stainless steels. and external pipe surface up to a distance of at least 25 mm from the bevels shall be thoroughly cleaned with an organic Welding consumables solvent. 202 The requirements to backing and shielding gases in 109 Welding consumables shall be segregated from consum- H105 also applies to 13Cr MSS. ables for C-Mn / low alloy steels. Production 110 The backing gas composition shall be monitored using 203 Welding of 13Cr MSS may be performed by the welding an oxygen analyser immediately prior to starting or re-starting processes listed in A200, except active gas shielded methods. welding. The flow rate of the back purge gas shall be adjusted The welding shall be double sided whenever possible. Welding to prevent gas turbulence and possible air entrainment through of the root pass in single sided joints will generally require open weld seams. welding with Gas Tungsten Arc Welding (GTAW / 141). 111 Inter-run cleaning shall be by grinding to bright, defect 204 During all stages contamination of 13Cr MSS with car- free material for all passes. bon steel and zinc shall be avoided. Direct contact with carbon steel or galvanised handling equipment (e.g. hooks, belts, rolls, 112 Internal high-low of clad/lined pipes shall not exceed etc.) shall be avoided. Tools such as earthing clamps, brushes 1 mm unless otherwise qualified or if the cladding at pipe ends etc., shall be stainless steel suitable for working on type of has a thickness increase allowing larger misalignment. In any material in question and not previously used for carbon steel. case the internal high-low shall not reduce the thickness of the Contamination of weld bevels and surrounding areas with iron CRA below the specified thickness. Internal high-low of and low melting point metals such as copper, zinc, etc. is not duplex stainless steel linepipe shall not exceeded 2 mm or 1% acceptable. The grinding shall not have previously been used of the pipe internal diameter, whichever is less, unless other- for carbon steel. Parts of internal line-up clamps that come in wise qualified. contact with the material shall be non-metallic or of a similar 113 Welds shall be multipass and performed in a continuous alloy as the internal pipe surface. Thermal cutting shall be lim- operation. ited to plasma arc cutting. 114 The interpass temperature shall be measured directly 205 The weld bevel shall be prepared by milling or other where a weld run will start and terminate. The weld zone shall agreed machining methods. The weld bevel and the internal be kept below the maximum interpass temperature before a and external pipe surface up to a distance of at least 25 mm welding run is started. Unless post weld heat treatment is per- from the bevels shall be thoroughly cleaned with an organic formed the maximum interpass temperature shall not exceed solvent. 100°C for nickel based CRAs and 150°C for all other CRAs. 206 Welding consumables shall be segregated from consum- 115 When clad/lined C-Mn linepipe is cut and/or re-bevelled ables for C-Mn steel. a lamination check by through thickness ultrasonic testing and 207 The backing gas composition shall be monitored using dye penetrant testing on the bevel face shall be performed. If a an oxygen analyser immediately prior to starting or re-starting laminar discontinuity is detected on the bevel face the clad- welding. Care shall be taken to adjust the flow rate of the back ding/liner shall be removed and a seal weld shall be overlay purge gas to prevent gas turbulence and possible air entrain- welded at the pipe end. ment through open weld seams. Additional for welding of duplex steel 208 Inter-run cleaning shall be by grinding to bright, defect 116 The heat input must be controlled to avoid detrimental free material for all passes using designated tools. weld cooling rates. For optimum control of the heat input faster 209 Internal high-low of 13Cr MSS linepipe shall not welding speeds and associated higher welding current should exceeded 2 mm or 1% of the pipe internal diameter, whichever be used. Stringer beads shall be used to ensure a constant heat is less, unless otherwise qualified. input, and any weaving of the weld bead shall be limited to maximum 3X filler wire/electrode diameter. For girth welds 210 Welds shall be multipass and performed in a continuous the heat input shall be kept within the range 0.5 - 1.8 kJ/mm operation. and avoiding the higher heat input for small wall thicknesses. 211 The interpass temperature shall be measured directly at For wall thickness > 25 mm and provided post weld heat treat- the points where a welding run will start and terminate. The ment (solution annealing) is performed a maximum heat input weld zone shall be below the maximum interpass temperature of 2.4 kJ/mm is acceptable. For the root pass the heat input before a welding run is started. The maximum interpass tem- shall be higher than for second pass. For SAW welding small perature shall not 150oC. diameter wire and modest welding parameters (high travel 212 Unless otherwise agreed PWHT (e.g.≈ 5 minutes speed and low arc energy) shall be used. The depth to width o ratio of the weld deposit shall be less than 1.0. at≈ 630 C) shall be performed in accordance with the PWHT procedure qualified during welding qualification 117 Any post weld heat treatment shall be performed in 213 Excavation of repair grooves shall be by chipping, accordance with the qualified post weld heat treatment proce- grinding or machining. Air-arc gouging shall not be used. dure. Entire welds shall be removed by plasma cutting or machining. 118 Excavation of repair grooves shall be by chipping, 214 All operations during welding shall be carried out with grinding or machining. Air-arc gouging shall not be used. adequate equipment and/or in a protected environment to Entire welds shall be removed by plasma cutting or machining. avoid carbon steel contamination of the corrosion resistant 119 All operations during welding shall be carried out with material. Procedures for examination of surfaces and removal adequate equipment and/or in a protected environment to of any contamination shall be prepared.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.C – Page 185

H 300 Pin brazing and aluminothermic welding Repair of welded/brazed anode leads 301 Anode leads may be attached by pin brazing or alumino- 309 Welded/brazed anode leads not meeting the require- thermic welding according to qualified procedures including ments in F500 shall be removed and the affected area shall be full details of the technique used and associated equipment. removed by grinding. Qualification of operators 310 For welded/brazed anode leads that are attached directly 302 Operators that have performed a qualified procedure test onto pressure containing parts the ground areas shall blend are thereby qualified. smoothly into the surrounding material. Complete removal of defects shall be verified by local visual inspection and polish- 303 Other operators shall prior to carrying out operation ing and etching to confirm removal of copper penetration. The work, each complete three test pieces made in accordance with remaining wall thickness in the ground area shall be checked the procedure specification under realistic conditions. Each by ultrasonic wall thickness measurements to verify that the test piece shall pass the test for electrical resistance and thickness of the remaining material is more than the specified mechanical strength according to Table C-6 and F500. minimum. Imperfections that encroach on the minimum per- Essential variables missible wall thickness shall be classified as defects. 304 Essential variables for pin brazing and aluminothermic welding shall be: Base material grade and chemical composition: I. Hyperbaric Dry Welding — a change in grade I 100 General — a change in the supply condition (TMCP, Q/T or normal- 101 Underwater welding on pressure containing components ised) for hydrocarbons shall be carried out utilising a low hydrogen — any increase in Pcm of more than 0.02, CE of more than process, in a chamber (habitat) where the water has been dis- 0.03 and C content of more than 0.02% for C-Mn linepipe. placed. Other methods can be used on non-pressure containing components subject to special acceptance by Purchaser. For both methods a change in: 102 All relevant welding parameters shall be monitored and — cable dimension recorded at the surface control station under supervision by a — process (brazing or aluminothermic welding) welding co-ordinator. The welding area shall have continuous — make, type and model of equipment communication with the control station. All operations includ- — method for cleaning and preparation of cable ends and ing welding shall be monitored by a video system that can be cable attachment area. remotely controlled from the control station. For Aluminothermic welding a change in: I 200 Qualification and testing of welding personnel for hyperbaric dry welding — type, classification and brand of start and welding powder Hyperbaric welding co-ordinator — type, make and model of other consumables — volume (cartridge, packaging type) and type of start and 201 The welding co-ordinator for hyperbaric dry welding welding powder that will change the heat input by more shall have EWE or IWE qualifications. In addition the welding than ± 15%. co-ordinator shall be familiar with and have adequate experi- ence with welding procedure qualification and offshore opera- For Pin brazing a change in: tions for the hyperbaric welding system used. 202 The welding co-ordinator shall, when applicable, have — type, composition, make and model of pin for pin brazing completed the training programme required for mechanised — the minimum preheat or working temperature welding required in I204 to I206. — range of equipment settings for pin brazing — the equipment earth connection area. Welders for hyperbaric welding 203 Prior to qualification testing for underwater (hyperbaric) Production requirements for welding/brazing of anode leads dry welding of girth welds, welders shall have passed a weld- 305 The anode cable attachments shall be located at least 150 ing test for pipeline girth welds as specified in B200 above. mm away from any weld. Training programme 306 For cable preparation cable cutters shall be used. The 204 The hyperbaric welders shall be informed on all aspects insulation shall be stripped for the last 50 mm of the cable to of the work related to the welding operation, the qualified be attached. The conductor core shall be clean, bright and dry. welding procedures, the applicable technical specifications Greasy and oily conductor cores shall be cleaned with residue and layout of the welding and habitat system. free solvent or dipped in molten solder. Corroded conductor cores shall be cleaned to bright metal with brush or other 205 Hyperbaric welders shall receive a training programme means. Wet conductor cores shall be dried by rapid drying res- and pass an examination upon completion of the programme. idue free solvent, alcohol or hand torch. The training programme shall be structured according to Annex B of ISO 15618-2. 307 The cable attachment area, and for pin brazing also the equipment earth connection area, shall be cleaned for an area 206 In addition, for mechanised welding the training pro- of minimum 50 mm × 550 mm. All mill scale, rust, grease, gramme shall include: paint, primer, corrosion coating, and dirt shall be removed and — software structure of welding programme and loading of the surface prepared to finishing degree St 3 according to ISO any welding programme prior to start of welding 8501-1. The surface shall be bright, clean and dry when weld- — perform a complete butt weld, from programming of the ing/brazing is started. welding parameters to welding of the cap passes Production testing — repair welding 308 Each welded/brazed anode lead shall be subjected to — daily maintenance of the welding equipment electrical resistance test and mechanical strength test accord- — knowledge about the functions of the welding heads and ing to Table C-6 with acceptance criteria according to F500. how to replace consumables such as welding wire, contact tubes, gas nozzles and tungsten electrodes.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 186 – App.C

Test welding the qualification welding. 207 The hyperbaric welders shall perform a qualification test Guidance note: using welding equipment identical or equal in function to the The dew point temperature at atmospheric pressure (1 bar) is hyperbaric welding equipment used for production welding. often used to specify the upper level acceptance criteria for the 208 The qualification welding for hyperbaric welding shall moisture content in shielding gases. However, for hyperbaric con- be performed in accordance with ISO 15618-2. ditions, even a low dew-point temperature (e.g. -30°C for an Argon gas) can result in condensation of water at the relevant Qualification testing of welders working depth/pressure and temperature (e.g. at 165 m at 5°C). 209 For welder qualification for dry hyperbaric welding of This means that the gas is saturated with water when used at this girth welds and other butt weld configurations the test pieces depth and condensed water will be present at greater depths. In general the acceptance level for the water content in the shield gas shall be subject to same the testing and acceptance criteria as must be specified precisely. The use of “ppm” alone is not suffi- for pipeline girth welds in B200. cient. It must be related either to volume or weight of the gas. 210 A welder is deemed qualified for the applicable ranges It is the water concentration in the gas at the working depth/pres- of approval stated in Clause 6 of ISO 15618-2 when the fol- sure which is essential. This can be specified as weight of the lowing requirements for inspection and testing of test pieces, water per volume unit (mg H2O/m3) or partial pressure of the as applicable, are met: H2O (millibar H2O).

— 100% visual examination and 100% ultrasonic testing ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- with test requirements and acceptance criteria in accord- ance with Appendix D I 600 Welding equipment and systems for hyperbaric — macro-examination according to Appendix B. The speci- dry welding men shall meet the requirements of ISO 15618-2, 601 In addition to the requirements given in B100 the fol- Chapter 8 lowing shall apply unless the voltage is measured at the arc — if 100% radiographic testing with test requirements and during both qualification and production welding: acceptance criteria in accordance with Appendix D is per- formed in lieu of 100% ultrasonic testing, bend testing as — Welding cables shall have the same dimension and required in ISO 9606 shall be performed for all welding approximately the same resistance during the welding pro- processes. cedure qualification and production welding. If necessary artificial resistance to simulate the full cable length used in Retesting production should be used during qualification welding. 211 See ISO 15618-2, Chapter 9. I 700 Welding procedures for hyperbaric dry welding Period of validity and prolongation Contents of pWPS 212 The period of validity shall be in accordance with ISO 15618-2, paragraph 10.1 and prolongations in accordance with 701 A pWPS shall be prepared for each welding and repair paragraph 10.2. welding procedure that will be qualified for use during welding of pipeline girth welds. I 300 Welding processes for hyperbaric dry welding 702 The pWPS shall contain the information required for the 301 The allowable welding processes are: applicable welding processes, including any tack welds and shall be prepared in accordance with Table C-1 and shall pro- — SMAW (Process ISO 4063-111) pose limits and ranges for the applicable essential variables for — G-FCAW (Process ISO 4063-137) welding and repair welding procedures given in Tables C-2 — GMAW (Process ISO 4063-131) and C-8. — GTAW (Process ISO 4063-141). 703 In addition the pWPS shall address the following: I 400 Welding consumables for hyperbaric dry welding 401 In addition to the requirements given in C100 to C400 — part of the root to be left open, number of runs to be depos- the following shall apply: ited before closing the root and methods for closing the root — conditions for release of external line-up clamps including — consumables should be of a type that is tested or developed the percentage of the circumference for the welded root sec- for dry hyperbaric welding with respect to arc stability and tions, the length of each section and spacing of the sections metal transfer behaviour and mechanical properties — water depth (minimum/maximum) — procedures for transfer of consumables to the hyperbaric — pressure inside the chamber chamber and for consumable handling in the chamber, — gas composition inside the chamber including disposal of unused exposed consumables. The — humidity, maximum level procedure shall particularly consider the maximum — temperature inside the chamber (minimum/maximum) humidity expected during production welding — length, type and size of the welding umbilical — all consumables for qualification of the welding procedure — position for voltage measurements shall be from the same batch, a consumable batch being — welding equipment. defined as the volume of product identified by the supplier under one unique batch/lot number, manufactured in one 704 The welding procedures for closing possible vent holes continuous run from batch/lot controlled raw materials. shall also be qualified. This qualification test shall as a mini- mum include impact testing of weld metal, FL, FL+2, FL+5, I 500 Shielding and backing gases for hyperbaric dry hardness testing and for CRA also metallographic examina- welding tion. The qualification may be performed as a "buttering" test 501 In addition to the requirements given in C500 the fol- providing considerations are made to start/stop and that access lowing shall apply: limitations for the actual production welding is simulated. — the purity of shielding and backing gases shall be 99.995 Essential variables for Ar and 99.997% for He. The maximum allowable 705 The essential variables for hyperbaric dry welding shall moisture content in the gas used in the actual welding is be according to Table C-2 with additional requirements governed by the moisture content of the gas used during according to Table C-8 below.

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Table C-8 Additional essential variables for hyperbaric dry welding A Qualified water depth for SMAW and GTAW 1) Water depth (WD) in metres: 1 WD ≤ 200 m: Any increase in excess of + 20% or 10 m or whichever is greater. 2 200 m < WD ≤ 300 m: ± 10% 3 300 m < WD ≤ 500 m: ± 10% B Habitat environment Gas composition (argon, heliox, air or 1 For water depth ≤ 200 m: A change from argon or heliox to air or nitrox but not vice versa nitrox), and humidity 2 For water depth > 200 m: Any change in gas composition 3 Any increase in relative humidity for SMAW and G-FCAW flux based welding processes oth- erwise any increase in excess of + 10% C Monitoring of electrical parameters Method and point of monitoring 1 Any change Note 1) For other processes the depth of qualification shall be agreed. I 800 Qualification welding for hyperbaric dry welding monitoring and communication equipment shall be performed 801 Qualification welding shall be performed in the habitat to a written and agreed procedure, and accepted before lower- at a water depth selected in accordance with the intended range ing the habitat to the working position. The function test shall of qualification, or under appropriately simulated conditions. also include verification of that the welding parameters are The qualification test program shall consist of a minimum of applied correctly on the actual equipment. one completed joint for manual welding, and a minimum of 1104 If used shielding and/or backing gas shall be of quali- three joints for mechanised welding systems. fied purity including moisture limit. Gas purity and composi- 802 Qualification welding shall comply with E100 and the tion in all containers shall be certified and traceable to the gas following additions: storage containers. The gas purity and moisture content shall be verified after purging the gas supply system prior to start of — for SMAW welding shall be performed at the maximum welding. The moisture content of the shielding gas shall be expected humidity in the chamber during production monitored at/near the torch during welding operation. welding 1105 Any pup pieces shall be bevelled at the surface and — the power source and the technical specification for the checked for correct length, laminations at cut ends and square- welding system shall be equivalent to the production sys- ness of ends. tem — the pipes shall be rigidly fixed to simulate restraint during 1106 At completion of positioning of the two pipe sections welding to be welded, the following information, as a minimum, shall — method and position/point for monitoring of electrical be reported to the surface: parameters shall be as for production welding — pipe sections to be connected (pipe number, heat number — with increasing pressure the voltage gradient will increase. if possible) Accordingly may small changes in arc length and or oper- — approximate distance from the girth weld to the pipe ating depth result in considerable changes in the monitored extremity values of arc voltage. For calculations of the heat input, the arc voltage shall be recorded at the position/point of weld- — position of the longitudinal welds. ing during qualification of the welding procedure and the 1107 If the requirement for staggering of welds can not be difference between these values and remote monitored met, any reduction in the separation of welds shall be limited values recorded for use during production welding. to two pipe lengths. Repair welding procedures 1108 All operations including welding shall be monitored by 803 Qualification welding shall be performed in compliance a video system that can be remotely controlled from the control with the requirements given in E200. station and the welding area shall have continuous communi- cation with the control station. All relevant data shall be mon- I 900 Qualification of welding procedures for hyper- itored and recorded at the surface control station under baric dry welding supervision by the welding co-ordinator, including: 901 The requirements given in E300 shall apply. — environmental conditions (humidity, temperature, atmos- phere composition) I 1000 Examination and testing — welding parameters (mechanised and automatic welding) 1001 Examination and testing shall be in accordance with — gas moisture content F100, F200 and F300. — preheat and interpass temperature — information transmitted by the welders. I 1100 Production welding requirements for dry hyper- baric welding 1109 The following records shall be presented as part of the 1101 In addition to the applicable requirements given in G, documentation: H100 and H200, the requirements below shall apply for dry hyperbaric production welding: — chart recordings of welding current, arc voltage, filler wire speed, welding speed 1102 The habitat shall be of adequate size to allow access for — video recording from the weld observation cameras. welding and for all necessary welding, safety and life support equipment. Further the habitat shall be lighted and be fitted Weld repair with remote cameras for surveillance. Welding fumes shall not 1110 The applicable requirements given Table C-7 shall prevent the use of the remote cameras in the welding area. apply. In addition repairs exceeding 30% of pipe OD shall be 1103 A function test of the habitat, habitat equipment and the performed only if agreed.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 188 – App.D

APPENDIX D NON-DESTRUCTIVE TESTING (NDT)

A. General Guidance note: The detectability of cracks with radiographic testing depends on A 100 Objective the crack height, the presence of branching parts of the crack, the direction if the X-ray beam to the orientation of the crack and 101 This Appendix specifies the requirements for methods, radiographic technique parameters. Reliable detection of cracks equipment, procedures, acceptance criteria and the qualifica- is therefore limited. tion and certification of personnel for visual examination and Lack of sidewall fusion will probably not be detected unless it is non-destructive testing (NDT) of C-Mn steels, low alloy steels, associated with volumetric imperfections or if X-ray beam is in duplex steels, other stainless steels and clad steel materials and the direction of the side-wall.

weldments for use in pipeline systems. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 102 This Appendix does not cover automated ultrasonic test- ing (AUT) of girth welds. Specific requirements pertaining to 405 When manual non-destructive testing in special cases is AUT of girth welds are given in Appendix E. used as a substitute for automated ultrasonic testing for pipe- line girth welds, both radiographic and ultrasonic testing of the 103 Requirements for NDT and visual examination of other girth weld shall be performed. materials shall be specified and be in general agreement with the requirements of this Appendix. 406 Alternative methods or combination of methods for detection of imperfections may be used if the methods are A 200 Applicability of requirements demonstrated as capable of detecting imperfections with an acceptable equivalence to the preferred methods. 201 The requirements in this Appendix are given in several subsections with each subsection dealing with the non-destruc- A 500 Personnel qualifications tive testing of specific objects. Manual or semi-automatic NDT 202 The requirements given in subsection A are applicable 501 Personnel performing manual or semi-automated NDT for the whole of this Appendix. and interpretation of test results shall be certified to Level 1 or 203 The requirements given within the other subsections are Level 2 by a Certification Body or Authorised Qualifying applicable only to the scope of the subsection as indicated in Body in accordance with EN 473, ISO 9712 or the ASNT Cen- the title of the subsection, unless specific references to other tral Certification Program (ACCP). Personnel qualification to subsections are made. an employer based qualification scheme as SNT-TC-1A may be accepted if the employer’s written practice is reviewed and A 300 Quality assurance found acceptable and the Level 3 is ASNT Level III or ACCP Professional Level III and certified in the applicable method. 301 NDT Contractors and organisations shall as a minimum have an implemented quality assurance system meeting the Automated NDT, general general requirements of ISO 9001 and supplemented with the 502 Personnel calibrating equipment and interpreting results requirements given in ASTM E1212. from automated equipment for NDT shall be certified to an appropriate level according to a certification scheme meeting A 400 Non-destructive testing methods the requirements of 501. In addition, they shall be able to doc- ument adequate training and experience with the equipment in 401 Methods of NDT shall be chosen with due regard to the question, and shall be able to demonstrate their capabilities conditions influencing the sensitivity of the methods. The abil- with regard to calibrating the equipment, performing an oper- ity to detect imperfections shall be considered for the material, ational test under production/site/field conditions, and evaluat- joint geometry and welding process used. ing size and location of imperfections. 402 As the NDT methods differ in their limitations and/or Automated NDT, linepipe manufacture sensitivities, combination of two or more methods shall be considered since this is often required in order to ensure opti- 503 Personnel operating automated equipment for NDT dur- mum probability of detection of harmful defects. ing manufacture of linepipe shall be certified according to ISO 11484 or equivalent certification scheme. 403 Magnetic particle, eddy current or magnetic flux leakage testing is preferred for detection of surface imperfections in Preparation of NDT procedures ferromagnetic materials. For detection of surface imperfec- 504 Preparation of NDT procedures and execution of all tions in non-magnetic materials, either liquid penetrant testing NDT shall be carried out under the responsibility of Level 3 or eddy current testing shall be preferred. personnel and shall be performed by personnel holding at least Level 2 qualifications. Personnel holding Level 1 qualifica- 404 Ultrasonic and/or radiographic testing shall be used for tions may carry out NDT under the direct supervision of Level detection of internal imperfections. It may be necessary to sup- 2 personnel. plement ultrasonic testing by radiographic testing or vice versa, in order to enhance the probability of detection or char- Visual examination acterisation/sizing of the type of flaws that can be expected. 505 Personnel performing visual examination of welds shall Radiographic testing is preferred for detection of volumetric have documented training and qualifications according to NS imperfections. For material thicknesses above 25 mm radio- 477 or minimum IWIS or equivalent certification scheme. Per- graphic testing should always be supplemented by ultrasonic sonnel performing visual examination of other objects shall testing. have training and examination according to a documented in- house standard. Ultrasonic testing shall be preferred for detection of planar imperfections. Whenever determination of the imperfection Visual acuity height and depth is necessary, e.g. as a result of an ECA, ultra- 506 Personnel interpreting radiographs, performing ultra- sonic testing is required. sonic testing, interpreting results of magnetic particle and liq-

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 189 uid penetrant testing and performing visual examination shall in the weld area and state if the weld satisfies the acceptance have passed a visual acuity test such as required by EN 473, criteria or not. paragraph 6.3 or a Jaeger J-w test at 300 mm, within the previ- 106 The report shall include the reporting requirements of the ous 12 months. applicable standard, NDT procedure and acceptance criteria. A 600 Timing of NDT At least the following minimum information must be given: 601 Whenever possible, NDT of welds shall not be per- formed until 24 hours has elapsed since completion of weld- — Name of the company and operator carrying out the testing ing. including certification level of the operator — Object and drawing references 602 If welding processes ensuring a diffusible hydrogen con- — Place and date of testing tent of maximum 5 ml/100 g of weld metal are used, adequate — Material type and dimensions handling of welding consumables is verified, shielding gas — Post weld heat treatment, if required content of H2 is controlled, or measures (such as post heating — Location of examined areas, type of joint of the weldment) are taken to reduce the contents of hydrogen, — Welding process used the time in 601 above can be reduced, subject to agreement. — Surface conditions 603 NDT of pipeline installation girth welds and longitudi- — Temperature of the object nal welds in linepipe can be performed as soon as the welds — Number of repairs if specific area repaired twice or more have cooled sufficiently to allow the NDT to be performed. — Contract requirements e.g. order no., specifications, spe- cial agreements etc. — Example of reporting forms — Sketch showing location and information regarding B. Manual Non-Destructive Testing detected defects and Visual Examination of Welds — Extent of testing — Test equipment used B 100 General — Description of the parameters used for each method 101 Manual non-destructive testing of welds shall be per- — Description and location of all recordable indications formed in compliance with the standards listed below and as — Testing results with reference to acceptance level required in the following: — Other information related to the specific method may be listed under each method. Radiography ISO 17636 Ultrasonic ISO 17640 B 200 Radiographic testing of welds Magnetic Particle ISO 17638 201 Radiographic testing shall be performed in compliance Liquid Penetrant ASTM E 1417 with ISO 17636 and as required below. Eddy Current ISO 17643 Visual examination ISO 17637 202 Radiographic testing shall be performed by use of X-ray according to accepted procedures. Use of radiographic iso- Non-destructive testing procedures topes (gamma rays) may be required in some situations and is 102 Non-destructive testing shall be performed in accord- subject to agreement in each case. If use of radiographic iso- ance with written procedures that, as a minimum, give infor- topes is agreed, Se 75 as gamma ray source shall be preferred. mation on the following aspects: Radiographic testing procedures — applicable code(s) or standard(s) 203 Radiographic testing procedures shall be according to — welding method (when relevant) B102 through B104 and include: — joint geometry and dimensions — material(s) — radiographic technique class — method — radiation source — technique — technique — equipment main and auxiliary — geometric relationships — consumables (including brand name) — film type — sensitivity — intensifying screens — calibration techniques and calibration references — exposure conditions — testing parameters and variables — processing — assessment of imperfections — Image Quality Indicator sensitivities in percent of the wall — reporting and documentation of results thickness, based on source and film side indicators respec- — reference to applicable welding procedure(s), tively — example of reporting forms — backscatter detection method — acceptance criteria. —density 103 If alternative methods or combinations of methods are — film side Image Quality Indicator (IQI) identification used for detection of imperfections, the procedures shall be method prepared in accordance with an agreed code or standard. The —film coverage need for procedure qualification shall be considered in each — weld identification system. case based on the method's sensitivity in detecting and charac- Classification of radiographic techniques terising imperfections and the size and type of defects to be detected. 204 The radiographic techniques used shall be according to Class B and the requirements below. 104 All non-destructive testing procedures shall be signed by the responsible Level III person. 205 Class B techniques shall also be used when using Reporting gamma ray sources, unless otherwise agreed. 105 All NDT shall be documented such that the tested areas 206 If, for technical reasons, it is not possible to meet one of may be easily identified and such that the performed testing the conditions specified for Class B, the note to can be duplicated. The reports shall identify the defects present Chapter 5 of ISO 17636 shall apply.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 190 – App.D

Image Quality Indicators used whenever possible 207 Image Quality Indicators (IQIs) shall meet the require- — Fluormetallic screens may be used in combination with X- ments given in ISO 19232. The wire material shall have a coef- ray based on a satisfactory procedure qualification test ficient of absorption as close as possible to the material tested. where all requirements to sensitivity are met. Films used If the absorption coefficients of the IQI material and the mate- with fluormetallic screens shall be designed for use with rial tested differ by more than 20%, an experimental evaluation this screen type according to ISO 19232-4 shall be performed to establish the — For pipe with internal diameter < 250 mm gamma ray and acceptable image quality values. panoramic (single wall single image) exposures may be used. The gamma ray source shall preferably be Se 75 Sensitivity used with a film system class better than C4 according to 208 The sensitivities obtained during production radiogra- ISO 17636, Table 3 unless otherwise agreed. Other types phy shall at least meet the requirements of ISO 17636, Annex of radiation sources may be used for small wall thick- A except for double wall techniques with the IQI on the film nesses in combination with other film types. The use of side. For this technique, the sensitivity of the film side IQI gamma ray sources shall always be based on a satisfactory from the procedure qualification shall be used as acceptance procedure qualification test where all requirements to sen- criterion for film sensitivity. sitivity are met — Where no internal access is possible, a double wall tech- Radiographic procedure qualification nique shall be applied 209 Each radiographic procedure and the consumables used — For the double wall double image technique x-ray shall be shall be qualified by making radiographic exposures of a used. Fluormetallic screens may be used based on a satis- welded joint or base material with the same or typical config- factory procedure qualification test where all requirements uration and dimensions, and of material equivalent to that to sensitivity are met. Films for use with fluormetallic which shall be used in production radiography. screens shall be suitable for this screen type For procedures using source side IQIs, the sensitivity shall — For the double wall single image technique both X-ray and meet the applicable criterion in ISO 17636, Annex A and the gamma ray may be used. The choice of radiation source, average density at the sound weld metal image shall be mini- film and screen types shall be based on a satisfactory pro- mum 2.0. The maximum density allowed shall be according to cedure qualification test where all requirements to sensi- the capabilities of the available viewing equipment, but not tivity are met. more than 4.0. B 300 Manual ultrasonic testing of welds in C-Mn/low 210 For procedures using film side IQIs, the IQIs shall for alloy steel with C-Mn/low alloy steel weld deposits radiographic procedure qualification purposes be placed on 301 Ultrasonic testing shall be performed in compliance with both the film side and the source side. ISO 17640 and as required below. The sensitivity of the source and film side IQIs shall both sat- 302 Ultrasonic testing shall be performed according to isfy the applicable criteria in ISO 17636, Annex A and the den- accepted procedures. sity shall meet the requirements of 208. Ultrasonic testing procedures If the sensitivity of the film side IQI is better than required by the applicable criterion in ISO 17636, Annex A the film side 303 Ultrasonic testing procedures shall be according to B102 sensitivity obtained during procedure qualification shall be through B104 and include: recorded and be acceptance criterion for the sensitivity of the film side IQI during production radiography. — type of instrument — type and dimensions of probes Processing and storage — range of probe frequencies 211 Processing of radiographs shall conform to ISO 17636. — description of reference block Storage shall be such that the radiographs maintain their qual- — calibration details, range and sensitivity ity for a minimum of 5 years without deterioration. Thiosul- — surface requirements, including maximum temperature phate tests shall be performed at regular intervals. — type of coupling medium If radiograph storage time in excess of 5 years is required, the — scanning techniques supplemented with sketches, show- radiographs should be digitised using methods giving adequate ing the probes used and area covered resolution and stored in electronic media in an agreed manner. — recording details. Reporting 304 Typical applications, which require specific UT proce- 212 Reports shall be in accordance with B105 and B106. In dures, are: addition to the items listed in ISO 17636 the following shall be — Estimation of defect size (height) using conventional included in the radiographic testing report: beam spread diagram (20 dB drop), Time-Of-Flight-Dif- — radiographic procedure reference fraction (TOFD) technique or the back diffraction tech- nique. — geometric unsharpness. — Testing of objects with temperature outside the range 0°C Radioscopic testing to 40°C. 213 Radioscopic testing techniques in accordance with EN The ultrasonic testing procedure shall be submitted for accept- 13068 may be used provided the equipment has been demon- ance. strated, in accordance with Subsection F, to give sensitivity 305 No special procedure qualification test should be and detection equivalent to conventional x-ray according to required when manual methods are used. ISO 12096. Ultrasonic testing techniques Specific requirements to radiography of installation girth welds 306 Ultrasonic testing techniques shall be in accordance with ISO 17640 and the requirements below. 214 For radiography the following additional requirements shall apply for installation girth welds: Guidance note: Manual or semi- automated ultrasonic phased array systems may — Panoramic (single wall single image) exposures shall be be used provided it is demonstrated that such systems will give

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 191

the same sensitivity, resolution and detection ability as conven- 311 Probe frequencies shall be selected according to tional ultrasonic testing performed according to the requirements ISO 17640. given in B300 and that specific ultrasonic testing procedures are developed and accepted. Guidance note:

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- The nominal angle of probes used are normally valid for C-Mn steels with compression wave velocity of approximately 5900 m/ o Manual ultrasonic testing equipment s and shear wave velocity of approximately 3200 m/s at 20 C.

