As 2885.1-2012 Design and Construction

AS 2885.1—2012

AS 2885.1—2012

Australian Standard® Pipelines—Gas and liquid petroleum

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Part 1: Design and construction

This Australian Standard® was prepared by Committee ME-038, Petroleum Pipelines. It was approved on behalf of the Council of Standards Australia on 27 July 2012. This Standard was published on 20 September 2012.

The following are represented on Committee ME-038:

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• • • • • • • • • • • • • • • • • • •

APIA Research and Standards Committee Australasian Corrosion Association Australian Chamber of Commerce and Industry Australian Institute of Petroleum Australian Petroleum Production and Exploration Association Australian Pipeline Industry Association Bureau of Steel Manufacturers of Australia Department of Labour New Zealand Department for Manufacturing, Innovation, Trade, Resources and Energy (SA) Department of Mines and Petroleum (WA) Department of Natural Resources and Mines (Qld) Department of Resources (NT) Energy Networks Association Energy Safe Victoria Gas Association of New Zealand NSW Department of Trade and Investment, Regional Infrastructure and Services Petroleum Exploration and Production Association New Zealand Primary Industries and Resources SA Welding Technology Institute of Australia

This Standard was issued in draft form for comment as DR AS 2885.1. Standards Australia wishes to acknowledge the participation of the expert individuals that contributed to the development of this Standard through their representation on the Committee and through the public comment period.

Keeping Standards up-to-date Australian Standards® are living documents that reflect progress in science, technology and systems. To maintain their currency, all Standards are periodically reviewed, and new editions are published. Between editions, amendments may be issued. Standards may also be withdrawn. It is important that readers assure themselves they are using a current Standard, which should include any amendments that may have been published since the Standard was published. Detailed information about Australian Standards, drafts, amendments and new projects can be found by visiting www.standards.org.au Standards Australia welcomes suggestions for improvements, and encourages readers to notify us immediately of any apparent inaccuracies or ambiguities. Contact us via email at [email protected], or write to Standards Australia, GPO Box 476, Sydney, NSW 2001.

AS 2885.1—2012

Australian Standard® Pipelines—Gas and liquid petroleum

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Part 1: Design and construction

First published in part as part of AS CB28—1972. Revised and redesignated AS 1697—1975. AS 1958 first published 1976. AS 2018 first published 1977. Second edition AS 1697—1979. Third edition 1981. Second edition AS 1958—1981. Second edition AS 2018—1981. AS 1958—1981 and parts of AS 1697—1981 and AS 2018—1981 revised, amalgamated and redesignated AS 2885—1987. Parts of AS 1697—1981, AS 2018—1981 and AS 2885—1987 revised, amalgamated and redesignated in part as AS 2885.1—1997. Second edition AS 2885.1—2007. Third edition AS 2885.1—2012.

COPYRIGHT © Standards Australia Limited All rights are reserved. No part of this work may be reproduced or copied in any form or by any means, electronic or mechanical, including photocopying, without the written permission of the publisher, unless otherwise permitted under the Copyright Act 1968. Published by SAI Global Limited under licence from Standards Australia Limited, GPO Box 476, Sydney, NSW 2001, Australia ISBN 978 1 74342 229 8

AS 2885.1—2012

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PREFACE This Standard was prepared by the Joint Standards Australia/Standards New Zealand Committee ME-038, Petroleum Pipelines, to supersede AS 2885—2007, Pipeline—Gas and liquid petroleum. After consultation with stakeholders in both countries, Standards Australia and Standards New Zealand decided to develop this Standard as an Australian Standard rather than an Australian/New Zealand Standard. The objective of this Standard is to provide requirements for the design and construction of steel pipelines and associated piping and components that are used to transmit single-phase and multi-phase hydrocarbon fluids. This Standard provides guidelines for use of pipe manufactured from certain non-steel or corrosion-resistant materials. This Standard is part of a series that covers high pressure petroleum pipelines, as follows: AS 2885 2885.0 2885.1 2885.2 2885.3 2885.4

Pipelines—Gas and liquid petroleum Part 0: General requirements Part 1: Design and construction (this Standard) Part 2: Welding Part 3: Operation and maintenance Part 4: Submarine pipelines

AS/NZS 2885.5

Part 5:

Field pressure testing

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2012—Minor revision (harmonization with other parts) This minor revision of AS 2885.1—2007 has been prepared to incorporate the revision/amendment to AS 2885.0, AS 2885.3 and AS 2885.5 to resolve inconsistencies between the Parts and update the referenced documents. Significant changes to this edition include the following: 1

The requirements for specific items to be ‘approved’ have been deleted from this Standard unless the item is considered of sufficient importance to require specific approval of the licensee. AS 2885.0 requires approval of all documents by the authority designated by the Licensee, except those specifically nominated for approval by the Licensee, or so nominated in this Standard.

2

Draws attention to the need to properly specify line pipe, to the limits of some commonly used pipe, and a requirement is introduced to address these matters in the design basis.

3

Requirements for design of a pipeline for hydrostatic test developed for AS 2885.5 have been incorporated in this Standard.

4

Requirements for commissioning of a pipeline developed for AS 2885.3 have been incorporated in this Standard in recognition of the fact that commissioning is almost always a responsibility of the design and construction project and, after successful commissioning, the pipeline is handed over to operations in accordance with AS 2885.3.

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A new appendix (Appendix BB), addressing issues that need to be considered when applying this Standard to the design of pipelines transporting CO 2, either pure or anthropogenic, has been included. This appendix was prepared in response to an initiative of the Carbon Capture Taskforce of the Australian Government Department of Resources Energy and Tourism.

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Changes have been made to achieve consistency between AS 2885.1, AS 2885.3 and AS 2885.5.

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Section 11 has been revised to recognize the intent in the 2007 edition to transfer some requirements to the next revision of AS/NZS 2885.5.

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Minor changes, the result of requests for clarification, have been included. Only minor clarifications have been addressed. Complicated clarifications have been reserved for the next revision of AS 2885.1.

9

Correction of an error in Equation S2(1).

2008 Amendment No. 1 Amendment No. 1 to AS 2885.1—2007 was prepared to correct errors in the 2007 revision and to clarify items identified as being potentially confusing. The amendment includes guidance on specifying fracture toughness when purchasing line pipe and includes a simplified calculation for energy release from leaks. The requirements for the control of fracture initiation in components other than line pipe have been clarified.

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2007 Revision The comprehensive revision of AS 2885.1 is the result of extensive work by subcommittee ME-038-1 in response to a request from the industry that it consider increasing the design factor from 0.72 to 0.80. This request prompted a detailed review of each section and each clause of the Standard, resulting in the preparation of some 70 ‘issue papers’ that considered the underlying technical issues (in relation to an increased design factor) and recommended changes to the Standard. These issue papers were debated within the subcommittee and published on the Industry web site to allow consideration by the Industry. The results of these deliberations form the basis of this revision. The revision also reflects the results of a significant and ongoing industry funded research program undertaken by the Australian Pipeline Industry Association and its research contractors, and through its association with the Pipeline Research Council International and the European Pipeline Research Group. This revision provides a basis for Industry to benefit through the application of an increased factor for pressure design (for new pipelines) and a structured basis for increasing the MAOP of a qualifying existing pipeline. These benefits are supported by robust requirements for safety, structural design, construction, testing and record keeping. Significant changes in this revision include the following: (a)

A restructure of the sections of the document to separate pipeline general, pipeline, stations, and instrumentation and control.

(b)

The incorporation of a section defining the minimum requirements for a pipeline whose maximum allowable operating pressure is proposed to be raised.

(c)

Section 2 (Safety) has been rewritten, to reflect experience gained in the seven years since it was revised to provide a mandatory requirement for risk assessment. This revision provides more explicit guidance on the obligation to undertake safety assessments with the integrity required for compliance with this Standard. Material is provided in normative and informative appendices.

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(d)

Section 3 (Materials and components) has been revised to better address the treatment of materials used in pipelines. It includes a requirement to de-rate the specified minimum yield stress of pipe designed for operation at temperatures of 65°C and higher. The use of fibreglass and corrosion resistant alloy pipe materials for pipelines constructed to this Standard is permitted and limited in this Section. A minimum toughness requirement for pipe DN 100 and larger has been introduced.

(e)

Section 4 (Pipeline general) contains most of the material in the ‘Pipeline general’ section of the 1997 revision. The Section has been expanded to include the following: (i)

A mandatory requirement for the design of a pipeline for the existing and intended land use.

(ii)

A revision of the requirements for effective pipeline marking including a change to require the marker sign to comply with a ‘danger sign’ in accordance with AS 1319, Safety signs for the occupational environment.

(iii) A plan for isolation of a pipeline. (iv)

Special requirements for pipelines constructed in locations where the consequence of failure by rupture is not acceptable. Provisions for compliance with these requirements for pipelines constructed to this edition, or to an earlier revision, of the Standard, in land where the location classification has changed to residential (or equal) is included.

(v)

The location classification definitions are revised and additional sub-classes are defined.

(vi)

The hydrostatic strength test pressure is redefined to address the situation where the pipe wall thickness exceeds the pressure design thickness, including corrosion allowance.

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(vii) Provisions for low temperature excursions. (viii) Calculation methods for critical defect length, energy release rate and radiation contour. (f)

The requirements for fracture control have been extensively revised to clarify the requirements and to reflect experience gained since 1997. Emphasis is placed on the use of the Battelle Two Curve model given the fact that most gas pipelines in Australia transport ‘rich’ gas.

(g)

Section 5 (Pipeline design) has been revised to incorporate those provisions specific to pipeline in the 1997 revision. Significant changes to this Section include the following: (i)

The pipe wall thickness is required to be the greater of the pressure design thickness, and the thickness required for each other identified load condition. The thickness terms used in this Standard are clarified.

(ii)

An equation for calculating the thickness required for external pressure is provided.

(iii) Recognizing the result of a comprehensive investigation, of its purpose and the impact of change, the design factor has been changed from 0.72 to 0.80, and the design factor for pipeline assemblies and pipelines on bridges has been changed from 0.60 to 0.67. (iv)

Requirements for stress and strain have been completely redrafted to clarify the requirements. The limits for each stress condition are tabulated and normative and informative appendices are provided incorporating the relevant equations. Reliability and limit state design methods are permitted for pipeline design and integrity analysis, using approved methods.

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(v)

The requirements for a ‘prequalified’ design are included in a new clause. This is permitted for short pipelines DN 200 and smaller with a MAOP of 10.2 MPa or less.

(vi)

The provisions for reduced cover for a pipeline constructed through ‘rock’ have been revised.

(vii) The method for calculating reinforcement AS 2885.1—1987 has been reinstated in full.

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AS 2885.1—2012

of

branch

connections

in

(h)

Section 6 (Station design) incorporates the provisions of Clause 4.4 of the 1997 revision in relation to stations. The Section has been expanded to require the Design Basis for stations to be documented. Additional guidance is provided on treatment of lightning, together with some clarifying revisions to the text.

(i)

Section 7 (Instrumentation and control design) incorporates the requirements of Clause 4.2 of the 1997 revision. The requirements for pipeline operation under transient conditions and a tolerance specification for pressure controls on pipelines intended to be operated at MAOP are addressed.

(j)

Section 8 (Corrosion mitigation) incorporates the requirements of Section 5 of the 1997 revision. The Section incorporates clarifying revisions.

(k)

Section 9 (Upgrade of MAOP) is a new Section that sets down the minimum process, including activities required, to demonstrate the fitness of a pipeline designed and operated at one pressure as suitable for approval for operation at a higher pressure. The Section establishes a structured methodology for demonstrating the pipeline fitness and, once approved, for commissioning the pipeline at the new pressure. The maximum pressure is limited to the hydrostatic strength test pressure divided by the equivalent test pressure factor.

(l)

Section 10 (Construction) incorporates Section 6 of the 1997 Standard. The requirements for construction survey are clarified, and a minimum accuracy for asconstructed survey is incorporated. Since padding and backfilling are two activities that impact on the pipeline integrity, this revision incorporates additional requirements for these activities reflecting outcomes from APIA research on backfilling.

(m)

Section 11 (Inspection and testing) has been revised to align it with the requirements of AS 2885.5. It specifies strength test endpoint requirements for pipelines with a pressure design factor of 0.80, and references APIA research and associated software designed to enable the analysis of the pipe in a proposed (and constructed) test section to be analysed to determine the presence and location of pipe that may be exposed to excessive strain at the intended strength test pressure.

(n)

Section 12 (Documentation). Obligations on the developer of a new pipeline to document the design and construction, and to transfer this information to the pipeline operator, are clarified and expanded.

(o)

Each appendix in the 1997 revision of the Standard has been critically reviewed and revised, as appropriate. New appendices are provided reflecting the findings of APIA research, clarification of concepts in the Standard, and providing detailed calculation methods.

(p)

Resistance to penetration calculation methods and design requirements provided.

In addition to the items identified above, there are a great many changes of lesser significance incorporated in the document to the extent that users should consider it as a familiar but new Standard.

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An informative Appendix, which provides guidance on the design, construction and testing of fibreglass pipelines, is included. The terms ‘normative’ and ‘informative’ have been used in this Standard to define the application of the appendix to which they apply. A ‘normative’ appendix is an integral part of a Standard, whereas an ‘informative’ appendix is only for information and guidance.

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Statements expressed in mandatory terms in notes to tables and figures are deemed to be requirements of the Standard.

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AS 2885.1—2012

CONTENTS Page SECTION 1 SCOPE AND GENERAL 1.1 SCOPE ....................................................................................................................... 11 1.2 APPROVAL .............................................................................................................. 11 1.3 APPLICATION ......................................................................................................... 11 1.4 RETROSPECTIVE APPLICATION ......................................................................... 12 1.5 REFERENCED DOCUMENTS ................................................................................. 12 1.6 DEFINITIONS........................................................................................................... 12 1.7 SYMBOLS AND UNITS ........................................................................................... 17 1.8 ABBREVIATIONS ................................................................................................... 19

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SECTION 2 SAFETY 2.1 BASIS OF SECTION ................................................................................................ 21 2.2 ADMINISTRATIVE REQUIREMENTS ................................................................... 22 2.3 SAFETY MANAGEMENT PROCESS ..................................................................... 23 2.4 STATIONS, PIPELINE FACILITIES AND PIPELINE CONTROL SYSTEMS....... 28 2.5 ENVIRONMENTAL MANAGEMENT .................................................................... 29 2.6 ELECTRICAL ........................................................................................................... 29 2.7 CONSTRUCTION AND COMMISSIONING ........................................................... 30 SECTION 3 MATERIALS AND COMPONENTS 3.1 BASIS OF SECTION ................................................................................................ 32 3.2 QUALIFICATION OF MATERIALS AND COMPONENTS ................................... 32 3.3 REQUIREMENTS FOR COMPONENTS TO BE WELDED.................................... 35 3.4 ADDITIONAL MECHANICAL PROPERTY REQUIREMENTS ............................ 36 3.5 REQUIREMENTS FOR TEMPERATURE-AFFECTED ITEMS.............................. 37 3.6 MATERIALS TRACEABILITY AND RECORDS ................................................... 38 3.7 RECORDS ................................................................................................................. 38 SECTION 4 DESIGN—GENERAL 4.1 BASIS OF SECTION ................................................................................................ 39 4.2 ROUTE ...................................................................................................................... 40 4.3 CLASSIFICATION OF LOCATIONS ...................................................................... 42 4.4 PIPELINE MARKING .............................................................................................. 44 4.5 SYSTEM DESIGN .................................................................................................... 47 4.6 ISOLATION .............................................................................................................. 51 4.7 SPECIAL PROVISIONS FOR HIGH CONSEQUENCE AREAS ............................. 53 4.8 FRACTURE CONTROL ........................................................................................... 55 4.9 LOW TEMPERATURE EXCURSIONS ................................................................... 63 4.10 ENERGY DISCHARGE RATE ................................................................................. 64 4.11 RESISTANCE TO PENETRATION ......................................................................... 65 SECTION 5 PIPELINE DESIGN 5.1 BASIS OF SECTION ................................................................................................ 67 5.2 DESIGN PRESSURE ................................................................................................ 67 5.3 DESIGN TEMPERATURES ..................................................................................... 68 5.4 WALL THICKNESS ................................................................................................. 68 5.5 EXTERNAL INTERFERENCE PROTECTION........................................................ 72 5.6 PREQUALIFIED PIPELINE DESIGN ...................................................................... 79 5.7 STRESS AND STRAIN............................................................................................. 81