307 Manual ultrasonic testing equipment shall: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — be applicable for the pulse echo technique and for the dou- Coupling medium ble probe technique 312 The same coupling medium as used for calibration and — cover as a minimum the frequency range from 2 to 6 MHz setting of gains and amplification shall be used during testing. — have a calibrated gain regulator with maximum 1 dB per step over a range of at least 60 dB Calibration of range scale and angle determination — have a flat screen accessible from the front for direct plot- 313 The IIW or ISO calibration blocks (V1 – V2) according ting of reference curves or be equipped with digital DAC- to ISO 2400 or ISO 7963 respectively, shall be used for cali- display presentation of user-defined curves bration of range scale and for angle determination. These cali- — allow echoes with amplitudes of 5 per cent of full screen bration blocks shall, as near as practicable, have the same height to be clearly detectable under test conditions. acoustic properties as the material to be tested. 308 Calibration of ultrasonic equipment shall be undertaken Reference blocks for setting of reference levels according to procedures established according to a recognised 314 For testing of welds reference blocks shall be used for code or standard, e.g. EN 12668-1-2-3 or ASME V. Verifica- gain calibration and construction of the reference curves. The tion of Screen Height Linearity and Amplitude Linearity shall reference block shall be manufactured from the actual material be performed at the beginning of each period of extended use to be examined. Reference blocks manufactured from other (or every 3 months, whichever is less). Calibration records materials may be acceptable provided that the material is doc- shall be made available upon request. umented to have acoustic properties similar to the actual mate- Probes rial to be examined. The reference block shall have length and width dimensions suitable for the sound beam path for all 309 Probes used for testing of welds with C-Mn steel weld probe types and the material dimension(s) to be tested. deposits shall be characterised as required by ISO 10375 and ISO 12715. For testing of welds in plate and similar geometries a reference block with side drilled holes shall be used. The thickness of the Angle beam shear-wave probes shall be available in angles reference block, diameter and position of the drilled holes shall allowing effective testing of the actual weld connections. For be as shown in Figure 1 and Table D-1. testing of girth welds or welds in plate probe angles of 45°, 60° and 70° will normally be sufficient but additional probes of 35° For testing of welds in pipe when testing can be performed and 55° are recommended. Other applications may require from one side only, and the DAC reference signals can only be probes covering the range of 35° to 80° to allow effective testing. obtained from the side where the inspection shall be per- formed, i.e. the OD side, the reference blocks shall have side Straight beam probes shall be single or twin crystal probes. drilled holes at T/4, T/2 and 3/4T. Twin crystal probes shall be used when testing is performed on material with nominal thickness t < 60 mm. Single crystal When ultrasonic testing is to be performed on TMCP steel ref- probes may be used when testing is performed on material with erence blocks shall, when required, be produced perpendicular nominal thickness t ≥ 60 mm. to and/or parallel to the direction of rolling. The rolling direc- Probes shall, if necessary, be suitable for use on hot surfaces tion shall be clearly identified. (100 to 150°C). 315 For testing of longitudinal welds in pipe and similar 310 Additional probes for time-of-flight diffraction (ToFD) geometries the reference block shall in addition to the features and double probe techniques are recommended. required above, have a curvature equal to the pipe to be tested.

Figure 1 Reference block dimensions

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 192 – App.D

Table D-1 Reference Block Dimensions Material thickness (t) Thickness Diameter of Position of Note of reference side drilled side drilled block (T) hole (mm) hole

T < 15 mm 15 mm or t 2.4 ± 0.2 T/2 Additional holes are required for testing 15 mm ≤ t < 35 mm 20 mm or t 3.0 ± 0.2 of pipe when the DAC can be constructed from one side only. Additional holes are 35 mm ≤ t < 50 mm 38 mm or t generally allowed and recommended 50 mm ≤ t < 100 mm 75 mm or t 3.0 ± 0.2 T/4 100 mm ≤ t < 150 mm 125 mm or t 316 All reference blocks shall be marked with an identifica- Contact surface tion that relates to the specific application of each block 324 For ultrasonic testing the contact surface shall be clean Gain calibration and smooth, i.e. free from dirt, scale, rust, welding spatter, etc. 317 The DAC- curve shall be constructed using reference which may influence the result of the testing. Correction for blocks with side-drilled holes as described in 315. differences in surface conditions and attenuation between the reference block and the actual work piece shall be performed 318 Reference blocks not made from the actual material to and the maximum correction allowed on flat surfaces is 6 dB. be tested shall be checked for variation in acoustic properties Testing levels between the reference block and the actual material. The vari- ation can be checked by calibrating the range scale on the ISO 325 The testing level shall be in accordance with ISO 17640, 2400 block with a normal probe and subsequently measure a chapter 11, testing level B and the requirements below. known material thickness with this calibration. Probe selection 319 Whenever ultrasonic testing of welds in TMCP steel is per- 326 In addition to straight beam probe minimum two angle formed, the difference in attenuation between transverse and lon- probes shall be used for the testing, see the guidance given in gitudinal rolling direction shall be checked when the scanning Table D-2. It is emphasised that this table is for guidance and direction changes between transverse and parallel to the rolling that the actual choice of angle probes must be made carefully direction. This requires DAC constructed by use of calibration and depending on material thickness, weld bevel and type of blocks taken from transverse and parallel to the rolling direction. defects likely to occur with the welding method used. Difference in gain setting must be noted and taken into consider- ation when evaluation of indications is performed. Table D-2 Guidance for angle probes 320 When testing is carried out of welds in TMCP steel the Parent material thickness, T Probe angle actual beam angle shall be determined. The angle can be cal- 8 – 20 mm 60° and 70° culated using trigonometric functions as long as the distance 20 – 40 mm 45°, 60°, 70° and depth to the reflectors in the TMCP steel reference block is known. Alternatively the method described in Appendix E, T > 40 mm 45°, 60° 70° subsection J can be used. 327 The choice of optimum probe angle for initial full scan- Construction of the reference curves (DAC) ning of the weld shall be chosen such that incident angle of the 321 The echo reflected from the drilled hole in the calibra- sound beam centre is perpendicular to the side of the weld tion block shall be maximised and the amplitude set at 80% of bevel. If this angle does not comply with any standard probe full screen height. angle, the nearest larger probe angle shall be selected. 322 The first point of DAC must be selected such that the 328 In addition to the probe used for initial scanning two distance in sound path from the probe index to the drilled hole additional angle probes shall be used when possible. is not less than 0.6 N where N is the near field length of the rel- 329 These additional probes shall have a larger and smaller evant probe. The DAC shall be constructed by obtaining at angle than the probe used for initial scanning. The differences least 3 points on the curve. The gain setting shall be recorded in angle shall be more than 10o. and comprises the primary gain. 330 If only one additional probe can be used the angle for The recorded gain following all corrections for surface condition this probe should be: and attenuation is the corrected primary gain. Alternatively, a Time Corrected Gain calibration can be used if the ultrasonic — ≥ 10° different apparatus is fitted with a time corrected gain (TCG) correction. — Larger than the initial probe if the sound beam centre of The echo amplitude reflected from the drilled hole in the calibra- the initial probe is perpendicular to the side of the weld tion can be adjusted to 80% of full screen height over the whole bevel range in question. DAC will thus be a horizontal line. — Smaller than the initial probe if the nearest larger probe angle was selected for the initial probe Periodical checks of equipment, re-calibration and re-exami- nation Testing of welds 323 At approximately four-hourly intervals and at the end of 331 When scanning, the gain shall be increased by a mini- testing, the range scale, probe angle and primary gain must be mum of 6 dB above the corrected primary gain. Testing of checked and confirmed. welds shall be performed in accordance with ISO 17640. If deviation is found to be larger than 2% of range scale, or 4 332 The scanning zone for angle probes in the base material dB of primary gain setting or 2° of nominal probe angle, the shall be examined with straight beam (normal) probes for fea- equipment shall be re-calibrated and the testing carried out tures that might influence the angle beam testing. The scanning with the equipment over the previous period shall be repeated. zone is defined as 1.25 × full skip distance. Features interfering Re-calibration shall be performed whenever the equipment has with the scanning shall be reported. been out function for any reason including on-off and when- 333 The welds shall whenever feasible be tested from both ever there is any doubt concerning proper function of the sides on the same surface and include scanning for both trans- equipment. verse and longitudinal indications. For T-joints and plate thick-

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 193 ness above 70 mm, scanning from both surfaces and all Ultrasonic testing procedures accessible sides shall be performed. 403 Specific ultrasonic testing procedures shall be developed Evaluation of indications for this testing in compliance with this chapter and including the 334 For evaluation of indications the gain shall be reduced information required in B102 and B303. The procedure shall be by the increased dB level used during scanning. submitted for acceptance prior to start of testing. 335 All indications equal to or exceeding 33% of the refer- Personnel qualifications ence curve (evaluation level) shall be evaluated. The indica- 404 In addition to the requirements given in A500 personnel tions shall be investigated by maximising the echoes by performing testing of welds with duplex, other stainless steels rotating the probes and by using different angle probes with and nickel alloy steel weld deposits shall be qualified for or DAC established according to 321 and 322. document adequate experience and training for this type of 336 The length of an indication shall be determined by meas- ultrasonic testing. uring the distance between the points where the echo ampli- Manual ultrasonic testing equipment tude exceeds the evaluation level using the fixed level technique. 405 The requirements given in B307 and B308 shall apply 337 The final evaluation against the acceptance criteria shall Probes be based on the echo amplitude and length measured with the 406 In addition to the requirements given in B309, B310 and probe angle giving the maximum response. B311, the requirements below shall apply. Reporting 407 Probes used for testing shall normally be straight beam 338 Reports shall be in accordance with B105 and B106. In transducers and twin crystal (transmitter/receiver) compres- addition to the items listed in ISO 17640 the following shall be sion wave probes of 45°, 60° and 70°. In addition similar shear- included in the ultrasonic testing report: wave angle probes shall be used, if found suitable. 408 In general, using a combination of shear and compres- — identification of the ultrasonic testing procedure used sion wave angle probes is recommended since the detection of — the length of acceptable indications with amplitude "open to surface" imperfections on the opposite surface of the exceeding 50% of the reference curve. scanning surface, e.g. incomplete penetration or lack of fusion, B 400 Manual ultrasonic testing of welds with CRA may increase by using shear wave probes. It must, however, be (duplex, other stainless steels and nickel alloy steel) weld verified by using calibration blocks with actual weld connec- deposits tions, see 418 below, that angle shear wave probes are suitable. General 409 Creep wave probes shall be used for detection of sub sur- face defects close to the scanning surface, unless testing can be 401 Ultrasonic testing shall be performed in compliance with performed from opposite sides. B300, ISO 17640, and as required below. Reference blocks for setting of reference levels 402 Weld deposits in duplex, austenitic stainless steels and nickel alloys have a coarse grain structure with variations in 410 In addition to the reference blocks as described in B314, grain size and structure resulting in unpredictable fluctuations B315 and B316, reference blocks prepared from the actual test in attenuation and ultrasonic beam patterns. Duplex and auste- material and containing welds produced in accordance with the nitic stainless steel base materials, in particular forgings and actual WPS shall be used for establishing the DAC. These ref- castings, will have the same characteristics. erence blocks shall have the weld ground flush and the surface condition of the calibration blocks shall be typical of the con- Ultrasonic testing of welds with CRA (duplex, other stainless dition of the parent material(s) in the scanning areas. steels and nickel alloy steel) weld deposits will in order to achieve an adequate detection of imperfections require that 411 The reference block for construction of DAC shall have special calibration blocks and probes are used for testing of side drilled holes with dimensions according to Table D-3 and welds in these materials. Angle probes generating compression located as shown in Figure 2. The length and width of the ref- waves must normally be used in addition to straight beam erence blocks shall be sufficient to allow the scanning needed probes, angle shear wave probes and creep wave probes. for construction of the DAC.

Figure 2 Reference block for construction of DAC, dimensions

Notes: 3) For double sided welds, side drilled holes shall be located in the fusion line for the full thickness of the weld. 1) Side drilled holes shall be drilled in the fusion line and in the base mate- 4) For hole positions when t 50 mm, see Table D-3. rial. Holes in the base material shall be in the same relative position as ≥ the fusion line holes. 2) Holes shall be drilled in both fusion lines and base material when two dis- similar materials are welded to each other.

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Table D-3 Reference Block Dimensions Material thickness (t) Thickness of reference block (T) in Diameter of side drilled hole in mm Position of side drilled holes. T < 15 mm 15 mm or t 2.4 ± 0.2 T/4, T/2 and T3/4 15 mm ≤ t < 35 mm 25 mm or t 3.0 ± 0.2 35 mm ≤ t < 50 mm 45 mm or t 50 mm ≤ t < 100 mm 75 mm or t 3.0 ± 0.2 The distance between the two outer 100 mm ≤ t < 150 mm 125 mm or t holes and the nearest surface shall not exceed 12 mm. 412 The reference block for sensitivity setting for creep Figure 3. The location of notches shall allow setting against wave probes shall have 0.5-1.0 and 2.0 mm spark eroded each individual notch. notches with a minimum length of 20 mm as shown in

Figure 3 similar to the production material. Reference block for sensitivity setting for creep wave probes, di- mensions Sensitivity setting for creep wave probes 417 The reference block shown in Figure 3 shall be used for sensitivity setting for creep wave probes. The echo response Construction of the reference curves (DAC) for angle com- from the 1.0 mm notch shall be set to 75% of FSH. pression wave probes Shear wave angle probes 413 Angle compression wave probes shall and can only be 418 If shear angle probes are considered for skipped scanning used for scanning without skipping. The construction of the or in the root area of single sided welds, it must be verified on the DAC curves using angle compression wave probe shall be per- reference blocks with welds, see Figure 2, if it is possible to formed according to: obtain a DAC with a shear wave angle probe that is comparable to the DAC obtained with an angle compression wave probe. — when the ultrasonic beam is passing through the parent metal only Preparation of weld and scanning surfaces for testing — when ultrasonic beam is passing through the weld metal. 419 Prior to starting the testing the external weld cap shall be ground flush with the adjacent base material. The surface fin- 414 When the ultrasonic beam is passing through the parent ish of the weld and the scanning areas shall be as that on the metal only the DAC curve shall be constructed from the drilled reference blocks to be used or better. holes in the parent material of the calibration blocks, see Figure 2. Next, a maximum response shall be obtained from the Probe selection holes in the weld fusion line and if necessary, the gain setting 420 In addition to the straight beam probe minimum two shall be adjusted such that this response reach the DAC con- angle probes shall be used for the testing, see the guidance structed against drilled holes in the parent material. This shall be given in Table D-2 and B326 through B330. the primary gain to be used when locating indications on the fusion line on the side of the weld nearest to the scanning side. 421 Where the weld configuration or adjacent parts of the object are such that scanning from both sides is not possible, 415 When the ultrasonic beam is passing through the weld two additional probes shall always be used. metal, the DAC curve shall be constructed from the holes drilled in the fusion line on the side of the weld opposite to the B 500 Manual magnetic particle testing of welds scanning side. See Figure 2. This DAC shall be verified against General the holes drilled in the base material. Any variations must be noted so that echoes reflected from indications within the weld 501 Magnetic particle testing shall be performed in compli- zone can be evaluated for amplitude response. ance with ISO 17638 and as required below. Transfer correction 502 Magnetic particle testing shall be performed according to accepted procedures. 416 Since compression wave angle probes can only be used without skipping, transfer correction can not be performed. Magnetic particle testing procedures The calibration blocks must therefore have a surface finish 503 Magnetic particle testing procedures shall be according

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 195 to B102 through B104 and include: — surface preparation — make and type of penetrant, remover, emulsifier and — type of magnetisation developer — type of equipment — details of pre-testing cleaning and drying, including mate- — surface preparation rials used and time allowed for drying — wet or dry method — details of penetrant application: the time the penetrant remains — make and type of magnetic particles and contrast paint on the surface, the temperature of the surface and penetrant — magnetising current (for prod magnetising, the prod type during the testing (if not within the 15°C to 35°C range) and spacing shall be stated) — details of developer application, and developing time — demagnetisation before evaluation — description of the testing technique. — method for post-test cleaning. 504 No special procedure qualification tests is required. Application techniques Magnetising equipment 605 The penetration and developing times shall be long enough to allow effective detection of the smallest indications 505 The equipment shall be tested at maximum 6 months allowed. Demonstration of adequate detection shall be per- interval to verify that the required field strength is established formed for short penetration times. at the maximum leg spread/prod spacing to be used. The results shall be recorded. Guidance note: The penetration time for water washable penetrants should nor- 506 Prods shall be soft tipped with lead or similar. Sparks mally not be less than 40 - 60 minutes and for post-emulsified between the prods and the material tested shall be avoided. penetrants not less than 15 - 20 minutes.

507 Electromagnetic AC yokes shall develop a minimum ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- lifting force of 5 kg at maximum leg spread. The lifting force shall be checked prior to start of any testing and at regular 606 When the temperature of the surface and the penetrant is intervals during testing. within the range 15°C to 35°C, no special procedure qualifica- tion tests should be required. 508 Use of permanent magnets is not permitted. DC yokes may only be used for specific applications if required by Outside the temperature range 15°C to 35°C, the procedure national regulations. shall be qualified and a suitable comparator block shall be used to compare indications from surface defects tested within and Application techniques outside the range during the procedure qualification. 509 Magnetic particle testing shall not be performed on parts Reporting with surface temperatures exceeding 300°C. Between 60°C and 300°C, only dry magnetic particle testing shall be used. 607 Reports shall be in accordance with B105 and B106. Detection media B 700 Manual eddy current testing of welds 510 Testing using fluorescent wet magnetic particles should General be the preferred method. 701 Eddy current testing shall be performed in compliance 511 If non-fluorescent wet or dry particles are used they shall with ISO 17643. The limitations given in ISO 17643, para- provide adequate contrast with the background or the surface graph 6.3, notes 1 and 2 shall apply. being tested. 702 Eddy current testing shall be performed according to Viewing conditions accepted procedures 512 Testing with fluorescent magnetic particles shall be con- Procedure ducted in a darkened area with maximum 20 lux background 703 Eddy current testing procedures shall contain the infor- light, using filtered ultraviolet light with wave lengths in the mation in B102 and: range of 3200 to 3900 Å. Operators/interpreters shall allow sufficient time for eyesight to adjust to the dark surroundings. — type of instrument Interpreters shall not wear photo-chromatic viewing aids. — type of probe Reporting — frequency setting — calibration blocks and calibration details 513 Reports shall be in accordance with B105 and B106. In addition to the items listed in ISO 17638 the following shall be — surface condition requirements included in the testing report: — scanning details — recording details. — Identification of the testing procedure used. Equipment B 600 Manual liquid penetrant testing of welds 704 Eddy current equipment, including probes and cables, General shall be calibrated at maximum 6 months intervals and shall have calibration certification pertaining to the characteristics 601 Liquid penetrant testing shall be performed in compli- of the equipment. ance with ASTM E 1417 and as required below 705 Functional checks of the eddy current equipment shall 602 Liquid penetrant testing shall unless otherwise agreed, be carried out whenever it has been out of function for any rea- only be used on non-ferromagnetic materials or materials with son including on/off, and whenever there is any doubt concern- great variation in magnetic permeability. ing proper functioning of the equipment. 603 Liquid penetrant testing shall be performed according to 706 All calibration blocks shall be marked with an identifi- accepted procedures cation that relates to the specific application of each block. Procedures Surface conditions 604 Liquid penetrant testing procedures shall be according to 707 Excess weld spatter, scale, rust and loose paint shall be B102 through B104 and include: removed before the inspection.

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Application techniques B 1000 ECA based non-destructive testing acceptance criteria for pipeline girth welds 708 ISO 17643 shall apply. General Reporting 1001 Acceptance criteria for pipeline girth welds can be 709 Reports shall be in accordance with B105 and B106. In based on an Engineering Critical Assessment (ECA) addition to the items listed in ISO 17643 the following shall be included in the testing report: 1002 Whenever acceptance criteria for NDT are established by an ECA, the ECA shall be performed in accordance with the — Identification of the testing procedure used. requirements given in Appendix A. 1003 If acceptance criteria for weld defects are based on an B 800 Visual examination of welds ECA and hence involves sizing of indication height and General lengths, manual ultrasonic testing or automated ultrasonic test- ing shall be performed. 801 Visual examination of welds shall be performed in 1004 Sizing of indication height and length by manual or accordance with ISO 17637 and accepted procedures. automated ultrasonic testing will have inherent inaccuracies. 802 Reports shall be in accordance with ISO 17637. In addi- The allowable defect sizes derived from an ECA must accord- tion to the items listed in ISO 17637 the following shall be ingly be corrected for the ultrasonic testing uncertainty (sizing error) as follows: included in the testing report: — If the ECA gives the allowable defect size the sizing error — Identification of the testing procedure used. shall be subtracted from the calculated allowable defect height and length to establish the acceptance criteria for B 900 Acceptance criteria for manual non-destructive non-destructive testing. testing of welds with nominal strains < 0.4% and no ECA — If the ECA gives the material properties and stresses/ General strains allowed to tolerate a given defect size the sizing error shall be added to the defect height and length used as 901 The acceptance criteria given in Table D-4, Table D-5 input into the ECA to establish the acceptance criteria for and Table D-6 are applicable for manual non-destructive test- non-destructive testing. ing of welds exposed to nominal strains < 0.4%. 1005 If an embedded defect is located close to a surface, 902 The acceptance criteria use the term defect to define an such that the ligament height is less than half the defect height, imperfection/indication that has exceeded given dimensions the ligament height between the defect and the surface shall be and thus is deemed unacceptable. included in the defect height. 903 The acceptance criteria given in Table D-5 assume that Automated ultrasonic testing uncertainty data multi-pass welds are used and that the height of defects will not 1006 If automated ultrasonic testing (AUT) is used for test- exceed 0.25 t or the height of a welding pass. The height of the ing of pipeline girth welds, the uncertainty data used shall be welding pass shall be assumed not to be more than 3 mm. If obtained from the qualification testing of the automated ultra- welding methods resulting in higher welding passes are used sonic testing system required in Appendix E. (SAW, "one-shot" welding etc.), flaw indications equal or Manual ultrasonic testing uncertainty data larger than the length limits given in the tables shall be height 1007 For manual ultrasonic testing the data used for quanti- determined with ultrasonic testing. If the height exceeds 0.2 t, tative estimates of uncertainty performance and reliability in the defect is not acceptable unless proven to meet the accept- the sizing of indication length and height, shall preferably be ance criteria for ultrasonic testing in Table D-6. of the "measured response versus actual flaw size" type. The estimates shall be based on published results from comprehen- Pipeline girth welds sive studies into the reliability of manual ultrasonic testing. 904 The acceptance criteria given in Table D-4, Table D-5 1008 If adequate data for manual ultrasonic testing are not and Table D-6 are generally applicable for manual non- available, the sizing error shall not be taken as less than destructive testing of pipeline girth welds exposed to total 2.5 mm. nominal strains < 0.4%. Acceptance criteria based on ECA assessment 905 If the allowable defect sizes are established by an ECA 1009 Appendix A gives requirements for establishing allow- for pipeline girth welds exposed to total nominal strains able defect sizes based on an ECA assessment. ≥ 0.4%, the provisions according to B1000 shall apply. 1010 Acceptance criteria shall be established by correcting the Welds in pipeline components allowable defect sizes derived from the ECA with the ultrasonic testing uncertainty in accordance with 1005 or 1006 and 1007. 906 The acceptance criteria given in Table D-4, Table D-5 and Table D-6 are generally applicable for manual non-destructive Guidance note: testing of welds in pipeline components. For girth welds con- Acceptance criteria based on ECA will frequently allow signifi- cantly larger indications than workmanship based acceptance cri- necting a component to the pipeline or for pup-pieces welded to teria. In order to maintain a high standard of welding ECA based the component, the acceptance criteria for pipeline girth welds allowable defect sizes may be used as a weld repair criterion shall apply, unless other acceptance criteria are given in the rather than as acceptance criterion. Criteria that are more restric- tive are then used as a measure of the welding standard obtained. design, manufacture and testing data for the component. If these more restrictive criteria are exceeded, it should be required that preventative or corrective actions are performed to 907 For welds exposed to total nominal strains ≥ 0.4%, the maintain the required welding standard. allowable defect sizes shall be established by an ECA and the provisions according to B1000 shall apply. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---

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Table D-4 Acceptance criteria for visual examination and surface method testing of welds 1) 2) Visual examination External profile Welds shall have a regular finish and merge smoothly into the base material and shall not extend beyond the original joint preparation by more than 3 mm (5 mm for SAW welds). Fillet welds shall be of specified dimensions and regular in form. Cap and root reinforcement height External welds: For t < 13 mm: max. 3.0 mm. The radial offset of HFW linepipe shall not (Longitudinal welds) For t ≥ 13 mm: max. 4.0 mm reduce the thickness at to weld to less than Internal welds: max. 3.5 mm tmin. Weld flash (HFW pipe longitudinal welds The external flash shall be trimmed essentially flush with the pipe surface. only) The internal flash shall not extend above the contour of the pipe by more than 1.5 mm. The trim- ming shall not reduce the wall thickness to below tmin,and the groove resulting from the trimming shall have a smooth transition to the base material without notches and the depth shall be max. 0.3 mm + 0.05 t. Cap and root reinforcement height Height < 0.2 t, but max. 4 mm (Double sided girth welds) Cap reinforcement (Single sided welds) Height < 0.2 t, but max. 4 mm Root penetration (Single sided welds) Height < 0.2 t, but max. 3 mm. Length of excess penetration: max 25 mm Cap concavity Not permitted. Root concavity At no point shall the weld thickness be less than tmin Offset of strip/plate edges For t ≤ 15 mm max. 1.3 mm For welds in clad/lined material the offset (Longitudinal welds) For 15 mm < t ≤ 25 mm max. 0.1 t shall not reduce the effective thickness of the For t > 25 mm max. 2.0 mm cladding/lining in the root area High/low on root side of single sided girth For t ≤ 13 mm max. 1.3 mm For welds in clad/lined material the offset welds For 13 mm < t ≤ 20 mm max. 0.1 t shall not reduce the effective thickness of the For t > 20 mm max. 2.0 mm cladding/lining in the root area Transverse misalignment of weld beads for max. 3.0 mm for t ≤ 20 mm max. 4.0 mm for t > 20 mm double sided welds Waving bead (deviation of weld toe from a max. 0.2 t, but max. 4 mm straight line) Undercut Individual undercuts Accumulated length of undercuts in any 300 Depth d Permitted length mm length of weld: d > 1.0 mm Not permitted None 1.0 mm ≥ d > 0.5 mm 50 mm < 4 t, max. 100 mm. 0.5 mm ≥ d > 0.2 mm 100 mm d < 0.2 mm unlimited unlimited Cracks, Arc burns, Start/stop craters/ poor Not permitted. restart, Surface porosity Lack of Not permitted for welds in duplex stainless steel, CRAs and clad/lined steel penetration/lack of Individual acceptable length: t, max. 25 mm. fusion Accumulated length in any 300 mm length of weld: t, max. 50 mm. Systematic imperfections Imperfections that are distributed at regular distances over the length of the weld are not permit- ted even if the size of any single imperfection meets the requirements above Burn through Not permitted for welds in duplex stainless steel, CRAs and clad/lined steel. Acceptable for welds in C-Mn and low alloy steels provided that weld thickness at no point is less than t and: — Individual length/width: t/4, max. 4 mm in any dimension. — Accumulated length in any 300 mm length of weld: t/2, max. 8 mm. Surface testing (MP, LP and EC) Wall thickness Type of indications mm Rounded Linear Number Dimension mm Number ≤ 16 2 4.0 2 > 16 2 4.0 2 Notes:

1) Any two imperfections separated by a distance smaller than the major dimension of the smaller imperfection shall be considered as a single imperfection. 2) Detectable imperfections are not permitted in any intersection of welds.