AS 2885.1—2012

5.8 5.9 5.10 5.11 5.12

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SPECIAL CONSTRUCTION .................................................................................... 86 PIPELINES ASSEMBLIES ....................................................................................... 95 JOINTING ................................................................................................................. 97 SUPPORTS AND ANCHORS ................................................................................... 98 HYDROSTATIC TESTING DESIGN ..................................................................... 100

SECTION 6 STATION DESIGN 6.1 BASIS OF SECTION .............................................................................................. 106 6.2 DESIGN .................................................................................................................. 106 6.3 STATION PIPEWORK ........................................................................................... 110 6.4 STATION EQUIPMENT ......................................................................................... 111 6.5 STRUCTURES ........................................................................................................ 112

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SECTION 7 INSTRUMENTATION AND CONTROL DESIGN 7.1 BASIS OF SECTION .............................................................................................. 115 7.2 CONTROL AND MANAGEMENT OF PIPELINE SYSTEM ................................ 115 7.3 FLUID PROPERTY LIMITS................................................................................... 117 7.4 SCADA—SUPERVISORY CONTROL AND DATA ACQUISITIONS SYSTEM ................................................................................................................. 118 7.5 COMMUNICATION ............................................................................................... 118 7.6 CONTROL FACILITIES ......................................................................................... 118 SECTION 8 MITIGATION OF CORROSION 8.1 BASIS OF SECTION .............................................................................................. 119 8.2 PERSONNEL .......................................................................................................... 119 8.3 RATE OF DEGRADATION ................................................................................... 119 8.4 CORROSION MITIGATION METHODS .............................................................. 120 8.5 CORROSION ALLOWANCE ................................................................................. 121 8.6 CORROSION MONITORING ................................................................................ 121 8.7 INTERNAL CORROSION MITIGATION METHODS .......................................... 122 8.8 EXTERNAL CORROSION MITIGATION METHODS ......................................... 123 8.9 EXTERNAL ANTI-CORROSION COATING ........................................................ 126 8.10 INTERNAL LINING ............................................................................................... 127 SECTION 9 UPGRADE OF MAOP 9.1 BASIS OF SECTION .............................................................................................. 128 9.2 MAOP UPGRADE PROCESS ................................................................................ 128 SECTION 10 CONSTRUCTION 10.1 BASIS OF SECTION ............................................................................................. 133 10.2 SURVEY ................................................................................................................. 133 10.3 HANDLING OF PIPE AND COMPONENTS ......................................................... 134 10.4 INSPECTION OF PIPE AND COMPONENTS....................................................... 135 10.5 CHANGES IN DIRECTION ................................................................................... 136 10.6 COLD-FIELD BENDS ............................................................................................ 137 10.7 FLANGED JOINTS ................................................................................................. 138 10.8 WELDED JOINTS .................................................................................................. 138 10.9 COVERING SLABS, BOX CULVERTS, CASINGS AND TUNNELS .................. 139 10.10 SYSTEM CONTROLS ............................................................................................ 139 10.11 ATTACHMENT OF ELECTRICAL CONDUCTORS ............................................ 139 10.12 LOCATION ............................................................................................................. 140 10.13 CLEARING AND GRADING ................................................................................. 140 10.14 TRENCH CONSTRUCTION .................................................................................. 141 10.15 INSTALLATION OF A PIPE IN A TRENCH ........................................................ 141 10.16 PLOUGHING-IN AND DIRECTIONALLY DRILLED PIPELINES...................... 143

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AS 2885.1—2012

10.17 SUBMERGED CROSSINGS .................................................................................. 143 10.18 REINSTATEMENT ................................................................................................. 143 10.19 TESTING OF COATING INTEGRITY OF BURIED PIPELINES ......................... 144 10.20 CLEANING AND GAUGING PIPELINES ............................................................ 144 10.21 ELECTRICAL EQUIPMENT INSTALLED IN HAZARDOUS AREAS ................ 144 SECTION 11 INSPECTIONS AND TESTING 11.1 BASIS OF SECTION .............................................................................................. 145 11.2 INSPECTION AND TEST PLAN AND PROCEDURES ........................................ 145 11.3 PERSONNEL .......................................................................................................... 145 11.4 PRESSURE TESTING ............................................................................................ 145 11.5 COMMENCEMENT OF PATROLLING ................................................................ 148

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SECTION 12 COMMISSIONING 12.1 BASIS OF SECTION .............................................................................................. 149 12.2 GENERAL ............................................................................................................... 149 12.3 PLANNING ............................................................................................................. 149 12.4 DESIGN AND CONSTRUCTION RECORDS ....................................................... 151 12.5 SAFETY MANAGEMENT STUDY REVIEW ....................................................... 151 12.6 TRAINING .............................................................................................................. 151 12.7 SAFETY TAG SYSTEM ......................................................................................... 151 12.8 PRE-COMMISISONING ......................................................................................... 152 12.9 COMMISSIONING AND TESTING....................................................................... 153 12.10 PERFORMANCE TEST .......................................................................................... 157 12.11 HANDOVER ........................................................................................................... 157 12.12 DELAYED COMMENCEMENT OF OPERATION ............................................... 158 SECTION 13 DOCUMENTATION 13.1 GENERAL ............................................................................................................... 159 13.2 RECORDS ............................................................................................................... 159 13.3 RETENTION OF RECORDS .................................................................................. 160 APPENDICES A REFERENCED DOCUMENTS ............................................................................... 161 B SAFETY MANAGEMENT PROCESS ................................................................... 167 C THREAT IDENTIFICATION ................................................................................. 173 D DESIGN CONSIDERATIONS FOR EXTERNAL INTERFERENCE PROTECTION......................................................................................................... 177 E EFFECTIVENESS OF PROCEDURAL CONTROLS FOR THE PREVENTION OF EXTERNAL INTERFERENCE DAMAGE TO PIPELINES ............................. 180 F QUALITATIVE RISK ASSESSMENT ................................................................... 187 G ALARP .................................................................................................................... 191 H INTEGRITY OF THE SAFETY MANAGEMENT PROCESS ............................... 193 I ENVIRONMENTAL MANAGEMENT .................................................................. 201 J PREFERRED METHOD FOR TENSILE TESTING OF WELDED LINE PIPE DURING MANUFACTURE ................................................................................... 203 K FRACTURE TOUGHNESS TEST METHODS....................................................... 204 L FRACTURE CONTROL PLAN FOR STEEL PIPELINES ..................................... 206 M CALCULATION OF RESISTANCE TO PENETRATION ..................................... 215 N FATIGUE ................................................................................................................ 220 O FACTORS AFFECTING CORROSION.................................................................. 223 P ENVIRONMENT-RELATED CRACKING ............................................................ 226 Q INFORMATION FOR CATHODIC PROTECTION ............................................... 233 R MITIGATION OF EFFECTS FROM HIGH VOLTAGE ELECTRICAL POWERLINES ........................................................................................................ 235

AS 2885.1—2012

S T U V W X Y Z AA

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BB

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PROCEDURE QUALIFICATION FOR COLD FIELD BENDS ............................. 244 GUIDELINES FOR THE TENSIONING OF BOLTS IN THE FLANGED JOINTS OF PIPING SYSTEMS ........................................................... 249 STRESS TYPES AND DEFINITIONS.................................................................... 264 EXTERNAL LOADS .............................................................................................. 271 COMBINED EQUIVALENT STRESS.................................................................... 275 PIPE STRESS ANALYSIS ...................................................................................... 285 RADIATION CONTOUR ....................................................................................... 290 REINFORCEMENT OF WELDED BRANCH CONNECTIONS ........................... 295 FIBREGLASS PIPE—MANUFACTURE, DESIGN AND CONSTRUCTION CONSIDERATIONS ............................................................................................... 301 GUIDELINES FOR PIPELINES FOR THE TRANSPORT OF CO2 .................................... 313

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AS 2885.1—2012

STANDARDS AUSTRALIA Australian Standard Pipelines—Gas and liquid petroleum Part 1: Design and construction

S E C T I O N

1

S C O P E

A N D

G E N E R A L

1.1 SCOPE This Standard specifies requirements for design and construction of carbon and carbonmanganese steel pipelines and associated piping and components that are used to transmit single-phase and multi phase hydrocarbon fluids, such as natural and manufactured gas, liquefied petroleum gas, natural gasoline, crude oil, natural gas liquids and liquid petroleum products. The principles are expressed in practical rules and guidelines for use by competent persons. AS 2885.0 sets out the fundamental principles on which AS 2885 based. These fundamental principles and the practical rules and AS 2885.1, AS 2885.2, AS 2885.3 and AS 2885.5 are the basis on assessment is to be made where these Standards do not provide appropriate to a specific item.

series of Standards is guidelines set out in which an engineering detailed requirements

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NOTE: AS 2885.4 for offshore submarine pipeline systems is a standalone document.

1.2 APPROVAL Each document prepared for a pipeline in accordance with this Standard shall be approved as required by AS 2885.0. Documents nominated in this Standard as requiring approval shall be approved by the Licensee and not delegated. All other documents shall be approved in accordance with the Licensee’s approval matrix. 1.3 APPLICATION Where this Standard imposes requirements, which add to or override the requirements of a nominated Standard or code, the additional requirements, that are explicitly stated in this Standard shall be met. Where approved, this Standard may also be used for design and construction of pipelines made with corrosion-resistant alloy steels, fibreglass and other composite materials. Where this Standard is used for pipelines fabricated from these materials, appropriate requirements shall be established to replace the provisions of this Standard in relation to nominated Standards for materials (Section 3), fracture control (Clause 4.8), stress and strain (Clause 5.7) and corrosion (Section 8) and the provisions of AS 2885.2 in relation to welding and non-destructive examination. For composite material, appropriate requirements shall be established to replace the hydrostatic strength test endpoint provisions of AS 2885.5. As provided in AS 2885.0, where approved, this Standard may be used for the design and construction of pipelines to transport fluids that are predominantly CO 2 and for other fluids including slurries. Where this Standard is applied to fluids other than gas and liquid petroleum, a gap analysis shall be conducted to identify the differences between the www.standards.org.au

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proposed fluid and those of gas and liquid petroleum, and appropriate requirements shall be established to address those differences. NOTE: Appendix BB provides guidance for the design of CO 2 pipelines using this Standard.

1.4 RETROSPECTIVE APPLICATION Retrospectivity is governed by AS 2885.0. This revision (AS 2885.1—2012) does not introduce additional changes that are intended to apply retrospectively. AS 2885.1—2007 introduced changes that reflect matters of public safety in high consequence areas and which are intended to apply retrospectively. Each existing pipeline shall be assessed against the requirements of Clauses 4.7.2 and 4.7.3. Where the existing pipeline does not comply with either Clause, mitigation shall be applied in accordance with Clause 4.7.4 regardless of whether or not there has been a land use change. 1.5 REFERENCED DOCUMENTS The documents referred to in this Standard are listed in Appendix A. 1.6 DEFINITIONS For the purpose of this Standard, the definitions given in AS 1929, AS 2812, AS 2832.1 and those below, apply.

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1.6.1 Accessory A component of a pipeline other than a pipe, valve or fitting, but including a relief device, pressure-containing item, hanger, support and every other item necessary to make the pipeline operable, whether or not such items are specified by the Standard. 1.6.2 Approved and approval Approved by the Licensee or the Licensee’s delegate, and includes obtaining the approval of the relevant regulatory authority where this is legally required. Approval requires a conscious act and is given in writing. NOTE: See AS 2885.0 for more information on approval and approved.

1.6.3 As low as reasonably practicable (ALARP) ALARP means the cost of further risk reduction measures is grossly disproportionate to the benefit gained from the reduced risk that would result. NOTE: Guidance on demonstration of ALARP and grossly disproportionate is given in Appendix G.

1.6.4 Buckle An irregularity in the surface of a pipe caused by a compressive stress. 1.6.5 Casing A conduit through which a pipeline passes, to protect the pipeline from excessive external loads or to facilitate the installation or removal of that section of the pipeline. 1.6.6 Collapse A permanent cross-sectional change to the shape of a pipe (normally caused by instability, resulting from combinations of bending, axial loads and external pressure).

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AS 2885.1—2012

1.6.7 Commissioning The process of verifying the operational and safety functions of a pipeline and the introduction of the process fluid prior to handover for operation. 1.6.8 Common threats Threats that occur at similar locations along the pipeline and which can therefore be treated by a standard design solution for that location type (e.g. road crossings). 1.6.9 Competent person A person who has acquired through training, qualification, and experience, or a combination of these, the knowledge and skills that enable the person to safely and effectively perform the task required. 1.6.10 Component Any part of a pipeline other than the pipe. 1.6.11 Construction Activities required to fabricate, construct and test a pipeline, and to restore the right of way of a pipeline. 1.6.12 Control piping Ancillary piping used to interconnect control or instrument devices or testing or proving equipment. 1.6.13 Critical defect length

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The length of a through wall axial flaw that, if exceeded, will grow rapidly and result in pipeline rupture. When the defect is smaller than this length, the pipeline will leak. A critical defect length also exists for part through wall flaws. 1.6.14 Defect A discontinuity or imperfection of sufficient magnitude to warrant rejection on the basis of the requirements of this Standard. 1.6.15 Dent A depression in the surface of the pipe, caused by mechanical damage, that produces a visible irregularity in the curvature of the pipe wall without reducing the wall thickness (as opposed to a scratch or gouge, which reduces the pipe wall thickness). 1.6.16 Failure The occurrence of one or more of the following conditions: (a)

Any loss of containment.

(b)

Supply is restricted.

(c)

MAOP is reduced.

(d)

Immediate repair is required in order to maintain safe operation.

NOTE: It is emphasized that failure is not restricted to loss of containment.

1.6.17 Fitting A component, including the associated flanges, bolts and gaskets used to join pipes, to change the direction or diameter of a pipeline, to provide a branch, or to terminate a pipeline. 1.6.18 Fluid Any liquid, vapour, gas or mixture of any of these. www.standards.org.au

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1.6.19 Gas Any hydrocarbon gas or mixture of gases, possibly in combination with liquid petroleum, condensates or water. 1.6.20 Heat Material produced from a single batch of steel processed in the final steel-making furnace at the steel plant. 1.6.21 High consequence area A location where pipeline failure can be expected to result in multiple fatalities or significant environmental damage. 1.6.22 High vapour pressure liquid (HVPL) A liquid or dense phase fluid that releases significant quantities of vapour when its pressure is reduced from pipeline pressure to atmospheric (e.g. LP gas). 1.6.23 Hoop stress Circumferential stress in a pipe or cylindrical pressure-containing component arising from internal pressure. 1.6.24 Hot tap A connection made to an operating pipeline. 1.6.25 Inspector A person appointed by the Licensee to carry out inspections required by this Standard. 1.6.26 Leak test

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A pressure test that determines whether a pipeline is free from leaks. 1.6.27 Licensee The organization responsible for the design, construction, testing, inspection, operation and maintenance of pipelines and facilities within the scope of this Standard. The Licensee is generally the organization named in the pipeline licence issued by the Regulatory Authority. 1.6.28 Location class The classification of an area according to its general geographic and demographic characteristics, reflecting both the threats to the pipeline from the land usage and the consequences for the population should the pipeline suffer a loss of containment. 1.6.29 Manufacturer’s data report (MDR) A document that consolidates all materials, testing, fabrication and installation data to comply with traceability requirements of this Standard. 1.6.30 May Indicates the existence of an option (see also ‘shall’ and ‘should’). 1.6.31 Mechanical interference-fit joint A joint for pipe, involving a controlled plastic deformation and subsequent or concurrent mating of pipe ends. 1.6.32 Nominated Standard A Standard referred to in Clause 3.2.2.

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1.6.33 Non-credible threat A threat for which the frequency of occurrence is so low that it does not exist for any practical purpose at that location. NOTE: The credibility or otherwise of a threat is a characteristic of the threat itself and is assessed independently of any protective measures that may be applied to mitigate it. A noncredible threat is not the same as a credible threat that has been controlled.