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Table D-5 Acceptance criteria for radiographic testing of welds Type of defect Acceptance criteria 1) 2) 3)10)11) Individual discontinuities Maximum accumulated size of in any 300 mm weld length for each type of discontinuity Porosity1) 2) Scattered Diameter: < t/4, but max. 3 mm See Note 4 Cluster 5) Individual pore: <2 mm, cluster diameter max. 12 mm One cluster or total length < 12 mm Wormhole Length: t/2, but max. 12 mm, Width: t/10, but max. 3 mm 2 wormholes or total length < 12 mm Hollow bead Length: t, but max. 25 mm, Width: max. 1.5 mm Length 2 t, but max. 50 mm Isolated 6) Diameter: < t/4, max 3 mm - On-line 7) Diameter: <2 mm group length: 2t, but max. 50 mm Length 2 t, but max. 50 mm Slag 1) 2) 3) 8) Isolated Width < 3 mm Length 12 mm, but max. 4 off separated by min 50 mm Single lines Width: max 1.5 Length 2 t, but max. 50 mm Parallel lines Individual width: max 1.5 Length 2 t, but max. 25 mm Inclusions Tungsten Diameter < 0.5 t, but max. 3 mm Max 2 off separated by min 50 mm Copper, wire Not permitted - Lack of Not permitted for welds in duplex stainless steel, CRAs penetration 1) 2) 3) 8) and clad/lined steel - Root 9) Length: t, but max. 25 mm Length t, but max. 25 mm Embedded Length: 2t, but max. 50 mm Length 2 t, but max. 50 mm Lack of fusion1) 2) 3) 8) Not permitted for welds in duplex stainless steel, CRAs - and clad/lined steel Surface Length: t, but max. 25 mm Length t, but max. 25 mm Embedded Length: 2 t, but max. 50 mm Length 2 t, but max. 50 mm Cracks Not permitted - Shrinkage cavities and Not permitted - crater pipes Root concavity Length: 2t, but max. 50 mm Length: 2 t, but max. 50 mm Root undercut See Table D-6 See Table D-6 Excess penetration Burn through Total accumulation of discontinuities (excluding porosity) — Maximum accumulation of discontinuities in any 300 mm weld length 3 t, max 100 mm. — Maximum accumulation of discontinuities: 12% of total weld length. — Any accumulation of discontinuities in any cross sections of weld that may constitute a leak path or may reduce the effective weld thick- ness with more than t/3 is not acceptable. Notes:

1) Refer to the additional requirements in 903 for welding methods that produce welding passes exceeding 0.25 t. 2) Volumetric imperfections separated by less than the length of the smallest defect or defect group shall be considered as one imperfection. 3) Elongated imperfection situated in a line and separated by less than the length of the shortest defect shall be considered as one imperfection. 4) For single layer welds: 1.5% of projected area, for multi layer welds with t < 15 mm 2% of projected area, for multi layer welds with t ≥ 15 mm 3% of projected area. 5) Maximum 10% porosity in cluster area. 6) "Isolated" pores are separated by more than 5 times the diameter of the largest pore. 7) Pores are "In a line" if not "Isolated" and if 4 or more pores are touched by a line drawn through the outer pores and parallel to the weld. "On-line" pores shall be checked by ultrasonic testing. If ultrasonic testing indicates a continuous defect, the criteria for lack of fusion defect shall apply. 8) Detectable imperfections are not permitted in any intersection of welds. 9) Applicable to double sided welding where the root is within the middle t/3 only. 10) Acceptance criteria of Table D-4 shall also be satisfied. 11) Systematic imperfections that are distributed at regular distances over the length of the weld are not permitted even if the size of any single imperfection meets the requirements above.

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Table D-6 Acceptance criteria for manual ultrasonic testing of welds 1) 2) 3) 4) 5) 6) Base material thickness 8 mm ≤ t < 15 mm Base material thickness 15 mm ≤ t ≤ 150 mm Max. echo amplitude Corresponding acceptable indication Max. echo amplitude Corresponding acceptable indication length, L (mm) length, L (mm) Reference level (DAC) L ≤ t (but max. 8 mm) DAC + 4 dB L ≤ 0,5t (but max. 12,5 mm) DAC – 6 dB L > t (but max. 8 mm) DAC – 2 dB 0,5 t < L ≤ t (but max. 25 mm) - - DAC – 6 dB L > t (but max. 25 mm in both outer t/3) - - DAC – 6 dB L > t (but max. 50 mm in middle t/3) Cracks are not permitted. For welds in duplex stainless steel, CRAs and clad/lined steel: Lack of fusion and lack of penetration are not permitted. Transverse indications: Indications shall be considered as transverse if the echo amplitude transversely exceeds the echo amplitude from the same indication longitudinally with more than 2 dB. Transverse indications are unacceptable unless proven not to be planar, in which case the acceptance criteria for longitudinal indications apply. For indications approaching the maximum permitted length, it shall be confirmed that the indication height is less than 0.2 t or maximum 3 mm (see 903). If an embedded defect is located close to a surface, such that the ligament height is less than half the defect height, the ligament height between the defect and the surface shall be included in the defect height. Total accumulation of discontinuities: The total length of acceptable indications with echo amplitude of reference level – 6 dB and above shall not exceed 3 t, maximum 100 mm in any weld length of 300 mm nor more than 12% of total weld length. Any accumulation of defects in any cross section of weld that may constitute a leak path or reduce the effective thickness of weld more than t/3 is not acceptable. If only one side of the weld is accessible for testing 6 dB shall be subtracted from the maximum echo permitted above. Notes:

1) Reference level is defined as the echo amplitude corresponding to the echo from the reflector in the reference blocks described in Figure 1, Figure 2 and Figure 3 of this appendix, or equivalent reflector. 2) All indications exceeding 20% of the reference level shall be investigated to the extent that the operator determines the shape, length and location of the imperfection. 3) Indications that cannot be established with certainty shall whenever possible be tested with radiography. Indications that are type determined in this way shall meet the acceptance criteria in Table D-5. 4) Longitudinal imperfections where the echo height intermittently is below and above the acceptance level shall if possible be investigated with radiogra- phy. Indications that are determined in this way shall meet the acceptance criteria in Table D-5. If radiography cannot be performed, the length shall not exceed 3 t, maximum 100 mm in any weld length of 300 mm. 5) Length and depth shall be determined by an appropriate method, see B335 and B336. 6) Detectable imperfections are not permitted in any intersection of welds. 7) Systematic imperfections that are distributed at regular distances over the length of the weld are not permitted even if the size of any single imperfection meets the requirements above. B 1100 Repair of welds 104 Manual non-destructive testing of plate, pipe and weld 1101 A repaired weld shall normally be subject to the same overlay shall be performed in compliance with the standards testing requirements and acceptance criteria as the original weld. listed below and as required in the following: 1102 In cases when the acceptance criteria are based on an ISO 10124 Seamless and welded (except submerged ECA, specific acceptance criteria for repair welds shall be estab- arc-welded) steel tubes for pressure pur- lished by an ECA based on the fracture toughness properties poses - Ultrasonic testing for the detec- obtained during qualification of the repair welding procedure. tion of laminar imperfections 1103 Repair welding of cracks is not permitted unless the ISO 12094 Welded steel tubes for pressure purposes cause of cracking has been established not to be a systematic - Ultrasonic testing for the detection of welding error. (If there is a crack in the weld, the weld is per laminar imperfections in strips or plates definition considered rejected. This means a technical evalua- used in manufacture of welded tubes tion of the cause of cracking shall be performed. If it can be ASTM E165 Standard Test method for Liquid Pene- demonstrated that the crack is a “one off” situation, then repair trant Inspection welding may be performed subject to agreement). ASTM E309 Standard Practice for Eddy-Current Examination of Steel Tubular products Using Magnetic Saturation ASTM E426 Standard Practice for Electromagnetic C. Manual Non-destructive testing and Visual (Eddy Current) of Welded and Seamless Examination of Plate, Pipe and Weld Overlay Tubular Products, Austenitic Stainless Steel and Similar Alloys C 100 General ASTM A578/578 Standard Specification for Straight- 101 All non-destructive testing, visual inspection of plate, Beam Ultrasonic Examination of Plain pipe and weld overlay shall be according to accepted proce- and Clad Steel Plates for Special Appli- dures. Note that the requirements of C200 are not applicable to cations plate or pipe mills, see 201. ASTM A577/577 Standard specification for Ultrasonic Angle-Beam Examination of Steel Plates 102 Manual non-destructive testing and visual examination ASTM E 709 Standard Guide for Magnetic Particle procedures shall be prepared as required in B102 through B104 Examination to reflect the requirements of the applied standard. ASTM E 1417 Standard Practice for Liquid Penetrant 103 Acceptance criteria for manual non-destructive testing Examination and visual examination of plate, pipe and weld overlay are ASTM E 1444 Standard Practice for Magnetic Particle given in C600. Examination.

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C 200 Plate and pipe longitudinal flaws in plate and pipe shall be done in general General accordance with ASTM A577 or equivalent standard. 201 These requirements are not applicable for plate and coil 215 Probes shall meet the requirements of 203. Additional examined at the plate/coil mill as covered by subsection G, or angle probes will be required for testing of pipe. for linepipe examined at the pipe mill as covered by 216 Sensitivity for C-Mn and low alloy steel shall be a DAC subsection H. curve based on reference blocks with a rectangular notch with General requirements for ultrasonic testing depth 3% of the material thickness on both sides. 202 Ultrasonic equipment shall meet the requirements given 217 Reference blocks for duplex stainless steel and auste- in B307 and B308. nitic steels shall have one Ø 3 mm flat bottom hole perpendic- ular to the angle of incidence of the probe and at the largest 203 Probes used for testing of pipe and plate shall be charac- possible depth from the scanning surface of the block. Refer- terised as required by ISO 10375 and ISO 12715. ence blocks shall be of the actual material tested or of a mate- Angle shear-wave probes of 45° and 60° shall be used for C- rial with similar with acoustic properties. Mn and low alloy steels. Angle probes for duplex stainless 218 Low frequency shear wave angle probes may be used for steel and austenitic steels shall be twin crystal (transmitter/ duplex stainless steel and austenitic steels instead of twin crys- receiver) compression-wave probes of 45° and 60°. Angle tal (transmitter/receiver) compression-wave probes. For compression wave probes shall and can only be used for scan- acceptance, it shall be verified on the reference blocks that it is ning without skipping. possible to obtain a DAC with a shear wave angle probe that is Straight beam probes shall be single or twin crystal. Twin crys- comparable to the DAC obtained with an angle compression tal probes shall be used when testing is performed on material wave probe. with nominal thickness t < 60 mm. The focusing zone of the 219 The pitch of the scanning grid shall small be enough to twin crystal probes shall be adapted to the material thickness to ensure detection of the smallest defect allowed according to be examined. the applicable acceptance criteria. Single or twin crystal probes can be used when testing is per- 220 All reference blocks shall be marked with an identifica- formed on material with nominal thickness t ≥ 60 mm. The sin- tion that relates to the specific application of each block. gle crystal probes shall have a dead zone as small as possible, e.g. 10% of the material thickness or 15 mm whichever is the Magnetic particle testing smaller. Selected probes shall have a nominal frequency in the 221 Manual magnetic particle testing of: range of 2 MHz to 5 MHz and dimensions Ø 10 mm to Ø 25 mm. — plate 204 The IIW or ISO calibration blocks (V1 – V2) according —pipe to ISO 2400 or ISO 7963 shall be used for calibration of range —edges scale and for angle determination. These calibration blocks — bevels shall, as near as practicable, have the same acoustic properties as the material to be tested. shall be done in accordance with ASTM E 709, ASTM E1444 or equivalent standard. Manual ultrasonic thickness measurements Liquid penetrant testing 205 Manual ultrasonic thickness measurements shall be done in accordance with ASTM E797 or equivalent standard. 222 Manual liquid penetrant testing of: Ultrasonic testing for detection of laminar flaws — plate 206 Manual ultrasonic testing for detection of laminar flaws —pipe in steel other than clad/lined steel shall be performed according —edges to ISO 10124, ISO 12094 or equivalent standard. — bevels 207 Manual ultrasonic testing for detection of laminar flaws shall be done in accordance with ASTM E165 or ASTM E1417 in clad/lined steel shall be done in accordance with ASTM or equivalent standard. The penetration and developing times A578/578M or equivalent standard. shall be long enough to allow effective detection of the small- 208 The surface condition of the material shall permit at least est indications allowed. two successive back-wall echoes to be distinguished when the Guidance note: probe is placed on any area free from internal imperfections. The penetration time for water washable penetrants should nor- 209 The range scale shall be selected such that there are mally not be less than 20 - 30 minutes and for post-emulsified always at least two back-wall echoes (reflections) on the penetrants not less than 10 - 15 minutes. screen. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 210 The sensitivity shall be based on echoes reflected from Eddy current testing Ø 6 mm flat bottom holes in reference blocks of the material used or of a material with similar with acoustic properties. 223 Manual eddy current testing of C-Mn steel Pipe shall be 211 DGS diagram or DGS- scales can be used provided they done in accordance with ASTM E309 or equivalent standard. are developed for the probe used and can be correlated to a Ø Manual eddy current testing of duplex stainless steels and 6 mm flat bottom hole. austenitic stainless steels shall be done in accordance with 212 The pitch of the scanning grid shall be small enough to ASTM E426 or equivalent standard. ensure detection of the smallest defect allowed according to C 300 Weld overlay the applicable acceptance criteria. 301 Manual magnetic particle testing of ferromagnetic weld 213 Sizing of indications shall be performed according to overlay deposits shall be performed in accordance with ASTM ISO 12094, Annex A. E 709, ASTM E1444 or equivalent standard. Manual ultrasonic testing for detection of transverse and lon- 302 Manual liquid penetrant testing of non-magnetic weld gitudinal flaws overlay deposits shall be performed in accordance with ASTM 214 Manual ultrasonic testing for detection of transverse and E 1417 or equivalent standard.

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303 Manual eddy current testing of weld overlay deposits methods may require a more stringent acceptance criterion. shall be performed in accordance with ASTM E309 or equiva- 502 Four readings shall be taken 90° apart around the cir- lent standard. cumference of each end of the pipe, and at equal spacing for 304 Manual ultrasonic testing of weld overlay shall be per- plate ends. The average of the four readings shall be ≤ 2.0 mT formed according to ISO 12094 or equivalent standard and: (20 Gauss), and no one reading shall exceed 2.5 mT (25 Gauss). — Straight beam probes shall be twin crystal. The focusing zone of the twin crystal probes shall be adapted to the 503 Any product that does not meet the requirements of 502 material thickness to be examined. shall be considered defective. — The surface condition of the material shall permit at least 504 All defective products shall be de-magnetized full two successive back-wall echoes to be distinguished when length, and then their magnetism shall be re-measured until at the probe is placed on any area free from internal imper- least three consecutive pipes meet the requirements of 502. fections. 505 The requirements for residual magnetism shall apply — The calibration of range scale shall be carried out using an only to testing at the specific location since the residual mag- IIW calibration block, a V2 calibration block or on a netism in products may be affected by procedures and condi- defect free area of known thickness in the material to be tions imposed during and after handling and shipment. examined. The range scale is to be selected such that there are always at least 2 back-wall echoes (reflections) on the C 600 Acceptance criteria for manual non-destructive screen. testing of plate, pipe and weld overlay — The sensitivity shall be based on echoes reflected from a Ø 3 mm flat bottom hole in reference blocks made from a Thickness measurements base material with similar acoustic properties of the actual 601 For manual ultrasonic thickness measurements accept- base material with overlay deposited according to the ance criteria shall be according to applicable specification or same WPS as the actual overlay. The Ø 3 mm flat bottom product standard. hole shall be placed approximately at the fusion line Laminar flaws between overlay and base material. If the testing shall be performed of machined overlay, the scanning surface shall 602 Acceptance criteria for manual ultrasonic testing for be machined to the same surface requirements as the over- laminar flaws in C-Mn, low alloy, duplex, other stainless steels lay. and nickel based corrosion resistant alloys (CRA) are given in — All reference blocks shall be marked with an identification Table D-12. that relates to the specific application of each block. 603 Acceptance criterion for manual ultrasonic testing for detection of laminar flaws in clad steel is given in ASTM Reporting A578, S7. In addition, no areas with laminations or lack of 305 Reports shall be in accordance with B105 and B106. bonding are allowed over a width extending at least 50 mm inside the location of future weld preparations. C 400 Visual examination Transverse and longitudinal flaws 401 Visual examination shall be carried out in a sufficiently illuminated area; minimum 350 lx, but 500 lx is recommended. 604 For manual ultrasonic testing for detection of transverse If required to obtain good contrast and relief effect between and longitudinal flaws in C-Mn and low alloy steel, the accept- imperfections and background additional light sources shall be ance criterion shall be that no indications exceed the DAC used. curve established against the rectangular notch with depth 3% of the thickness. 402 For direct examination the access shall generally permit placing the eye within 600 mm of the surface to be examined For manual ultrasonic testing for detection of transverse and and at an angle of not less than approximately 30°. If this is not longitudinal flaws in duplex stainless steel, the acceptance cri- possible then the use of mirrors, boroscopes, fibre optics or terion shall be that no indications exceed the DAC curve estab- cameras shall be considered. lished against the Ø 3 mm flat bottom hole. 403 A sufficient amount of tools, gauges, measuring equip- Magnetic particle testing of plate / pipe bevels and edges ment and other devices shall be available at the place of exam- 605 Acceptance criterion for manual magnetic particle test- ination. ing of plate / pipe bevels and edges shall be: 404 The objects to be examined shall be cleaned to remove — No indications longer than 6 mm are permitted. all scale and processing compounds prior to examination. The cleaning process shall not injure the surface finish or mask pos- Liquid penetrant testing of plate / pipe bevels and edges sible imperfections. 606 Acceptance criterion for manual liquid penetrant testing 405 Reporting of visual examination shall include: of plate / pipe bevels and edges shall be: — Name of manufacturer — no indications longer than 6 mm are permitted. — Name of examining company — Identification of examined object(s) Eddy current testing of plate / pipe bevels and edges — Material 607 Acceptance criterion for manual eddy current testing of — Imperfections exceeding the acceptance criteria and their pipe / pipe bevels and edges shall be: location — Extent of examination — no indications longer than 6 mm are permitted. — Supplementary sketches/drawings. Disposition of defects at plate / pipe bevels and edges C 500 Residual magnetism 608 Defects at pipe bevels and edges shall be examined 501 Residual magnetism shall be measured with a calibrated ultrasonically as required in this subsection and the pipes cut Hall effect gauss meter or equivalent equipment. The residual back until no defects are present in the tested area. magnetism the residual magnetism shall not exceed an average value (out of 4 measurements) of 2.0 mT (20 Gauss), with a Weld overlay maximum single value of 2.5 mT (25 Gauss). Some welding 609 Acceptance criteria for as-welded surfaces of magnetic

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 202 – App.D and non magnetic weld overlay for visual examination, mag- — scanning techniques supplemented with sketches, show- netic particle testing, liquid penetrant and eddy current testing ing the probes used and area covered by each probe are: — description of methods for recheck of areas with reduction or loss of back reflection — no round indications with diameter above 2 mm and no — recording details. elongated indications — indications separated by a distance less than the diameter Ultrasonic Apparatus or length of the smallest indication, shall be considered as one indication 203 Verification of Screen Height Linearity and Amplitude — accumulated diameters of round indications in any Linearity shall be performed at the beginning of each period of extended use (or every 3 months, whichever is less). Records 100 × 100 mm shall not exceed 10 mm. shall be made available upon request. 610 Acceptance criteria for ultrasonic testing of as-welded Probes surfaces of magnetic and non-magnetic weld overlay shall be no loss of back wall echo and no echo from an indication shall 204 Straight beam probes with frequency 2-5 MHz and exceed 66% of the echo reflected from Ø 3 mm flat bottom dimension Ø 10-30 mm shall be used. The probes shall be sin- holes in reference blocks. gle or twin crystal. Twin crystal probes shall be used when test- ing is performed on material with nominal thickness 611 For machined surfaces, acceptance criteria shall be espe- t < 60 mm. The focusing zone of the twin crystal probes shall cially agreed upon. be adapted to the material thickness to be examined. 612 Defects shall be ground out, re-welded and re-tested to Single or twin crystal probes can be used when testing is per- meet the acceptance criteria above. formed on material with nominal thickness t ≥ 60 mm. The sin- gle crystal probes shall have a dead zone as small as possible, e.g. 10% of the material thickness or 15 mm whichever is the smaller. D. Non-destructive Testing and Visual 205 Angle beam probes shall be used for testing on rings, Examination of Forgings hollow and cylindrical sections. Angle beam probes shall be D 100 General available in angles, or be provided with wedges or shoes, rang- ing from 30° to 75°, measured to the perpendicular of the entire 101 All non-destructive testing of forgings shall be per- surface of the forging being tested. formed according to accepted procedures. Reference blocks for straight beam testing 102 Manual non-destructive testing and visual examination procedures shall be prepared as required in B102 through B104 206 Supplementary requirement S1 of ASTM A388 shall to reflect the requirements of the applied standard. apply, but with the following additional requirements: 103 Acceptance criteria for manual non-destructive testing — For material thickness t ≤ 38 mm the flat bottom holes and visual examination forgings are given in D500. shall be Ø 1.6 mm 104 Manual non-destructive testing of forgings shall be per- — For material thickness 38 mm < t < 60 mm the flat bottom formed in compliance with the standards listed below and as holes shall be Ø 3 mm required in the following: — For material thickness t ≥ 60 mm the flat bottom holes shall be Ø 6 mm. — ASTM E165Standard Test method for Liquid Penetrant Inspection Reference blocks for angle beam testing — ASTM A388Specification for Ultrasonic Examination of 207 The reference notches shall be rectangular OD and ID Heavy Steel Forgings notches with a depth of: — ASTM E709 Standard Guide for Magnetic Particle Exam- ination — For material thickness t ≤ 38 mm, 3% of the thickness — ASTM A 961Standard Specification for Common — For material thickness 38 mm < t < 100 mm, 5% of the Requirements for Steel Flanges, Forged Fittings, Valves, thickness and Parts for Piping Applications — For material thickness t ≥ 100 mm, 10% of the thickness. — ASTM E 1417Standard Practice for Liquid Penetrant Examination 208 A separate reference block shall have the same configu- — ASTM E1444Standard Practice for Magnetic Particle ration, nominal composition, forging ratio, heat treatment and Examination thickness as the forgings it represents. 209 Where a group of identical forgings is made, one of the D 200 Ultrasonic and magnetic particle testing of C-Mn forgings may be used as the separate reference block. and low alloy steel forgings 210 All reference blocks shall be marked with an identifica- Ultrasonic testing tion that relates to the specific application of each block. 201 Ultrasonic testing of forgings shall be performed in accordance with ASTM A388 and the requirements below. Preparation of forgings for ultrasonic testing Ultrasonic testing procedures 211 For forgings of uncomplicated geometry, the require- ments of ASTM A388, chapter 6 shall apply. 202 Ultrasonic testing procedures shall contain the informa- tion in B102 and: Forgings of complex geometry 212 Forgings are required to be forged and/or to be rough — type of instrument machined to near final dimensions prior to heat treatment in — type and dimensions of probes order to obtain the required properties. This machining of forg- — range of probe frequencies ings shall consider that cylindrical shapes and faces that are flat — description of reference blocks and parallel to one another shall be obtained in order to provide — calibration details, range and sensitivity adequate conditions for ultrasonic testing. In the case of forg- — surface requirements, including maximum temperature ings with complex geometry, machining shall provide inter- — type of coupling medium secting

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 203 cylindrical and/or flat faces. The machining shall be such that Periodical checks of equipment areas where adequate ultrasonic testing is not possible will be removed during the final machining. A sketch shall be pro- 222 At approximately four-hourly intervals and at the end of vided for acceptance showing the areas of the forging where testing, the range scale, probe angle and primary gain must be adequate ultrasonic testing will not be achieved. checked and if necessary, corrected. Checks shall also be car- ried out whenever a system parameter is changed or changes in Calibration of amplification and testing procedure the equivalent settings are suspected. If deviation is found to be larger than 2% of range scale, or 3 dB of primary gain setting 213 The IIW or ISO calibration blocks (V1 – V2) according or 2° of nominal angle probe, the testing carried out with the to ISO 2400 or ISO 7963 shall be used for calibration of range equipment over the previous period shall be repeated. scale and for angle determination. These calibration blocks shall, as near as practicable, have the same acoustic properties Reporting as the material to be tested. Calibration of range scale can alter- 223 Reports shall be in accordance with B105 and B106 and natively be done on a defect free area of known thickness in the ASTM A388, chapter 9. material to be examined. The range scale is to be selected such that there are always at least 2 back-wall echoes (reflections) Manual magnetic particle testing of C-Mn steel forgings on the screen. 224 Manual magnetic particle testing of C-Mn steel forgings 214 The calibration of the required amplification shall be shall be performed in accordance with ASTM E 709, ASTM performed according to ASTM A388, chapter 7. The probe E1444 or equivalent standard. size and frequency that provides optimum response shall be used for the testing. D 300 Ultrasonic and liquid penetrant testing of duplex stainless steel forgings 215 Notes 2 and 3 of, chapter 7 in ASTM A388 shall be adhered to. Ultrasonic testing 216 When scanning, the gain shall increased by minimum 301 Ultrasonic testing of duplex stainless steel forgings shall 6 dB above the corrected primary gain. For evaluation of indi- be performed in accordance with D200, but with the following cations the gain shall be reduced by the increased dB level used additions to the requirements to: during scanning. —probes 217 The method for re-check of areas with reduction or loss — reference blocks for angle beam testing of back reflection, ASTM A 388, paragraph 7.2.4, shall be — preparation of forgings for ultrasonic testing described. — testing procedure. 218 Different frequencies, types, angles and diameter of probes shall be employed to obtain additional information Angle probes about detected indication. 302 Angle probes for duplex stainless steel shall be twin crystal (transmitter/receiver) compression-wave probes. Angle Sizing of indications compression wave probes shall and can only be used without 219 In general, the area containing imperfections shall be skipping. sized (area and length) using the 6 dB drop technique. The area 303 Low frequency shear wave angle probes may be used for refers to the surface area on the forgings over which a contin- duplex stainless steel instead of twin crystal (transmitter/ uous indication exceeds the acceptance criteria. This area will receiver) compression-wave probes, provided it is verified on be approximately equal to the area of the real defect provided the reference blocks that it is possible to obtain a DAC with a the defect size is larger than the 6 dB beam profile of the probe. shear wave angle probe that is comparable to the DAC 220 If the real imperfection size is smaller than the 6 dB obtained with an angle compression wave probe. beam profile, the 6 dB drop technique is not suited for sizing. 304 Creep wave probes shall be used for detection of sub sur- The area measured on the surface will be measured too large face defects close to the scanning surface, unless testing can be and not represent the real indication size. A guide to classify if performed from both sides. the revealed indications are greater or smaller than the 6 dB drop profile is given in EN 10228-3, part 13. Reference blocks for angle beam testing 221 If the size of the indication is evaluated to be smaller 305 Reference blocks for angle beam testing of duplex stain- than the 6 dB drop profile at the depth of discontinuity a less steel with angle compression wave probes shall have side graphic plot, that incorporates a consideration of beam spread drilled holes and a 1 mm deep and 20 mm wide spark eroded should be used for realistic size estimation. notch according to Figure 4 and Table D-7.

Figure 4 Reference block for construction of DAC, duplex stainless steel

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 204 – App.D

Table D-7 Reference Block Dimensions Mn and low alloy steel forgings Material thickness (t) Thickness Diame- Position of 502 Acceptance criteria for manual magnetic particle testing of reference ter of side drilled of C-Mn and low alloy steel forgings shall be according to block (T) side holes Table D-8. drilled hole mm Acceptance criteria for manual liquid penetrant testing of duplex stainless steel forgings T < 20 mm 15 mm or t 2.4 ± 0.2 T/4, T/2 and T3/4 20 mm ≤ t < 35 mm 20 mm or t 3.0 ± 0.2 503 Acceptance criteria for manual liquid penetrant testing of duplex stainless steel forgings done in accordance with 35 mm ≤ t < 75 mm 50 mm or t ASTM E1417 or equivalent standard shall be according to 75 mm ≤ t < 100 mm 90 mm or t 6.0 ± 0.2 The distance Table D-8. 100 mm ≤ t < 150 mm 125 mm or t between the two outer holes and the nearest surface Table D-8 Acceptance criteria for manual magnetic particle and shall not exceed liquid penetrant testing of forgings 12 mm A Crack-like indications: not permitted Preparation of forgings for ultrasonic testing B Linear indications with length more than 2 mm or three times the width: not permitted. 306 The machining of duplex stainless steel forgings for Linear indications with length < 1.5 mm may be deemed ultrasonic testing shall take into account that angle compres- irrelevant sion wave probes shall and can only be used without skipping. C Rounded indications: Diameter < 3 mm, accumulated diame- Testing procedure ters in any 100 x150 mm area < 8 mm. 307 The testing procedure for duplex stainless steel forgings Acceptance criteria for visual examination shall take into account that angle compression wave probes 504 Acceptance criteria for visual examination of forgings shall and can only be used without skipping. The testing shall shall be in accordance with ASTM A 961, Chapter 15. If the hence be performed from as many faces that access permits. surface imperfections acceptable under 15.5 are not scattered, Manual liquid penetrant testing of duplex stainless steel forg- i.e. more than 3 off in any 100 x 150 mm area, such imperfec- ings tions shall be considered injurious. 308 Manual liquid penetrant testing of duplex stainless steel forgings shall be performed in accordance with ASTM E 1417 or equivalent standard. Post-emulsified penetrants should be preferred. The penetration and developing times shall be long E. Non-destructive Testing and Visual enough to allow effective detection of the smallest indications Examination of Castings allowed. E 100 General Guidance note: The penetration time for water washable penetrants should not be 101 All non-destructive testing of castings shall be done less than 35 - 45 minutes and for post-emulsified penetrants not according to accepted procedures. less than 10 - 15 minutes. 102 Manual non-destructive testing and visual examination

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- procedures shall be prepared as required in B102 through B104 to reflect the requirements of the applied standard. 309 Reports shall be in accordance with B105 and B106 and 103 Acceptance criteria for manual non-destructive testing ASTM A388, chapter 9. and visual examination of castings are given in E600. D 400 Visual examination of forgings 104 Manual non-destructive testing of castings shall be per- 401 Visual examination of forgings shall be performed in formed in compliance with the standards listed below and as accordance with C400, with acceptance criteria according to required in the following: D500. ASTM E165 Standard Test method for Liquid Penetrant D 500 Acceptance criteria for forgings Inspection 501 Acceptance criteria for manual ultrasonic testing of ASTM A609 Standard Practice for Castings, Low Alloy, forgings shall be: and Martensitic Stainless Steel, Ultrasonic Examination Thereof. Straight beam testing ASTM E709 Standard Guide for Magnetic Particle Exam- — No single indication shall be larger than the indication ination received from the flat bottom holes in the reference block ASTM E 1417 Standard Practice for Liquid Penetrant required in D200. Examination ASTM E1444 Standard Practice for Magnetic Particle Angle beam testing of C-Mn and low alloy steel forgings Examination — No single indication shall exceed a DAC curve established ASME Boiler and Pressure Vessel Code, Section V, using the notches in the reference block required in D200. Article 2. MSSSP-55 Quality standard for steel castings for valves, Angle beam testing of duplex stainless steel forgings flanges, and fittings and other piping compo- — No single indication shall exceed a DAC curve established nents (visual method). using the side drilled holes in the reference Multiple indi- E 200 Ultrasonic and magnetic particle testing of C-Mn cations and low alloy steel castings — No indications within 13 mm of each other in any direction shall exceed 50% of the reference curve. 201 Manual ultrasonic testing of castings shall be done according to ASTM A609, procedure A, and Supplementary Acceptance criteria for manual magnetic particle testing of C- requirement S1. In addition the requirements below apply.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 205

Ultrasonic testing procedures Sizing of indications 202 Ultrasonic testing procedures shall contain the informa- 213 In general, the area containing imperfections, shall be tion in B102 and: sized (area and length) using the 6 dB drop technique. The area refers to the surface area on the castings over which a continu- — type of instrument ous indication exceeds the acceptance criteria. This area will — type and dimensions of probes be approximately equal to the area of the real defect provided — range of probe frequencies the defect size is larger than the 6 dB beam profile of the probe. — description of reference blocks 214 If the real imperfection size is smaller than the 6 dB — calibration details, range and sensitivity beam profile, the 6 dB drop technique is not suited for sizing. — surface requirements, including maximum temperature The area measured on the surface will be measured too large — type of coupling medium and not represent the real indication size. A guide to classify if — scanning techniques supplemented with sketches, show- the revealed indications are greater or smaller than the 6 dB ing the probes used and area covered by each probe drop profile is given in EN 10228-3, part 13. — description of methods for re-check of areas with reduc- tion or loss of back reflection 215 If the size of the indication is evaluated to be smaller — recording details. than the 6 dB drop profile at the depth of discontinuity, a graphic plot that incorporates a consideration of beam spread Ultrasonic Apparatus should be used for realistic size estimation. 203 Verification of Screen Height Linearity and Amplitude Periodical checks of equipment Linearity shall be performed at the beginning of each period of 216 At approximately four-hourly intervals and at the end of extended use (or every 3 months, whichever is less). Records testing, the range scale, probe angle and primary gain must be shall be made available upon request. checked and corrected. Checks shall also be carried out when- Probes ever a system parameter is changed or changes in the equiva- lent settings are suspected. If deviation is found to be larger 204 Straight beam (normal) probes with frequency 1-5 MHz than 2% of range scale, or 3 dB of primary gain setting or 2° of and dimension Ø 10-30 mm shall be used. Straight beam, nor- nominal angle probe, the testing carried out with the equip- mal probes shall be single or twin crystal. Twin crystal probes ment over the previous period shall be repeated. shall be used when testing is performed on material with nom- inal thickness t < 60 mm. The focusing zone of the twin crystal Reporting probes shall be adapted to the material thickness to be exam- 217 Reports shall be in accordance with B105, B106, and ined. ASTM A609, chapters 9 and 19. All indications exceeding 205 Single or twin crystal probes can be used when testing is 50% of the DAC shall be reported. performed on material with nominal thickness t ≥ 60 mm. The Manual magnetic particle testing of C-Mn and low alloy steel single crystal probes shall have a dead zone as small as possi- castings ble, e.g. 10% of the material thickness or 15 mm whichever is 218 Manual magnetic particle testing of C-Mn steel castings the smaller. shall be performed in accordance with ASTM E 709, ASTM Reference blocks E1444 or equivalent standard. 206 All reference blocks shall be marked with an identifica- 219 Reports shall be in accordance with B105 and B106. tion that relates to the specific application of each block. E 300 Ultrasonic and liquid penetrant testing of duplex Casting conditions for ultrasonic testing stainless steel castings 207 Castings shall as far as possible be machined according Ultrasonic testing to D211 and D212. 301 Ultrasonic testing of duplex stainless steel castings shall Calibration of amplification and testing procedure be performed in accordance with E200, but with the following 208 The IIW or ISO calibration blocks (V1 – V2) according additions to the requirements to: to ISO 2400 or ISO 7963 shall be used for calibration of range scale and for angle determination. These calibration blocks —probes shall, as near as practicable, have the same acoustic properties — reference blocks for angle beam testing as the material to be tested. Calibration of range scale can alter- — casting conditions for ultrasonic testing natively be done on a defect free area of known thickness in the — testing procedure. material to be examined. The range scale is to be selected such that there are always at least 2 back-wall echoes (reflections) Angle probes on the screen. 302 Angle probes for duplex stainless steel shall be twin 209 The calibration of the required amplification shall be crystal (transmitter/receiver) compression-wave probes. Angle performed according to ASTM A609, chapter 8 and S1. The compression wave probes shall and can only be used without probe size and frequency that provides optimum response shall skipping. be used for the testing. 303 Low frequency shear wave angle probes may be used for 210 Note 3 of ASTM A609, chapter 8: When scanning, the duplex stainless steel instead of twin crystal (transmitter/ gain shall be increased by minimum 6 dB above the corrected receiver) compression-wave probes, provided it is verified on primary gain. For evaluation of indications the gain shall be the reference blocks that it is possible to obtain a DAC with a reduced by the increased dB level used during scanning. shear wave angle probe that is comparable to the DAC obtained with an angle compression wave probe. 211 Rechecks shall be performed if the loss of back reflec- tion is 50% or greater. The method for further investigation of 304 Creep wave probes shall be used for detection of sub sur- areas with reduction or loss of back reflection, ASTM A 609 face defects close to the scanning surface, unless testing can be paragraph 8.5, shall be described. performed from both sides. 212 Different frequencies, types, angles and diameter of Reference blocks for angle beam testing probes shall be employed to obtain additional information 305 Reference blocks for angle beam testing of duplex stain- about detected indication less steel with angle compression wave probes shall have side

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 206 – App.D drilled holes and a 1 mm deep and 20 mm wide spark eroded — No crack-like indications are acceptable, and notch according to Figure 4 and Table D-7. — According to Table D-9. Casting conditions for ultrasonic testing Table D-9 Ultrasonic testing acceptance criteria for castings 306 Duplex steel stainless castings shall be machined Straight beam testing according to D211 and D212. ASTM A609, 10.2.1, 10.2.2 and 10.2.3 307 The machining of duplex stainless steel castings for Critical areas Other areas ultrasonic testing shall take into account that angle compres- Table 2, Quality Level 1 Table 2, Quality Level 3 sion wave probes shall and can only be used without skipping. Angle beam testing Testing procedure ASTM A609 S1.4.1 and Table 2 308 The testing procedure for duplex stainless steel castings Critical areas Other areas shall take into account that angle compression wave probes Table 2, Quality Level 1 Table 2, Quality Level 3 shall and can only be used without skipping. The testing shall hence be performed from as many faces that access permits. 603 Acceptance criteria for manual radiographic testing of critical areas of castings shall be according to Table D-10: Manual liquid penetrant testing of duplex stainless steel cast- ings Table D-10 Radiographic acceptance criteria for castings 309 Manual liquid penetrant testing of duplex stainless steel Type of defect Acceptance criteria castings shall be performed in accordance with ASTM E 1417 Standard Maximum Severity Level or equivalent standard. Post-emulsified penetrants should be Gas porosity 2 used on precision castings only. The penetration and develop- ing times shall be long enough to allow effective detection of Inclusions 2 Shrinkage 2 the smallest indications allowed. ASTM E280 Cracks 0 Guidance note: The penetration time for water washable penetrants should not be Hot tears 0 less than 35 - 45 minutes and for post-emulsified penetrants not Inserts 0 less than 10 - 15 minutes.

604 Acceptance criteria for manual magnetic particle testing ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- and manual liquid penetrant testing of castings shall be accord- ing to Table D-11. 310 Reports shall be in accordance with B105 and B106. E 400 Radiographic testing of castings Table D-11 Acceptance criteria for manual magnetic particle and liquid penetrant testing of castings General A Crack-like defects: not permitted 401 Radiographic testing of castings shall be done according B Linear indications with length more than three times the to ASME Boiler and Pressure Vessel Code, Sec.7, article 2 or width: not permitted. equivalent standard. In addition, the applicable requirements Linear indications with length < 1.5 mm may be deemed irrel- of B200 and the requirements below shall apply. evant. Procedures C Rounded indications: Diameter < 3 mm, accumulated diame- ters in any 100 × 150 mm area < 8 mm. 402 Radiographic procedures shall in addition to the require- ments of B203, give the following information: 605 Acceptance criteria for visual inspection of castings shall be in accordance with MSS SP-055. — shooting sketches — coverage — Type 1: Not acceptable — source location — Types 2 through 12: A and B. — location of IQI — acceptance criteria. Repairs by welding 606 Complete removal of the defect shall be confirmed by E 500 Visual examination of castings magnetic particle testing, or liquid penetrant testing for non- 501 Visual examination of castings shall be performed in ferromagnetic materials, before re-welding. accordance with C400 and MSS SP-55. 607 Repair welds of castings shall meet the acceptance crite- 502 Reports shall be in accordance with C405. ria designated for the particular portion of the casting. E 600 Acceptance criteria for castings General F. Automated Non-Destructive Testing 601 Acceptance criteria shall apply for the entire casting or portions of the casting. If different acceptance criteria shall F 100 General apply for different portions of the casting, the critical areas of 101 These requirements are applicable to all automated NDT the casting shall be defined. processes except automated ultrasonic testing of girth welds Guidance note: where specific requirements are given in Appendix E. The Critical areas shall include abrupt changes of sections and at the requirements given in this subsection are additional to the junctions of risers, feeders and gates to the casting. Highly requirements of any code or standard where automated NDT stressed areas such as weld necks shall be considered as critical methods are prescribed or optional. areas. 102 Automated non-destructive testing can replace manual

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- non-destructive testing or one automated non-destructive testing method/system can replace another automated non-destructive 602 Acceptance criteria for manual ultrasonic straight beam testing method/system provided the equivalence of systems is testing of castings shall be: documented with regard to function, operation, ability in detec-

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.D – Page 207 tion and sizing and performance. G. Non-Destructive Testing at Plate 103 Documentation of capability/performance and qualifica- and Coil Mill tion of automated NDT systems in pipe mills will normally not be required for systems meeting the documentation require- G 100 General ments given in H404. 101 The non-destructive testing during manufacture of plate and coil shall be performed according to documented proce- F 200 Documentation of function and operation dures. The automated NDT equipment shall be documented with 102 The testing shall include testing of a band along the four regard to function and operation. Items subject to documenta- edges of plate for laminar imperfections. A suitable allowance tion include: in the width of the band shall be made to compensate for pos- sible oversized plates and subsequent edge milling and end — brief functional description of the equipment bevelling. — detailed equipment description 103 Testing of coil, e.g. for HFW pipe, may alternatively be — operation manual including type and frequency of func- substituted with testing of finished pipe at the pipe mill. tional checks 104 The width of the band at the longitudinal plate edges — calibration shall extend: — limitations of the equipment with regard to material or weld features including size, geometry, type of flaws, sur- — at least 50 mm inside the location of future welding prep- face finish, material composition etc. arations for SAW longitudinal welds — repeatability. — At least 15 mm inside the location of future welding prep- arations for HFW longitudinal welds. F 300 Documentation of performance 105 The width of the band at the transverse plate edges shall 301 The capability and performance of automated NDT normally extend: equipment shall be documented by statistical records covering, as relevant: — at least 50 mm inside the location of future welding prep- arations for girth welds. — accuracy in indication sizing (random and systematic deviation) Additional non-destructive testing — accuracy in positioning / location 106 Any additional non-destructive testing shall be specified — defect characterisation abilities compared to the results of by the purchaser. other NDT performed 107 If automated ultrasonic testing of girth welds during — repeatability, and installation will be performed the width of the band should — probability of detection values or data for different thresh- extend at least 150 mm inside the location of future welding old settings to determine the threshold to be used for preparations for girth welds. required detection during testing. 108 If allowance for re-bevelling of pipe shall be included, the width of the band should extend at least 100 mm inside the Guidance note: location of future welding preparations for girth welds. Automated non-destructive testing equipment can generally be 109 For detection of cracks angle probes shall be used to sup- divided into two groups. One group consists of equipment plement the straight beam probes. Testing shall be in general intended for detection, sizing and positioning of indications (typ- accordance with ASTM A577 or equivalent standard and: ically real time radiography) and one group consisting of equip- ment intended for detection only and where sizing and — Probes shall meet the requirements of C203. positioning of indications is performed by other means (typically ultrasonic testing of the weld seam according to ISO 9765). For — Sensitivity for C-Mn steel shall be a DAC curve based on the latter types of equipment, documentation of performance reference blocks with a rectangular notch with depth 3% may be limited to demonstration of adequate detection of defects of the material thickness on both sides. typical for the manufacturing process, threshold setting parame- — Reference blocks for duplex stainless steel and austenitic ters and repeatability. steels shall have one Ø3 mm flat bottom hole perpendicu- lar to the angle of incidence of the probe and at the largest ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- possible depth from the scanning surface of the block. Ref- erence blocks shall be of the actual material tested or of a F 400 Qualification material with similar with acoustic properties. — Low frequency shear wave angle probes may be used for 401 A full qualification programme for automated NDT CRA material instead of twin crystal (transmitter/receiver) equipment will in general comprise the following stages: compression-wave probes. For acceptance, it shall be ver- ified on the reference blocks that it is possible to obtain a — initial evaluation and conclusions based on available DAC with a shear wave angle probe that is comparable to information the DAC obtained with an angle compression wave probe. — identification and evaluation of significant parameters and their variability 110 The acceptance criterion is: — planning and execution of a performance test programme — reference investigations. — No indications shall exceed the DAC. G 200 Ultrasonic testing of C-Mn steel and CRA plates F 500 Evaluation of performance documentation 201 Ultrasonic testing for laminar imperfections shall be in 501 As a minimum a qualification will involve an assess- accordance with ISO 12094 amended as follows: ment of the automated NDT equipment technical documenta- tion, including the quality assurance system, and available — the distance between adjacent scanning tracks shall be suffi- information on equipment capability and performance. Lim- ciently small to ensure detection of the minimum imperfec- ited practical tests must be performed in many cases. tion size to be considered in the plate body and all four edges

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 208 – App.D

202 Acceptance criteria for ultrasonic testing of C-Mn and 402 The demonstration of the alternative test method shall be duplex steel plate for laminar imperfections are given in Table based on the principles given in Subsection F and using sam- D-12. ples of plate similar to those ordered. The plates shall contain a representative and agreed size range of natural and/or artifi- Table D-12 Ultrasonic testing, acceptance criteria for laminar cial defects of types that are typical for the manufacturing imperfections process in question. Acceptance criteria for body G 500 Disposition of plate and coil with unacceptable Service Maximum Minimum Size of Maximum laminations or inclusions allowed imperfection reference population imperfection size to be area density 501 Plates and coil that contain unacceptable laminations or considered inclusions shall be rejected or, if possible, be cut back until no Non- Area: Area: 300 mm2 1 000 mm 10 lamination or inclusion exceeding the acceptance criteria is sour 1 000 mm2 Length: 35 mm × within the present in the plate/coil. Width: 8 mm 1 000 mm reference area G 600 Visual examination of plate and coil Sour Area: Area: 150 mm2 500 mm 5 2 601 Visual examination shall be carried out in a sufficiently 500 mm Length: 15 mm × within the illuminated area, minimum 350 lx, but 500 lx is recommended. Width: 8 mm 500 mm reference area If required to obtain good contrast and relief effect between imperfections and background additional light sources shall be Acceptance criteria for edges used. Service Maximum Minimum size of Size of Maximum allowed imperfection to reference population 602 For direct examination the access shall generally permit imperfection be considered area density placing the eye within 600 mm of the surface to be examined All Area: Length: 10 mm 1 000 mm 3 and at an angle of not less than approximately 30°. 100 mm2 length within the 603 A sufficient amount of tools, gauges, measuring equip- Width: reference ment and other devices shall be available at the place of exam- 6 mm area ination. Notes: 604 The objects to be examined shall be cleaned to remove 1) For an imperfection to be larger than the minimum imperfection to be all scale and processing compounds prior to examination. The considered, all dimensions, e.g. min area, min length and min width, cleaning process shall not injure the surface finish or mask pos- will have to be exceeded (for body). sible imperfections. 2) Two or more adjacent imperfections shall be considered as one imper- fection if they are separated by less than the smaller dimension of either G 700 Acceptance criteria and disposition of surface indication. imperfections 3) The population density shall be the number of imperfections smaller than the maximum allowed and larger than the minimum imperfection Acceptance criteria size to be considered 701 Plate/coil shall meet the acceptance criteria specified by 4) The reference area for plate/coil when the plate width is less than one side of the square reference area shall be 1.00 m2 for non-sour and 0.25 the pipe mill. The acceptance criteria shall under no circum- m2 for sour service. stance be less stringent than the applicable requirements for 5) The width of an imperfection is the dimension transverse to the longi- pipe, as specified in H500. tudinal edge of the plate/coil or for pipe the longitudinal axis. 702 Imperfections shall be dressed out by grinding. Ground 203 Subject to agreement the acceptance criteria for the body areas shall blend smoothly into the surrounding material. Com- of plate and coil can be limited to an allowed permitted area of plete removal of defects shall be verified by local visual 100 mm2 and a population density of 5 and with the minimum inspection and, if necessary, aided by suitable NDT inspection imperfection size area 30 mm2, length and width 5 mm. All methods. The remaining wall thickness in the ground area shall other requirements in Table D-12 shall apply. be checked by ultrasonic wall thickness measurements to ver- ify that the thickness of the remaining material is more than the G 300 Ultrasonic testing of CRA clad C-Mn steel plate specified minimum. Imperfections that encroach on the mini- mum permissible wall thickness after grinding shall be classi- 301 For ultrasonic testing of the backing material the fied as defects. requirements of G100 and G200 shall apply. Disposition of plate with defects 302 Ultrasonic testing for the detection of lack of bond between the C-Mn backing material and CRA shall be per- 703 Plate and coil that contain defects shall be rejected or, if formed in accordance with ASTM A578, S7 amended as fol- possible, be cut back until no defect is present in the plate/coil. lows: — the distance between adjacent scanning tracks shall be suf- ficiently small to ensure detection of the minimum imper- H. Non-Destructive Testing fection size to be considered in the plate body and all four of Linepipe at Pipe Mills edges. H 100 General 303 Acceptance criteria are: 101 The extent of non-destructive testing during manufac- — ASTM A578, S7. In addition, no areas with laminations or ture of linepipe shall be as required in Sec.7 F. lack of bond are allowed in the plate edge areas. 102 The types of testing required are defined as: G 400 Alternative test methods — ultrasonic testing 401 If agreed alternative methods of testing may be accepta- — surface imperfection testing ble, if the alternative test method is documented as required in — radiographic testing. H402 and the alternative test method is demonstrated to give at least the same sensitivity and capability in detection of imper- Whenever the choice of non-destructive testing methods is fections. optional, this is indicated in this subsection.

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103 Non-destructive testing shall be performed in compli- 104 All NDT shall be performed according to documented ance with the standards listed below and as required in this procedures that, as a minimum, give information on the fol- subsection: lowing aspects: Electromagnetic (flux leakage) — applicable code(s) or standard(s) ISO 9402 Seamless and welded (except submerged arc — welding method (when relevant) welded) steel tubes for pressure purposes - Full — joint geometry and dimensions (when relevant) peripheral magnetic transducer/ flux leakage —material testing of ferromagnetic steel tubes for the — NDT method detection of longitudinal imperfections — technique ISO 9598 Seamless steel tubes for pressure purposes - Full — equipment, main and auxiliary peripheral magnetic transducer/flux leakage — consumables when relevant (including brand name) testing of ferromagnetic steel tubes for the — coverage calculation supplemented with sketches detection of transverse imperfections — sensitivity — calibration references and technique Electromagnetic (eddy current) — trigger or alarm settings — for ultrasonic testing equipment the procedure shall ISO 9304 Seamless and welded (except submerged arc- describe the method for setting and checking the lack of welded) steel tubes for pressure purposes - Eddy coupling alarm current testing for the detection of imperfections — assessment of imperfections Radiographic — method for demonstrating compliance of equipment with the assumptions in the procedure ISO 12096 Submerged arc-welded steel tubes for pressure — reporting and documentation of results. purposes - Radiographic testing of the weld seam for the detection of imperfections. 105 Personnel performing NDT shall be qualified according Ultrasonic to A500. 106 All NDT for final acceptance of pipe shall be performed ISO 9303 Seamless and welded (except submerged arc- after completion of any cold expansion and heat treatment welded) steel tubes for pressure purposes - Full operations. peripheral ultrasonic testing for the detection of longitudinal imperfections For seamless pipe, the NDT for final acceptance may be per- formed prior to cropping, bevelling and end sizing. Cold ISO 9305 Seamless tubes for pressure purposes - Full straightening and cold sizing of seamless pipe ends imposing a peripheral ultrasonic testing for the detection of maximum strain of 1.5% may be performed after surface test- transverse imperfections ing of the pipe body but prior to testing of pipe ends. ISO 10124 Seamless and welded (except submerged arc- welded) steel tubes for pressure purposes - All NDT for "in-house" purposes may be performed at any Ultrasonic testing for the detection of laminar time at the Manufacturer's discretion. imperfections 107 If NDT of plate in accordance with subsection G is per- ISO 10543 Seamless and hot-stretch reduced welded steel formed at the plate mill, ultrasonic testing for laminar imper- tubes for pressure purposes - Full peripheral fections may be omitted at the pipe mill. ultrasonic thickness testing ISO 11496 Seamless and welded steel tubes for pressure 108 Reporting of NDT shall be according to the require- purposes - Ultrasonic testing of tube ends for the ments of the applicable ISO standard unless otherwise agreed. detection of laminar imperfections H 200 Suspect pipe ISO 13663 Welded steel tubes for pressure purposes - Ultra- sonic testing of the area adjacent to the weld 201 In all cases when pipe inspection results in the auto- seam body for detection of laminar imperfec- mated NDT system is giving signals equal to or greater than tions the threshold level or when surface imperfections are disclosed ISO 12094 Welded steel tubes for pressure purposes - Ultra- by visual examination, the pipe shall be deemed suspect. sonic testing for the detection of laminar imper- Suspect pipe can be dealt with according to one of the follow- fections in strips or plates used in manufacture ing options: of welded tubesUltrasonic (weld seam) ISO 9764 Electric resistance welded steel tubes for pres- — the suspect pipe can re-inspected using the automated sure purposes - Ultrasonic testing of the weld NDT equipment in the static mode. Pipes passing these seam for longitudinal imperfections tests are deemed acceptable ISO 9765 Submerged arc-welded steel tubes for pressure — the suspect area of the pipe can be re-tested by manual purposes - Ultrasonic testing of the weld seam NDT using the same NDT method and sensitivity as the for the detection of longitudinal and/or trans- automated NDT, and using appropriate techniques. Pipes verse imperfections passing these tests are deemed acceptable — the suspect area of welds, except HFW welds, can be radi- Liquid penetrant ographed to determine if the indication is caused by slag or porosity type indications. Pipes meeting the require- ISO 12095 Seamless and welded steel tubes for pressure ments of ISO 12096 are deemed acceptable purposes - Liquid penetrant testing — defective welds, except HFW welds, can be repaired by Magnetic particle welding according to H301 through 307 — defects can be removed by grinding according to H308 ISO 13664 Seamless and welded steel tubes for pressure — the suspect area can be cut off if the minimum specified purposes - Magnetic particle inspection of tube length is met after cutting ends for the detection of laminar imperfections — the pipe can be scrapped. ISO 13665 Seamless and welded steel tubes for pressure purposes - Magnetic particle inspection of tube If the suspect area is cut off, then all NDT requirements per- body for the detection of surface imperfections taining to pipe ends shall be performed on the new pipe end.

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H 300 Repair of suspect pipe sensitivity. The documentation shall, as a minimum cover: Repair welding — NDT system operating procedures 301 Repair welding of pipe body or repair welding of welds — capability for the intended wall thickness in HFW pipe is not permitted. — capability for the intended material 302 Repair welding of cracks is not permitted unless the — repeatability cause of cracking has been established not to be a systematic — detection of defects typical for the manufacturing process welding error. (If there is a crack in the weld the pipe is per def- with the equipment in question inition considered rejected.) This means a technical evaluation — threshold level setting parameters of the cause of cracking shall be performed. If it can be dem- — dynamic test data demonstrating the systems capability onstrated that the crack is a “one off” situation, repair welding under production test conditions. may be performed subject to agreement) Reference standards for ultrasonic and electromagnetic 303 Repair welding shall be performed according to quali- inspection fied repair welding procedures. Each repair shall be performed 405 Reference standards shall meet the requirements of the with a minimum of two passes over a length not less than 50 applicable ISO standard and the requirements given in this mm. appendix. 304 The total length of weld repair in any single pipe shall 406 The reference standard shall be a length of pipe with the not exceed 5% of the weld length. same outside diameter and wall thickness tolerances and with 305 Weld defects separated by less than 100 mm shall be similar acoustic properties as the pipe tested during produc- repaired as a single continuous repair. tion. For welded pipe the reference standard shall contain a weld typical for the production weld to be tested. 306 Re-inspection of repair welds shall be 100% visual examination and 100% ultrasonic and/or 100% radiographic 407 Reference standards may be of any convenient length as testing as required for the original weld. decided by the manufacturer. 307 Acceptance criteria for weld repairs shall be as for the 408 Reference standards shall contain reference indications original weld. as required by this Appendix for the pipe to be tested. Repair of welds by grinding 409 Verification of the dimensions and shape of all reference indications shall be performed according to a documented pro- 308 Surface defects may be dressed out by cosmetic grind- cedure. Documentation shall be available. All reference stand- ing. Ground areas shall blend smoothly into the surrounding ards shall be marked with an identification that relates to the material. Complete removal of defects shall be verified by specific application of each reference standard. local visual inspection and, if necessary, aided by suitable NDT inspection methods. The remaining wall thickness in the Validation of length of pipe tested ground area shall be checked by ultrasonic wall thickness 410 When automated non-destructive testing equipment is measurements to verify that the thickness of the remaining used, a short area at both pipe ends will normally not be tested. material is more than the specified minimum. Imperfections A sample pipe shall be fitted with a suitable reference indicator that encroach on the minimum permissible wall thickness and/ at each end. The distance from the pipe end to the reference or weld thickness shall be classified as defects. indicator shall be equal to the length not covered by the auto- Repair of pipe body by grinding mated testing equipment during production testing. Prior to start of production the sample pipe shall be passed through the 309 Repair of pipe body by grinding shall be performed testing equipment at the operational scanning velocity. For according to H525 through 527. acceptance of the equipment, both reference indicators shall be Disposition of pipe containing defects detected. At the manufacturer’s option, these reference indica- tors may be included in the reference standard. 310 Disposition of pipe containing defects after repair shall be according to H528. Scanning velocity 411 The scanning velocity shall be selectable. The scanning H 400 General requirements for automated NDT sys- velocity shall be set low enough so that the length between the tems activation of each probe (spatial resolution) is sufficiently Alternative methods of testing short, i.e. the distance the probe travels while inactive, shall be significantly less than the maximum length of allowable 401 Subject to agreement, alternative methods of testing imperfections. may be accepted if the alternative test method is documented as required in H402 and the alternative test method is demon- 412 The scanning velocity VC for inspection of longitudinal strated to give at least the same sensitivity and capability in welds shall be determined according to: detection of imperfections. V ≤ W • PRF⁄ 3 402 The demonstration of the alternative test method shall be C C based upon the principles given in Subsection F and using sample lengths of pipe similar to those ordered. The pipes shall Where WC is the narrowest - 6 dB effective beam width at the contain a representative and agreed size range of natural and/ appropriate distance of all probes within the array and PRF is or artificial defects of types that are typical for the manufactur- the effective pulse repetition frequency per probe. ing process in question. 413 The circumferential scanning velocity for inspection of System calibration seamless pipe and helical welds shall be decided depending on 403 All automated NDT systems shall have a full system cal- effective pulse spacing (pulse density) and on circumferential ibration with intervals not exceeding 12 months. Documenta- scanning speed and helical pitch. The effective pulse spacing tion shall be available. (EPS) is specified as follows: Documentation of system capabilities — EPS = circumferential scanning speed/PRF 404 Documentation of automated NDT systems shall be — EPS shall not exceed 1 mm/pulse. available to demonstrate that the systems are capable of detect- — The helical pitch (mm/revolution) shall not exceed the narrow- ing the reference indicators used to establish the specified test est - 6 dB effective beam width of all probes within the array.