1.6.34 Non-location specific threat Threats that can occur anywhere along the pipeline (e.g. corrosion). 1.6.35 Petroleum Any hydrocarbon or mixture of hydrocarbons in a gaseous or liquid state and which may contain hydrogen sulfide, nitrogen, helium and carbon dioxide. 1.6.36 Pig (pipeline inspection gauge) A device inserted in a pipeline for operation or inspection, and transported through it by the flow of the product in the pipeline. 1.6.37 Pig trap (scraper trap) A pipeline assembly to enable a pig to be inserted into or removed from an operating pipeline. 1.6.38 Pipeline design engineer The person responsible for the design of the pipeline. 1.6.39 Pipework, mainline Those parts of a pipeline between stations, including pipeline assemblies.

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1.6.40 Pipework, station Those parts of a pipeline within a station that begin and end where the pipe material specification changes to or from the mainline pipework. 1.6.41 Piping An assembly of pipes, valves and fittings associated with a pipeline. 1.6.42 Pretest (also known as ‘Pretested’) A pressure test of pipe, pipeline assembly or a component that is undertaken separately from the pipeline and is not retested after installation (e.g. spare pipe, isolation valve assemblies.) 1.6.43 Preliminary test A test that is undertaken on pipe that will be subsequently exposed to the strength test pressure of the mainline pipe. NOTE: The purpose of the test is to eliminate the risk of failure of the pipe during the strength test.

1.6.44 Pressure, design The pressure nominated in the Design Basis for the purpose of performing calculations on the mechanical and process design of the pipeline. 1.6.45 Pressure, maximum allowable operating (MAOP) The maximum pressure at which a pipeline or section of a pipeline may be operated, following hydrostatic testing in accordance with this Standard or after an MAOP review performed in accordance with AS 2885.3.

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1.6.46 Pressure, maximum operating (MOP) The operating pressure limit (lower than the MAOP) imposed by the Licensee from time to time for pipeline safety or process reasons. 1.6.47 Pressure strength The maximum pressure measured at the point of highest elevation in a test section. NOTE: Pressure strength for a pipeline or a section of a pipeline is the minimum of the strength test pressures of the test sections comprising the pipeline or the section of the pipeline.

1.6.48 Propagating fracture A fracture that is not arrested within the length of pipe in which the fracture initiated. 1.6.49 Proprietary item An item made or marketed by a company having the legal right to manufacture and sell it. 1.6.50 Protection measures, procedural Measures for protection of a pipeline that minimize the likelihood of human activities with potential to damage the pipeline. 1.6.51 Protection measures, physical Measures for protection of a pipeline that prevent external interference from causing failure, either by physically preventing contact with the pipe or by providing adequate resistance to penetration in the pipe itself. 1.6.52 Regulatory authority An authority with legislative powers relating to petroleum pipelines covered by the scope of this Standard. Accessed by Fyfe Pty Ltd on 18 Oct 2012 (Document currency not guaranteed when printed)

1.6.53 Rupture Failure of the pipe such that the cylinder has opened to a size equivalent to its diameter. 1.6.54 Safety management study or process The process that identifies threats to the pipeline system and applies controls to them, and (if necessary) undertakes assessment and treatment of any risks to ensure that residual risk is reduced to an acceptable level. 1.6.55 Shall Indicates that a requirement is mandatory (see also ‘may’ and ‘should’). 1.6.56 Should Indicates a recommendation (see also ‘may’ and ‘shall’). 1.6.57 Sour service Piping normally conveying crude oil or natural gas containing hydrogen sulfide together with an aqueous liquid phase in a concentration that may affect materials. 1.6.58 Specified minimum yield stress (SMYS) The minimum yield stress for a pipe material that is specified in the manufacturing standard with which the pipe or fittings used in the pipeline complies. 1.6.59 Strength test That part of the pressure test procedure that establishes the pressure strength of the test section.

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1.6.60 Supervising test engineer The person responsible for the detailed planning, execution and assessment of the test. 1.6.61 Telescoped pipeline A pipeline that is made up of more than one diameter or MAOP, tested as a single unit. 1.6.62 Threat Any activity or condition that can adversely affect the pipeline if not adequately controlled. 1.6.63 Wall thickness, design pressure (tP ) The wall thickness of pipe required to contain the design pressure, based on steel grade and design factor. 1.6.64 Wall thickness, required (tW) The greatest of the wall thicknesses required to meet the various design requirements nominated in Clause 5.4.2. 1.6.65 Wall thickness, nominal(tN) The wall thickness nominated for pipe manufacture or certified on supplied pipe. 1.7 SYMBOLS AND UNITS

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NOTES: 1 Unless otherwise noted, pressure and calculations involving pressure are based on gauge pressures. 2 Symbols defined and used in appendices are not listed in this table.

Symbol

Description

Unit

AC

Fracture area of the Charpy V-notch specimen

mm 2

CDL

Critical defect length

mm

CVN

Upper shelf Charpy V-notch energy (Full size equivalent)

c

Half of the length of an axial through wall flaw

mm

D

Nominal outside diameter = Pipe diameter = Pipeline diameter

mm

Dm

Average diameter

mm

D max

Greatest diameter

mm

D min

Smallest diameter

mm

d

Branch diameter

mm

dW

Depth of part through wall flaw

mm

E

Young’s modulus

MPa

FD

Design factor for pressure containment

FBucket

Force exerted at a bucket, correlated against excavator mass

kN

FMAX

Maximum force exerted at bucket (most severe geometry)

kN

FP

Pressure factor for bends

FTP

Test pressure factor

FTPE

Equivalent test pressure factor

fo

Ovality factor

G

Sum of allowances

mm

H

Manufacturing tolerance

mm

L

Length of tooth at tip

mm

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J

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Symbol

Description

KC

In plane stress intensification factor (fracture initiation toughness) MPa/mm 0.5

MT

Folias factor

PC

Collapse pressure

MPa

PD

Design pressure

MPa

PEXT

External pressure

MPa

PL

Pressure limit

MPa

PM

Measured pressure from hydrostatic test

MPa

PTMAX

Maximum strength test pressure

MPa

PTMIN

Minimum strength test pressure

MPa

R

Bend radius to the centreline of the pipe

mm

rM

Mean pipe radius

mm

Rp

Puncture resistance

kN

RLi

Number of runs of np pipe, each run having a length i

SDEV

Standard deviation of toughness in all heat population

SEFF

Effective stress (consistent with API RP 1102)

SF

Statistical factor

SFG

Stress limit for girth weld fatigue (consistent with API RP 1102)

MPa

SFL

Stress limit for longitudinal weld fatigue (consistent with API RP 1102)

MPa

Td t

Design minimum temperature for brittle fracture control Wall thickness

°C mm

tP

Wall thickness internal pressure design

mm

tN

Wall thickness—Nominal

mm

tW

Wall thickness—Required

mm

W

Width of tooth at tip

mm

WOP

Operating weight

tonne

ΔSH

Stress for longitudinal welds (consistent with API RP 1102)

MPa

ΔSL

Stress for girth welds (consistent with API RP 1102)

MPa

σ σc

Stress

MPa

Combined equivalent stress

MPa

σE

Expansion stress

MPa

σflow

Flow stress = SMYS + 10 ksi for fracture control

MPa

σH

Hoop stress

MPa

σL

Longitudinal stress

MPa

σO

Occasional stress

MPa

σSUS

Sustained stress

MPa

σU

Ultimate tensile strength

MPa

σW

Bending stress

MPa

σY

Specified minimum yield strength (SMYS)

MPa

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Unit

MPa

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AS 2885.1—2012

Symbol

Description

Unit

σYA

Lowest yield strength estimated statistically from the population of yield strength

MPa

ν

Poisson’s ratio (stress and strain)

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1.8 ABBREVIATIONS Abbreviations

Meaning

AFV

Allowable fluid variation

ALARP

As low as reasonably practicable

AS

Australian Standard

CDL

Critical defect length

CHAZOP

Control hazard and operability

CRA

Corrosion-resistant alloy

CW

Continuously welded

DN

Nominal diameter

DWTT

Drop weight tear test

EIP

External interference protection

EIS

Environmental impact statement

EMP

Environmental Management Plan

EPRG

European Pipeline Research Group

ERW

Electric resistance welded

FRP

Fibre-reinforced plastic

GIS

Geographic information system

HAZ

Heat-affected zone

HAZAN

Hazard analysis study

HAZOP

Hazard and operability study

HAZID

Hazard identification study

HVPL

High vapour pressure liquid

JSA

Job safety analysis

LPG

Liquefied petroleum gas

MAOP

Maximum allowable operating pressure

MDR

Manufacturer’s data report

MLV

Main line valve

MOP

Maximum operating pressure

O&M

Operation and maintenance

P&ID

Piping and instrumentation diagram

PDR

Public draft

PRCI

Pipeline research council international

QC

Quality control

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Unit L/24 h

MPa

MPa

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Submerged arc welded

SCADA

Supervisory control and data acquisition

SCC

Stress corrosion cracking

SIL

Safety integrity level

SLV

Station limit valve

SMYS

Specified minimum yield strength

MPa

SMTS

Specified minimum tensile strength

MPa

XS

Extra strong

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SAW

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S E C T I O N

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AS 2885.1—2012

S A F E T Y

2.1 BASIS OF SECTION Pipeline safety management shall be undertaken rigorously, shall apply controls to identified threats and shall reduce residual risk to an acceptable level through a safety management study, and a risk assessment of threats that are not controlled. All threats to the integrity of the pipeline shall be identified and multiple independent controls shall be applied to each identified threat. This Standard recognizes the hierarchy of effectiveness of controls: (a)

Elimination.

(b)

Physical controls.

(c)

Procedural controls.

(d)

Reduction.

(e)

Mitigation.

Mandatory requirements are specified for control of external interference threats (which are known to be the most frequent events with the potential to create a failure). Mandatory requirements are specified in high consequence areas for— (i)

elimination of rupture; and

(ii)

maximum energy release rate.

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Where land use changes from a low consequence area to a high consequence area, this Standard applies mandatory requirements for maintaining the risk at an acceptable level. The safety management study shall include stations, pipeline facilities and control systems. The process safety of stations, pipeline facilities and control systems shall also be reviewed by HAZOP and, as appropriate, by other recognised safety study methods. The safety management process involves two stages: (A)

Design and Safety Review in accordance with this Standard.

(B)

Assessment of residual risks in accordance with AS/NZS ISO 31000.

The Licensee shall ensure that pipeline safety management activities are carried out by suitably qualified, trained and experienced personnel. The safety management process and its outcomes shall be documented and approved. Pipeline safety management shall be an ongoing process over the life of the pipeline. Safety controls require continuous management so that they remain effective. The outcomes of the safety management study shall be incorporated in the pipeline management system. This Standard includes requirements for management of construction safety, electrical safety and environmental impacts.

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2.2 ADMINISTRATIVE REQUIREMENTS 2.2.1 Documentation 2.2.1.1 General All aspects of the safety management process shall be documented with sufficient detail for independent or future users of the safety management study to make an informed assessment of the integrity of the process and its outcomes, including the identification of threats and the reasoning behind the assessment of the effectiveness of the control measures applied. For new pipelines, or modifications to existing pipelines, the detailed design and the safety management study are undertaken as integrated iterative processes. The output of these processes is a design (generally shown on alignment sheets), and a safety management study document (generally recorded on a database). 2.2.1.2 Pipeline management system Where threat control requires actions by the Licensee, the obligations of the Licensee shall be documented in the pipeline management system. The pipeline management system shall identify these actions including the implementation of specific risk management actions as an integral part of pipeline safety management. NOTES: 1 Because the pipeline management system is prepared after the design phase safety management study, the safety management documentation should clearly summarize the obligations of the pipeline Licensee that arise in order to facilitate transfer of these requirements to the pipeline management system. 2 The detailed requirements for the incorporation of the safety management study are provided in AS 2885.3. Accessed by Fyfe Pty Ltd on 18 Oct 2012 (Document currency not guaranteed when printed)

2.2.2 Implementation All actions arising from the safety management study shall be implemented and the implementation documented. Where ongoing action is required, a reporting mechanism to demonstrate action shall be established, implemented and audited. Safety management documentation shall be transferred from the design and construct phase of the project to the operating phase of the project in a form that enables safety management to be undertaken from the time that operation commences. For new pipelines, all actions that are considered necessary for the safe pressurization of the pipeline shall be completed prior to the commencement of commissioning. For existing pipelines the period for the implementation of each action shall be identified as part of the safety management documentation. The schedule for implementation shall be approved. 2.2.3 Safety management study validation Each detailed safety management study shall be validated by a properly constituted workshop, which shall critically review each aspect of the safety management study. The information requirements listed in Paragraph B3, Appendix B, shall be considered in the validation workshop. NOTE: Guidance on assessment of the integrity of the safety management process is provided in Appendix H.

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2.2.4 Operational review A safety management study shall be conducted as a result of any of the following triggers: (a)

At intervals not exceeding five years.

(b)

At any review for changed operating conditions.

(c)

At any review for extension of design life.

(d)

As may be required by AS 2885.3.

(e)

At any other time that new or changed threats occur.

(f)

At any time when there is a change in the state of knowledge affecting the safety of the pipeline.

Where a trigger point relates to a part of the pipeline (for example a change at a specific location or a specific safety aspect), the safety management study may be restricted to only that part which is changed. An assessment of the implementation and effectiveness of all threat controls shall be made at each operational review. 2.3 SAFETY MANAGEMENT PROCESS 2.3.1 General

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The pipeline safety management process consists of the following: (a)

Threat identification.

(b)

Application of physical, procedural and design measures to identified threats.

(c)

Review and control of failure threats.

(d)

Assessment of residual risk from failure threats.

Figure 2.3.1 illustrates the pipeline safety management process. This section describes its detail and application.

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T h r e at i d e nti f i c ati o n

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Pr e li m i n a r y d e s c r i pti o n of d e s i g n a n d o p e r a ti o n

C o m m o n th r e a t s / c o m m o n th r e a t l o c a ti o n / standard design

Lo c atio n a n a l ys i s N o n l o c a ti o n s p e c i f i c th r e a t s

T h r e at i d e nti f i c ati o n

I s t h r e a t c r e di b l e?

No

Ye s

Threat control

A p p l y ex te r n a l i n te r fe r e n c e p r ote c ti o n (w h e r e a p p l i c a b l e)

Apply design & procedures

A p p l y f u r th e r d e s i g n & /o r p r o c e d u r e s

Fa i l u r e p o s s i b l e?

No

Ye s

Ca n f u r th e r t h r e a t c o n t r o l s b e a p p l i e d?

Ye s

R e s i d u a l r i s k a s s e s s m e nt

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No

AS / NZS I SO 310 0 0 R e s i d u a l th r e at s r i s k a s s e s s m e nt No

R i s k a c c e pt a b l e

Ye s

Fi n a l d e s i g n a n d pipeline management sys te m R i s k & d e s i g n a c c e pte d

FIGURE 2.3.1 PIPELINE SAFETY MANAGEMENT PROCESS

2.3.2 Threats 2.3.2.1 General The underlying principle of threat identification is that a threat exists at a location. Threats exist— (a)

at a specific location (e.g. excavation threat at a particular road crossing);

(b)

at specific sections of a pipeline (e.g. farming; forestry; fault currents for sections with parallel power lines); or

(c)

over the entire length of the pipeline (e.g. corrosion).

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AS 2885.1—2012

The same safety management process applies to both location-specific and non-locationspecific threats. NOTE: Non-location-specific threats are often qualitatively different to location-specific threats (e.g. corrosion, versus external interference threats at a road crossing).

2.3.2.2 Location analysis The pipeline route shall be analysed to divide it into safety management sections where the land use and population density are consistent. A safety management section shall not contain more than one location class. NOTE: Use of safety management sections facilitates the analysis of threats that apply over whole sections of the route (e.g. farming, forestry, urban development, etc.).

2.3.2.3 Threat identification

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Threat identification shall be undertaken for the full length of the pipeline, including stations and pipeline facilities. The threats to be considered shall include, at least— (a)

external interference,

(b)

corrosion,

(c)

natural events,

(d)

electrical effects,

(e)

operations and maintenance activities,

(f)

construction defects,

(g)

design defects,

(h)

material defects,

(i)

intentional damage, and

(j)

other threats such as seismic and blasting. NOTE: Guidance on threats is given in Appendix C.