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Lack of coupling — the sensitivity during production testing will not be 414 Automated ultrasonic testing systems shall incorporate a affected by the lower accuracy of the tracking system system for detection of lack of coupling. The settings for lack — that the lower accuracy is compensated by system sensitiv- of coupling alarm and check of the settings shall be described ity and gate settings. in the manufacturer’s written procedure. 423 The gates shall be set wide enough to cover 3 mm of the Initial sensitivity and threshold settings (calibration) base material outside the fusion line and to compensate for: 415 The sensitivity and threshold settings shall be estab- — the tolerances of weld tracking system lished according to a documented procedure. The system shall — variations in the width of external and internal caps be optimised in the static mode. When the settings are opti- — offsets between the external and internal weld bead. mised, the relevant parameters shall be recorded and the refer- ence standard shall be passed 3 times through the equipment at Ultrasonic testing of CRA pipes and welds with CRA weld the operational velocity. Any change in settings required to deposits maintain the static mode settings shall be recorded as an aver- age of the 3 runs. For acceptance of the settings, all reference 424 Ultrasonic testing of welds with CRA (duplex, other reflectors need to be detected at or above the threshold. stainless steels and nickel alloy steel) weld deposits will in order to achieve an adequate detection of imperfections, nor- 416 During production testing the relative speed of move- mally require that special reference blocks and probes are used ment between the pipe and the test assembly shall not exceed for testing of these materials. that used for the sensitivity and/or alarm settings during dynamic calibration. 425 Angle probes for duplex stainless steel and austenitic steels shall be twin crystal (transmitter/receiver) compression- Verification of sensitivity and threshold settings (calibration) wave probes. Angle compression wave probes shall and can 417 The sensitivity of sensitivity and/or alarm settings shall only be used for scanning without skipping and creep wave be verified every fourth hour or once every 10 pipes tested, probes must therefore be used for detection of sub-surface whichever is the longer period, and: defects close to the scanning surface. 426 Reference blocks for duplex stainless steel and auste- — at the start and end of each shift nitic steels materials and the weld deposits shall have a specific — at any change of equipment operator (for continuous shifts location and type of reference reflectors in general compliance the end and start verification can be combined) with B400. Surface notches will not be suitable due to the — whenever a malfunction of the equipment is suspected. mode conversions at base material and a surface notch. This The verification frequency when manufacturing HFW pipe will result in multiple echoes with different arrival time from coil shall be agreed upon. As a minimum the frequency appearing from the same notch. The actual reflection from the shall be at the beginning and end of an inspection and at any reflector will be weak and distinguishing this echo from other stops in production. signals will often not be possible. Resetting of sensitivity and threshold settings (recalibration) 427 Specific ultrasonic testing procedures shall be devel- oped for this testing. The procedures shall be developed con- 418 Resetting of sensitivity and threshold settings shall be sidering the requirements B400 and addressing the specific performed whenever: features and characteristics of the equipment to be used. — the standard reflectors do not trigger the alarm during ver- 428 It is recognised that not all equipment will be adaptable ification of sensitivity and threshold settings to meet the requirements above. — a change of component affecting the sensitivity and/or 429 Low frequency shear wave angle probes may be used for alarm setting is made in the system duplex stainless steel and austenitic steels instead of the angle — the verification of sensitivity and/or alarm settings fails to compression wave probes, provided it is verified on reference meet the requirements for the particular equipment. blocks made in accordance with B400 that it is possible to obtain a DAC with shear wave angle probe(s) that is compara- For re-setting of sensitivity and threshold settings during pro- ble to a DAC obtained from angle compression-wave probes. duction the settings shall be optimised in the static mode. The shear wave angle probes used for this verification shall be When the settings have been optimised, the reference standard identical to the probes used in the production testing equip- shall be passed once through the equipment at the operational ment. velocity. Any change in settings required to maintain the static mode settings shall be recorded. For acceptance of the settings, 430 If it is not possible to demonstrate adequate performance all reference reflectors need to be detected at or above the of low frequency shear wave angle probes for ultrasonic test- threshold. ing of duplex stainless steel and austenitic steels, other meth- ods or combination of methods shall be used and the adequacy Retesting of pipes of the method(s) demonstrated. 419 If the verification of sensitivity and threshold settings 431 Notches and through drilled holes are not considered a fails to meet the requirements for the particular equipment, all suitable reflector for compression wave angle probes due to the pipes inspected since the previous successful verification shall mode conversion and unpredictable arrival times of mode con- be retested. verted signals. When compression wave angle probes are used, Specific requirements for ultrasonic testing equipment for other types of reflectors shall be used and the acceptance crite- welds ria specified accordingly. 420 The equipment shall be capable of inspecting the entire Specific requirements for radiographic testing thickness of the weld seam. 432 Radiographic testing shall be performed in accordance 421 Before starting production testing, the range scale and with ISO 12096, image class R1 using wire type Image Quality angle of all probes shall be demonstrated to comply with the Indicators (IQI) in accordance with ISO 19232. documented procedure. 433 Radioscopic testing techniques in accordance with EN 422 Equipment for testing of welds shall have a weld track- 13068 may be used provided the equipment has been demon- ing system. The system should be capable of tracking the weld strated, in accordance with Subsection F, to give sensitivity centreline with an accuracy of ± 2 mm or better. For systems and detection equivalent to conventional x-ray according to not meeting this requirement it shall be documented that: ISO 12096.

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434 If radioscopic testing techniques are used, the quality of 514 All pipes shall be free from defects in the finished con- the ray image has to be verified as required in 417. dition. The manufacturer shall take adequate precautions to prevent pipe damage and minimise the presence of imperfec- H 500 Visual examination and residual magnetism tions. General 515 Cracks, sweats or leaks are not acceptable and shall be 501 Visual examination shall be carried out in a sufficiently classified as defects. illuminated area; minimum 350 lx, but 500 lx is recommended. 516 Surface imperfections evident by visual inspection shall If required additional light sources shall be used to obtain good be investigated, classified and treated as according to H517 to contrast and relief effect between imperfections and back- H522. H519 applies to surface imperfections at the internal ground. surface of clad or lined pipes. 502 In accordance with Sec.7, Table 7-16, each linepipe 517 Imperfections with depth ≤ 5% of the specified wall shall be subject to 100% visual inspection. This implies 100% thickness, or 0.5 mm, whichever is greater, but maximum 0.7 visual inspection of the outside of the pipe body. The interior mm for t ≤ 25 mm, and maximum 1.0 mm for t > 25 mm, and of the pipe shall be inspected from both ends as far as access which do not encroach upon the specified minimum wall thick- permits. The interior of duplex stainless steel and clad/lined ness, shall be classified as acceptable imperfections. The material should be 100% visually inspected. imperfections may remain in the pipe or be dressed out by cos- 503 A sufficient amount of tools, gauges, measuring equip- metic grinding. ment and other devices shall be available at the place of exam- 518 Imperfections with depth larger than stated in H517, and ination. which do not encroach upon the specified minimum wall thick- 504 The pipes to be examined shall be cleaned to remove ness, shall be classified as dressable defects and shall either be loose scale and processing compounds that may interfere with removed by grinding in accordance with H525 or treated in the examination. The cleaning process shall not affect the sur- accordance with H528, as appropriate. face finish or mask possible imperfections. 519 For the internal surface of clad or lined pipes the follow- 505 Subject to agreement, alternative methods of testing ing applies: Imperfections with depth ≤ 0.5 mm, and which do may be accepted. It shall be demonstrated that the alternative not encroach upon the specified minimum wall thickness, shall test method give at least the same sensitivity and capability in be classified as acceptable imperfections. The imperfections detection of imperfections. The demonstration of the alterna- may remain in the pipe or be dressed out by cosmetic grinding. tive test method shall be based upon the principles given in Imperfections with larger depth, and which do not encroach Subsection F on similar pipes to those ordered. The pipes shall upon the specified minimum wall thickness, shall be classified contain a representative and agreed size range of natural and/ as dressable defects and shall either be removed by grinding in or artificial defects of types that are typical for the manufactur- accordance with H525 or treated in accordance with H528, as ing process in question. appropriate. Visual examination of all linepipe 520 Imperfections which encroach upon the specified mini- mum wall thickness shall be classified as defects. 506 End preparation such as bevelling shall meet the speci- fied requirements. 521 Two or more adjacent imperfections shall be considered as one imperfection if they are separated by less than the 507 The internal weld bead shall be removed by grinding for smaller dimension of either indication. a distance of at least 100 mm from each pipe end. The transi- tion between base material and weld metal shall be smooth and 522 Imperfections with depth according to H517 or H519 of the height of the remaining weld bead shall not extend above which the depth can not be assessed by suitable gauges or alter- the adjacent pipe surface by more than 0.5 mm. native means, shall either be removed by grinding in accord- ance with H525 or treated in accordance with H528, as 508 If specified, the external weld bead shall be removed by appropriate. grinding for a distance of at least 250 mm from each pipe end. The transition between base material and weld metal shall be Dents smooth and the height of the remaining weld beads shall not 523 For dents without any cold formed notches and sharp extend above the adjacent pipe surface by more than 0.5 mm. bottom gouges, the length in any direction shall be ≤ 0.5 D and Visual examination of welds in linepipe the depth, measured as the gap between the extreme point of the dent and the prolongation of the normal contour of the pipe, 509 Each linepipe weld shall be subject to 100% visual shall not exceed 6.4 mm. examination in accordance with ISO 17637. For C-Mn steel linepipe with internal diameter (ID) ≥ 610, the internal weld — For dents with cold-formed notches and sharp bottom shall be 100% visually inspected. The internal weld of C-Mn gouges with depth according to H517 the depth of dents linepipe with ID < 610 mm shall be inspected from both ends shall not exceed 3.2 mm. as far as access permits. — Dents > 1 mm are not acceptable at the pipe ends, i.e. 510 The internal weld and adjacent surfaces in duplex stain- within a length of 100 mm at each of the pipe extremities. less steel, CRA and clad linepipe shall be inspected full length. — Dents exceeding these dimensions shall be classified as If necessary, the inspection of the internal weld shall be defects. assisted by a boroscope, video endoscope or similar equip- ment. Hard spots 511 Welds shall meet the requirements of Table D-4. 524 Hard spots, as identified e.g. due to irregularities in the pipe curvature of cold-formed welded linepipe, shall be inves- 512 Line pipe containing welds not meeting the require- tigated to determine the hardness and dimensions of the area. ments above shall be classified as suspect pipe according to H200, and treated according to H300. For linepipe intended for non sour service the hardness shall not exceed: Surface conditions, imperfections and defects 513 The surface finish produced by the manufacturing proc- — 300 HV10 for C-Mn steels ess shall be such that surface defects can be detected by visual — the values given in Sec.7 Table 7-11, for the material in inspection. question.

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For linepipe intended for sour service (Supplementary require- — Pipe produced prior to these three acceptable pipes need ment S) the hardness shall not exceed: not be measured — Pipe produced after the defective pipe shall be measured — 250 HV10 C-Mn steel individually until at least three consecutive pipes meet the — for other steels, maximum allowable hardness according requirements. to ISO 15156-3. 533 All defective pipe shall be de-magnetized full length, Hard spots outside the hardness requirements for the applica- and then their magnetism shall be re-measured until at least ble material larger than 50 mm in any direction and within 100 three consecutive pipes meet the requirements of H530. mm of the pipe ends regardless of size shall be classified as defects. 534 For pipe handled with electromagnetic equipment after measurement of magnetism, such handling shall be performed Grinding in a manner demonstrated not to cause residual magnetism 525 Imperfections or defects according to H518 or H519 exceeding the acceptance criteria in H530. may be dressed-out by grinding. Ground areas shall blend 535 The requirements for residual magnetism shall apply smoothly into the surrounding material. Complete removal of only to testing within the pipe mill since the residual magnet- defects shall be verified by local visual inspection and, if nec- ism in pipe may be affected by procedures and conditions essary, aided by suitable NDT inspection methods. The imposed on the pipe during and after shipment. remaining wall thickness in the ground area shall be checked by ultrasonic wall thickness measurements to verify that the H 600 Non-destructive testing of pipe ends not tested by thickness of the remaining material is more than the specified automated NDT equipment minimum. Untested pipe ends 526 The sum of the ground area shall not exceed 10% of the 601 When automated non-destructive testing equipment is sum of the external and internal surface area of each pipe. used, a short area at both pipe ends will normally not be tested Ground areas which have been smoothly blended into the sur- (see H410). Either the untested shall be cut off or the ends sub- rounding material and classified as cosmetic grinding shall not jected to manual or automated NDT to the same extent as be counted in the calculation. required for the full length of pipe 527 Full length machining of pipes is acceptable if machin- 602 The methods, sensitivity and acceptance criteria for test- ing is performed according to a qualified procedure that ing of untested ends shall be the same as used for retesting of ensures freedom from circumferential grooves or other defects pipes having signals equal to or greater than the threshold level with depth > 0.5 mm. H526 does not apply to pipe that are from the automated non-destructive testing equipment. machined full length. 603 The manufacturer shall prior to start of production Disposition of pipe containing defects present for acceptance the proposed extent, methods, sensitiv- 528 Linepipe containing defects shall be rejected or the area ity and acceptance criteria for testing of untested ends with ref- containing defects can be cut off. If pipes are cut, the minimum erence to applicable procedures. specified length shall be met after cutting and all NDT pertain- ing to pipe ends shall be performed on the new pipe end. H 700 Non-destructive testing of pipe ends Residual magnetism General 529 The longitudinal magnetic field shall be measured on 701 These requirements apply to both seamless and welded pipe with OD ≥ 168.3 mm and all smaller pipes that are pipe. Pipes not meeting the acceptance criteria below shall be inspected full length by magnetic methods or are handled by deemed as “suspect pipe” according to H200 and shall be magnetic equipment prior to loading. treated according to H300. Testing of pipe ends for laminar imperfections — The measurements shall be taken on the root face or square cut face of finished pipe. Measurements made on pipe in 702 Both ends of each pipe shall be tested for laminar imper- stacks are not considered valid. fections in accordance with ISO 11496 and the additional — Measurements shall be made on each end of a pipe, for 5% requirements in H400 over a band at least 50 mm inside the of the pipes produced but at least once per 4 hr per operat- location of future welding preparations for girth welds. ing shift using a Hall-effect gauss-meter or other type of 703 If additional non-destructive testing is specified by the calibrated instrument. In case of dispute, measurements purchaser, the width of the band should be: made with a Hall-effect gauss-meter shall govern. Meas- urements shall be made in accordance with a written pro- — at least 150 mm inside the location of future welding prep- cedure demonstrated to produce accurate results. arations for girth welds if automated ultrasonic testing of — Pipe magnetism shall be measured subsequent to any girth welds during installation will be performed inspection that uses a magnetic field, prior to loading for — at least 100 mm inside the location of future welding prep- shipment from the pipe mill. arations for girth welds if allowance for re-bevelling of — Four readings shall be taken 90° apart around the circum- pipe shall be included. ference of each end of the pipe. 704 Acceptance criteria are: 530 The average of the four readings shall be less or equal to 2.0 mT (20 Gauss), and no single reading shall exceed 2.5 mT — according to Table D-12 or, if agreed, G203 (25 Gauss). Any pipe that does not meet this requirement shall — G300 for clad pipe. be considered defective. Testing of end face or bevel for laminar imperfections 531 All pipes produced between the defective pipe and the last acceptable pipe shall be individually measured unless the 705 Magnetic particle testing or eddy current testing, manual provisions of H530 can be applied. or automated, of both end faces or bevels of each pipe in ferro- magnetic steel for the detection of laminar imperfections shall 532 If the pipe production sequence is documented, pipe be performed in accordance with the requirements in H400 and: may be measured in reverse sequence, beginning with the pipe produced immediately prior to the defective pipe, until at least — ISO 13664 for magnetic particle testing three consecutively produced pipes meet the requirements. — ISO 9304 for eddy current testing.

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706 Liquid penetrant or eddy current testing, manual or auto- in the pipe body of ferromagnetic pipe mated, of the end face or bevel of each pipe in non-ferromag- netic steel for the detection of laminar imperfections shall be 810 Testing of ferromagnetic seamless pipe for the detection performed in accordance with the requirements in H400 and: of longitudinal and transverse surface imperfections shall be performed in accordance with the requirements in H400 and — ISO 12095 for liquid penetrant testing one of the following standards: — ISO 9304 for eddy current testing. — ISO 9304 (eddy current testing) 707 The acceptance criterion is: — ISO 9402 (flux leakage testing for longitudinal indica- tions) — Imperfections longer than 6 mm in the circumferential — ISO 9598 (flux leakage testing for transverse indications) direction are not permitted. — ISO 13665 (magnetic particle testing). H 800 Non-destructive testing of seamless pipe 811 For detection of internal indications ISO 9304, ISO 9402 or ISO 9598 shall be preferred provided adequate signal ampli- Pipe ends tudes from the internal surface reflector are documented and 801 Pipe ends shall be tested as required by H600 and 700. used for sensitivity setting. Ultrasonic inspection for laminar imperfections in the pipe 812 The acceptance criteria are: body — ISO 9304: Alarm level/acceptance level L2 802 Ultrasonic inspection of the pipe body shall be per- — ISO 9402: Alarm level/acceptance level L2 formed in accordance with the requirements in H400 and ISO 10124 amended as follows: — ISO 9598: Alarm level/acceptance level L2 — ISO 13665: Alarm level/acceptance level Table 2, M2. — the distance between adjacent scanning tracks shall be suf- ficiently small to ensure detection of the minimum Surface testing for longitudinal and transverse indications in allowed imperfection size. pipe body of non-magnetic pipe 813 Testing of non-magnetic seamless pipe for the detection 803 The acceptance criteria are: of longitudinal and transverse surface imperfections shall be performed in accordance with the requirements in H400 and — according to Table D-12 or, if agreed, G203. one of the following standards: Ultrasonic inspection for longitudinal imperfections in the — ISO 9304 (eddy current testing) pipe body — ISO 12095 (liquid penetrant testing). 804 Ultrasonic inspection of the pipe body shall be per- formed in accordance with the requirements in H400 and ISO 814 For detection of internal indications ISO 9304 shall be 9303. The probe angles shall be chosen to obtain the best test preferred provided adequate signal amplitudes from the inter- result for the wall thickness/diameter ratio of the pipe to be nal surface reflector are documented and used for sensitivity tested. setting. For pipes in CRA materials it shall be verified that the presence 815 The acceptance criteria are: of any possible coarse, anisotropic zones will not impede the testing, see H424 through H431. — ISO 9304: Alarm level/acceptance level L2 — ISO 12095: Alarm level/acceptance level P2. 805 The acceptance criterion is: Suspect pipe — Acceptance level L2/C according to ISO 9303. 816 Pipes not meeting the acceptance criteria above shall be Ultrasonic inspection for transverse imperfections in the pipe deemed as “suspect pipe” according to H200 and shall be body treated according to H300. 806 Ultrasonic inspection of the pipe body shall be per- H 900 Non-destructive testing of HFW pipe formed in accordance with the requirements in H400 and ISO 9305. The probe angles shall be chosen to obtain the best test Pipe ends result for the wall thickness/diameter ratio of the pipe to be 901 Pipe ends shall be tested as required by H600 and H700 tested. Ultrasonic testing of the pipe body for detection of laminar For pipes in CRA materials it shall be verified that the presence imperfections of any possible coarse, anisotropic zones will not impede the testing, see H424 through H431. 902 Ultrasonic testing of the pipe body for detection of lam- inar imperfections need not be performed at the pipe mill if 807 The acceptance criterion is: testing of the coil edges was performed at the coil mill accord- ing to subsection G. — Acceptance level L2/C according to ISO 9305. 903 If performed at the pipe mill, ultrasonic testing of the Ultrasonic thickness testing of the pipe body pipe body for detection of laminar imperfections shall be per- 808 Ultrasonic thickness testing of the pipe body shall be formed in accordance with the requirements in H400 and ISO performed in accordance with the requirements in H400 and 10124 amended as follows: ISO 10543. — the distance between adjacent scanning tracks shall be suf- 809 The acceptance criterion is: ficiently small to ensure detection of the minimum allowed imperfection size. — The specified maximum and minimum wall thickness shall be met. 904 Acceptance criteria are: Surface testing for longitudinal and transverse imperfections — according to Table D-12 or, if agreed, G203.

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Ultrasonic testing of the area adjacent to the weld seam for old level shall be set corresponding to a loss of 75% of the detection of laminar imperfections transmitted signal. 905 Ultrasonic testing of the area adjacent to the weld seam 916 For each probe, the following shall be recorded: body for detection of laminar imperfections shall be performed at the pipe mill if the strip is made by splitting of coil. If the — type, frequency, angle and dimension strip is not made by splitting of coil and is tested for laminar — the distance from the index point to the weld centreline imperfections at the coil mill according to subsection G, no — the angle between the ultrasound direction and the major testing for detection of laminar imperfections need to be per- pipe axis. formed at the pipe mill — amplitudes and gain settings. 906 If performed at the pipe mill, the testing shall be per- 917 Gates shall be set such that reflections from the tracks formed according to the requirements in H400 and ISO 13663. resulting from removal of the internal flash are avoided but 907 Acceptance criteria are: sufficiently wide to ensure that the tolerances in the weld track- ing system will result in responses from indications inside the — according to Table D-12 or, if agreed G203. weld and the HAZ. Ultrasonic testing for longitudinal imperfections in the weld 918 The settings for lack of coupling alarm shall be set and seam checked. 908 Ultrasonic testing of the full length of the weld seam of 919 The acceptance criterion is: HFW pipe for the detection of longitudinal imperfections shall — Pipes producing signals below the threshold shall be be performed in accordance with the requirements in H400 and deemed to have passed the test. ISO 9764 with modifications as described in 909 through 918. 909 Accurate weld tracking with a tolerance ± 2 mm with Plate/strip end welds respect to the centreline of the weld is essential due to the 920 Testing of plate/strip end welds (when such welds are width of the weld. allowed) shall, unless otherwise agreed be performed by ultra- 910 The reference standard shall contain a typical weld, with sonic testing according to this standard. The testing shall com- the external flash removed and including tracks resulting from ply with the requirements of this standard and methods and a removal of the internal flash. set-up suitable for the applied welding method shall be used. The reference reflectors shall be: Suspect pipe — external and internal reference notches located parallel to 921 Pipes not meeting the acceptance criteria above shall be deemed as “suspect pipe” according to H200 and shall be and in the centre of the weld. The notches shall be “N” treated according to H300. type with a depth of 5% of the wall thickness notches with a depth of minimum 0.3 mm and maximum 1.2 mm. H 1000 Non-destructive testing of CRA liner pipe 911 One or more of the following probe configurations shall 1001 Testing of CRA pipe for the detection of longitudinal be used: and transverse surface imperfections and the longitudinal weld shall be performed in accordance with the requirements in — Single pulse echo probes shall be selected such as the H400 and ISO 9304 (eddy current testing). angle of incidence is as perpendicular to the radial cen- treline of the weld as possible. — The acceptance criterion for eddy current testing is: — Tandem probes on each side of the weld with the angle of — The response shall not exceed half the response of alarm incidence as perpendicular to the radial centreline of the level/acceptance level L2 according to ISO 9304. weld as possible. — Probes alternating as transmitter-receiver with the angle of 1002 Testing of the weld seam can alternatively be per- incidence as perpendicular to the radial centreline of the formed in accordance with the requirements in H400 and ISO weld as possible. 12096 (radiographic testing). 1003 The acceptance criteria for radiographic testing are: The probe configuration shall provide a sufficient number of probes to cover the entire wall thickness from both sides of the — No cracks, lack of fusion, lack of penetration or pore clus- weld. ters. Individual circular imperfections shall not exceed 912 The equipment shall include devices for weld tracking/ 1.5 mm or ¼ t, whichever is smaller. Accumulated diame- centering and provide checking of adequate coupling for all ters of permitted imperfections shall not exceed 3 mm or probes. ½ t, whichever is smaller. No other discernable indications are allowed. 913 Each probe shall be calibrated against the reference reflector located in the area of the weld to be covered by that Untested pipe ends probe. 1004 Untested pipe ends shall be tested as required by H600. 914 For single pulse echo probes and tandem probes the threshold settings shall be as follows: Suspect pipe 1005 Pipes not meeting the acceptance criteria above shall — If the testing is performed with one probe pair covering the be deemed as “suspect pipe” according to H200 and shall be entire wall thickness, the response from the intersections treated according to H300. between the reference notches and the external and inter- nal pipe surface shall optimised and the threshold level set H 1100 Non-destructive testing of lined pipe at 80% of full screen height of the lowest of the obtained Non-destructive testing of the backing pipe responses. — If the testing is performed with probe pairs each covering 1101 Non-destructive testing of the outer C-Mn steel back- a part of the wall thickness, the threshold level shall be set ing pipe shall be performed prior to insertion of the CRA liner at 80% of full screen height. pipe. The backing pipe shall be subjected to the same testing with the same acceptance criteria that are required in this 915 For probes alternating as transmitter-receiver the thresh- Appendix for the type of backing pipe used.

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Pipe ends ance of low frequency shear wave angle probes other methods 1102 After insertion of the liner pipe and performing seal or combination of methods shall used and the adequacy of the and/or clad welding the ends of lined pipe shall be tested for methodology demonstrated. laminar imperfections in accordance with the requirements in Ultrasonic testing of the weld seam of clad pipe for the detec- H400 and ISO 11496 or ASTM A578 S7 in a band at each pipe tion of longitudinal and transverse imperfections, when dem- end. For clad welded pipe ends this includes testing for bond- onstrated to give acceptable results, shall be in accordance ing defects. The band shall be sufficiently wide to cover the with the requirements in H400 and ISO 9765 with modifica- width of the seal/clad weld between the C-Mn steel backing tions as described in 1208 through 1219. pipe and the CRA liner pipe. Manual or automated methods 1208 The reference standard shall contain a typical produc- may be used. tion weld. The weld surface shall be ground flush with the orig- 1103 The acceptance criterion is: inal pipe contour in an area around each reference reflector sufficient to obtain signals without interference from un- — No indications are allowed within the tested areas. ground weld reinforcements. Seal and clad welds 1209 The reference reflectors shall be: 1104 The seal and/or clad welds at pipe ends shall be subject — One 1.6 mm diameter through-drilled hole at the weld cen- to manual liquid penetrant testing according to B600 or eddy treline for detection of transverse indications. current testing according to B700. — Longitudinal external and internal notches on both sides, 1105 The acceptance criteria are: parallel and adjacent to the weld seam for detection of lon- gitudinal imperfections outside the root area. The notch — No round indications with diameter above 2 mm and no shall be the “N” type with 5% of the wall thickness, but not elongated indications. more than 1.5 mm or less than 0.3 mm. — Indications separated by a distance less than the diameter — One notch on each side of the internal weld cap located or length of the smallest indication, shall be considered as immediately adjacent to and parallel with the weld for one indication. detection of longitudinal imperfections in the root area. — Accumulated diameters of round indications in any 100 The notch shall be the “N” type with 3% of the wall thick- mm length of weld shall not exceed 6 mm. ness, but not more than 1.2 mm or less than 0.3 mm. — If agreed, the reference reflectors for detection of trans- H 1200 Non-destructive testing of clad pipe verse imperfections can be internal and external notches, Pipe ends “N” type with 3% of the wall thickness, positioned at right 1201 Pipe ends shall be tested as required by H600 and angles to, and centred over, the weld seam. H700. — Additional reflectors may be used to define the weld extremities and aiding in the gate settings. The use, type Ultrasonic testing of the pipe body for detection of laminar and numbers of such reflectors shall be at the manufac- imperfections turer’s option. 1202 Ultrasonic testing of the pipe body for detection of lam- inar imperfections in the backing pipe need not be performed The length of the notches shall be 1.5 times the probe (crystal) at the pipe mill if testing of the plate was performed at the plate element size or 20 mm, whichever is shorter. The length does mill according to subsection G. not include any rounded corners. The width of the notches shall not exceed 1 mm. 1203 If performed at the pipe mill, ultrasonic testing of the pipe body for detection of laminar imperfections shall be per- 1210 The probe angles shall be chosen to obtain the best pos- formed in accordance with the requirements in H400 and ISO sible test result for wall thickness and diameter of the pipe to 10124 amended as follows: be tested. The probe angle shall be chosen such that the angle of incidence is as perpendicular as possible to the weld bevel — The distance between adjacent scanning tracks shall be in the area covered by the probe. sufficiently small to ensure detection of the minimum 1211 The frequency of the probes used in the root area shall allowed imperfection size. be as low as possible and not above 2 MHz. 1204 Acceptance criteria are: 1212 The probe configuration for detection of the longitudi- nal indications shall provide a sufficient number of opposing — according to Table D-12 or, if agreed, G203. probe pairs to cover the entire wall thickness. E.g. one pair of probes for the external and internal N5 notches and one pair for 1205 Ultrasonic testing of the pipe body for detection of lack the internal N3 notches in the root area. of bond between the cladding and backing pipe shall be per- formed in accordance with the requirements in H400 and 1213 The probe configuration for detection of transverse ASTM 578 S7 amended as follows: indications shall be two wide beam, opposing probes travelling “on bead”. An X type configuration of the probes for detection — The distance between adjacent scanning tracks shall be of transverse indications may be used, subject to agreement. sufficiently small to ensure detection of the minimum 1214 The gates shall be set wide enough to compensate for: allowed imperfection size. — The tolerances of weld tracking system 1206 The acceptance criterion is: — Variations in the width of external and internal caps — ASTM A578 - S7. In addition, no areas with laminations — Offsets between the external and internal weld bead. or lack of bond are allowed in the plate edge areas. 1215 Each probe shall be calibrated against the reference Ultrasonic testing for longitudinal and transverse imperfec- reflector located in the area of the weld to be covered by that tions in the weld seam probe. The response from the reference reflectors shall be opti- mised for each probe and probe pair: 1207 For ultrasonic testing of the CRA part of the weld seam it must be demonstrated that low frequency shear wave angle — For detection of longitudinal imperfections in the root area probes are adequate for detection as required in H424 through the optimised response for each probe shall be obtained H431. If it is not possible to demonstrate adequate perform- from the internal notch on the opposite side of the weld.