The threat identification shall consider all threats with the potential to damage the pipeline, cause of interruption to service, cause of release of fluid from the pipeline, or cause harm to pipeline operators, the public or the environment. NOTE: Typical data sources used to conduct the threat identification include alignment survey data to determine basic geographical information; land user surveys in which land liaison officers gather information from land users on the specific activities carried out on the land, and obtain any other local knowledge; third-party spatial information (GIS type data) on earthquakes, drainage, water tables, soil stability, near-surface geology, environmental constraints, etc., and land planning information.

The threat identification shall generate sufficient information about each threat to allow external interference protection and engineering design to take place. For each identified threat, at least the following information shall be recorded: (i)

What is the threat to the pipeline?

(ii)

Where does it occur? (the location of the threat)

(iii) Who (or what) is responsible for the activity? (iv)

What is done? (e.g. depth of excavation)

(v)

When is it done? (e.g. frequency of the activity, time of the year)

(vi)

What equipment is used? (if applicable, e.g. power of plant, characteristics of the excavator teeth, etc.).

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2.3.2.4 Threats to typical designs The pipeline design process involves the development and application of typical designs to locations where there is a common range of design conditions and identified threats. Threats common to typical designs shall be documented. Each typical design shall be subjected to the safety management process in accordance with this Standard to demonstrate that the design provides effective control for the identified threats. 2.3.2.5 Other threats at typical design locations Each location at which a typical design is applied shall be assessed to determine whether threats other than the threats common to that design exist at that location. Where other threats are identified, effective controls shall be applied to each of these additional location specific threats. 2.3.2.6 Non-credible threats Each threat identified as being non-credible shall be documented. The reason for it being declared non-credible shall also be documented. The validity of this decision shall be considered at each review of safety management study. Non-credible threats do not require controls. 2.3.3 Controls 2.3.3.1 General Effective controls for each credible threat shall be identified and applied using a systematic process. Physical and procedural controls shall be applied to all credible external interference threats. Accessed by Fyfe Pty Ltd on 18 Oct 2012 (Document currency not guaranteed when printed)

NOTE: Guidance on the criteria for effectiveness of procedural controls is given in Appendix E.

Design and/or procedures shall be applied to other threats. Control is achieved by the application of multiple independent protective measures in accordance with this Standard. Controls are considered effective when failure as a result of that threat has been removed for all practical purposes at that location. Where controls are determined to be not effective for a particular threat, that threat shall be subject to failure analysis. 2.3.3.2 Control by external interference protection The pipeline shall be protected from external interference by a combination of physical and procedural controls at the location of each identified threat. All reasonably practicable controls should be applied. External interference protection shall be designed in accordance with Clause 5.5. The physical controls applied shall be demonstrated to protect the pipeline from the specified threat. The procedural controls shall be demonstrated to be effective in contributing to reducing the frequency of the occurrence of that threat. Where the minimum requirements of Clause 5.5 cannot be satisfied, other design and/or procedures shall be applied. NOTE: Re-routing is an example of a design change decision that may be taken here if external interference protection is not sufficient.

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2.3.3.3 Control by design and/or procedures Design and/or procedures shall be applied to threats other than external interference threats in accordance with this Standard: (a)

Materials shall be specified, qualified and inspected in accordance with Section 3.

(b)

Pipeline design shall be carried out in accordance with Section 4 and Section 5.

(c)

Protection against stress and strain shall be designed in accordance with Clause 5.7.

(d)

Operational controls shall be designed in accordance with Section 7.

(e)

Corrosion and erosion protection for the full length of the pipeline shall be designed in accordance with Section 8. Guidance on design for environment related cracking is provided in Appendix P.

(f)

Protection against construction related defects shall be in accordance with Section 10.

(g)

Induced voltage, lightning and fault current protection for sections of the pipeline affected by these conditions shall be designed in accordance with AS 4853. NOTE: Further guidance on design for a.c. electrical hazards is provided in Appendix R.

2.3.4 Failure analysis 2.3.4.1 General Where controls may not prevent failure for a particular threat, the threat shall be analysed to determine the damage that it may cause to the pipeline. Where the outcome is failure, the analysis shall determine the mode of failure and if applicable, the energy release rate at the point of failure, as inputs to the consequence analysis.

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NOTE: Modes of failure include rupture as a running crack in brittle fracture mode, rupture as a ductile tear, hole, pinhole, crack, dent, and gouge, loss of wall thickness.

The analysis may conclude there is no immediate or delayed failure. Appropriate management actions may be required to minimize non-failure consequences. 2.3.4.2 Treatment of failure threats Where a failure event is identified additional controls to prevent failure shall be investigated and applied where practicable. Any remaining failure events shall be subject to risk assessment in accordance with AS/NZS ISO 31000. 2.3.4.3 Documentation The failure analysis for the specific threat shall document the following (as applicable): (a)

The pipeline design features.

(b)

The threat.

(c)

The mode of failure.

(d)

The physical dimensions of the failure.

(e)

The location of the failure.

(f)

The nature of the escaping fluid.

(g)

The energy release rate and the contour radius for a radiation intensity of 12.6 and 4.7 kW/m2.

(h)

Environmental effects at the location (e.g. wind).

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For fluids with potential to cause environmental damage, the volume release and other factors related to the spread of the fluid in the environment (e.g. oil and drainage systems). NOTE: Some of this information may be addressed in a generic manner for a given set of pipeline parameters, and does not necessarily have to be documented against every threat analysed.

2.3.5 Risk assessment Risk assessment of failures shall be undertaken in accordance with AS/NZS ISO 31000. Appendix F provides the requirements for qualitative risk assessment and it provides a risk matrix to be used in an AS/NZS ISO 31000 qualitative risk assessment. There are circumstances where risk estimation using quantitative methods is required to enable comparison of alternative mitigation measures as a basis for demonstration of ALARP, and in some jurisdictions, to satisfy planning criteria. 2.3.6 Demonstration of fault tolerance To demonstrate the fault tolerance of the pipeline design, a situation where failure of threat control measures leads to pipe damage or loss of containment shall be considered as a threat. The residual risk of such threats shall be assessed and treated in accordance with Appendix F.

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NOTES: 1 Almost all pipeline incidents occur as a result of failure of control measures. Hence failure of threat controls is itself an important threat. The control failure threat(s) should be at a location where the consequences are most severe. It may be appropriate to address failures of different threat controls (e.g. external interference, corrosion) or different locations. 2 It is recommended that such threats are identified toward the end of the safety management review by which time sufficient knowledge of the threats and controls will have been developed to identify locations where fault tolerance is an essential part of the design.

2.4 STATIONS, PIPELINE FACILITIES AND PIPELINE CONTROL SYSTEMS 2.4.1 General Stations and pipeline facilities involve processes that control or change the operating conditions of the fluid being transported. Such facilities are above-ground and contain operable components. Consequently, the threats and failure outcomes are normally different than those for a pipeline. 2.4.2 Safety assessments The safety of facilities shall be assessed by the application of one or more of a number of recognized safety study methodologies. The most appropriate methodologies shall be used for each facility. As a minimum— (a)

a hazard and operability (HAZOP) study shall be made to determine the process safety of each facility; and

(b)

non-process threats shall be reviewed in accordance with the safety management process in this Standard.

NOTE: Other methodologies that should be considered include CHAZOP, SIL and numerical risk assessment.

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AS 2885.1—2012

2.5 ENVIRONMENTAL MANAGEMENT This Standard requires the threats to the environment from each part of the life cycle of the pipeline to be identified and control measures implemented so that risks to the environment are reduced to an acceptable level. Preference shall be given to ensuring environmental threats are managed by avoidance (route selection) and, where necessary, specific construction techniques. The requirements of this Standard complement the requirements of regulatory authorities in assessment and management of environmental risk, and are intended to be used during planning construction and operational phases of a pipeline to ensure that— (a)

environmental management effort is concentrated on significant threats;

(b)

environmental management methods are assessed holistically for their contribution to minimizing the impact to the environment; and

(c)

there is a basis for assessing alternative construction and management methods to minimize the impact of the environment

Effective environmental impact assessment requires gathering basic environmental data and shall include consultation with key stakeholders at an early stage so that all relevant information required for all subsequent planning is available. An environmental impact assessment shall be conducted in accordance with this Standard along the length of the pipeline route. The environmental impact assessment report shall form the basis of the environmental management plan.

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An analysis of the impacts of construction techniques and design at sensitive locations shall be included in the environmental impact assessment. Threat of damage to the environment from operational maintenance and abandonment activities shall be identified and control measures developed. The environmental management plan shall include procedures for protecting the environment from constructions, operation maintenance and abandonment activities. The environmental management plan shall address emergency situations. NOTE: The APIA Code of Environmental Practice provides industry accepted guidance on management of the Environment through the Design, construction and Operational phase of a project.

The following data shall be obtained prior to conducting the environmental safety assessment: (i)

Basic environmental data (including cultural heritage and archaeological data).

(ii)

Stakeholder survey information.

(iii) Constructability/and safety constraints. (iv)

Emergency response capabilities.

(v)

Legislative requirements.

NOTE: For guidance on the environmental management process, see Appendix I.

2.6 ELECTRICAL A pipeline can be subject to significant voltages that can be hazardous to the pipeline itself, or to personnel who may come in contact with it. High voltages can arise due to a variety of causes, such as earth potential rise in the vicinity of electrical earthing under fault conditions or due to voltages induced on the pipeline when faults occur on nearby parallel powerlines. A pipeline in the vicinity of electricity supply powerlines or facilities shall be analysed to determine if controls are required to provide for electrical safety. NOTE: General guidance on electrical safety is given in Appendix R. www.standards.org.au

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2.7 CONSTRUCTION AND COMMISSIONING 2.7.1 Construction safety Construction of pipelines shall be carried out in a safe manner. The safety of the public, construction personnel, adjacent property, equipment and the pipeline shall be maintained and not compromised. A construction safety plan shall be prepared, reviewed by appropriate personnel, and approved. This review shall take the form of a construction safety plan workshop. Specific construction safety requirements exist in each regulatory jurisdiction. The more stringent of the regulatory requirements and the requirements of this Section shall apply. NOTES: 1 Review by appropriate personnel should include designers, construction personnel, OH&S personnel, environmentalists and/or the approval authority. 2 The construction safety plan detail should be consistent with the nature of the work being undertaken. It may be a component of an integrated construction safety system, a construction safety case (where the regulatory jurisdiction requires this), or a project or activity specific safety plan.

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At least the following shall be addressed: (a)

Fire protection shall be provided and local bushfire and other fire regulations shall be observed.

(b)

Where the public could be exposed to danger or where construction operations are such that there is the possibility that the pipeline could be damaged by vehicles or other mobile equipment, suitable physical and/or procedures measures shall be implemented.

(c)

Where a power line is in close proximity to the route safe working practice shall be established.

(d)

Where a pipeline is in close proximity to a power line, potential threats from induced voltage and induced or fault currents to personnel safety shall be assessed and appropriate measures taken to mitigate dangers to personnel and equipment. NOTE: For guidance on measures that may be implemented, see Appendix R.

(e)

Adequate danger and warning signs shall be installed in the vicinity of construction operations, to warn persons of dangers (including those from mobile equipment, radiographic process and the presence of excavations, overhead powerlines and overhead telephone lines).

(f)

Unattended excavations in locations accessible to the public shall be suitably barricaded or fenced off and, where appropriate, traffic hazard warning lamps shall be operated during the hours of darkness.

(g)

During the construction of submerged pipelines, suitable warnings shall be given. Signs and buoys shall be appropriately located to advise the public of any danger and to minimize any risk of damage to shipping. Where warnings to shipping are required by an authority controlling the waterway, the authority’s requirements for warnings should be ascertained and the authority advised of all movements of construction equipment.

(h)

Provision of adequate measures to protect the public from hazards caused by welding.

(i)

Procedure to be followed for lifting pipes both from stockpile and into trench after welding.

(j)

Procedure for safe use and handling of chemicals and solvents.

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(k)

Frequency and provision of safety talks (tool box meetings).

(l)

Accident reporting and investigation procedure.

(m)

Appointment of safety supervisor and specification of duties.

(n)

Travel associated with attending the worksite.

(o)

Statutory obligations.

(p)

Traffic management plan.

AS 2885.1—2012

NOTE: APIA document Onshore Pipeline Projects, Construction Safety Guidelines provides guidance on construction safety for the Australian Pipeline Industry.

2.7.2 Testing safety The construction safety plan shall address safety through all phases of testing of the pipeline during construction. 2.7.3 Commissioning safety

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The commissioning plan shall consider the safety of the activities undertaken through all phases of commissioning and, where required, develop specific procedures to manage the safety during commissioning of the pipeline.

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3

M A T E R I A L S

A N D

C O M P O N E N T S

3.1 BASIS OF SECTION Materials and components shall be fit for purpose for the conditions under which they are used, including construction. They shall have the pressure strength, ductility, fracture toughness, weldability, temperature rating, and design life specified by the engineering design. The engineering design shall take into account the effect of all of the manufacturing and construction processes and service conditions on the properties of the materials. 3.2 QUALIFICATION OF MATERIALS AND COMPONENTS 3.2.1 General Materials and components shall comply with one or more of the relevant requirements of this Clause. They shall be supplied with test certificates containing sufficient data to demonstrate compliance with this Standard, the engineering design, the relevant nominated Standard(s), and any supplementary specifications. Where materials and components do not comply with nominated standards and have been qualified in accordance with this Clause, documentary evidence of that qualification shall be provided and approved.

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3.2.2 Materials and components complying with nominated Standards Where allowed by the engineering design, materials and components complying with one of the following nominated Standards may be used for appropriate applications as specified and as limited by this Standard without further qualification. Except as provided in Clause 3.4.3, they shall be used in accordance with the pressure/temperature rating contained in those Standards: NOTES: 1 Nominated Standards for materials and components, especially line pipe specifications API Spec 5L and ISO 3183, contain multiple options that need to be specified by the purchaser, and for this reason, as well as the very common specification of supplementary requirements by pipeline designers, compliance with a nominated Standard will be necessary but insufficient. 2 A particular example where compliance with a nominated line pipe Standard will be insufficient for Australian pipelines arises from the fact that API Spec 5L and ISO 3183 do not require drop weight tear testing below DN 500, whereas AS 2885.1 requires control of brittle fracture by DWTT down to DN 300, and by alternative methods for smaller diameters. 3 Multiple examples have occurred in recent years of pipeline projects where materials certified as complying with nominated Standards was found in audit and/or pressure testing not to comply, and so care should be exercised by line pipe purchasers to ensure that appropriate levels of inspection and quality assurance are implemented (see e.g. USA DOT PHMSA Advisory Bulletin ADB-09-01).

(a)

Pipe—Carbon/carbon manganese steel pipe. API Spec 5L, ISO 3183, ASTM A106, ASTM A333, ASTM A671. NOTES: 1 ASTM A106 specifies pipe for high temperature service and has no specific requirements for Charpy toughness. It is usually unsuitable for use in pipelines, stations and pipeline assemblies unless toughness properties are specified, and specific tests are made to confirm compliance.

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The other listed permissible ASTM pipe grades are primarily intended for facility applications. They are available in multiple grades and conditions. Care has to be taken to ensure the selected grade and condition are fit for the intended pipeline service conditions.

Minimum additional requirements for pipes complying with any of these Standards consist of the following: (i)

Pipe for use in accordance with this Standard shall not have an SMYS greater than 555 MPa (X80).

(ii)

The integrity of each pipe length shall be demonstrated by both longitudinal seam NDT and hydrostatic testing as part of the manufacturing process.

(iii) Wall thickness tolerance—where the design factor exceeds 0.72— (A)

the minimum weight tolerance in API Spec 5L shall be adhered to, irrespective of the Standard to which the pipe is purchased.

(B)

the level of eccentricity permitted in seamless pipe shall be established, and the resulting minimum allowable wall thickness shall be adopted in design calculations (see Clause 5.4.7); and

(C)

the minimum permissible wall thickness after grind repair or internal trim for pipe manufactured by ERW or laser methods, shall be 90% of required wall thickness for material with an SMYS up to 485 MPa (X70) and 92% for material with an SMYS up to 550 MPa (X80).

(b)

Corrosion-resistant alloys—API Spec 5LC and API Spec 5LD.