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The threshold level for each of the internal notches shall be — ISO 9598: Alarm level/acceptance level L2 set no higher than 50% of full screen height from the max- — ISO 13665: Alarm level/acceptance level Table 3, M2. imised response. — For detection of longitudinal imperfections outside the Radiographic testing of welds root area the response from the external and internal 1225 Full length radiographic testing of the weld shall be notches shall optimised and the threshold level set to 80% performed in accordance with the requirements in H400 and of full screen height for each of the maximised responses. ISO 12096. — For detection of transverse imperfections the threshold level for the 1.6 mm through drilled hole or transverse 1226 For pipe subject to full length ultrasonic testing of the notches shall be set no higher than 80% of full screen weld, radiographic testing of the weld at each pipe end shall height. include the area not covered by the automated ultrasonic test- — If the use of transverse notches is agreed for detection of ing and shall at least cover a weld length of 300 mm. The test- transverse indications, the response from the external and ing shall be performed in accordance with the requirements in internal notches shall optimised and the threshold level set H400 and ISO 12096. to 80% of full screen height for each of the maximised 1227 The acceptance criteria are: responses. — The additional reflectors allowed in 1209 shall not be used — according to ISO 12096. for threshold settings. Suspect pipe 1216 For each probe, the following shall be recorded: 1228 Pipes not meeting the acceptance criteria above shall — type, frequency, angle and dimension be deemed as “suspect pipe” according to H200 and shall be — the distance from the index point to the weld centreline treated according to H300. — the angle between the ultrasound direction and the major pipe axis H 1300 Non-destructive testing of SAWL and SAWH pipe — amplitudes and gain settings. Pipe ends 1217 Gates shall be set such that reflections from the weld 1301 Pipe ends shall be tested as required by H600 and caps are avoided but sufficiently wide to ensure that, with the H700. given tolerances of the weld tracking system, responses are Ultrasonic testing of the pipe body for detection of laminar obtained from indications located inside the weld and the imperfections HAZ. 1302 Ultrasonic testing of the pipe body for detection of lam- 1218 The settings for lack of coupling alarm shall be set and inar imperfections need not be performed at the pipe mill if checked. testing of the plate/coil edges was performed at the plate/coil 1219 The acceptance criterion when using shear wave mill according to subsection G. probes is: 1303 If performed at the pipe mill, ultrasonic testing of the pipe body for detection of laminar imperfections shall be per- — Pipes producing signals below the threshold shall be formed in accordance with the requirements in H400 and ISO deemed to have passed the test. 10124 amended as follows: When compression wave angle probes are used, other types of reflectors shall be used and the acceptance criteria shall be — the distance between adjacent scanning tracks shall be suf- specified and agreed accordingly. ficiently small to ensure detection of the minimum allowed imperfection size. Ultrasonic testing of the area adjacent to the weld seam for detection of laminar imperfections 1304 Acceptance criteria are: 1220 Ultrasonic testing of the area adjacent to the weld seam — according to Table D-12 or, if agreed, G203. body for detection of laminar imperfections need not be per- formed at the pipe mill if testing of the plate edges was per- Ultrasonic testing of the area adjacent to the weld seam for formed at the plate mill according to subsection G. detection of laminar imperfections 1221 If performed at the pipe mill, the testing shall be per- 1305 Ultrasonic testing of the area adjacent to the weld seam formed according to the requirements in H400 and ISO 13663. body for detection of laminar imperfections need not be per- 1222 Acceptance criteria are: formed at the pipe mill if testing of the plate/coil edges was performed at the plate/coil mill according to subsection G. — according to Table D-12 or, if agreed, G203. 1306 If performed at the pipe mill, the testing shall be per- Testing for the detection of surface imperfections in the weld formed according to the requirements in H400 and ISO 13663. area 1307 Acceptance criteria are: 1223 Testing for the detection of longitudinal and transverse surface imperfections in the weld area shall be performed in — according to Table D-12 or, if agreed, G203. accordance with the requirements in H400 and one of the fol- lowing standards: Ultrasonic testing for longitudinal and transverse imperfec- tions in the weld seam — ISO 9304 (eddy current testing) 1308 Ultrasonic testing of the weld seam of SAW pipe for — ISO 9402 (flux leakage testing for longitudinal indica- the detection of longitudinal and transverse imperfections shall tions) be in accordance with the requirements in H400 and ISO 9765 — ISO 9598 (flux leakage testing for transverse indications) with modifications as given in 1309 through 1320. — ISO 13665 (magnetic particle testing). 1309 The reference standard shall contain a typical produc- 1224 The acceptance criteria are: tion weld. The weld surface shall be ground flush with the orig- inal pipe contour in an area around each reference reflector — ISO 9304: Alarm level/acceptance level L2 sufficient to obtain signals without interference from un- — ISO 9402: Alarm level/acceptance level L2 ground weld reinforcements.

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1310 The reference reflectors shall be: — type, frequency, angle and dimension — the distance from the index point to the weld centreline — One 1.6 mm diameter through drilled hole at the weld cen- — the angle between the ultrasound direction and the major treline for detection of transverse indications pipe axis — Longitudinal external and internal notches on both sides, — amplitudes and gain settings. parallel and adjacent to the weld seam for detection of lon- gitudinal imperfections. The notch shall be the “N” type 1315 The gates shall be set wide enough to compensate for: with 5% of the wall thickness, but not more than 1.5 mm or less than 0.3 mm. The length of the notches shall be 1.5 — the tolerances of weld tracking system times the probe (crystal) element size or 20 mm, which- — variations in the width of external and internal caps ever is shorter. The length does not include any rounded — offsets between the external and internal weld bead. corners. The width of the notches shall not exceed 1 mm. — For wall thickness ≥ 19 mm a longitudinal reference 1316 The settings for lack of coupling alarm shall be set and reflector, e.g. a side-drilled hole, shall be located at mid checked. thickness of the weld and parallel to the weld. This reflec- 1317 When the settings are optimised, the relevant parame- tor shall provide a return signal comparable to that from a ters shall be recorded and the reference standard shall be N5 notch. The Manufacturer shall propose a type of reflec- passed 3 times through the equipment at the operational veloc- tor suitable for the purpose, and the type of reflector used ity. Any change in settings required to maintain the static mode is subject to agreement. settings shall be recorded as an average of the 3 runs. For — If agreed, the reference reflectors for detection of trans- acceptance of the settings, all reference reflectors need to be verse imperfections can be internal and external notches, detected at or above the threshold and there shall be no signif- positioned at right angles to, and centred over, the weld icant relative changes in amplitudes between any opposing seam. longitudinal probes. Gate settings shall not deviate more than — Both internal and external weld reinforcements shall be 2.5 mm from the reference position. ground flush to match the pipe contour in the immediate 1318 The acceptance criterion is: area and on both sides of the reference notches. — Additional reflectors may be used to define the weld Pipes producing signals below the threshold shall be deemed extremities and aiding in the gate settings. The use, type to have passed the test. and numbers of such reflectors shall be at the manufac- Additional requirements for SAWH pipe strip/plate end welds turer’s option and shall be described in the documented procedure. 1319 For SAWH pipe the full length of strip/plate end welds (when such welds are allowed) shall be ultrasonically tested as 1311 The probe angles shall be chosen to obtain the best pos- required above for the helical seam. Alternatively manual sible test result for wall thickness and diameter of the pipe to ultrasonic testing in accordance with Subsection H1400 may be tested. The probe angle should be chosen such that the angle be used for testing of test strip/plate end welds. of incidence is as perpendicular as possible to the weld bevel In addition, the joints where the extremities of the helical and in the area covered by the probe. strip/plate end welds meet shall be subject to radiographic test- 1312 The probe configuration for detection of the longitudi- ing in accordance with the requirements in H400 and ISO nal indications shall provide a sufficient number of opposing 12096. probe pairs to cover the entire wall thickness. Each reference 1320 Acceptance criteria for these tests are: reflector shall have a dedicated probe pair. — For automated ultrasonic testing: according to H1319 1313 The probe configuration for detection of transverse above indications shall be two wide beam, opposing probes travelling “on bead”. An X type configuration of the probes for detection — For manual ultrasonic testing: according to H1400 of transverse indications may be used, subject to agreement. — For radiographic testing: According to ISO 12096. 1314 Each probe shall be calibrated against the reference Additional requirements for testing of SAW CRA pipes and reflector located in the area of the weld to be covered by that welds with CRA weld deposits probe. The response from the reference reflectors shall be opti- 1321 Ultrasonic testing of welds in CRA materials with mised for each probe and probe pair: CRA (duplex, other stainless steels and nickel alloy steel) weld deposits will, in order to achieve an adequate detection of — For detection of longitudinal imperfections the response imperfections, normally require that special reference blocks from the longitudinal external and internal notches shall and probes are used. optimised and the threshold level set to 80% of full screen height for each of the obtained responses. 1322 The requirements given in H424 through H431 shall be — If a separate reflector is positioned at mid thickness, the fulfilled and special reference is made to H430 and H431. response from this reflector shall optimised and the thresh- 1323 When compression wave angle probes are used, other old level set to 80% of full screen height for each of the types of reflectors shall be used and the acceptance criteria obtained responses. specified accordingly. — For detection of transverse imperfections the threshold level for the 1.6 mm through drilled hole or transverse Testing of ferromagnetic pipe for the detection of surface notches shall be set no higher than 80% of full screen imperfections in the weld area height. 1324 Testing of ferromagnetic pipe for the detection of lon- — If the use of transverse notches is agreed for detection of gitudinal and transverse surface imperfections shall be per- transverse imperfections, the response from the transverse formed in accordance with the requirements in H400 and one external and internal notches shall be optimised and the of the following standards: threshold level set to 80% of full screen height for each of the obtained responses. — ISO 9304 (eddy current testing) — The additional reflectors allowed in 1310 shall not be used — ISO 9402 (flux leakage testing for longitudinal indica- for threshold settings. tions) — ISO 9598 (flux leakage testing for transverse indications) For each probe, the following shall be recorded: — ISO 13665 (magnetic particle testing).

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The acceptance criteria are: 1406 Any additional non-destructive testing shall be as spec- ified by the purchaser. — ISO 9304: Acceptance level L2 — ISO 9402: Acceptance level L2 1407 If automated ultrasonic testing of girth welds during — ISO 9598: Acceptance level L2 installation will be performed the width of the band should — ISO 13665: Acceptance level Table 3, M2. extend at least 150 mm inside the location of future welding preparations for girth welds. Testing of non magnetic pipe for the detection of surface 1408 If allowance for re-bevelling of pipe shall be included, imperfections in the weld area the width of the band should extend at least 100 mm inside the 1325 Testing of non-magnetic SAW pipe for the detection of location of future welding preparations for girth welds. longitudinal and transverse surface imperfections shall be per- 1409 Acceptance criteria are: formed in accordance with the requirements in H400 and one of the following standards: — according to table d-12 or, if agreed, g203. — ISO 9304 (eddy current testing) Manual ultrasonic testing of pipe ends, radial cracks — ISO 12095 (liquid penetrant testing). 1410 For detection of cracks angle probes shall be used to The acceptance criteria are: supplement the straight beam probes. Testing shall be in gen- eral accordance with ASTM A577 or equivalent standard and: — ISO 9304: Acceptance level L2 — ISO 12095: Acceptance level P2. — Probes shall meet the requirements of C203. — Sensitivity for C-Mn steel shall be a DAC curve based on Radiographic testing reference blocks with a rectangular notch with depth 3% 1326 Radiographic testing of the weld at each pipe end shall of the material thickness on both sides. include the area not covered by the automated ultrasonic test- — Reference blocks for duplex stainless steel and austenitic ing and shall at least cover a weld length of 300 mm. The test- steels shall have one Ø 3 mm flat bottom hole perpendic- ing shall be performed in accordance with the requirements in ular to the angle of incidence of the probe and at the largest H400 and ISO 12096 possible depth from the scanning surface of the block. Ref- erence blocks shall be of the actual material tested or of a The acceptance criteria are: material with similar with acoustic properties. — according to ISO 12096. — Low frequency shear wave angle probes may be used for CRA material instead of twin crystal (transmitter/receiver) Suspect pipe compression-wave probes. For acceptance, it shall be ver- 1327 Pipes not meeting the acceptance criteria above shall ified on the reference blocks that it is possible to obtain a be deemed as “suspect pipe” according to H200 and shall be DAC with a shear wave angle probe that is comparable to treated according to H300. the DAC obtained with an angle compression wave probe. H 1400 Manual NDT at pipe mills 1411 The acceptance criterion is: General — no indications shall exceed the DAC. 1401 In all cases when the automated NDT system give sig- nals equal to or greater than the threshold level, or surface Manual ultrasonic testing of the pipe body for detection of imperfections are disclosed by visual examination, manual laminar imperfections NDT may be performed in order to confirm the presence or 1412 Manual ultrasonic testing of the pipe body for detection absence of a defect. Automated or semi-automated NDT may of laminar imperfections need not be performed at the pipe mill be used as substitution of the manual NDT required in H1400 if testing of the plate/coil edges was performed at the plate/coil provided the method is demonstrated to provide the same or mill according to subsection G. better sensitivity in detection of imperfections. 1413 If performed at the pipe mill, manual ultrasonic testing 1402 In addition, manual NDT may be performed on pipe of the pipe body for detection of laminar imperfections shall be ends that are not tested by the automated equipment. See H600. performed in accordance ISO 10124 amended as follows: 1403 The requirements in H1400 are only applicable to man- ual NDT performed at pipe mills only. — the distance between adjacent scanning tracks shall be suf- ficiently small to ensure detection of the minimum Radiographic testing allowed imperfection size. 1404 Radiographic testing shall be performed in accordance with the requirements in H400 and ISO 12096 to cover the full 1414 Acceptance criteria are: weld length or to supplement other NDT methods when the type of or severity of an indication in weld can not be deter- — according to Table D-12 or, if agreed, G203. mined with certainty. Manual ultrasonic testing of the area adjacent to the weld The acceptance criteria are: seam for detection of laminar imperfections — according to ISO 12096. 1415 Manual ultrasonic testing of the area adjacent to the weld seam body for detection of laminar imperfections need All pipe; manual ultrasonic testing for laminar imperfections not be performed at the pipe mill if testing of the plate/coil and thickness testing edges was performed at the plate/coil mill according to Sub- 1405 Manual ultrasonic thickness testing and testing for lam- section G. inar imperfections shall be performed on untested pipe ends 1416 If performed at the pipe mill, the manual NDT shall be and to confirm the presence or absence of a defect when auto- performed according to ISO 13663. mated NDT systems gives signals equal to or greater than the threshold level. 1417 Acceptance criteria are: Manual ultrasonic testing of pipe ends, laminar imperfections — according to Table D-12 or, if agreed, G203.

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Manual ultrasonic thickness testing of the pipe body Manual ultrasonic testing of welds in CRA materials and in 1418 Manual ultrasonic thickness testing of the pipe body shall clad pipe be performed in accordance with the requirements ISO 10543. 1431 Ultrasonic testing of welds in CRA materials with 1419 The acceptance criterion is: CRA (duplex, other stainless steels and nickel alloy steel) weld deposits will in order to achieve an adequate detection of — the specified maximum and minimum wall thickness shall imperfections normally require that special reference blocks be met. and probes are used for testing of these materials. Unless it can be demonstrated as required in B418 and H429 that use of low Seamless pipe; manual ultrasonic testing for longitudinal and frequency shear wave angle probes gives acceptable detection, transverse imperfections manual ultrasonic testing of the CRA weld deposit in the root 1420 Manual ultrasonic testing and testing of seamless pipe shall be performed as required in B400 for longitudinal and transverse imperfections shall performed 1432 Angle beam probes shall be available in angles, or be on untested pipe ends and to confirm the presence or absence provided with wedges or shoes, ranging from 30° to 75°, meas- of a defect when automated NDT systems gives signals equal ured to the perpendicular of the surface of the pipe being to or greater than the threshold level. tested. Probe angles shall be selected as required in B300. The 1421 For pipes in CRA materials it shall be verified that the probe angles shall be chosen to obtain the best possible test presence of any possible coarse, anisotropic zones will not result for wall thickness and diameter of the pipe to be tested impede the testing, see H424 through H431. and such that the angle of incidence is as perpendicular as pos- sible to the weld bevel in the area covered by the probe. If shear 1422 Manual ultrasonic testing of the pipe body for longitu- wave angle probes are used for testing of the root the frequency dinal imperfections shall be performed in accordance with ISO shall be 2 MHz or lower. 9303. The probe angles shall be chosen to obtain the best test result for the wall thickness/diameter ratio of the pipe to be 1433 The reference standard for testing with shear angle tested. probes shall be according to H1208 and H1209. The acceptance criterion is: Testing sensitivities shall be established as follows: — acceptance level L2/C according to ISO 9303. — For testing of longitudinal imperfections in the weld vol- ume outside the root area, the DAC shall be constructed 1423 Manual ultrasonic inspection of the pipe body for using the longitudinal external and internal notches. A 2- transverse imperfections shall be performed in accordance point DAC shall only be used if scanning is limited to one with the requirements in ISO 9305. The probe angles shall be full skip or less. If scanning is performed using more than chosen to obtain the best test result for the wall thickness/ one full skip, a 3-point DAC shall be established as a min- diameter ratio of the pipe to be tested. imum. — For testing of the root area longitudinal imperfections sen- The acceptance criterion is: sitivity setting shall be against the notch in the root area on — acceptance level L2/C according to ISO 9305. the opposite side of the weld and the response set to 50% of full screen height. Welded pipe; manual ultrasonic testing of welds — For testing of transverse imperfections, the DAC shall be constructed using the 1.6 mm diameter through drilled 1424 Manual ultrasonic testing and testing of welds in holes at the weld centreline with 2 points (e.g. ½ and full welded pipe for longitudinal and transverse imperfections shall skip). be performed on untested pipe ends and to confirm the pres- ence or absence of a defect when automated NDT systems 1434 Scanning for transverse indications shall be performed gives signals equal to or greater than the threshold level. "on bead". Probes with beam angles of 45° and 60° shall be 1425 Manual ultrasonic testing of welds in C-Mn steel mate- available. rial with C-Mn steel weld deposits shall be performed in 1435 The acceptance criteria are: accordance with B300 except that B314, B317, B321, B322 and B338 shall not apply. — No maximised indications exceeding DAC for longitudi- Manual ultrasonic testing of welds in HFW pipe nal and transverse indications. — No maximised indications in the root area exceeding 50% 1426 The reference block shall be according to H910. of full screen height. 1427 One or more of the following probe configurations shall be used: When compression wave angle probes are used, other types of reflectors are used and the acceptance criteria shall be speci- — Single pulse echo probes with the angle of incidence as fied and agreed accordingly. perpendicular to the radial centreline of the weld as possi- Manual ultrasonic testing of welds in SAWL and SAWH pipe ble. — Tandem probes with the angle of incidence as perpendic- 1436 The reference standard shall be according to H1309 ular to the radial centreline of the weld as possible. and H1310. 1437 Angle beam probes shall be available in angles, or be 1428 The probe angle for the initial scanning shall be chosen provided with wedges or shoes, ranging from 30° to 75°, meas- to obtain the best possible test result for wall thickness and ured to the perpendicular of the surface of the pipe being diameter of the pipe to be tested and such that the angle of inci- tested. Probe angles shall be selected as required in B300. dence is as perpendicular as possible to the weld bevel. 1438 Testing sensitivities shall be established as follows: 1429 The DAC shall be constructed using the notches in the reference block. A 2-point DAC shall only be used if scanning — For testing of longitudinal imperfections in the weld vol- is limited to one full skip or less. If scanning is performed ume, the DAC shall be constructed using the longitudinal using more than one full skip, a 3-point DAC shall be estab- external and internal notches. A 2-point DAC shall only be lished as a minimum. used if scanning is limited to one full skip or less. If scan- 1430 The acceptance criterion is: ning is performed using more than one full skip, a 3-point DAC shall be established as a minimum — no maximised echo from any probe shall exceed the DAC. — For testing of transverse imperfections, the DAC shall be

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constructed using the 1.6 mm diameter through drilled 1446 Manual magnetic particle testing of welds shall be per- holes at the weld centreline with 2 points (e.g. ½ and full formed as required by B500. skip). 1447 Acceptance criteria shall be according to the relevant 1439 Scanning for transverse indications shall be performed requirements of this subsection. "on bead". Probes with beam angles of 45° and 60° shall be Manual liquid penetrant testing available. Use of 4 MHz probes shall be preferred. 1448 Manual liquid penetrant surface testing and testing of 1440 Acceptance criterion is: pipe ends shall be performed in accordance with ISO 12095. — no maximised indications exceeding DAC 1449 Manual liquid penetrant testing of welds shall be per- formed in accordance with B600, paragraphs 602 through 605. Manual ultrasonic testing of welds in CRA materials and CRA 1450 Acceptance criteria shall be according to the relevant weld deposits/materials. requirements of this subsection. 1441 Refer to H424 through H431. Ultrasonic testing of Manual eddy current testing CRA materials and welds with CRA (duplex, other stainless steels and nickel alloy steel) weld deposits will in order to 1451 Manual eddy current surface testing and testing of pipe achieve an adequate detection of imperfections require that ends shall be performed in accordance with ISO 9304. special calibration blocks and probes are used for testing of 1452 Manual eddy current testing of welds shall be per- welds in these materials. Angle probes generating compression formed in accordance with B700, paragraphs 702 through 708 waves must normally be used in addition to straight beam and ISO 9304 (eddy current testing) probes, angle shear wave probes and creep wave probes. 1453 Acceptance criteria shall be according to the relevant 1442 Unless it can be demonstrated as required in B418 and requirements of this subsection. H429 that use of low frequency shear wave angle probes only gives acceptable detection, manual ultrasonic testing of CRA H 1500 Non-destructive testing of weld repair in pipe materials and welds with CRA weld deposits shall be per- formed as required in B400. 1501 Weld repair of the body of any pipe and of the weld in HFW pipe is not permitted. 1443 Acceptance criteria manual ultrasonic testing of CRA materials and welds with CRA weld deposits performed with 1502 Before re-welding, complete removal of the defects angle compression wave probes are: shall be confirmed by magnetic particle testing, or liquid pen- etrant testing for non- ferromagnetic materials. — according to Table D-6. 1503 A repaired weld shall be completely re-tested using applicable NDT methods in accordance with H800 through Manual magnetic particle testing 1300. 1444 Manual magnetic particle surface testing shall be per- Alternatively, manual NDT may be performed in accordance formed in accordance with B500 and ISO 13665. with H1400 and with acceptance criteria in accordance with 1445 Manual magnetic particle testing of pipe ends shall be the requirements in H1400. In this case, manual ultrasonic test- performed in accordance with B500 and ISO 13664. ing shall be governing for embedded defects.

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APPENDIX E AUTOMATED ULTRASONIC GIRTH WELD TESTING

A. General be within given tolerances and the scanner head is configured accordingly. For supplementary UT, the provisions of Appen- A 100 Scope dix D apply. 101 This Appendix details the examination requirements for Supplementary UT support is not required if weld repair the automated ultrasonic testing of pipeline girth welds. grooves are made with mechanical equipment that consistently 102 The Appendix applies when automated ultrasonic test- prepares the same groove geometry, and the repair AUT is ing (AUT) is performed on pipeline girth welds. qualified according to Subsection H. 106 The ultrasonic system shall incorporate facilities for A 200 References detection of transverse defects, when it is clearly identified that the weld process, parent material, application and environmen- a) American Society for Testing Materials - E 317-94: Stand- tal condition may increase the risk for transversal type flaws. ard Practice for Evaluating Performance Characteristics of Pulse Echo Testing Systems Without the Use of Electronic 107 For variations from nominal wall thickness outside a Measurement Instruments standard deviation value (SD) of 0.7 mm, additional valida- tions or qualification tests are required. These tests shall reflect b) EN12668-1 Non destructive testing - Characterisation and the total expected wall thickness variation, and provide evi- verification of ultrasonic examination equipment- Part 1: dence of 100% coverage of the fusion face and the root area. Instruments The (SD) is calculated as follows: c) EN12668-2 Non destructive testing - Characterisation and verification of ultrasonic examination equipment- Part 2: SD = (tmax – tmin)/ 12 Transducers The tmax and tmin should be based on data from the pipe man- d) EN12668-3 Non destructive testing - Characterisation and ufacture. If data from pipe manufacture are not available, SD verification of ultrasonic examination equipment- Part: 3: should be calculated based on the specified wall thickness tol- Combined equipment erance. e) EN583-6 Non destructive testing - Ultrasonic examination 108 Counter bores may be used to compensate for large Part 6 - Time-of-flight diffraction as a method for defect thickness variations if the counter bore is machined to provide detection and sizing parallel external and internal surfaces before the start of the taper. The length of the parallel surfaces shall at least be suffi- cient to allow scanning from the external surface and sufficient for the required reflection off the parallel internal surface. B. Basic Requirements 109 Weld deposits in duplex, austenitic stainless steels and nickel alloys have a coarse grain structure with variations in B 100 General grain size and structure resulting in unpredictable fluctuations 101 The primary requirement to any AUT system is that its in attenuation. Duplex and austenitic stainless steel base mate- performance is documented in terms of adequate detection and rials will have the same characteristics. sizing, or rejection abilities in relation to specified / deter- Ultrasonic testing of welds with CRA (duplex, other stainless mined acceptable defects. steels and nickel alloy steel) weld deposits will in order to 102 The ultrasonic system to be used shall be accepted achieve an adequate detection of imperfections require that through qualification, see Subsection H. special calibration blocks and transducers are used for testing 103 The ultrasonic system may use pulse echo, tandem, of welds in these materials. Angle transducers generating com- time-of-flight diffraction (TOFD) and/or through transmission pression waves, must normally be used in addition to angle techniques employing either fixed or phased arrays. It shall shear wave transducers and creep wave transducers. have a fully automatic recording system to indicate the loca- Creep wave transducers should be used for detection of sub tion of defects and the integrity of acoustic coupling. If a zonal surface defects close to the scanning surface. approach is used, the recommended maximum zone height is 3 In general, using a combination of shear and compression mm. The zonal approach shall be combined with root and weld wave angle transducers is recommended since the detection of volume mapping channels, and preferably TOFD. The zonal "open to surface" imperfections on the opposite surface of the concept may be deviated from. This requires an adequate tech- scanning surface, e.g. incomplete penetration or lack of fusion, nical description of the alternative approach, and a system may increase using shear wave transducers. It must, however, qualification according to Subsection H. be verified by using calibration blocks with actual weld con- 104 The information provided by all AUT channel types nections that angle shear wave transducers are suitable. shall be actively used in order to ensure adequate defect detec- 110 An operating Quality Assurance system shall be used tion and sizing. covering the development of ultrasonic examination systems, 105 The ultrasonic system may include scanner heads and testing, verification and documentation of the system and its system set-up specifically configured for testing of repairs. As components and software against given requirements, qualifi- a minimum the AUT system with its normal set-up, but with cation of personnel and operation of ultrasonic examination wider gates shall be used to confirm that AUT detected defects systems. The Quality Assurance system employed shall be have been removed. During this special attention shall also be documented in sufficient detail to ensure that AUT systems made to TOFD channel indications, and indications outside the used for field inspection will be designed, assembled and oper- normal gate settings. ated within the essential variables established during the qual- Due to the wide variation in repair weld groove shapes that ification and in all significant aspects will be equal to the may limit the detection capabilities of the system, manual UT, qualified AUT system. ISO 9000 and ASTM E 1212 shall or a dedicated semi-automatic UT system, shall support the apply as basic requirements to the Quality Assurance system. AUT on weld repairs unless the groove shape is controlled to The following shall be documented:

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— document control 401 The system shall be capable of examining a complete — system development including establishing performance weld including the heat affected zone in one circumferential — requirements to the system, its components and calibration scan. This requirement may, as agreed, be deviated from for blocks very thick / small diameter pipe, if it is not possible to cover — selection/qualification/follow-up/auditing of suppliers/ the whole depth range in one scan. subcontractors 402 There shall be recordable signal outputs for at least each — procurement of system components and calibration blocks 2 mm of weld length. — verification of delivered system components and calibra- tion blocks against given requirements 403 The ultrasonic instrument shall provide a linear A-scan — marking/identification of system components and calibra- presentation. The instrument linearity shall be determined tion blocks complying with given requirements according to the procedures detailed in ASTM-317-01 or — control and verification of software development/changes EN12668. Instrument linearity shall not deviate by more than — design of AUT system(s) set-up for specific field opera- 5% from ideal. tion conditions/requirements The assessment of ultrasonic instrument linearity shall have — assembly of AUT systems for field operation from verified been performed within 6 months of the intended end use date. components in stock, including identification of the sys- For production AUT with an expected duration exceeding 6 tem and identification/documentation of its components, months, but less than one year, the assessment of instrument calibration block(s) and spare parts linearity may be performed immediately before the start of — verification/testing of AUT systems for field operation work. — operational checks and field maintenance of AUT systems A calibration certificate shall be made available upon request. — documentation/verification of in field modifications of AUT systems Specific requirements for ultrasonic instruments using multi- — return of field systems, dismantling, check/repair/upgrad- ple channels, pulse echo, tandem and/or through transmission ing of system components techniques. — verification of repaired/upgraded system components 404 The instrument shall provide an adequate number of against given requirements inspection channels to ensure the examination of the complete — AUT operator training and qualification. weld through thickness in one circumferential scan, if possible (see B401). Each inspection channel shall provide: — pulse echo or through transmission modes B 200 Documentation — one or more gates, each adjustable for start position and 201 The configuration of the ultrasonic system shall for eval- length uation purposes be described and documented with regard to: — gain adjustment — recording threshold between 5 and 100% of full screen — brief functional description of the system height — reference to the code, standard or guideline used for design — recording of either the first or the largest signal in the gated and operation of the system region — description of the Quality Assurance system — signal delay to enable correlation to distance marker posi- — equipment description tions (real time analogue recording only) — limitations of the system with regard to material or weld — recordable signal outputs representing signal amplitude features including sound velocity variations, geometry, and sound travel distance wall thickness, size, surface finish, material composition, — specific requirements to ultrasonic instruments using the etc. ToFD technique — number and type of transducers, or phased array set up with description of characteristics and set-up 405 The instrument shall provide a ToFD B-scan image. — number of and height of examination zones, where rele- ToFD function software shall incorporate adequate facilities vant for online indication assessment using range calibrated cur- — gate settings sors. A-scan reference and numerical translation of time of — function of scanning device flight positions shall be incorporated. — ultrasonic instrument, number of channels and data acqui- Depth range efficiency shall be identified for each ToFD set sition system up. It may be required to employ two or more ToFD channels — recording and processing of data in order to increase reliability over the through thickness range — calibration blocks being inspected. For thicknesses above 50 mm at least two — coupling monitoring method TOFD channels are recommended. — temperature range for testing and limitations — coverage achieved 406 The instrument shall fulfil the requirements to ultrasonic — maximum scanning speed and direction instruments described in EN12668-1 and EN583-6, Chapter 6 — reporting of indications and documentation of calibration "Equipment requirements" and sensitivity settings. Specific requirements to ultrasonic instruments using phased arrays. B 300 Qualification 407 The phased array system shall incorporate means for 301 Automated ultrasonic systems shall be qualified and the periodical verification of the function of required active ele- performance of the system shall be documented. ments necessary to maintain a specific focal law. Further guidance is given in Subsection H. 408 A system preventing any unqualified alterations to For applications other than ferritic steel girth weld examina- agreed focal laws shall be implemented for the phased array tions, specific qualifications programs shall be designed and AUT system. agreed upon. 409 If additional conventional transducers to the phased array ones are used, for example for transverse inspection and B 400 Ultrasonic system equipment and components ToFD, the information for all transducers shall be available in General requirements the same set up and recording system.