(c)

Fibreglass pipe—API Spec 15LR, API Spec 15HR or ISO 14692-1 and ISO 14692-2.

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NOTE: Where this Standard is used for pipelines constructed with corrosion-resistant alloy or fibreglass pipe, attention is drawn to the requirements of Clause 3.1.

(d)

Fittings, and components—ASME B16.9, ASME BPVC Section VIII, BS 5500, AS/NZS 1200 ASME B16.11, ASME B16.25, ASME B16.28, ASTM A105, ASTM A234, ASTM A350, ASTM A420, BS 1640.3, BS 1640.4, BS 3799, MSS SP-75, MSS SP-97.

(e)

Pipeline assemblies—Elements of a pipeline assembled from pipe complying with a nominated Standard and pressure-rated components complying with a nominated Standard or of an established design and used within the manufacturer’s pressure and temperature rating.

(f)

Station piping—AS 4041, ASME B31.3.

(g)

Induction bends—ISO 15590-1, ASME B16.49.

(h)

Valves—ASME B16.34, API Spec 6D, API Std 600, ASTM A350, BS 5351, MSS SP-25, MSS SP-67.

(i)

Flanges—ASME B16.5, ASME B16.21, ANSI B16.47, MSS SP-6, MSS SP-44.

(j)

Gaskets—ASME B16.21, BS 3381.

(k)

Bolting—AS 2528, ANSI B18.2.1, ASME B16.5, ASTM A193, ASTM A307, ASTM A320, ASTM A325, ASTM A354, ASTM A449.

(l)

Pressure gauges—AS 1349.

(m)

Welding consumables—AS 2885.2.

(n)

Anti-corrosion coatings—AS/NZS 2312, AS 3862, AS 1518, CSA Z245.21 system B tri-laminate.

(o)

Galvanic anodes—AS 2239.

www.standards.org.au

API Std 602,

API Std 603,

ASTM A194,

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3.2.3 Materials and components complying with Standards not nominated in this Standard Materials and components complying with Standards that are not nominated in Clause 3.2.2 may be used subject to qualification. The materials or components shall be approved. Qualification may be achieved by one of the following means: (a)

Compliance with an approved Standard that does not vary materially from a Standard listed in this Section with respect to quality of materials and workmanship. This Clause shall not be construed as permitting deviations that would tend to adversely affect the properties of the material. The design shall take into account any deviations that can reduce strength.

(b)

Tests and investigations to demonstrate their safety, provided that this Standard does not specifically prohibit their use. Pressure-containing components that are not covered by nominated Standards or not covered by design equations or procedures in this Standard may be used, provided the design of similarly shaped, proportioned and sized components has been proved satisfactory by successful performance under comparable service conditions. Interpolation may be made between similarly shaped proven components with small differences in size or proportion. In the absence of such service experience, the design shall be based on an analysis consistent with the general philosophy embodied in this Standard and substantiated by one of the following: (i)

Proof tests as described in AS 1210, or an equivalent international Standard.

(ii)

Experimental stress analysis.

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(iii) Theoretical calculations. (iv)

Function testing (supplementary).

The results of tests and findings of investigations shall be recorded. 3.2.4 Components, other than pipe, for which no standard exists Components, other than pipe, for which no standards exist, may be qualified by investigation, tests or both, to demonstrate that the component is suitable and safe for the proposed service, provided the component is recommended for that service from the standpoint of safety by the manufacturer. 3.2.5 Reclaimed pipe Reclaimed pipe may be used, provided that— (a)

the pipe was manufactured to a nominated Standard;

(b)

the history of the pipe is known;

(c)

the pipe is suitable for the proposed service in light of its history;

(d)

an inspection is carried out to reveal any defects that could impair strength or pressure tightness;

(e)

a review and, where necessary, an inspection is carried out to determine that all welds comply with the requirements of this Standard; and

(f)

defects are repaired or removed in accordance with this Standard.

Provided that full consideration is given in the design to the effects of any adverse conditions under which the pipe had previously been used, the reclaimed pipe may be treated as new pipe to the same Standard only after it has passed a hydrostatic test (see Clauses 3.2.10 and 11.4). © Standards Australia

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3.2.6 Reclaimed accessories, valves and fittings Reclaimed accessories, valves and fittings may be used, provided that— (a)

The component was manufactured to a nominated Standard;

(b)

The history of the component is known;

(c)

The component is suitable for the proposed service in light of its history;

(d)

An inspection is carried out to reveal any defects that could impair its use; and

(e)

Where necessary, an inspection is carried out to determine that the welds comply with the requirements of this Standard.

Components shall be cleaned, examined and where required reconditioned and tested, to ensure that they comply with this Standard. Provided any adverse conditions under which the component had been used will not affect the performance of the component under the operating conditions that are to be expected in the pipeline, the component may be treated as a new component to the same Standard, but shall be hydrostatically tested (see Clauses 3.2.10 and 11.4). 3.2.7 Identification of components Components that comply with nominated Standards that are produced in quantity, carried in stock and wholly formed by casting, forging, rolling or die-forming, (e.g. fittings, flanges, bolting) are not required to be fully identified or to have test certificates unless otherwise specified. However, each such component shall be marked with the name or mark of the manufacturer and the markings specified in the Standard to which the component was manufactured. Components having such marks shall be considered to comply with the Standard indicated.

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3.2.8 Material and components not fully identified Where an identity with a nominated Standard is in doubt, any material or component may be used, provided it is approved and has the chemical composition mechanical properties and integrity tests specified in the nominated Standard. 3.2.9 Unidentified materials and components Materials, pipes and components that cannot be identified with a nominated Standard or a manufacturer’s test certificate may be used for parts not subject to stress due to pressure (e.g. supporting lugs), provided the item is suitable for the purpose. 3.2.10 Hydrostatic test Reclaimed pipe and components, the strength of which may have been reduced by corrosion or other form of deterioration, or pipe or components manufactured to a Standard which does not specify hydrostatic test during manufacture, shall be tested hydrostatically either individually in a test complying with an appropriate nominated Standard or as part of the pipeline to the test pressure specified for the pipeline. 3.3 REQUIREMENTS FOR COMPONENTS TO BE WELDED 3.3.1 Welding of prequalified materials Except where otherwise indicated herein, where welding is specified by Standards nominated in this Section, that welding shall be acceptable without further qualification. NOTE: AS 2885.2 states that that Standard is not intended to be applied to welds made during the manufacture of a pipe or a component.

3.3.2 Materials specifications NOTE: AS 2885.2 provides information on factors that affect weldability and should be considered when specifying components. www.standards.org.au

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3.4 ADDITIONAL MECHANICAL PROPERTY REQUIREMENTS 3.4.1 Yield strength The yield strength (σY) used in equations in this Standard shall be the SMYS specified in the Standard with which the pipe or component complies. NOTE: The preferred method for determining the tensile properties of line pipe complying with API Spec 5L is given in Appendix J.

3.4.2 Pipe yield to tensile ratio For cold expanded pipe the API Spec 5L yield to tensile strength ratio requirement of 0.93 maximum shall be met using either the ring expansion test or the round bar test, irrespective of the Standard to which it is manufactured. Subject to approval, this requirement may be demonstrated by correlation between one of those tests and the results of flattened bar tests. This correlation shall be established using the actual material concerned. 3.4.3 Strength de-rating

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Carbon steel and carbon manganese steel flanges and valves complying with nominated Standards may be used without derating at design temperatures not exceeding 120°C. NOTES: 1 Reference ASME B31.3, ASME VIII, and MSS SP44 – At temperatures up to 120°C flange designs are based on (a constant) ultimate tensile strength resulting in no strength derating requirement. 2 The temperature limit for flanged valves applies only to the flanges. Assurance should be sought from the valve manufacturer that the valve body and seals are suitable for the required service conditions. 3 The adoption of a higher design temperature for flanges requires that the pipeline and the piping each satisfy the stress limits required by the design standard. 4 This permission does not currently apply to vessels designed in accordance with AS 1210 (e.g. filter vessels). In these cases, a design check in accordance with AS 1210 or ASME Boiler and Pressure Vessel Code (BPVC), Section VIII, should be considered.

Where the pipeline design temperature is above 65°C the yield strength of the pipe steel shall be de-rated. The reduction in yield strength shall be 0.07%/°C by which the design temperature exceeds 23°C. NOTE: The use of 65°C as a boundary below which no de-rating needs to be applied covers common gas pipeline compressor discharge temperatures. This exemption results in a step change in de-rating above 65°C.

3.4.4 Fracture toughness 3.4.4.1 Fracture toughness of station pipe and accessories For stations (see Figure 4.1), fracture toughness of station pipe shall comply with the requirements of the piping design Standard at the station pipe design minimum temperature. NOTE: See Clause 6.3 for more information on station pipework.

3.4.4.2 Fracture toughness of pipeline For pipelines (see Figure 4.1), a fracture control plan shall be prepared in accordance with Clause 4.8 except when— (a)

the pipeline diameter is less than DN 100 and the thickness is less than 6.1 mm and the design pressure is less than 10.5 MPa; or

(b)

the pipeline carries a stable liquid where the minimum design pipe temperature is above 0°C.

NOTE: 6.1 mm thickness is adopted on the basis that a 5 mm specimen is the smallest relevant size for Charpy testing. The thickness margin is required to allow the test specimen to be machined from the pipe wall. © Standards Australia

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AS 2885.1—2012

For pipe requiring a fracture control plan, minimum Charpy energy shall be demonstrated. Fracture control plan requirements shall not specify Charpy energy requirements lower than specified in this Clause, but may override the test temperature and specimen orientation. The following shall apply: (i)

The test temperature shall be 0°C or lower.

(ii)

The minimum specimen size shall be half size.

(iii) Transverse specimens shall be tested where geometry permits, or otherwise, longitudinal specimens. (iv)

The minimum toughness tested on a per heat basis (average of 3 specimens) shall be 27 J full size equivalent when measured using transverse specimens or 40 J using longitudinal specimens.

Test methods for fracture toughness shall be in accordance with Appendix K. 3.4.4.3 Fracture toughness of pipeline accessories For pipeline accessories, fracture initiation shall be controlled by specifying Charpy toughness in accordance with Clause 3.4.4.2, except where the design minimum temperature for the accessory is less than 0°C. When the design minimum temperature is less than 0°C, the Charpy toughness shall be determined for the design minimum temperature of the accessory in accordance with AS 4041 or ASME B31.3.

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Control of fast tearing fracture is not required. NOTES: 1 For the purpose of this Clause, pipeline accessories means induction bends, pipeline assemblies, and the interconnecting piping associated with the scraper, MLV or similar pipeline facilities. 2 The length of the assembly or interconnecting piping is short and the pipe usually contains valves and fittings that act as crack arresters. Consequently, there is no change in consequence whether fast tearing fracture in this pipe is arrested within the initiating pipe, or in a connecting pipe.

3.5 REQUIREMENTS FOR TEMPERATURE-AFFECTED ITEMS 3.5.1 General Properties of materials may be altered by exposure to non-ambient temperatures during manufacture and construction by processes such as hot bend manufacture, application of corrosion prevention coatings including joint coating, pre-weld and post-weld heat treatment, and where pipe coating is exposed to cryogenic temperatures. Exposure to above ambient temperatures during operation such as downstream of compressor stations or in hot oil, or gas gathering service may also affect material properties. The effect of these processes on the integrity of the pipeline shall be considered. 3.5.2 Items heated subsequent to manufacture Where pipe or components are heated as part of processes subsequent to manufacture, the effect of the heating on yield strength and fracture properties shall be established. Materials and components that are heated, or hot-worked at temperatures above 280°C, after completion of the manufacturing and testing processes, shall not be used without approval. In order for such approval to be obtained it shall be demonstrated that the materials and components satisfy the minimum strength and fracture toughness requirements for the pipeline design after the heat treatment or hot-work is performed.

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Where carbon manganese steel components are subject to temperatures above 100°C during coating, field weld heat treatment or similar processes, strain-ageing effects shall be considered. The mechanical property limits of the relevant material Standard (e.g. API Spec 5L) are not required to be achieved in the strain-aged condition. The effect of material processing on strength, ductility and fracture properties shall be determined by representative tests on samples subjected to simulated or actual heat treatment cycles and taken into consideration in the design, including the fracture control plan. Flattened strap test pieces shall not be used for yield strength determination. NOTE: Research on yield to tensile ratio and its causes and effects has been undertaken by APIA and recommendations adopted in this Standard. The reference is CRC-WS report 2003-328 ‘High Y/T and low strain to failure effects in coated high strength pipe’ M Law and G Bowie.

3.5.3 Pipe operated at elevated temperatures Where pipe is operated at elevated temperatures, the yield strength shall be de-rated in accordance with Clause 3.4.3. The effect of exposure to the design maximum temperature on the competing processes of increased strength due to strain ageing and loss of strength due to the elevated temperature shall be considered. Other mechanical properties including toughness need not be considered. 3.5.4 Pipe exposed to cryogenic temperatures Exposure of carbon manganese steel to cryogenic temperatures is deemed not to alter subsequent properties within the design temperature range. The effect of cryogenic temperatures on the pipeline coating shall be considered.

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3.6 MATERIALS TRACEABILITY AND RECORDS All pressure-containing materials installed on a pipeline system shall be traceable to the purchase documentation, the manufacturing Standard, the testing standard, and to inspection and acceptance documents. The pipeline Licensee shall maintain the records until the pipeline is abandoned or removed. Special traceability procedures shall be applied to materials whose markings are destroyed in processes following their manufacture (e.g. coated pipe). Consideration shall be given to the need in subsequent operation, maintenance and development of the pipeline for the materials to be identified spatially, by item (e.g. identification of each pipe by coordinate, and each component by mark to the as constructed drawing). Where such identification is applied, the requirement shall be documented and the quality procedure implemented shall be sufficient to ensure the accuracy of the data. Electronic records that can be accessed by common text, database or spreadsheet programs are preferred. Where documents are only available on paper, they should be scanned into an appropriate format. 3.7 RECORDS The identity of all materials shall be recorded and this identity shall include reference to the test certificates and/or inspection reports.

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AS 2885.1—2012

D E S I G N — G E N E R A L

4.1 BASIS OF SECTION Every pipeline shall be leak tight and have the necessary capability to safely withstand all reasonably predictable influences to which it may be exposed during the whole of its design life. A structured design process, appropriate to the requirements of the specific pipeline, shall be carried out to ensure that all safety, performance and operational requirements are met during the design life of the pipeline.

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The following aspects of pipeline design, construction and operation shall be considered in the design of a pipeline: (a)

Safety of pipeline and public is paramount.

(b)

Design is specific to the nominated fluid(s).

(c)

Route selection considers existing land use and allows for known future land planning requirements and the environment.

(d)

The fitness for purpose of pipeline and other associated equipment.

(e)

Engineering calculations for known load cases and probable conditions.

(f)

Stresses, strains, displacements and deflections have nominated limits.

(g)

Materials for pressure containment are required to meet standards and be traceable.

(h)

Fracture control plan to limit fast fracture is required.

(i)

Pressure positively controlled and limited.

(j)

Pipeline integrity is established before service by hydrostatic testing.

(k)

For gas pipelines, the likelihood, extent and consequences of the formation of condensates and hydrates in the pipeline is established and prevention or mitigation measures are put in place to ensure the safe operation and integrity of the pipeline.

(l)

Pipeline design includes provision for maintenance of the integrity by— (i)

external interference protection;

(ii)

corrosion mitigation;

(iii) integrity monitoring capability where applicable; and (iv)

operation and maintenance in accordance with defined plans.

(m)

Changes in the original design criteria which prompt a design review.

(n)

Design life defines the period for mandatory review, and calculation of time dependent parameters.

(o)

Contaminants such as dust, compressor oils and other liquids.

The design process shall be undertaken in parallel with and as an integrated part of the safety management process and shall reflect the obligation to provide protection for the pipeline, people, and the environment. Figure 4.1 describes the separation of a pipeline system into pipeline and stations.

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The break between pipeline and station shall be defined for each station. The break should preferably be at or adjacent to the first valve off the pipeline on the side of the valve remote from the pipeline. Other suitable location may be a flange, a weld or a point defined by dimensions. The requirements of Section 5 shall apply to the pipeline and to piping associated with pipeline assemblies and shall be met notwithstanding the use of any other Standard for design of elements of the pipeline. The requirements of Section 6 shall apply where an element of the pipeline has been designated as a station.