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The recording system 503 Acoustic velocity and attenuation measurements shall 410 The recording or marking system shall clearly indicate be performed on material from all sources of pipe material sup- the location of imperfections relative to the 12 o'clock position ply to be used. These measurements shall be performed of the weld, with a ± 1% accuracy or 10 mm, whichever is according to Subsection J100 unless an equivalent method is greater. The system resolution shall be such that each segment agreed. If differences in acoustic velocity for the same nominal of recorded data from an individual inspection channel does wall thickness from any source of supply results in a beam not represent more than 2 mm of circumferential weld dis- angle variation of more than 1.5°, specific calibration blocks tance. shall be made for material from each source of supply showing such variations. Acoustic coupling 504 Details of the specific weld bevel geometries including 411 Acoustic coupling shall be achieved by contact or cou- relevant dimensions and tolerances shall be provided in order plant column using a liquid medium suitable for the purpose. to determine the particulars and numbers of calibration blocks An environmentally safe agent may be required to promote required. wetting, however, no residue shall remain on the pipe surface 505 Type and size of calibration reflectors shall be deter- after the liquid has evaporated. mined by the required sensitivity to achieve the necessary The method used for acoustic coupling monitoring and the loss Probability of Detection (PoD) and sizing capability as deter- in signal strength defining a "loss of return signal" (loss of cou- mined by the smallest allowable defect deriving from the pling) shall be described. agreed acceptance criteria. The preferred principal calibration Transducers reflectors are normally flat bottom holes (FBHs) and surface notches. Other reflector dimensions and types may be used, if 412 Prior to the start of field weld examination, details of the it is demonstrated during the system qualification that the types and numbers of transducers or focal laws shall be speci- defect detection and sizing capabilities of the system is accept- fied. Once agreed, there shall not be any transducer or focal able. Specific notches for ToFD may be incorporated, to check law design changes made without prior agreement. Transduc- TOFD system functionality. ers other than phased arrays shall be characterised according to EN12668-2. Transducers shall be documented with respect to 506 The calibration blocks shall be designed with sufficient manufacturer, type, characteristics and unique identification surface area so that the complete transducer array will traverse (serial number). the target areas in a single pass. Transducer characteristics shall include (not all parameters are 507 Drawings showing the design details for each type of applicable to phased array transducers): calibration block shall be prepared. The drawings shall show: — frequency — the specific weld bevel geometry, dimensions and toler- ances — beam angle — the height and position of examination zones — wedge characteristics — the calibration reflectors required and their relative posi- — beam size tions — pulse shape — the ultrasonic path associated with each reflector. — pulse length — signal to noise 508 The calibration block shall be identified with a hard — focus point and length for focused transducers. stamped unique serial number providing traceability to the examination work and the material source of supply for which 413 Transducers used for zonal discrimination shall give sig- the standard was manufactured. Records of the correlation nals from adjacent zones (overtrace) at least 6 dB lower and between serial number and wall thickness, bevel design, diam- not more than 10 dB lower than the peak signal from the cali- eter, and ultrasound velocity shall be kept and be available. bration reflector representing the zone of interest. The machining tolerances for calibration reflectors are: 414 TOFD transducers shall be optimised for the wall thick- ness to be tested and the refracted angle shall be the same for (a) Hole diameters ± 0.2 mm transmitter and receiver. Frequency, damping and incident angle shall be chosen to limit the dead zone formed by the lat- (b) Flatness of FBH ± 0.1 mm eral wave. (c) All pertinent angles ± 1° 415 When required, transducers shall be contoured to match (d) Notch depth ± 0.1 mm the curvature of the pipe. (e) Notch length ± 0.5 mm (f) Central position of reference reflectors ± 0.1 mm B 500 Calibration (reference) blocks (g) Hole depth ± 0.2 mm 501 Calibration blocks shall be used to set AUT system sen- sitivity, and to verify the inspection system for field inspection 509 The lateral position of all calibration reflectors shall be and to monitor the ongoing system performance. Calibration such that there will be no interference from adjacent reflectors, blocks shall be manufactured from a section of pipeline spe- or from the edges of the blocks. cific linepipe. The wall thickness of the pipe used for calibra- tion blocks shall preferably correspond to the average wall 510 Holes shall normally be protected from degradation by thickness of the pipes used, unless a number of calibration covering the hole with a suitable sealant. Filling of surface blocks are needed to cover wall thickness variations outside notches and other near surface reflectors may influence the the limitations given in B108. reflecting ability of the reference reflector and shall be avoided. 502 For examination of austenitic or austenitic/ferritic weld deposits the calibration block shall contain a weld. The weld 511 Dimensional verification of all calibration reflectors and shall be made using the welding procedure and bevel prepara- their position shall be performed and recorded according to a tion to be applied during construction. Reference reflectors documented procedure. shall normally be positioned opposite to the scanning side such 512 Whenever possible, an AUT system similar to that used that the ultrasonic beams pass through the weld metal before during field inspection shall be successfully calibrated against reaching the reference reflectors. Notches shall not be used as the calibration block after dimensional verification of the reference reflectors for compression wave angle transducers. block. The set-up data shall be recorded and the same data used

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.E – Page 225 to verify that any additional/spare calibration blocks will not Positioning of the band on the corrosion coating will require give significantly different calibration results. that the coating thickness is not excessive and that the coating 513 A calibration block register shall be established. The is sufficiently flat and will remain hard enough at the temper- register shall include all calibration blocks, including spare atures in the pipe resulting from preheat and welding to avoid blocks, to be used, identified with a unique serial number and that the band supports slips or penetrates the coating. include the drawings, dimensional verification records, ultra- Positioning of the band partly on bare pipe and partly on the sound velocity, name of the plate/pipe manufacturer and the corrosion coating may result in instability problems for the heat number. scanner and should be avoided. B 600 Recorder set-up Coating cut back 601 Channel output signals shall be arranged on the record- 1003 The cut-back of the corrosion coating to bare pipe shall ing media in an agreed order. The function of each channel be wide enough to accommodate the footprint of all transduc- shall be clearly identified. The hard copy recording shall be ers at the required stand-off distance + minimum 20 mm. The corrected to account for any difference introduced due to dif- cut-back of any weight coating shall allow placing the band ferent circumferential positions of the transducers. wholly on the bare pipe or on the corrosion coating, as appli- 602 Distance markers shall be provided on the recording at cable, and sufficient to avoid interference between weight intervals not exceeding 100 mm of circumferential weld coating and scanner. length. The coating cut back required allowing for scanner mounting 603 The scanning direction (clockwise or anti-clockwise) and movement shall be clearly identified in the operating man- shall be clearly described and referred to an identifiable datum, uals. and shall be maintained throughout the duration of the field weld examination. B 1100 Reference line tools 1101 The tool used to align the scanning band to the refer- B 700 Circumferential scanning velocity ence line shall be adjusted to account for weld shrinkage. 701 The maximum allowable circumferential scanning Shrinkage is determined by marking the reference line on both velocity shall be determined so that there are at least 3 pulse pipe ends during WPQ or for the first 25 welds, and then meas- firings within each 6 dB beam width at the appropriate operat- uring the distance between them after welding. ing distance of all transducers within the an array. The tools used for marking the reference line for band position- B 800 Power supply ing, shall give accuracy in the position of the scribe line of ± 0.5 mm relative to the bevel root face. The accuracy of each 801 The ultrasonic system shall have a dedicated power sup- scribe line tool shall be documented and each tool shall be ply. There shall be provisions for alternative power supply in uniquely identified. case of failure in the main power supply. There shall be no loss of inspection data as a result of a possible power failure. B 1200 Operators B 900 Software 1201 Details of each AUT operator shall be provided prior to start of field weld examination. 901 All recording, data handling and presenting software, including changes thereto, shall be covered by the Quality 1202 Operators performing interpretation shall be certified Assurance system and all software versions shall be identifia- to Level 2 by a Certification body or Authorised qualifying ble by a unique version number. body in accordance with EN 473, ISO 9712 or the ASNT Cen- 902 The software version number, and for phased array tral Certification Program (ACCP). In addition they shall doc- equipment also each identified set-up (executable focal law ument adequate training and field experience with the programme) in use, shall be clearly observable on all display equipment in question, by passing a specific and practical and printout presentations of calibration and examination examination. If requested, they shall be able to demonstrate results. their capabilities with regard to calibrating the equipment, per- forming an operational test under field conditions and evaluat- 903 For phased array equipment, each identified set-up (exe- ing size, nature and location of imperfections. cutable focal law programme) shall be available for review. 1203 Operators who are not accepted shall not be used, and 904 Changes to an executable focal law programme shall not operators shall not be substituted without prior approval. In be possible without a simultaneous change in the version case additional operators are required, details of these shall be number. accepted before they start to work. 905 Software updates shall not be performed on systems dur- 1204 One individual shall be designated to be responsible for ing field examination use. the conduct of the ultrasonic personnel, the performance of B 1000 Reference line, band position and coating cut- equipment, spare part availability and inspection work, includ- back ing reports and records. Reference line 1205 The operators shall have access to technical support from one individual qualified to Level 3 at any time during 1001 Prior to welding a reference line shall be scribed on the execution of the examination work. pipe surface at a fixed distance from the centreline of the weld preparation on the inspection band side. This reference line B 1300 Spares shall be used to ensure that the band is adjusted to the same dis- tance from the weld centreline as to that of the calibration 1301 There shall be a sufficient number of spare parts avail- block. able at the place of examination to ensure that the work can proceed without interruptions. The type and number of spares Guiding band positioning shall be agreed. 1002 The tolerance for band positioning is ± 1 mm relative to the weld centreline. B 1400 Slave monitors The band can be positioned either wholly on the bare pipe or 1401 The system shall include the possibility to provide on the corrosion coating. slave monitors for use by supervising personnel, if agreed.

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C. Procedure response is the Primary Reference Level (PRL) for that reflec- tor. C 100 General Fusion zone channels 101 A detailed AUT Procedure shall be prepared for each 103 Pulse echo and tandem transducers shall be positioned at weld joint geometry to be examined prior to the start of any its operating (stand-off) position and adjusted to provide a welding. The procedure is as a minimum, and as relevant for peak signal from its calibration reflector. In the case of phased the equipment in question, to include: arrays, the focal laws shall be designed to provide a peak signal — functional description of equipment from each of the calibration reflectors as appropriate. This sig- — reference standards and guidelines controlling equipment nal shall be adjusted to the specified percentage of full screen maintenance height (FSH). — instructions for scanning device, ultrasonic instrument, TOFD channels ultrasonic electronics, hard- and software for recording, 104 For single TOFD channels, the transducer spacing shall processing, display, presentation and storage of inspection be selected to place the theoretical crossing of beam centres at data the weld centreline at 66 to 95% of the wall thickness. — number of examination zones for each wall thickness to be examined, as relevant For double TOFD channels the theoretical crossing of beam — transducer configuration(s), characteristics, types, cover- centres at the weld centreline shall be at 66 to 95% of the wall age; and/or focal law details thickness for one channel and approximately 33% of the wall — description/drawings of calibration block(s), including thickness for the other channel. type, size and location of all calibration reflectors The amplitude of the lateral wave shall be between 40 and 80% — pre-examination checks of equipment of full screen height (FSH). In cases when use of the lateral — methodology for sensitivity setting and for fusion zone wave is not applicable, e.g. surface conditions and steep beam transducers; overtrace (signal amplitude from adjacent angles, the amplitude of the back wall signal shall be set at zones) requirements consistent with the overtrace used as between 12 to 24 dB above FSH. When use of neither the lat- basis for establishing height sizing corrections for ampli- eral wave nor the back wall signal is applicable, the sensitivity tude sizing should be set such that the noise level is between 5 and 10% of — gate settings FSH. — equipment settings — threshold settings Mapping channels — the added gain above PRL (D102) to be used for mapping 105 Each transducer shall be positioned at its operating channels (stand-off) position and adjusted to provide a peak signal from — dynamic verification of set-up its calibration reflector. In the case of phased arrays, the focal — signal strength defining a "loss of return signal" (loss of laws shall be designed to provide a peak signal from each of coupling) the calibration reflectors as appropriate. This signal shall be — visual examination of scanning area, including surface adjusted to the specified percentage of FSH. condition and preparation Normally a gain increase in the range of 4 to 10 dB over the — identification of inspection starting point, scanning direc- gain necessary to obtain the specified percentage of FSH is tion, and indication of length inspected required to obtain the production scanning sensitivity. This — method for scanner alignment and maintenance of align- gain shall not be added during sensitivity setting, dynamic cal- ment ibration and calibration verification during field examination. — verification of reference line and guide band positioning — maximum allowed temperature range D 200 Gate settings — control of temperature differentials (pipe and calibration block) 201 With each transducer positioned for a peak signal response from the calibration reflector the detection gates shall — calibration intervals be set as detailed in the agreed AUT procedure and as detailed — calibration records below. — couplant, coupling and coupling control — operational checks and field maintenance Fusion zone channels — transducer and overall functional checks 202 The detection gates are to be set with each transducer / — height, depth and length sizing methodology focal law positioned for the peak signal response from the cal- — acceptance criteria, or reference thereto ibration reflector. The gate shall start before the theoretical — instructions for reporting including example of recorder weld preparation and a suitable allowance shall be included to chart and forms to be used allow for the width of the heat affected zone, so that complete — spare part philosophy. coverage of the heat affected zone is achieved. The gate ends shall at least be after the theoretical weld centreline, including 102 The AUT procedure shall be submitted for acceptance. a suitable allowance for offset of the weld centreline after welding. 203 For specific applications, e.g. for austenitic/duplex D. Calibration (Sensitivity Setting) weldments with angle compression waves with the reference reflectors positioned at the far side of the weld, an extension of D 100 Initial static calibration the gate onto the far bevel and HAZ may be required. Transducer positioning and Primary Reference Sensitivity Similar considerations may apply in the root area related to 101 The system shall be optimised for field inspection in monitoring of guidance band offset. accordance with the details given in the AUT procedure and ToFD technique using the relevant calibration block(s). The calibration block 204 Ideally the time gate start should be at least 1 µs prior to shall have the same orientation (vertical/horizontal) as the pipe the time of arrival of the lateral wave, and should at least to be tested, unless it has been proven through the qualification extend up to the first back wall echo. Because mode converted tests that differences in response are negligible. echoes can be of use in identifying defects, it is recommended 102 The gain level required to produce the peak signal that the time gate also includes the time of arrival of the first

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.E – Page 227 mode converted back wall echo. 502 In addition to the qualification chart required above, any 205 As a minimum requirement, the time gate shall at least changes in the data records made in accordance with D306 cover the depth region of interest. above shall be recorded. 206 Where a smaller time gate is appropriate, it will be nec- The “set-up sheet” shall after dynamic calibration include as a essary to demonstrate that the defect detection capabilities are minimum: not impaired. — PRL and the signal to noise (S/N) ratio for each transducer Mapping channels — the stand-off distance for each transducer and alignment of 207 For mapping channels the gates shall be set to cover the tandem transducers HAZ and the total weld volume dedicated to the transducer or — the settings for gate start and gate length for each channel focal law. — the gain to be added to any channel during field examina- tion D 300 Recording Threshold — filtering settings, when applicable — the order of transmitters and receivers Threshold level — the transducer case height at each corner for each trans- 301 It shall be verified that the threshold level, based on data ducer and the protrusion of each “carbide tip” with an from the AUT system qualification, is set low enough to detect accuracy of 0.1 mm the minimum height critical defect identified in the acceptance — calibration block identification. criteria (see Subsection H300). 302 The threshold levels shall in any case not be set higher than required in the following. E. Field Inspection Fusion zone channels 303 The recording threshold for fusion zone channels shall E 100 Inspection requirements be at least 6 dB more sensitive than the reference reflector, General requirements unless a different sensitivity is required for detection of indica- 101 The ultrasonic system used for examination during pro- tions depending upon the size of reflectors used and the appli- duction shall in all essential aspects be in compliance with the cable acceptance criteria. set-up and configuration of the system used for system qualifi- TOFD technique cation (see Subsection H). 304 The recording threshold for ToFD is normally not rec- Documentation ommended to be changed from the calibration threshold. How- 102 The following documentation shall be available at the ever, a change of threshold may be prescribed in the procedure. place of field examination: Mapping channels An AUT system dossier for each operating AUT system 305 The recording threshold for mapping channels shall be including performance/characteristics data and identification at least 14 dB more sensitive than the reference reflector sig- of at least: nal. — pulser/receiver 306 Sufficient data shall be recorded on a “set-up sheet” to — transducers enable a duplication of the original set-up at any stage during — umbilical field inspection. — encoder As a minimum the PRL, the signal to noise (S/N) ratio, the — software version and executable focal law programmes stand-off distance for each transducer, the transducer case (when applicable) height at each corner for each transducer (with an accuracy of — other essential equipment. 0.1 mm) and settings for gate start and gate length for each channel shall be recorded. An AUT system spare parts dossier including: D 400 Dynamic calibration — performance/characteristics data and identification of essential spare parts. Detection channels 401 With the system optimised, the calibration block shall be A calibration block register including: scanned. The position accuracy of the recorded reflectors rela- tive to each other shall be within ± 2 mm, and with respect to — the documentation for each calibration block, including the zero start within ± 10 mm. spares, as required by B513. 402 For all phased array focal laws or transducers the record- An AUT personnel qualification dossier including: ing media shall indicate the required percentage of FSH and locate signals from each calibration reflector in its correctly — certificates for all AUT personnel. assigned position. The overtrace shall be in accordance with the requirements given in the AUT procedure. An AUT procedures dossier including: Coupling monitor channels — AUT procedures to be applied 403 The coupling monitor channels shall indicate no loss of — AUT system check and maintenance instructions return signal as required by the procedure. — work instructions for AUT personnel. D 500 Recording of set-up data Additional information including: 501 The calibration qualification chart shall be used as the — other NDT procedures inspection quality standard to which subsequently produced — AUT and NDT acceptance criteria. calibration charts may be judged for acceptability. This record- ing shall be kept with the system Log Book. For phased array 103 The AUT system dossier shall be updated when changes equipment also the identified set-up (executable focal law pro- of parts/components are made and shall at all times reflect the gramme) used shall be recorded. current configuration of the AUT system in use.

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The AUT system spare parts dossier shall be updated when- — at any change of components, transducers, wedges or after ever parts/components are replaced or new parts/components resurfacing of transducers arrive and shall at all times reflect the number of spares avail- — before and after examination of repairs able. — after any adjustments to scanner head or transducers System Log Book — after any change in the order of transmitters and receivers and filtering settings. 104 The System Log Book shall be kept at the place of inspection, and be made available for review upon request. Weld identification The system log book shall be continuously updated and at least 113 Each weld shall be numbered in the sequence used in the include the following information: pipe tracking system. — set-up data as required in D500 114 The starting point for each scan shall be clearly marked — the calibration qualification chart(s) on the pipe and the scan direction shall be clearly marked using — replacement of main components with spares from stock an arrow. If the scanning direction is changed from the regular — replacement of calibration block direction, this shall be noted on the records of the scan. — results from operational checks — results of periodical verifications (linearity checks, cali- E 200 Operational checks bration block wear, element verification for phased array 201 Operational checks shall be performed according to a transducers etc.) documented procedure. The execution of and the results of the — weld inspection- and calibration charts. operational checks shall be recorded in the system log book. 105 Hard copy recordings for each calibration scan (and 202 The following operational checks shall be performed for phased array set up file, if appropriate) shall be included every weld inspected: sequentially with the weld inspection charts. The last weld number examined before calibration and the time at which the — reference line shall be within required tolerance and calibration was performed shall appear on each calibration clearly marked around the pipe circumference chart. — the scanning surface shall be free of weld spatter and other that may interfere with the movement of transducers Pre- examination tests — physical damage and loose connections in the band. band 106 Before the ultrasonic system is used for field examina- position shall be within a tolerance of maximum ± 1.0 mm tion of production welds the system shall be tested. After cali- — the pipe surface temperature and the difference between bration of the complete system using the applicable “set-up calibration block temperature and pipe temperature shall sheet” parameters, the calibration block shall be scanned. If be within the required tolerance. any of the echo amplitudes from the reflectors of the calibra- tion block deviate more than 2 dB from the initial calibration, 203 The following operational checks shall be performed corrections shall be made. daily or at least once per shift: The system shall not be used until 5 successive satisfactory — the scanner head shall be checked for physical damage and scans are obtained. loose connections At least one scan shall be performed with the scanning surface — the bevel prepared at the bevelling station shall be of the wiped dry. The coupling monitor channels shall indicate loss specific weld bevel geometry, dimensions and tolerances of return signal as required by the procedure. shown on the drawings of the calibration block in use In addition, a power failure shall be simulated and operation of — the calibration block in use shall be checked for physical the system on the alternative power source with no loss or cor- damage and scanning tracks ruption of examination data shall be verified. — transducers shall not be rocking in the scanner and shall be in firm contact with the scanning surface. the transducers Verification of Calibration shall be firmly screwed onto the wedges. the transducer 107 The calibration of the system shall be verified by scan- wear faces (wedges) shall be checked for scores which ning the calibration block before and after inspection of each may cause local loss of contact weld. The gain added to any channel for field examination — the transducer stand-off distance shall be as recorded in shall be removed during verification scans. the set-up sheet within ± 0.5 mm — the transducer case height and the difference between the 108 If agreed, the frequency of verification scans may be protrusions of carbide tips shall be as recorded in the set- reduced to a minimum of 1 scan for each 10 consecutive welds. up sheet within ± 0.2 mm 109 The verification scans shall not show amplitude changes — the position accuracy of the chart distance markers shall be in any channel outside ± 2 dB from the reference calibration shall be ± 1 cm or better. chart (see D501). 110 The peak signal responses from each verification scan 204 Other operational checks such as linearity checks and shall be recorded. Any gain changes required to maintain the transducer element verification checks (when applicable) and PRL in the set-up sheet (see D502) shall be recorded. field maintenance shall be performed according to the AUT system check and maintenance instructions. Re-calibration Guidance note: 111 The system shall be re-calibrated and a new reference Checking of transducer angles may require a custom made black calibration chart shall be established according to Subsection since the standard V1 block may not be wide enough to include D if a verification scans shows amplitude changes in any chan- the carbide tips during checks and due to that the gap between the nel outside ± 2 dB from the reference calibration chart or if V1 block and transducers with radiused surfaces will be too large gain changes outside ± 2 dB are required to maintain the PRL for adequate checks.

in the set-up sheet. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 112 The system shall also be re-calibrated and a new refer- ence calibration chart and a new set-up sheet established: 205 A verification scan shall be performed prior to resuming inspection after the operational checks required in E203 and — at any change of calibration block any field maintenance. The verification scan shall meet the — at any change of nominal wall thickness requirements given in E109.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.E – Page 229

If necessary, a re-calibration shall be performed and a new ref- — transverse location of defects/indications (US, DS, Cen- erence calibration chart shall be established according to Sub- tral) section D. — maximum amplitude for each reported indication — indication type. E 300 Adjustments of the AUT system 301 Adjustments to the AUT system other than correcting G 300 Inspection records deviations from the qualified set-up sheet following opera- 301 The following inspection records shall be provided: tional checks and maintenance shall not be performed. Fine adjustments to the sensitivity settings by changing the gain set- — a hard copy record of each weld examined tings to optimise the peak signal response to accommodate — an assessment of the weld quality according to the accept- mechanical wear can be made within a window of ± 1.0 dB. ance criteria — hard copy records of all calibration scans 302 Practices such as changing transducer angles by lifting transducer front and back by adjusting of carbides, changing — examination data in electronic form. stand-off distances and changing the order of transmitter/ 302 In lieu of hard copy records an alternative recording receivers etc. are not permitted. media is acceptable. Where weld interpretation has been per- formed using digitally processed signals, the data files shall be stored and backed up immediately following the examination of each weld. The stored data shall be in the same format as F. Re-examination of Welds used by the operator to assess the acceptability of welds at the time of examination. F 100 General 303 It agreed, a software package and one set of compatible 101 Welds shall be re-examined whenever any of the follow- hardware shall be provided in order to allow the weld data file ing occur: to be retrieved in the same manner as the operator viewed the Sensitivity data at the time of inspection. 102 Welds examined at a sensitivity outside ± 2 dB from the PRL shall be re-examined. Coupling loss H. Qualification 103 Welds exhibiting a loss of acoustic coupling over a cir- cumferential distance which exceeds the minimum allowable H 100 General defect length for the affected channel shall be re-examined. 101 The AUT system shall be qualified for the applications Out of calibration it is intended used for. The qualification shall be based on the required performance as identified by the requirements for 104 If a verification scan shows that the system is in any way Probability of Detection (PoD) and sizing ability; or, alterna- "out of calibration", all welds examined since the last success- tively a requirement to defect rejection. The qualification level ful verification scan shall be re-examined. shall be documented and independently verified. 102 The qualification is AUT system specific and shall only be valid when all essential variables remain nominally the G. Evaluation and Reporting same as covered by the documented qualification. This stand- ard does not require a new qualification to be performed pro- G 100 Evaluation of indications vided that the documented performance i.e. PoD and sizing ability meets or exceeds the requirements for the specific 101 Indications from weld imperfections shall be evaluated application being considered. against the defect acceptance criteria. 103 Qualification involves a technical evaluation of the AUT 102 Indications shall be evaluated following the height, system and application in question combined with any depth and length sizing methodology given in the AUT proce- required practical tests. dure. All information available shall be used in the evaluation to avoid undersizing, - and excessive oversizing of indications. 104 The qualification shall be based on a detailed and agreed qualification programme. 103 Indications recorded from sources other than weld imperfections shall be evaluated. Their nature shall be clearly H 200 Scope identified in the examination report. 201 A qualification programme shall document the follow- 104 All evaluations shall be completed immediately after ing: examination of the weld. — fulfilment of the requirements to AUT systems according G 200 Examination reports to this Appendix 201 The examination results shall be recorded on a standard — the repeatability of the AUT system under variable exam- ultrasonic report form. The reports shall be made available on ination conditions a daily basis or on demand. — the sensitivity of the AUT system to the temperature of tested objects 202 The following items are as a minimum to be reported for — the ability of the AUT system to detect defects of relevant each indication found to be not acceptable or at the boundary types and sizes in relevant locations of acceptability: — the accuracy in sizing and locating defects. — project reference H 300 Requirements — pipeline identification — weld identification/number Detection —date 301 The detection ability of an AUT system shall be deemed — ultrasonic procedure number with associated revision sufficient if the probability of detecting a defect of the smallest — circumferential position of indication allowable height determined by an Engineering Critical — height, depth and length of indication Assessment (ECA) or by other considerations is 90% shown at

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 230 – App.E a 95% confidence level (i.e. a 90%|95% PoD). 502 The extent of each of these stages will be dependent on Sizing accuracy the prior available information and documentation, and may be totally omitted if the prior knowledge is sufficient. 302 Sizing accuracy shall be established during the qualifi- cation programme. For this purpose it is required to demon- 503 As a minimum, a qualification will involve an assess- strate the accuracy over the range of expected defect sizes. ment of the AUT system technical documentation, including Based on the determined sizing errors, the undersizing error the quality assurance system, and available information on tolerances giving less than or equal to 5% probability of under- detection abilities and defect sizing accuracy. sizing shall be determined and used in relation to any ECA In many cases practical tests of the AUT system must be per- specified defect sizes. formed. Information pertaining to these practical tests is given No specific tolerance is required for oversizing of indications. in H700. Oversizing of indications should however be within reasonable limits since excessive oversizing will result in unnecessary H 600 Test welds repairs during pipeline construction. 601 Qualification testing shall be performed using test welds Rejection containing intentionally induced defects typical of those expected to be present in welds produced with the welding 303 The detection criterion of H301 and the undersizing tol- methods to be used. erance specified in H302 may be combined into one rejection criterion: There shall be more than 85% probability of reject- 602 The material and the weld geometry shall be as for the ing a defect, which is not acceptable according to determined actual use of the equipment. Minor variations to for instance ECA criteria. This shall be shown at a 95% confidence level, the weld root groove, which are regarded irrelevant in relation i.e. a Probability of Rejection (PoR) of 85%|95% is required. to the AUT system, may be acceptable. This rejection criterion approach may be preferable when the two step process detection-sizing is not followed, e.g. when If repair welds are to be covered by the qualification, a repre- acceptance or rejection is based directly on echo amplitudes, or sentative selection of these should also be included. solely on AUT reported defect sizes. 603 The intentionally introduced defects shall vary in length, 304 The AUT system shall be deemed unqualified for its height and location. Too close spacing and stacking of the purpose with respect to ECA determined non-acceptable defects shall be avoided. The number of defects in simulated defects if it is not possible to document adequate detection and production welds shall be sufficiently high for each welding sizing abilities according to H301 and H302, or adequate rejec- and method/joint geometry to be used. tion abilities according to H303. 604 As a minimum 29 defects, or ultrasonically independent parts of defects, is required. Ultrasonically independent parts of H 400 Variables defect are those several beam widths apart. For PoD/PoR deter- 401 Variables, which must be taken into account during a mination the required number of defects may be substantially qualification, include, but are not necessarily limited to: higher, in order to ensure sufficient statistical confidence. — welding method and groove geometry 605 The locations where defects were intentionally induced — root and cap channels transducer set-up shall be recorded. The presence and sizes of the induced — transducer set-up for other channels (the number of these defects in the test welds shall be confirmed. For this purpose channels may be increased or decreased provided there are the test welds shall be subject to supplementary NDT: Radiog- no set-up changes) raphy and manual ultrasonic and preferably magnetic particle or eddy current testing. The reference point for all testing shall — reference reflectors be the same and shall be indicated by hard stamping on the test — system, data acquisition and data treatment welds. The techniques used for this testing shall be optimised — software version (except changes affecting viewing or dis- for the weld geometries in question. The interpretation of radi- play only). ographs and other test results should at least be performed by H 500 Qualification programme two individuals, initially working independently of each other and later reporting their findings jointly. General 606 The report shall identify the identified defects from the 501 A full qualification programme for a specific application supplementary NDT in the test welds with respect to circum- of an AUT system will in general comprise the following ferential position, length, and height. The report shall be kept stages: confidential. 1) Collection of available background material, including H 700 Qualification testing technical description of the AUT system and its perform- ance. 701 The testing described in the following is required for a full qualification. If limited practical testing is performed the 2) Initial evaluation and conclusions based on available testing and documentation requirements given shall apply as information. applicable to the actual testing performed 3) Identification and evaluation of significant parameters and their variability. 702 The test welds shall be subjected to testing by the AUT system. 4) Planning and execution of a repeatability test programme, see H705 and H706. For testing, a low echo amplitude recording threshold shall be used. This threshold should be selected somewhat above the 5) Planning and execution of a temperature sensitivity test noise level and the recording of echo amplitudes may be used programme, see H707 and H708. for possible later determination of the examination threshold 6) Planning and execution of detection ability and sizing setting to achieve sufficient detection. accuracy test programme, see H709 and H710. 703 The reference point for circumferential positioning shall 7) Reference investigations. be a hard stamped on the test welds. 8) Evaluation of results from repeatability, temperature sen- 704 The AUT system shall be set-up, calibrated and subject sitivity and detection ability and sizing accuracy trials. to test runs before starting the formal qualification.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.E – Page 231

Repeatability testing — minimum 2 scans of the test weld in the CW direction with 705 The testing shall include: re-setting of the band between each scan — one scan of the calibration block(s) — one initial scan of the calibration block in the horizontal — minimum 2 scans of the test weld in the CCW direction position with resetting of the band between each scan — minimum 3 scans of the calibration block(s) with the cen- — one scan of the calibration block(s) tre of the calibration block(s) in the 12 o’clock, 3 o’clock — assessment and sizing of indications. and 6 o’clock positions — if relevant for the application of the AUT system the scans 710 All scans shall be given a unique number indicating above shall be repeated with the calibration block(s) in the weld number, the scan sequence and the scanning direction vertical position and the documentation of the test scans shall include: — minimum 3 scans of the calibration block with the band offset 1 mm to the DS side a) hard copy and electronic output of all scans — minimum 3 scans of the calibration block with the band b) defect/indication number with reference to sizing method offset 1 mm to the US side and for each defect/indication the dimensions: — minimum 3 scans of the calibration block with the band removed and reset between each scan. The calibration — circumferential position block shall be in the least favourable position as deter- —length mined in 2 and 3 above. — height — depth to bottom of indication 706 All scans shall be given a unique number and the docu- — transverse location of defects/indications (US, DS, mentation of the test scans shall include: C(entral)) — maximum amplitude for each scan and variations in — hard copy and electronic output of all scans maximum amplitude between scans — a table for repeatability test scans showing for each scan — main AUT zone the maximum amplitude response of each transducer to its — defect type. dedicated calibration reflector and the deviation for each scan from the initial calibration scan. It may further be required to report height, location, depth and echo amplitude at certain additional local defect positions (see Temperature sensitivity testing also H603). 707 Typical test welds containing at least 6 clearly identifia- In addition the following information shall be provided: ble and distinct AUT indications each shall be used for scan- ning with the pipe axis in the horizontal position. — weld identification The test welds shall after the initial scans be heated to the ele- — pipe material vated temperature expected during field work and maintained — pipe thickness/diameter at this temperature during scanning. The calibration block(s) — welding method shall be kept at environmental temperature or be heated to an — groove geometry agreed temperature and maintained at this temperature during — calibration block documentation. scanning. Verification of coupling alarm settings The testing shall include: 711 Scans shall be performed on different test welds. The — one initial scan of the calibration block couplant flow shall be reduced and the surface wiped dry — one initial scan of the non-heated weld between scans until the coupling alarm level/coupling monitor — one scan of the heated test weld immediately followed by channels indicates loss of return signal. The level at which the a scan of the calibration block(s) coupling alarm/ coupling monitor channels indicates loss of — repeat with 5 minutes intervals several scans of the heated return signal shall be recorded. The final level for coupling test weld each immediately followed by a scan of the cal- alarm /coupling monitor channels settings shall be at least 4 dB ibration block(s). lower than the recorded value. If the AUT system shows unacceptable temperature sensitivity H 800 Reference destructive testing the test can be repeated with agreed different test conditions. 801 The reports from the AUT qualification testing shall be 708 All scans shall be given a unique number and the docu- validated for accuracy in the determination of defect circum- mentation of the test scans shall include: ferential position, length, height and depth by reference destructive testing. — hard copy and electronic output of all scans — a table for the temperature sensitivity test scans showing 802 The testing shall be by cross-sectioning, preferably by the maximum amplitude response for each identified indi- the "salami method", by making more cross-sections around cation for each scan. each location chosen. The defects as reported in the AUT reports shall be used when selecting the areas for cross section- Detection ability and sizing accuracy testing ing. 709 The test welds shall normally be scanned with the pipe In addition, locations where the AUT shows indications near axis horizontal. If the AUT system shall be qualified for scan- the threshold level, locations where indications are identified ning with the pipe axis vertical, the testing shall be performed by the supplementary NDT (see H605), locations where inten- in this position only or in both positions. tionally induced defects was planned and randomly chosen locations shall be included. The scanning directions identified as clockwise or counter clockwise (CW or CCW) shall be hard stamped on the test Alternatives to macro sectioning such as C-scan immersion weld. The calibration block shall be in the least favourable testing of the girth weld may be acceptable. However, any position as determined by the repeatability testing. See H705. other methods other than macro sectioning need to be sepa- rately qualified to establish the degree of accuracy. The testing shall include: 803 The cross sections shall be referenced to and validated — one initial scan of the calibration block against the recording chart positions.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 232 – App.E

804 The weld sections containing defects shall be machined according to this Appendix in increments of maximum 2.0 mm. Each machined cross sec- — description of the specimens and tests performed, includ- tion of the weld shall be polished with 600 grit and etched and ing sensitivities used the defect location, height and depth measured with accuracy — definitions of the essential variables (see I200) for the better than ± 0.1 mm. Each cross section shall be documented welds and equipment used during qualification testing by a photograph with 5 - 10x magnification. — data recorded for each defect and each defect cross-section 805 The extent of sectioning shall be sufficient to ensure that (sizes, locations, types, measured and determined during the defect height/length sizing analysis will be based on a suf- reference investigation, echo amplitudes) ficient number of different defects and/or ultrasonically inde- — outcome of the analysis of data (H900) pendent parts of defects (i.e. at locations many beam widths — conclusion of the qualification. apart). Indications with small and large heights shall be included. H 900 Analysis I. Validity of Qualification Repeatability I 100 Validity 901 The data from the repeatability test programme shall be 101 A qualification is AUT system, weld method and groove analysed with respect to system repeatability and stability. The geometry specific. maximum deviations in amplitude from each reference reflec- tor between the initial scan and: A qualification of an AUT system will remain valid on the con- dition that no changes are made in the essential variables — the scans performed with each calibration block position defined in I200 that would influence on AUT performance. — the scans performed with the band offset — the scans performed with removal and resetting of the I 200 Essential variables band. 201 The following essential variables apply: shall be determined. — welding method and groove geometry (including repair Temperature sensitivity welds, if relevant) — root and cap transducer set-up 902 The data from the temperature sensitivity test pro- — transducer set-up for other channels (the number of these gramme shall be analysed with respect to the influence of tem- channels may be increased or decreased to accommodate perature build-up in the transducers over time. The maximum changes in wall thickness provided there are no set-up variations in amplitude from each selected indication between changes) the initial scan and the scans performed with heated test weld — focal laws and with or without or heated calibration blocks shall be deter- — reference reflectors mined. — working temperature range Based upon an acceptable variation in amplitude of ± 2 dB, the — system, data acquisition and data treatment analysis shall determine the: — software version (except changes affecting viewing, dis- play or bug-fixing only). — acceptable maximum temperature of welds — the sum of transducer inactive time on weld and scanning 202 Changes in the essential variables for an existing quali- time fied system will require a demonstration of the ability of the — the minimum time between scanning of hot welds new or modified system to detect and accurately size and posi- — the maximum temperature difference between weld and tion weld imperfections. calibration block. Detection ability and sizing accuracy 903 The data recorded during the tests and reference investi- J. Determination of Wave Velocities gations shall be analysed with respect to: in Pipe Steels — accuracy in height sizing (random and systematic devia- J 100 General tion, and 5% fractile) The procedure defined covers methods that may be used to — accuracy in length sizing determine acoustic velocity of ultrasonic waves in linepipe — accuracy in circumferential positioning / location steels. Equivalent methods may be used subject to agreement. — AUT defect characterisation abilities compared to the results of the destructive tests and the other NDT per- Linepipe used in oil and natural gas transmission exhibit vary- formed ing degrees of anisotropy with varying acoustic velocities — as relevant, determination of PoD/PoR values or curves depending on the propagation direction with resultant changes for different assumed echo amplitude or other employed in the refracted angle of the sound in the steel. This is espe- threshold settings to determine the threshold to be used cially critical where focused beams are used for zonal discrim- during examination. ination. It is thus required to determine the ultrasonic shear or longitudinal (as appropriate) wave velocity for propagation in 904 The analysis shall be performed by recognised and different directions. applicable statistical methods, e.g. according to Nordtest NT Techn. Report 394 (Guidelines for NDE Reliability Determi- J 200 Equipment nation and Description, Approved 1998-04). The omission of To determine the wave velocity (shear or compression) direc- any reported indication in the analysis shall be justified. tional dependency an ultrasonic wave transducer of the same frequency used in the inspection with a crystal diameter of 6 - H 1000 Reporting 10 mm should be used in combination with an ultrasonic appa- 1001 A qualification report shall as a minimum contain: ratus with bandwidth at least up to 10 MHz and a recom- mended capability of measuring ultrasonic pulse transit times — a technical documentation of the AUT system with a resolution of 10 ns and an accuracy of ± 25 ns. Devices — outcome of the technical evaluation of the AUT system for measuring mechanical dimension of the specimens should

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.E – Page 233 have a recommended accuracy of ± 0.1 mm. As couplant an plane to be evaluated; one pair of surfaces is made in the radial easily removable glue or special high viscosity shear or com- direction (perpendicular to the OD surface) and the other pair pression wave couplant (as appropriate) is recommended. made 20° from the perpendicular to the OD surface, see Figure 1. Additional pairs of parallel surfaces may be J 300 Specimens machined at other angles in the plane to be evaluated if more A specimen is cut from a section of pipe to be tested and the data points are desired. corresponding results are specific for a particular pipe diame- The machined surfaces should be smooth to a 20 μm finish or ter, wall thickness and manufacturer. Specimen dimensions better. Minimum width of the specimen surface to be measured should be a minimum of 50 × 50 mm. should be 20 mm and the minimum thickness between the par- A similar arrangement can also be used for measuring veloci- allel surfaces to be measured should be 10 mm. Vertical extent ties in a plane normal to pipe axis. of the test surface will be limited by the pipe wall thickness. J 400 Test method Using the machined slots as reflectors for the wave pulses with the transducer in the appropriate positions and measuring the pulse transit times determines together with the mechanically measured pulse travelling distances the wave velocities in the axial and 20° direction (Figure 1). A similar measurement in the through thickness direction determines the radial velocity. Pulse transit times shall be measured between the forefront parts of 1st and 2nd back wall echo, or, alternatively, using more multiple echoes. A minimum of three readings shall be made for each plane in which testing shall be done. J 500 Accuracy Errors in velocity determination shall not be greater than ± 20 m/s. J 600 Recording Values for the velocities determined can be tabulated and graphed. By plotting velocities on a two dimensional polar graph for a single plane, velocities at angles other than those Figure 1 Test specimen and transducer placement made directly can be estimated. The effect of temperature on velocity can be significant under extreme test conditions; therefore the temperature at which A minimum of three parallel surfaces are machined for the these readings have been made should also be recorded.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 234 – App.F

APPENDIX F REQUIREMENTS FOR SHORE APPROACH AND ONSHORE SECTIONS

A. Application 203 This appendix does not cover regular onshore pipelines, i.e. pipelines starting and ending onshore not having any sub- A 100 Objective marine parts. River crossings or crossing of fresh water lakes 101 The objective of this appendix is to provide the comple- are not considered as submarine sections. mentary requirements to the onshore part of the submarine Guidance note: pipeline system compliant with the safety philosophy for the This appendix is not meant to replace current industry practice offshore part. This appendix specifies the requirements for onshore codes or any national requirements.

design, construction and operation of parts of pipeline systems ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- going onshore. This appendix is meant to ease the project execution of subma- 204 Specific requirements for the onshore parts given in this rine pipeline developments where parts are going onshore. appendix overrule requirements given elsewhere in the stand- ard. Guidance note: A submarine pipeline system is defined to end at weld beyond the A 300 Other codes first flange/valve onshore or to the pigging terminal. This implies that a, sometimes significant, part of the pipeline system can be 301 This Appendix is fully aligned with the requirements located onshore. This part of the pipeline system may have dif- given in ISO 13623 ferent legislations, failure modes and failure consequences com- Guidance note: pared to the submarine part. ISO 13623 requires a specific utilisation for landfall. According The exact limit of the submarine pipeline system at the onshore to this code the assessment of risk will constitute selection of end may differ from this definition herein based on different stat- safety class for each specific pipeline and pipeline sections. Nor- utory regulations which may govern. mally the safety class classification for a landfall will give the Onshore codes may also take precedence of this part due to leg- same utilisation as required by ISO 13623 however this does not islation aspects. always need to be the case. This implies that the utilisation in

landfall may differ from the ISO 13623 requirements and care ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- should be taken when stating compliance with ISO 13623 for a specific pipeline development. 102 The appendix also covers requirements to shore approach. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- A 200 Scope and limitation 302 Onshore pipelines are normally regulated by national regulations and cover a wide range of areas from public safety, 201 The limitations found in Sec.1 A300 are in general also traffic and roads, water ways, environmental impact, etc. Some applicable for this Appendix. of these regulations may be stricter than the requirements 202 The onshore section is limited by the definition of sub- given in this code and care shall be exercised when assuring marine pipeline system. compliance with different national regulations.

Application of OS-F101 with Appendix F Isolation joint First (or last) valve last) (or First Nearshore section Shore approach

Offshore section Onshore section

Figure 1 the location of the first flange or valve onshore. Note that this Maximum application extent of OS-F101 with Appendix F. may differ based on different statutory regulations. 403 First (or last) valve onshore - valve separating the off- A 400 Definitions shore and onshore pipeline. Often the position of the battery 401 Battery limit - the limit at which the scope of work ends. limit and the code break. Often an emergency shut down The battery limit can be different for designer, installation con- valves (ESDV) tractor, verifier and owners. Normally defined at as ‘including’ 404 Isolation joint - a special component separating (isolat- or ‘up to’ a certain weld. ing) the offshore cathodic protection from the onshore 402 Code break - the exact point at which the design code cathodic protection system and installed within the onshore changed from submarine to onshore code. Normally defined at part of the offshore pipeline. It is normally positioned very as ‘including’ or ‘up to’ a certain weld. This is often defined at close to the landfall as the offshore cathodic protecting system

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.F – Page 235 has limited protection capabilities when the pipeline is not sub- B 300 Quantification of consequence merged in water. 301 Fluids shall be categorised in line with Sec.2 of this 405 Landfall - where the pipeline comes on shore. Often standard. defined by a point called LTE; Land Terminal End. 302 A location class shall be determined for each part of the 406 Near shore - the transition from the offshore pipeline to pipeline as shown in Table F-1. the shore approach area. Often not well defined, but can be the area in where the pipeline goes from laying on the sea-bed to Table F-1 Location Classes Onshore being positioned in an open trench to where it is buried. Some- Location Class Description times the extent of the areas is defined by the reach of the 1 Locations subject to infrequent human activity installation vessel or trenching equipment, and sometimes this (Equivalent to with no permanent human habitation. Location area is given special attention by the fishing industry. Location class 1 Class 1 is intended to reflect inaccessible areas 407 Onshore part of offshore pipeline - the first part of the as defined in such as deserts and tundra regions pipeline on shore. It is distinct as the offshore design code is Sec.2) still applied, while the pipeline is not offshore. The length is 2 Locations with a population density of less than normally short, up to some kilometres. 50 persons per square kilometre. Location Class 2 is intended to reflect such areas as wasteland, 408 Onshore pipeline - the pipeline on shore following grazing land, farmland and other sparsely popu- onshore codes and normally subject to different authority reg- lated areas ulations 3 Locations with a population density of 50 per- 409 Right-of-way – corridor of land within which the pipe- (Equivalent to sons or more but less than 250 persons per line operator has the right to conduct activities in accordance Location class 2 square kilometre, with multiple dwelling units, with the agreement with the land owner. as defined in Sec- with hotels or office buildings where no more tion 2) than 50 persons may gather regularly and with 410 Shore approach - the last part of the pipeline before it occasional industrial buildings. Locations Class comes on shore. The need for burying the pipeline in the shore 3 is intended to reflect areas where the popula- approach area should be evaluated and include: tion density is intermediate between location Class 2 and Location Class 4, such as fringe — environmental loading (breaking waves, current and tide), areas around cities and towns, and ranches and — requirements to a ‘clean beach’ for recreation, country estates. — shipping activity or 4 Locations with a population density of 250 per- — protection (reduced access by 3rd parties). sons or more per square kilometre, except where a Location Class 5 prevails. A Locations Class 4 is intended to reflect areas such as suburban housing developments, residential areas, indus- trial areas and other populated areas not meeting B. Safety Philosophy Location Class 5. B 100 General 5 Location with areas where multi-storey build- ings (four or more floors above ground level) are 101 The design philosophy for the shore approach and the prevalent and where traffic is heavy or dense onshore pipeline shall comply with Sec.2. This implies that the and where there may be numerous other utilities consequences of failure (economical, environmental and underground. human) shall be quantified by the concept of safety class. The safety class is normally determined by fluid category, location 303 The population density in Table F-1, expressed as the class and phase (construction, operation) of the pipeline. number of persons per square kilometre, shall be determined by laying out zones along the pipeline route, with the pipeline 102 The presence of people and facilities necessitates a fur- in the centreline of this zone having a width of: ther refinement of the location classes used offshore. In highly populated areas the consequences may be more severe than for — 400 m for category D fluids, and offshore, requiring a higher safety class, Very High. — to be determined for category E fluid pipelines, but not These complementary issues are described in this sub-section. less than 400 m. The determination shall include the pos- Guidance note: sibility of very low temperature during a leakage of high It should be noted that ISO 13623 contain even more stringent pressure pipelines, giving high density gas that may utilisation requirements than safety class Very High. However, “float” significant distance prior to ignition. as this code is meant to only cover onshore parts of an offshore pipeline system it is not foreseen that such a line will be located 304 Half the zone width shall not be less than the effective in areas with even higher population densities. distance of fluid release.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 305 The length of the zones shall be 1.5 km and located at any location along the pipeline. The length of the random sec- B 200 Safety philosophy tions may be reduced where physical barriers or other factors 201 The safety philosophy outlined in Sec.2 B is applicable exist, which will limit the extension of the more densely pop- for shore approach and onshore sections. ulated area to a distance less than 1.5 km. Guidance note: 306 The possible increase in population density and level of In particular is it important to perform a systematic review of all human activity from planned future developments shall be hazards to identify consequences as third party presence is more determined and accounted for when determining population significant onshore. density.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 307 Additional considerations shall be given to the possible consequences of a failure near a concentration of people such 202 The quality assurance outlined in Sec.2 B is applicable as found in a church, school, multiple-dwelling unit, hospital, for shore approach and onshore sections. or recreational area of an organised character in location 203 The health, safety and environmental aspects outlined in classes 2 and 3. Sec.2 B is applicable for shore approach and onshore sections 308 Pipeline design according to this standard is based on also. potential failure consequence and is quantified by the concept

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 236 – App.F of safety class. These may vary for different phases and loca- C 200 Routing tions and are defined in Table F-2. 201 The requirements in Sec.3 C apply to the shore approach section. Additional requirements are given below. Table F-2 Definition of safety classes Safety Class Description 202 The routing shall be selected and prepared so that risk of fire, explosions and un-intended occurrences is at an accepta- Low Where failure implies low risk of human injury and minor environmental and eco- ble level. Spacing between pipelines, associated equipment, nomic consequences harbours, ship traffic and buildings shall be evaluated by risk assessments considering the service of the pipeline. Medium Where failure implies risk of human injury, significant environmental pollution or very Guidance note: high economic or political consequences The preferred means of routing for shore approach pipeline will High Where failure during operating conditions be to bury them. Examples of additional protective means are implies high risk of human injury, significant Concrete coating or cover, additional steel wall thickness, deeper environmental pollution or very high eco- trenching, additional marking and means to minimize the possi- nomic or political consequences bility for impacts from ship traffic and vehicles.

Very High Where failure during operating conditions ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- implies very high risk of human injury. 203 Special focus shall be on: 309 The acceptable failure probability of safety class Very High is one order of magnitude lower than for safety class — safety of public High as given in Sec.2 of this standard. — protection of environment 310 The safety class determined by the crossing shall apply — 3rd party activities from: — access — other property and facilities. — for road crossings — the road right-of-way boundary 204 Pipeline conveying category B, C, D and E fluids should — if this boundary has not been defined, to 10 m from the edge avoid built-up areas or areas with frequent human activity. of the hard surface of major roads and 5 m for minor roads 205 In absence of public safety statutory requirements, a —for railways safety evaluation shall be performed in accordance with the — 5 m beyond the railway boundary or general requirements for: — if this boundary has not been defined, to 10 m from the rail. — Pipeline conveying category D fluids in locations where multi-storey buildings are prevalent, where traffic is heavy 311 The safety class can often be determined based on the or dense, and where there may be numerous other utilities location class and fluid category. Typical selection of safety underground class is given in Table F-3. — Pipelines conveying category E fluids.

Table F-3 Classification of safety classes 206 An Environmental Impact Assessment (EIA) shall be performed. The EIA shall consider as a minimum: Phase Fluid Location Class Category 123452 — temporary works during construction and operation (e.g. Temporary1 All Low - repair, modifications etc.) Operating A,C Low Medium - — the long-term presence of the pipeline Onshore B Medium Medium High Very - — leakage. High 207 The route shall permit the required access and working D,E Medium Medium High Very - width for the construction and operation (including any High replacement), of the pipeline. The availability of utilities nec- 1) Installation until commissioning (temporary) will normally be classified essary for construction and operation should also be reviewed. as safety Class low. During temporary conditions after commissioning of the pipeline, special considerations shall be made to the consequences of 208 The route shall be tidy and free from flammable materials failure, i.e. giving a higher safety class than Low. on and in the vicinity of the pipeline system. A safety area along the pipeline shall be defined which may restrict public access 2) This code is not applicable for areas in location Class 5. and activities. The extent of the area shall be established based on risk analyses and shown on the plan for the pipeline system. 209 Facilities along the pipeline route should be identified C. Design Premise and their impact evaluated in consultation with the operator of these facilities. Facilities should not be allowed closer than 4 C 100 General m from the pipeline. 101 The basis for design premises for the shore approach 210 A wider restriction zone compared to public access may shall be as given in Sec.3. Special attention shall be given to apply to future development (buildings etc.). aspects related to installation, on-bottom stability, fatigue due to direct wave loading and 3rd party activities. Statutory C 300 Environmental data requirements apply. 301 Environmental data shall be collected as described in 102 The shore approach should be constructed by either Sec.3. Long term shore profile shall be considered. Special attention shall be given to tidal variations. — a tunnel, — horizontal directional drilled (HDD) guide tube, C 400 Survey — cofferdam, 401 Route and soil surveys shall be carried out to identify — trench, and locate with sufficient accuracy the relevant geographical, — dredging, or geological, geotechnical, corrosive, topographical and envi- — combinations of the above. ronmental features, and other facilities such as other pipelines,

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 App.F – Page 237 cables and obstructions, which may impact the pipeline route Table F-4 apply. selection. The surveys shall be continuous, and the accuracy and tolerance should be selected with regard to the adjoining Table F-4 Partial safety class resistance factor for safety class land and offshore surveys. Very High 402 Inshore survey coverage should be continuous and in Limit state γSC agreement within specified tolerances and accuracies of both Pressure containment 1.593 adjoining land and offshore route surveys. Other limit states 1.5 C 500 Marking 403 Buried pipelines on land should be installed with a cover 501 The pipeline system shall be marked in such a way that depth not less than shown in Table F-5. its location in the terrain is clearly visible. Provisions shall be made to restrict public access to pipelines that are not buried. Table F-5 Minimum cover depth for buried pipelines on land (alternative, preferred formulation to the table above) 502 Warning signs shall be placed within visible distance Safety Class 3) Cover depth [m] 1) 2) 4) 5) 6) 7) and at each side of crossings with rivers, roads and rail ways giving information on: Trench blasted in rock Other Low 0.5 0.8 — content Medium 0.8 —owner High 1.2 — phone number to nearest manned station which may be Very High 1.2 alerted in the event of fault on the pipeline. 1) Cover depth shall be measured from the lowest possible ground surface level to the top of the pipe, including coatings and attachments. 2) Special consideration for cover may be required in areas with frost heave. D. Design 3) River crossings, road crossings and railway crossing shall in this context be classified as safety class High. D 100 General 4) Cover shall not be less than the depth of normal cultivation +0.3 m. 101 The pigging requirements in Sec.5 B114 and B115 5) For river crossings; to be measured from the lowest anticipated bed. applies to the pipeline system. 6) For roads and railway crossings; to be measured from the bottom of the drain ditches D 200 System design 7) The top of pipe shall be at least 0.15 m below the surface of the rock. 201 Any electrical equipment within the location class areas shall comply with the location class requirements. 404 The effect of cover depth shall be considered in the expansion evaluations. 202 The need for lightening rod and means to avoid build up 405 If the pipeline is not laid at a frost free depth, the mass of static electricity shall be considered. below the pipe’s centre line must be frost proof. 203 Branch connections for pipelines on land shall be supported 406 Pipelines may be installed with less cover depth than by consolidated backfill or provided with adequate flexibility. indicated in Table F-5, provided a similar level of protection is 204 Braces and damping devices required to prevent vibration of provided by alternative methods. The design of alternative pro- piping shall be attached to the pipe by full encirclement members. tection methods should take into account: 205 Structural items should not be welded directly to pres- — any hindrance caused to other users of the area sure containing parts or linepipe due to the increased local — soil stability and settlement stress on the linepipe. External supports, attachments etc. shall — pipe stability cathodic protection be welded to a doubler plate or ring. The double plate or ring — pipeline expansion shall be designed with sufficient thickness to avoid stresses on — access for maintenance. the linepipe. In case structural items are integrated in the pipe- line, e.g. pipe in pipe bulkheads, and are welded directly to the 407 Pipelines running parallel to a road or railway should be linepipe, detailed stress analyses are required in order to docu- routed outside the corresponding right-of-way. ment sufficiently low stress to ensure resistance against 408 The vertical separation between the top of the pipe and fatigue, fracture and yielding. the top of the rail should be a minimum of 1.4 m for open-cut crossings and 1.8 m for bored or tunnelled crossings. D 300 Design loads 409 Protection requirements for pipeline crossings of canals, 301 The loads shall be established as described in Sec.4. rivers and lakes should be designed in consultation with local Special attention shall be given calculations of loads from 3rd water and waterways authorities. party activities such as traffic (potential cyclic loading) and other construction work. 410 Crossings of flood defences can require additional design measures for prevention of flooding and limiting the 302 The loads shall be classified into functional, environ- possible consequences. mental, interference or accidental loads as per Sec.4 of this standard with the additional requirements below. 411 Crossing pipelines and cables should be kept separated by a minimum vertical distance of 0.3 m. 303 Traffic axle loads and frequency shall be established in consultation with the appropriate authorities or other relevant 412 Pipeline bridges may be considered when buried cross- sources and with recognition of existing and forecast residen- ings are not practicable. Pipe bridges shall be designed in tial, commercial and industrial developments. accordance with structural design standards, with sufficient clearance to avoid possible damage from the movement of traf- D 400 Design criteria fic, and with access for maintenance. Interference between the cathodic protection of the pipelines and the supporting bridge 401 The design should comply with the requirements in Sec.5. structure shall be considered. Special attention shall be given to statutory requirements. 413 Provisions shall be made to restrict public access to pipe 402 For safety class Very High the safety class factors in bridges.

DET NORSKE VERITAS Offshore Standard DNV-OS-F101, October 2010 Page 238 – App.F

414 If other criteria are used, the nominal failure probabili- 406 Test points for the routine monitoring and testing of the ties shall be demonstrated to be as specified in Sec.2. cathodic protection should be installed at the following loca- tions: — crossings with DC tractions systems E. Construction — road, rail and river crossings and large embankments — sections installed in sleeve pipes or casings E 100 General — isolated couplings 101 The same requirements as for the Offshore part of the — where the pipeline runs parallel to high-voltage cables pipeline system shall be applied to the onshore part, if applica- — sheet piles ble. Where this is not applicable, the requirements of — crossings with other major metallic structures with, or ISO 13623 should be complied with. without, cathodic protection. Guidance note: This is applicable for e.g. welding and NDT in Appendixes C, D 407 The primary corrosion control for internal corrosion is and E identical with the submarine part, see Sec.8.

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E 200 Linepipe F. Operation 201 The manufacture of linepipe should comply with the requirements in Sec.6. F 100 General 101 The requirements to safe and reliable operation of the E 300 Components and assemblies pipeline systems and the pipeline integrity management (PIM) 301 The requirements to components and structural items as as described in Sec.10 apply. well as assemblies should comply with Sec.7. 102 The whole route shall regularly be checked for: E 400 Corrosion protection & coatings — any required re-classification of location class due to 401 The corrosion protection shall comply with Sec.8. changes in premises like populations etc. 402 All metal pipelines should be provided with an external — new facilities coating and, for buried or submerged sections, cathodic protec- — new intruders or changed configurations that may cause tion. Corrosion protection should normally be provided by increase risk of threats. impressed current. 403 The design of the impressed current protection system shall strive for a uniform current distribution along the pipe- G. Documentation lines and shall define the permanent location for the measure- ment of the protection potentials. G 100 General 404 Protected pipelines should be electrically isolated from 101 In addition to the requirements in Sec.11, the following other structures, such as compressor stations and terminals, by apply: suitable in-line isolation components. 405 Isolation joints should be provided with protective — crossing locations related to lakes, straits, rivers, streams, devices to prevent damage from lightning or high-voltage transport communication arteries and similar earth current where possible. Low-resistance grounding to — maps necessary to evaluate the proposed route classifica- other buried metallic structures shall be avoided. Electrical tion continuity shall be provided across components, other than — relevant drawings on bridges etc. couplings/flanges, which would otherwise increase the longi- — maps with any crossing services (cables, sewage etc.). tudinal resistance of the pipeline. Spark gaps shall be installed between protected pipelines and lightning protection systems.

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