1

1 Booster station

Supply station

Receipt station Station Pipeline

Scraper launcher

Main line valve

Inline scraper facility

Scraper receiver 1

Branch connection

Pipeline Station

Offtake station

NOTE: The break between pipeline and station shall be defined for each station.

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FIGURE 4.1 PIPELINE SYSTEM SCHEMATIC

4.2 ROUTE 4.2.1 General The route of a pipeline shall be selected having regard to public safety, pipeline integrity, environmental impact, and the consequences of escape of fluid. A new pipeline shall be designed in accordance with the requirements of this Standard— (a)

for the land use existing at the time of design; and

(b)

for the future land use that can be reasonably determined by research of public records and consultation with land planning agencies in the jurisdiction through which the pipeline is proposed.

The land use for which the pipeline is designed shall be documented and approved. For an existing pipeline, changes in land use from those for which the pipeline was designed introduce an obligation for a safety management study of the pipeline and where required, the implementation of design and/or operational changes to comply with the safety obligations of the Standard. 4.2.2 Investigation A detailed investigation of the route and the environment in which the pipeline is to be constructed shall be made. The appropriate authorities shall be contacted to obtain details of any known or expected development or encroachment along the route, the location of underground obstructions, pipelines, services and structures and all other pertinent data.

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4.2.3 Route selection

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The route shall be carefully selected, giving particular attention to the following items: (a)

Pipeline integrity.

(b)

Fluid properties, particularly if HVPL.

(c)

The consequences of escape of fluid.

(d)

Public safety.

(e)

Proximity to populated areas.

(f)

Easement width.

(g)

Future access to pipelines and facilities (e.g. in a particular route option, the possibility of future developments by others limiting access to the pipeline).

(h)

Special concerns associated with the use of common infrastructure corridors

(i)

Proximity of existing cathodic protection groundbeds.

(j)

Proximity of sources of stray d.c. currents.

(k)

Proximity of other underground services.

(l)

Proximity of high voltage transmission lines.

(m)

Environmental impact.

(n)

Cultural heritage.

(o)

Present land use and any expected change to land use.

(p)

Prevailing winds.

(q)

Topography.

(r)

Geology.

(s)

Soil types (e.g. for effect of soil properties on corrosion and CP).

(t)

Possible inundation.

(u)

Constructability

(v)

Ground stability, including other land uses which may create instability (e.g. mine subsidence, land development/excavation)

NOTE: Environmental studies may be required by the relevant authority.

4.2.4 Route identification The pipeline route and the location of the pipeline in the route shall be identified and documented. The following shall be considered in developing an appropriate marking strategy for the pipeline: (a)

Identification for public information.

(b)

Identification for services information.

(c)

Identification for emergency services.

(d)

Identification on maps.

(e)

Identification on land titles.

(f)

Identification using visible markers generally complying with the marker illustrated in Figure 4.2, as aid to protection from external interference damage.

(g)

As built location of the pipeline relative to permanent external references.

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4.3 CLASSIFICATION OF LOCATIONS 4.3.1 General The pipeline route shall be allocated location classes that reflect threats to pipeline integrity, and risks to people, property and the environment. The primary location class shall reflect the population density. Where appropriate, one or more secondary location classes reflecting special land uses shall be allocated to locations along the route. For a new pipeline, the location class analysis shall be based on the land use permitted in gazetted land planning instruments. A detailed investigation shall also be undertaken to identify all reasonably anticipated changes in land use along the route. Where the limits of the anticipated land use change can reasonably be determined, the pipeline location classes shall be based on the anticipated land use. Location class analysis of an existing pipeline shall take full account of current land use and authorized developments along the pipeline route, but need not take full account of land use which is planned, but not implemented. NOTE: Consideration of population density includes both residents and others who spend prolonged periods in the vicinity of the pipeline as a result of their employment, recreation or any other reason.

4.3.2 Measurement length The measurement length is the radius of the 4.7 kW/m2 radiation contour for a full bore rupture, calculated in accordance with Clause 4.10. NOTE: For a pipeline transporting hydrocarbon liquid or heavier than air gases, the measurement distance may be variable. For these fluids the 4.7 kW/m 2 radiation contour may follow topographic features such as streams or drains, as the spilled fluid flows away under the influence of gravity and the variable topography.

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4.3.3 Location classification It is the intent of this Standard that the location class is selected from an analysis of the predominant land use in the broad area traversed by the pipeline. The following requirements shall be followed in determining the location class: (a)

Where land within the measurement length on either side of the pipeline is consistent with a more demanding location class than the predominant land use, the more demanding location class shall be applied.

(b)

Where a location class changes, the more severe location class shall extend into the less severe location class by at least the measurement length.

(c)

For a new pipeline, the area assessed in determining the location classification shall consider the general land use beyond the measurement length for the potential for changes in land use.

(d)

For an existing pipeline, the area assessed in determining the location classification as part of a periodic review of the pipeline may restrict the assessment to only land within the measurement length on each side of the pipeline.

NOTE: A GIS with quality aerial photography and themes showing the radiation contour for full bore rupture, cadastre, and land planning zones is a valuable tool in determining the location class.

4.3.4 Primary location class The pipeline route shall be classified into one of the primary location classes R1, R2, T1 and T2 as defined below.

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Land through which the pipeline passes shall be classified as follows: (a)

Rural (R1) Land that is unused, undeveloped or is used for rural activities such as grazing, agriculture and horticulture. Rural applies where the population is distributed in isolated dwellings. Rural includes areas of land with public infrastructure serving the rural use; roads, railways, canals, utility easements.

(b)

Rural Residential (R2) Land that is occupied by single residence blocks typically in the range 1 ha to 5 ha or is defined in a local land planning instrument as rural residential or its equivalent. Land used for other purposes but with similar population density shall be assigned rural residential location class. Rural residential includes areas of land with public infrastructure serving the rural residential use; roads, railways, canals, utility easements.

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NOTE: In rural residential societal risk (the risk of multiple fatalities associated with a loss of containment) is not a dominant design consideration.

(c)

Residential (T1) Land that is developed for community living. Residential applies where multiple dwellings exist in proximity to each other and dwellings are served by common public utilities. Residential includes areas of land with public infrastructure serving the residential use; roads, railways, recreational areas, camping grounds/caravan parks, suburban parks, small strip shopping centres. Residential land use may include isolated higher density areas provided they are not more than 10% of the land use. Land used for other purposes but with similar population density shall be assigned Residential location class.

(d)

High Density (T2) Land that is developed for high density community use. High Density applies where multi storey development predominates or where large numbers of people congregate in the normal use of the area. High density includes areas of public infrastructure serving the high density use; roads, railways, major sporting and cultural facilities and land use areas of major commercial developments; cities, town centres, shopping malls, hotels and motels. NOTE: In residential and high density areas the societal risk associated with loss of containment is a dominant consideration.

In rural and rural residential areas, consideration shall be given to whether a higher location class may be necessary at any location where a large number of people may be present for a limited period. NOTE: Examples include roads subject to heavy traffic congestion and sports fields.

4.3.5 Secondary location class Location classes S, CIC, I, HI and W are subclasses that may occur in any primary location class. The affected length is generally less than the length of the primary location class. Where the land use through which the pipeline route passes is identified as S, CIC, I, HI or W the requirements of the primary location class (R1, R2, T1, T2) shall be applied together with additional consideration and additional requirements established for the S, CIC, I or W location class, as follows: (a)

Sensitive use (S) The sensitive use location class identifies land where the consequences of a failure may be increased because it is developed for use by sectors of the community who may be unable to protect themselves from the consequences of a pipeline failure. Sensitive uses are defined in some jurisdictions, but include schools, hospitals, aged care facilities and prisons. Sensitive use location class shall be assigned to any portion of pipeline where there is a sensitive development within a measurement length. It shall also include locations of high environmental sensitivity to pipeline failure.

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The design requirements for high density shall apply. NOTE: In sensitive use areas, the societal risk associated with loss of containment is a dominant consideration.

(b)

Industrial (I) The Industrial location class identifies land that poses a different range of threats because it is developed for manufacturing, processing, maintenance, storage or similar activities or is defined in a local land planning instrument as intended for light or general industrial use. Industrial applies where development for factories, warehouses, retail sales of vehicles and plant predominates. Industrial includes areas of land with public infrastructure serving the industrial use. Industrial location class shall be assigned to any portion of pipeline where the immediately adjoining land use is industrial. The design requirements for residential shall apply. NOTE: In industrial use areas the dominant consideration may be the threats associated with the land use or the societal risk associated with the loss of containment.

(c)

Heavy industrial (HI) Sites developed or zoned for use by heavy industry or for toxic industrial use locations shall be considered classified as heavy industrial. They shall be assessed individually to assess whether the industry or the surroundings include features that— (i)

contain unusual threats to the pipeline; or

(ii)

contain features that may cause a pipeline failure to escalate either in terms of fire, or for the potential release of toxic or flammable materials into the environment.

Depending on the assessed severity the design, requirements of R2, T1 or T2 shall be applied.

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NOTE: In heavy industrial use areas the dominant consideration may be the threats associated with the land use or a range of location specific risks associated with the loss of containment.

(d)

Common infrastructure corridor (CIC) Land which because of its function results in multiple (more than one) parallel infrastructure development within a common easement or reserve, or in easements which are in close proximity. CIC classification includes pipelines within reserves or easements for roads, railways, powerlines, buried cables, or other pipelines. NOTE: In CIC areas the dominant consideration may be the threats associated with the land use by other infrastructure operators or the higher consequences of loss of containment associated with increased transient population (e.g. roads) or other parallel infrastructure.

(e)

Submerged (W) Land that is continuously or occasionally inundated with water to the extent that the inundation water, or activities associated with it, is considered a design condition affecting the design of the pipeline. Pipeline crossings of lakes, estuaries, harbours, marshes, flood plains and navigable waterways are always included. Pipeline crossings of non-navigable waterways, rivers, creeks, and streams, whether permanent or seasonal, are included where appropriate. The submerged class extends only to the estimated high water mark of the inundated area. NOTE: The submerged class refers only to onshore pipelines designed to this Part. Submarine or offshore pipelines are designed to AS 2885.4.

4.4 PIPELINE MARKING 4.4.1 General Signs shall be installed along the route so that the pipeline can be properly located and identified from the air, ground or both as appropriate to each particular situation.

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Signs should be located so that from any location along the pipe centreline, a sign is visible in either direction from the observer. In class locations T1, T2, S, CIC, I and HI signs shall be intervisible unless the site renders this impracticable. Table 4.4.1 provides guidance on sign spacing in each location classification. TABLE 4.4.1 SIGN SPACING Location class

Location subclass

Recommended maximum sign spacing, m

R1

500 (Note 1)

R2

250 (Note 1)

T1

100

T2

50 S

50

CIC

Note 2

I, HI

100

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NOTES: 1

In land subject to cropping or grazing where these activities mean that the recommended sign spacing is unacceptable to the landowner or cannot be maintained, an acceptable alternative is to place an appropriate sign at fence lines and at every gate giving access to each paddock where the spacing is greater than recommended.

2

In common infrastructure corridors the sign spacing shall be as required by the location class, except that where a pipeline is parallel to an overhead power line a sign shall be placed adjacent to each power pole or pylon.

4.4.2 Sign location Signs shall be placed at the following locations: (a)

Both sides of public roads.

(b)

Both sides of railways.

(c)

At each property boundary (and at internal fence lines as appropriate).

(d)

Both sides of rivers.

(e)

Vehicle tracks.

(f)

Each change of direction.

(g)

Utility crossings (buried or above-ground).

(h)

At the landfall of submerged crossings or submarine pipelines, which shall be legible from a distance of at least 100 m on the water side of the landfall.

(i)

At all pipeline facilities.

(j)

At locations where signs marking the location of the pipeline are considered to contribute to pipeline safety by properly identifying its location.

Where strict adherence to the requirements of this Clause is shown to provide no increase in safety, alternative spacing may be developed. Where a pipeline closely parallels a road, railway, powerline or other linear infrastructure consideration shall be given to sign spacing closer than that recommended in Table 4.4.1.

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A single sign is sufficient at sites where a number of the above locations coincide (e.g. utilities alongside a road, vehicle tracks). At ephemeral streams signs should be placed where required to locate the pipeline. Where signs are used to provide procedural protection, the spacing to provide effective protection shall be established in the external interference protection design in accordance with Clause 5.5. 4.4.3 Sign design Except as noted herein, marker signs shall comply with the requirements of a DANGER sign generally in accordance with AS 1319. Figure 4.4.3 illustrates a typical marker sign for cross-country pipeline. The sign dimensions and shape may be modified to suit the constraints of the location. Marker signs shall— (a)

indicate the approximate position of the pipeline, its description, the name of the operator, and a telephone number for contact for assistance and in emergencies;

(b)

indicate that excavating near the pipeline is hazardous; and

(c)

include a direction to contact the pipeline operator before beginning excavation near the pipeline.

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NOTE: For guidance on the effectiveness of procedural measures, including signs, in contributing to pipeline awareness, see Appendix E.

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350-450

150

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350-450

DIMENSIONS IN MILLIMETRES

NOTES: 1

For further information, see AS 1319.

2

The word OIL is to be used when the fluid is a liquid hydrocarbon or a mixture of liquid hydrocarbons.

3

The word GAS is to be used when the fluid is gas or a dual-phase mixture of gas and liquid.

4

The word LP GAS is to be used when the fluid is HVPL

FIGURE 4.4.3 TYPICAL PIPELINE MARKERS

4.5 SYSTEM DESIGN 4.5.1 Design basis The basis for design of the pipeline, for each station, and for each modification to the pipeline or station shall be documented in the design basis. The purpose of the design basis is to document both principles and philosophies that will be applied during the development of the detailed design, and specific design criteria that will be applied throughout the design. The design basis is usually an output of the planning and preliminary design phase of a project. The design basis shall be revised during the development of the project to record changes required to the design basis as a result of additional knowledge of the project requirements as the detailed design is developed. www.standards.org.au

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The design basis shall be revised at the completion of the project to reflect the as-built design. The design basis shall record, as a minimum, the following: (a)

A description of the project covered by the design basis.

(b)

Statutory legislation and industry codes and Standards applicable to the pipeline and facilities.

(c)

Specific physical criteria to be used in the design including at least: (i)

The design capacity of the pipeline and of each associated station, and where applicable the pressure and temperature conditions at which this applies, and including initial and final capacity where this is significant to the design.

(ii)

Design life of pipeline system and design lives of subsystems as applicable.

(iii) Design pressure(s), internal and external. (iv)

Design temperature(s).

(v)

Corrosion allowance, internal and external.

(vi)

Fluids to be carried.

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(vii) Where required, the maximum fluid property excursion and the duration of any excursion beyond which the fluid must be excluded from the pipeline. (d)

Materials.

(e)

The methods by which compliance with pressure strength, ductility, fracture toughness, weldability, temperature rating and design life specified by the engineering design for the materials will be demonstrated.

(f)

Minimum design and installation criteria for the pipeline and stations.

(g)

Design requirements for internal inspection tools, including bend radius, internal pipe diameter and scraper trap dimensions and design criteria.

(h)

Specific process and maintenance criteria to be used in the design including, as a minimum, the following: (i)

Operating and maintenance philosophy.

(ii)

The basis for fracture control design, including gas composition.

(iii) Performance requirements for pipeline depressurization, repressurization, and isolation valve bypass. (iv)

Pipeline pressure/flow regime established by commercial objectives for the pipeline system.

(v)

Isolation principles.

(vi)

Limiting conditions.

(vii) Corrosion mitigation strategy. (i)

Design principles established as the basis of detailed design.

(j)

Design philosophies established to guide development of the detailed design.

(k)

The location of facilities and their functionality.

(l)

Communications and control principles.

(m)

Inspection and testing principles.

(n)

System reliability principles.

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4.5.2 Maximum velocity The design shall establish the presence in the fluid of any contaminants that could reduce the pipe wall thickness during the pipeline design life through erosion or a synergistic erosion-corrosion mechanism (wear). Where erosion or erosion-corrosion mechanisms exist and where these mechanisms can be controlled by limiting the maximum velocity in the pipeline, the maximum velocity in the transmission pipeline and in the station piping shall be determined and documented in the design basis. NOTES: 1 Transmission pipelines (and the associated facilities) usually transport clean fluids that can be transported at any practical velocity without causing any reduction of wall thickness as a result of wear. 2 API RP 14E is one experience-based method of determining limiting velocity for control of erosion in piping systems containing solids and liquids. PD 8010.1 contains information that is more specific to clean fluid transmission pipelines. 3 Where synergistic erosion-corrosion mechanisms exist, specific designs should be developed. 4 The recommendations of API RP14E only apply to steel pipe. Where other materials are adopted the maximum velocity shall be established based on the material’s wear characteristics. 5 High velocities may promote corrosion from gases containing CO2.

4.5.3 Design life The design life for a pipeline shall be determined and documented. Design lives include the following:

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(a)

System design life A design life shall be nominated for the pipeline system, and shall be used for design. At the end of the system design life the pipeline shall be abandoned unless an engineering investigation determines that its continued operation is safe. The system design life shall be approved. NOTE: The system design life should be set at a value that is meaningful in terms of the ability of the designers to reasonably foresee the impact of time dependent parameters.

(b)

Engineering design lives For each metallic, non-metallic, electrical and electronic component (or sub-system) that may be expected to have a service life that is different from the System Design Life, an Engineering Design Life should be nominated, and applied when specifying each subsystem or component. The individual engineering design lives shall be considered when preparing operating and maintenance plans and safety management studies. Where a component supplier is unable to meet the engineering design life, the change shall be nominated in the project records, and the plans and procedures dependent on the life shall be reviewed. Non-replaceable components shall be designed for a similar life to that of the pipeline, since premature failure will impact on the continued operation of the pipeline.

NOTE: Normally replaceable components (e.g. seals and gaskets) that are required to have essentially an indefinite life if left in position and untouched should be selected from materials whose properties will not diminish during that service. Replaceable components may have a lesser design life, reflecting the ease with which the component can be maintained, without impacting on the safe operation of the pipeline.

4.5.4 Maximum allowable operating pressure (MAOP) The MAOP of a new pipeline shall be determined after the pipeline has been constructed and tested in accordance with this Standard. The MAOP shall be approved before the pipeline is placed in operation.

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The MAOP of a pipeline shall be not more than the lesser of the following: (a)

The design pressure (PD).

(b)

The pressure limit (PL) derived from the measured hydrostatic strength test pressure (PM) using the equation— PL =

PM FTPE

. . . 4.5.4(1)

The equivalent test pressure factor FTPE shall be calculated from the following formula:

FTP (t N − H ) . . .4.5.4(2) (t N − G − H ) FTP shall be 1.25. A value of 1.1 may be used in a telescoped pipeline for all except the weakest section, provided that in each of the sections to which it is applied, a 100% radiographic examination of all of the circumferential butt welds has shown compliance with AS 2885.2. FTPE =

In T1 and T2 locations, the MAOP shall be no greater than the pressure that, in combination with the maximum credible hole size determined through the safety management study, will result in a discharge rate equal to the maximum allowable discharge rate determined in accordance with the isolation plan. Where the measured hydrostatic test pressure is to be used to confirm a pressure limit, the engineering design shall be critically reviewed to determine that all aspects of the design components are suitable for the target pressure limit to be confirmed prior to the hydrostatic pressure test being carried out.

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The MAOP of a pipeline is conditional on the integrity of the pipeline established by hydrostatic testing being maintained throughout the operating life and on the design assumptions used to derive the design pressure. Where the Licensee determines that the operating conditions or integrity have changed from those for which the pipeline was approved, the MAOP shall be reviewed in accordance with AS 2885.3. 4.5.5 Minimum strength test pressure 4.5.5.1 General The minimum strength test pressure (PTMIN) of the pipeline system shall be calculated from the following formula: PTMIN = PDFTPE

. . . 4.5.5

Where the pipeline contains short lengths of increased strength or increased thickness pipe, the equivalent test pressure factor shall be calculated for the pipe having the lowest thickness and/or grade in the test section. Where the pipeline test section includes a short or isolated section of T1 or S location class in an area that is predominantly R1 or R2 location class, the designer shall consider the benefit of any additional safety to these locations that would be conferred by subjecting them to a separate strength test using an equivalent test pressure factor calculated in accordance with Equation 4.5.4(2). 4.5.5.2 Minimum strength test pressure exceeds rating of flange Where the value of FTPE calculated from Equation 4.5.4(2) would require a strength test pressure that exceeds the pressure test strength of a flanged valve, the strength test for a new pipeline shall be completed in accordance with this Standard before the flange or flanged valve is attached to the pipeline. © Standards Australia

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All flanges and flanged valves not included in the strength pressure test shall have been hydrostatically tested to a strength test pressure of not less than 1.5 times the MAOP of the pipeline before installation. Fittings shall be designed to withstand the pipeline strength test pressure and shall be hydrostatically tested with the pipeline. Where an existing pipeline is hydrostatically pressure tested to re-establish its MAOP then the minimum and maximum strength test pressure shall be determined within the constraints of the pipeline system, having regard to the remaining corrosion allowance, the flanges or fittings and any other constraint. The duration of new MAOP shall be nominated at the time of re-test, based on an analysis of the measure rate of degradation of the pipeline at its expected operating conditions. NOTE: Clause 8.3 provides requirements for monitoring the rate of degradation.

4.6 ISOLATION 4.6.1 General Equipment shall be provided within a pipeline or pipeline system for the isolation of segments of the pipeline or pipeline system for maintenance purposes and for the isolation of segments of the pipeline or pipeline system in the event of a loss of containment within the segment. Equipment shall be provided to isolate a pipeline or segment of a pipeline from pressure sources that could provide pressure higher than the MAOP of the pipeline or segment. Equipment shall be provided for evacuation of the fluid from a pipeline where required for maintenance and for repairs after a loss of containment.

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This isolation and depressurization equipment shall be defined in an isolation plan. The isolation plan shall be approved prior to the pipeline or segment of the pipeline being placed in service. 4.6.2 Isolation plan The isolation plan shall define the operations and maintenance functions and the loss of containment events for which isolation and pipeline depressurization are required. The loss of containment events considered shall include— (a)

in location classes T1 and T2, an unplanned loss of containment with ignition; and

(b)

for liquid pipelines, the environmental consequence of the loss of containment.

The isolation plan shall define the facilities provided to perform the functions required and shall consider, as a minimum, the following items: (i)

The locations of, and facilities for isolation of a pipeline from a source of pressure higher than the MAOP.

(ii)

The mainline pipe segments to be isolated, including the isolation valve locations and controls.

(iii) The pipeline assemblies to be isolated from mainline pipe, including isolation valves and controls. (iv)

The stations to be isolated from mainline pipe, including isolation valves and controls.

(v)

The segments of the pipeline for which depressurizing facilities are required, including length, stored gas volume, depressurization time, and plan for depressurizing each section.

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The isolation requirements for operation and maintenance of separable segments within pipeline assemblies and stations.

(vii) The response time to effect isolation of mainline pipe, pipeline assembly and station segments in all location classes in the event of a loss of containment. (viii) For branches from the main pipeline, the consequence of a loss of containment in the branch on the supply to other locations along the main pipeline. (ix)

The isolation plan for pipelines carrying liquid products shall include automatic failure detection systems. The practicability of automatic failure detection on other pipelines shall be considered. Where automatic failure detection systems are installed, the practicability of automatic shutdown shall be considered.

(x)

A plan for isolating and depressurizing stations.

(xi)

Short lengths of higher location class within lower location class.

4.6.3 Review of isolation plan The isolation plan shall be reviewed at intervals of five years or whenever— (a)

the location class of a pipeline segment or system changes;

(b)

the MAOP of a pipeline segment or system changes;

(c)

the fluid carried by a pipeline changes from that for which it was designed; and

(d)

modifications are made to a pipeline which affect the isolation plan or require new isolation facilities.

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4.6.4 Isolation valves Valves shall be provided to isolate the pipeline in segments for maintenance, operation, repair and for the protection of the environment and the public in the event of loss of pipeline integrity. The position and the spacing of valves shall be approved. The location of valves shall be determined for each pipeline. An assessment shall be carried out and the following factors shall be considered: (a)

The fluid.

(b)

The security of supply required.

(c)

The response time to events.

(d)

The access to isolation points.

(e)

The ability to detect events which might require isolation.

(f)

The consequences of fluid release.

(g)

The volume between isolation points.

(h)

The pressure.

(i)

Operating and maintenance procedures.

For guidance for the spacing of mainline valves, see Table 4.6.4.

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TABLE 4.6.4 GUIDE FOR THE SPACING OF MAINLINE VALVES Recommended maximum spacing of valves, km Location class Gas and HVPL

Liquid petroleum

R1

As required

As required

R2

30

As required

T1 and T2

15

15

NOTE: A short length of higher location class in a pipeline that is of predominantly lower location class does not necessarily require compliance with the recommendations of Clause 4.6.4.

Liquid transportation pipelines that cross a river or are located within a public water supply reserve shall be provided with isolation valves located to minimize the impact of spilled liquid on the river or reservoir. Typical isolation valve requirements are as follows: (A)

On an upstream section ..................................................................... a mainline valve.

(B)

On a downstream section ................................. a mainline valve or a non-return valve.

The valve locations may not necessarily be immediately adjacent to the river or water supply reserve.

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Valves shall be installed so that, in the event of a leak, the valves can be expeditiously operated. Consideration shall be given to providing for remote operation of individual mainline valves to limit the effect of any leak that may affect public safety and the environment. Where such a facility is provided, the individual mainline valves shall be equipped with a closing mechanism that can be reliably activated from a control centre. 4.7 SPECIAL PROVISIONS FOR HIGH CONSEQUENCE AREAS

4.7.1 General Locations may exist along a pipeline route where special provisions are necessary to limit the consequence of pipeline failure on the community or the environment. For gas pipelines, the consequence is likely to result from ignition of the fluid released, while for oil pipelines the environmental consequence may be dominant. This Clause sets out the minimum requirements for compliance with this Standard in high consequence areas. 4.7.2 No rupture In Residential (T1), High Density (T2), Industrial (I), and Sensitive (S) location classes and in Heavy Industrial (HI) location class (where pipeline failure would create potential for consequence escalation), the pipeline shall be designed such that rupture is not a credible failure mode. For the purpose of this Standard, this shall be achieved by either one of the following: (a)

The hoop stress shall not exceed 30% of SMYS.

(b)

The largest equivalent defect length produced by the threats identified in that location shall be determined.

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The hoop stress at MAOP shall be selected such that the critical defect length is not less than 150% of the axial length of the largest equivalent defect. The analysis shall consider through wall and part through wall defects. NOTES: 1 Clause 4.8.5 defines the method to be used in calculating the critical defect length. 2 Where the identified threat is an excavator, Table M3, Appendix M, nominates the hole diameter by machine mass and tooth type that should be used in this analysis. 3 API 579 and PD 7910 provide methods for converting actual defects into the equivalent through wall flaw.

4.7.3 Maximum discharge rate In all locations, consideration shall be given to providing means of limiting the maximum discharge rate through a pipeline segment in the event of a loss of containment in that segment resulting from the design threat used in Clause 4.7.2. In high consequence locations where loss of containment can result in jet fires or vapour cloud fires the maximum discharge rate shall be determined and shall be approved. For pipelines carrying flammable gases, HVPLs and other liquids with a flash point less than 20°C, the maximum discharge rate shall not exceed 10 GJ.s-1 in Residential and Industrial locations or 1 GJ.s-1 in High Density and Sensitive locations. The energy release rate shall be calculated for quasi-steady state conditions that exist 30 seconds after the pipeline puncture. NOTE: Clause 4.10 provides guidance on the methods for calculating energy release rate.

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For pipelines carrying other combustible fluids, the maximum allowable discharge rate shall be determined by the safety management study specified in this Standard. NOTE: Operating pressure limit and flow restriction devices are two effective methods of limiting the maximum discharge rate. Designs that limit the maximum hole size may also be used to effectively control the maximum discharge rate.

4.7.4 Change of location class Where there are changes in land use planning (or land use) along the route of existing pipelines to permit Residential, High Density, Industrial, or Sensitive development or Heavy Industrial development in areas where these uses were previously prohibited, a safety assessment shall be undertaken and additional control measures implemented until it is demonstrated that the risk from a loss of containment involving rupture is ALARP. A location class change to Heavy Industrial requires compliance with this Clause only when pipeline failure in this location would create potential for consequence escalation. This assessment shall include analysis of at least the alternatives of the following: (a)

MAOP reduction (to a level where rupture is non-credible).

(b)

Pipe replacement (with no rupture pipe).

(c)

Pipeline relocation (to a location where the consequence is eliminated).

(d)

Modification of land use (to separate the people from the pipeline).

(e)

Implementing physical and procedural protection measures that are effective in controlling threats capable of causing rupture of the pipeline.

For the selected solution, the assessment shall demonstrate that the cost of the risk reduction measures provided by alternative solutions is grossly disproportionate to the benefit gained from the reduced risk that could result from implementing any of the alternatives.

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4.8 FRACTURE CONTROL 4.8.1 General The engineering design of the pipeline shall include a fracture control plan except where excluded by Clause 3.4.4. The following failure modes are known to occur in pipelines: (a)

Leak without rupture where a defect grows through the wall in a stable manner and allows loss of containment of the pipeline contents through an opening which is small relative to the diameter of the pipeline.

(b)

Rupture resulting from a flaw that is larger than the critical defect length leading to an opening which is comparable to or larger than the diameter of the pipeline.

(c)

Brittle fracture in which the fracture propagates beyond the rupture stage in the predominantly cleavage mode at or below the transition temperature of the pipe steel. The appearance of the fracture surface is crystalline.

(d)

Tearing fracture (commonly called ductile fracture) in which the fracture propagates beyond the rupture stage in the shear mode above the transition temperature. The appearance of the fracture surface is fibrous.

A classification of pipeline fluids for the purpose of the fracture control plan is shown in Figure 4.8.1.

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Low temperatures caused during pressure changes in commissioning or in operation shall be considered in the fracture control plan.

Lean natural gas

Stable liquids

Other fluids (eg. rich gases, other gases, other liquids, HVPL’s)

Gas and liquid petroleum fluids

NOTES: 1

For guidance on the development of the fracture control plan, see Appendix L.

2

Stable liquids have no significant vapour phase at atmospheric pressure, e.g. distillate or processed crude (not wellhead products).

3

Lean natural gas consists almost entirely of methane. For the purpose of this classification it may contain up to 5% ethane. However, it shall contain less than 1% total of higher hydrocarbons.

4

Other gases and liquids include all other fluids such as, but not restricted to, wellhead products, LPG, HVPL, rich natural gas, multi-phase fluids and CO 2 .

FIGURE 4.8.1 CLASSIFICATION OF PIPELINE FLUIDS FOR THE FRACTURE CONTROL PLAN

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4.8.2 Fracture control plan The requirements of the fracture control plan are as follows: (a)

The fracture control plan shall only apply to the line pipe portion of the pipeline as defined in Figure 4.1. It shall not apply to pipeline accessories, which are addressed in Clause 3.4.4.3.

(b)

The fracture control plan shall define the following: (i)

The stresses and pipe temperatures for which arrest of fracture is to be achieved.

(ii)

For pipelines in high consequence areas (location Classes T1, T2, S and I, and if applicable, HI), the method for ensuring the following: (A)

That in the line pipe, rupture is not a credible failure mode in accordance with Clause 4.7.2.

(B)

The maximum energy release rate at a leak or penetration not greater than the limit defined in Clause 4.7.3.

(C)

The longitudinal weld seam (weld metal and HAZ) of line pipe has adequate levels of fracture toughness to minimize the likelihood of fracture initiation. NOTE: Because higher levels of toughness are required to arrest propagating fractures than are required to avoid the initiation of a fracture, the specification of sufficient toughness to control fast fracture propagation will always ensure that the pipe body will be sufficiently tough so that initiation is flow stress controlled rather than toughness-dependent.

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(D)

That, where required by the safety management study, pipeline components have sufficient fracture toughness to minimize the likelihood of fracture initiation.

(iii) The design fracture arrest length (expressed as the number of pipe lengths each side of the point of initiation). (iv)

The methods of providing for crack arrest.

(c)

The fracture toughness properties of the materials and components, which are relied on to achieve the requirements of the fracture control plan, shall take into account any effect of exposure to non-ambient temperatures as required by Clause 3.5 of this Standard.

(d)

The design fracture arrest length in each location class shall not exceed the values in Table 4.8.2. TABLE 4.8.2 FRACTURE ARREST LENGTHS Location class

Arrest length

R1

5 pipes unless otherwise justified in the fracture control plan (see Note)

R2

5 pipes (see Note)

All others

Arrest within the initiating pipe

NOTE: The arrest length of 5 pipes is comprised of the pipe in which the fracture initiates, and not more than two (2) pipes on each side of the initiating pipe. (Refer Appendix L.) © Standards Australia

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(e)

AS 2885.1—2012

The following information required for the design and safety management study shall be included in the fracture control plan: (i)

The critical defect length for the pipe (see Clause 4.8.5).

(ii)

The resistance to penetration (where penetration could initiate fracture) (see Clause 4.11).

The stress, temperature and fracture arrest length parameters do not need to be uniform over the pipeline and may differ for each location class or for each relevant fracture mode. The sequence of decision making required to develop and implement a fracture control plan to ensure arrest of fast fracture shall be in accordance with Figure 4.8.2. Where this Standard is used for pipelines constructed from corrosion resistant alloy pipe, fibreglass or other materials, the fracture control plan shall be developed with a full understanding of the fracture behaviour of the pipe material.

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NOTE: Appendix L does not deal with materials other than carbon-manganese steels and expert advice is recommended for other materials.

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Control of brittle fracture

Fracture control

t Stable liquid and T d 0°C

Yes

DN 200 MAOP 10.5 MPa

Yes

Yes

300

DWTT FATT shall be T d

Yes Yes

5 mm or DN

D DN100 and t 6.1 mm and MAOP 10.5 Mpa

Stable liquid

Control of tearing fracture

Fracture control plan not required

Hoop stress at P D 85 MPa

Yes

Yes

CVN

Yes

DN 300 and MAOP 10.5 MPa

Clause 3.4.4.2 Yes

MAOP 40% SMYS

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CVN = Clause 3.4.4.2

Yes

Lean gas MAOP 15.3 MPa and grade X70

High consequence areas

Use Battelle two curve model & fudge factor 1.4 if X80

Apply special provision for high consequence areas (Clause 4.7)

Brittle and tearing fracture are controlled

Yes

Use Battelle short form equation

DOCUMENTED FRACTURE CONTROL PLAN

NOTES: 1

40% SMYS is a conservative approximation of the threshold stress for tearing fracture, which is more accurately given by 30% of the flow stress. A higher value than 40% SMYS based upon actual data, may be used where approved.

2

For pipelines carrying gas or HVPL, the minimum toughness shall comply with Clause 3.4.4.

FIGURE 4.8.2 FRACTURE CONTROL PLAN DECISION TREE

4.8.2.1 Fracture control—Other than line pipe This Clause applies to induction bends and pipeline assemblies, including the interconnecting piping associated with the scraper or MLV assembly.

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AS 2885.1—2012

For these items— (a)

fracture initiation shall be controlled in all accessories and associated piping; and

(b)

consideration of propagating fracture is not required (see Note 2).

NOTES: 1 Fracture control may be demonstrated by compliance with station pipe design (Section 6) for pipe at the design minimum temperature (AS 4041 or ASME B31.3, low temperature service) or with Clause 3.4.4. 2 The length of the assembly or interconnecting piping is short and the pipe usually contains valves and fittings that act as crack arresters. Consequently there is no change in consequence whether fast tearing fracture in this pipe is arrested within the initiating pipe, or in a connecting pipe.

4.8.3 Specification of toughness properties for brittle fracture control

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The following applies: (a)

Brittle fracture resistance The resistance to brittle fracture propagation shall be determined from measurements of the fracture appearance of drop-weight tear test (DWTT) specimens representative of the pipe body material fractured in the line of the pipe axis. Test specimens may be taken from finished pipe or, after correlation has determined any effect of pipe making, from the strip or plate from which pipes are made.

(b)

Brittle fracture test temperature The test temperature for brittle fracture control shall be the lowest temperature at which the hoop stress exceeds the threshold stress for brittle fracture (see Appendix L, Paragraph L3). The temperature should consider both operating and transient conditions, including any temperature and pressure limits established by the isolation plan for pipeline depressurization and repressurization. NOTES: 1 For detailed methods for conducting tests to determine fracture appearance and for evaluation of results, see Appendix K. 2 For guidance for avoidance of brittle fracture for thick wall and small diameter pipelines, see Appendix L, Paragraph L5.

4.8.4 Specification of toughness properties for tearing fracture control 4.8.4.1 Specification of fracture toughness properties for pipe body materials Where the fracture control plan determines that it is necessary to specify pipe body fracture toughness, the following applies: (a)

Tearing fracture resistance The resistance to tearing fracture propagation (ductile fracture) shall be determined from measurements of the transverse energy absorption of Charpy test specimens representative of the pipe body material. Test specimens may be taken from finished pipe or, after correlation has confirmed any effect of pipe making, may be taken from the strip or plate from which the pipes are made. NOTES: 1 For methods for conducting tests to determine energy absorption of pipe body materials and for evaluation of results, see Appendix K. 2 For guidance for control of tearing fracture, see Appendix L.

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The requirements for transverse energy absorption shall be determined in the fracture control plan using a recognized analytical method and shall take into consideration— (i)

the design arrest length;

(ii)

the pipe diameter and steel grade; and

(iii) the wall thickness (t W ) minus the thickness of ‘vanishing’ allowances (e.g. corrosion allowance). (b)

Calculation of tearing fracture arrest toughness The tearing fracture arrest toughness Charpy energy requirements may be calculated using the following equation provided the following conditions are met: (i)

The design fluid is lean natural gas.

(ii)

The MAOP does not exceed 15.3 MPa.

(iii) Grade is ≤X70. 1

1

CVN = 2.836 × 10 −5 σ H (D ) 3 (t w ) 3 2

. . . 4.8.4(1)

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Where the design does not meet all of the above conditions the arrest toughness shall be calculated using the Battelle Two Curve model with the decompression characteristics of the design gas at the most severe combination of composition and temperature, computed from MAOP. Some rich gas compositions require higher arrest toughness at temperatures higher than the design minimum temperature. Where the arrest toughness is determined using the Batelle Two Curve method, decompression characteristics shall be determined at the MAOP and the range of temperatures over which the pipeline is designed to operate and the applicable toughness defined (see Note 2). Under some circumstances the predictions (of arrest toughness) are known to be non-conservative—in this case the calculated arrest toughness shall be multiplied by a factor of safety determined by experience or by full scale burst test. Where the steel grade is X80, the specified toughness shall be at least the calculated toughness multiplied by 1.4. For pipelines in which the calculated arrest toughness CVN exceeds 100 J, the method of achieving arrest within the design length shall be the subject of an independent expert verification. Such verification shall be included in the fracture control plan at the stage it is submitted for approval (see Note 3). NOTES: 1 Equation 4.8.4(1) is derived from the Battelle short form formula (metric version) for a 2/ 3 size specimen by multiplying by 3/ 2. This equation is one of a number of similar relationships that correlate full scale arrest/propagate behaviour with small scale laboratory Charpy tests. 2 Fracture initiation resistance will still need to be defined at the lowest operating temperature. 3 The technology of fracture control in pipelines is complex and needs to be empirically validated. Attention is directed to the absence of an experimental database supporting the fracture control design of small diameter, high-strength pipelines.

(c)

The tearing fracture test temperature shall be determined on the basis of the following: (i)

For a transmission pipeline, the minimum steady state operating temperature of the pipeline (normally minimum ground temperature at pipe depth) rounded down to the nearest 5°C.

(ii)

For a transmission pipeline where the temperature and pressure are changed by an in-line device (e.g. a pressure control valve), the minimum steady state operating temperature downstream of the device, rounded down to the nearest 5°C.

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AS 2885.1—2012

NOTES: 1 The minimum temperatures normally occur sometime after winter due to seasonal lag. 2 Transient events such as repressurization of a pipeline section may involve temperatures lower than these minimum temperatures. Because the pressure in the pipeline at the time that the low temperature exists is low, the risk of fracture initiation and propagation of a brittle fracture must be controlled, rather than ductile tearing fracture. Control during activities of this type should be achieved by maintaining the pressure so that the hoop stress does not exceed the threshold stress at any time that the temperature is lower than the fracture initiation transition temperature (see Clause 4.8.3). 3 The temperature specified for Charpy impact tests in the material purchase order may be lower than the temperature specified in the fracture control plan.

(d)

The tearing fracture arrest toughness shall be the highest toughness determined in accordance with Clause 4.8.4.1(b).

4.8.4.2 Tearing fracture toughness specification for pipe purchase After determining the toughness required for fast tearing fracture arrest, it shall be incorporated in the technical specification for pipe supply. The specification shall nominate at least the minimum toughness (any heat) and the minimum toughness (all heat average). The specification may nominate minimum toughness (any specimen) as required by the project.

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The definition of these terms is as follows: (a)

Charpy impact test A Charpy impact ‘test’ toughness is the mean energy absorbed by testing three specimens prepared from a pipe in accordance with Appendix K.

(b)

Minimum toughness (any specimen) This is the toughness of any of the three specimens broken in a Charpy impact test. This is sometimes specified by a designer to eliminate tests where the average may comply with the ‘test’ toughness, but where the toughness of each of the three specimens varies wildly (suggesting that there is inconsistency in the steel, the sampling technique or the testing technique). The minimum toughness (any specimen) is not usually specified except where the designer has a specific requirement for manufacturing control.

(c)

Minimum toughness (all heat average) This is the tearing fracture arrest toughness as defined in Clause 4.8.4.1(d). The average of all Charpy impact test toughness tests determined on the pipe population supplied to the order at the frequency nominated in the pipe specification must not be less than the minimum toughness (all heat average).

(d)

Minimum toughness (any heat) This is the minimum toughness of any heat of pipe supplied to an order. It is required to define the arrest length specified in Table 4.8.2. The minimum toughness (any heat) is determined from: Minimum toughness (any heat) = SF* minimum toughness (all heat average).

(e)

Statistical factor (SF) The statistical factor reflects the random distribution of pipes whose toughness is less than the tearing fracture arrest toughness in any string of pipeline. For a new pipeline, SF can be estimated from knowledge of the number of heats required to manufacture the pipe in the pipeline, and from historical knowledge of the toughness distribution in similar strip manufactured by the steel mill. For an existing pipeline, SF can be estimated from the as-built data. NOTE: For guidance on the statistical methodology required to determine the arrest length, see Appendix L.

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When the design requires each pipe to be an arrest pipe or when the pipeline is made using a few heats of steel, SF shall be 1.0. When the pipe population required for a pipeline contains a large number of heats, specifying SF = 0.75 will result in there being a 95% chance that a tearing fracture will be arrested within two pipes of the initiation pipe. When there is sufficient knowledge about the statistical distribution of toughness from the steel mill, SF can be estimated to achieve arrest in a different number of pipes or to achieve the required arrest length in a pipeline containing a moderate number of heats. 4.8.4.3 Specification of fracture toughness properties for pipe weld seam materials Where the fracture control plan determines that it is necessary to specify pipe weld seam fracture toughness, the following shall apply: (a)

Test temperature The test temperature shall be as determined by Clause 4.8.4.1(c). No account shall be taken of the effect of escaping pipeline product upon the temperature.

(b)

Fracture initiation resistance The resistance to fracture initiation shall be determined from Charpy tests conducted on the weld seam in accordance with AS 1544.2 or equivalent. SAW pipe shall have tests conducted upon the weld metal and HAZ. ERW pipe shall have tests conducted upon the centre of the weld seam.

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The requirements for Charpy energy for initiation shall be determined in the fracture control plan using a recognized method. NOTES: 1 The results of Charpy tests upon ERW weld seams are likely to be highly variable, and are very sensitive to notch locations. Great care and skill is necessary in the achievement of proper notch locations. The notch should be located within 0.1 mm of the weld centreline. 2 The method developed by Battelle in research sponsored by the American Gas Association is an acceptable method.

4.8.5 Critical defect length When the axial length of a defect in the pipe wall exceeds a limiting value the defect will grow, and the pipe will rupture. For high toughness steels, the critical defect length (CDL) may be calculated from:

σH =

σ flow

. . . 4.8.5(1)

MT

⎡ ⎤ ⎢ ⎥ 2 4 c c ⎥ M T = ⎢1 + 1.255 − 0.0135 2 ⎢ ⎥ D ⎛D⎞ 2 tW ( ) ⎢ t ⎥ ⎜ ⎟ W 2 ⎢⎣ ⎝2⎠ ⎦⎥ CDL = 2c

0.5

. . . 4.8.5(2)

. . . 4.8.5(3)

Equation 4.8.5(1) applies to the limiting condition of flow stress or plastic instability, recognizing that increasing the steel toughness beyond a certain value will not increase the size of a limiting defect.

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AS 2885.1—2012

For design and the safety management study, the CDL shall be defined for σH at MAOP. NOTE: The toughness required to control fracture initiation is usually calculated for a through wall flaw that is 80% (or sometimes 90%) of the critical defect length. Once the critical defect length is known, the toughness required to control initiation can be calculated from Equation 4.8.5(4) and 4.8.5(5).

The CDL determined from Equations 4.8.5(4) and 4.8.5(5) is the same as that determined from Equation 4.8.5(1) at toughness values typically required for arrest of tearing fracture in accordance with Clause 4.8.4.

2

KC =

8c (σ flow )

2

π

⎛ πM T σ H 1n.sec ⎜⎜ ⎝ 2σ flow

⎞ ⎟⎟ ⎠

. . . 4.8.5(4)

KC may be estimated from the Charpy V-notch test toughness according to: 2

KC 1000CVN = E AC

. . . 4.8.5(5)

Equations 4.8.5(4) and 4.8.5(5) may be used to calculate the through wall flaw size that can be sustained by pipe with a known toughness at the design (or other prevailing) pressure. The above equations apply to through wall defects only. There is a family of curves that can be developed for part through wall defects predicted from the failure stress of rectangular flaws, using the following equation:

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σH

d ⎛ ⎜ 1− W (t W ) = σ flow ⎜ ⎜ dW ⎜1− (t W )M T ⎝

⎞ ⎟ ⎟ ⎟ ⎟ ⎠

. . . 4.8.5(6)

4.9 LOW TEMPERATURE EXCURSIONS A pipeline shall not be operated at combinations of high stress and low temperature that fall outside limits set in the design. These limits and their basis shall be documented in the design basis. Low temperature conditions are associated with unusual operations, particularly in gas pipelines including— (a)

initial fill and pressurization;

(b)

depressurization;

(c)

purging prior to repressurization;

(d)

repressurization;

(e)

throttling through a valve designed for the purpose of temporarily reducing the pressure in a downstream pipe (required, for example, for a pipe that has experienced damage); and

(f)

throttling through a valve designed for the purpose of releasing specification gas.

The design shall consider each operating condition that has the potential to cause temperatures lower than the minimum design temperature of the pipeline, or its components. The design shall document the controls incorporated in the design, and any operational procedures required to comply with the high stress-low temperature limits.

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Unless the properties of the materials incorporated in the design support the use of an alternative limit the design and operating procedures shall control the pipeline so that the hoop stress in any component does not exceed 85 MPa at any time that the temperature of the pipe wall is lower than −29°C. The temperature limit for continuous operation at a hoop stress in excess of 85 MPa shall be established and documented. NOTES: 1 For guidance on the effect of temperature on fracture control, see Appendix L. 2 The bolts used in flanged valves intended to provide high pressure drops should be assessed to determine whether they are suitable for the low temperatures that may arise (e.g. mainline valve bypass valves). Downstream equipment should also be considered. 3 Since line pipe is usually the most highly stressed pressure-containing component exposed to low-temperature excursions, consideration should be given to establishing the transition temperature of line pipe intended for operation at low ambient temperatures and pressures higher than 10.2 MPa.

4.10 ENERGY DISCHARGE RATE Where this Standard requires use of energy release rate or radiation contour it shall be established by calculation of the quasi-steady state volumetric (or energy) flow 30 seconds after the initiating event, determined by a suitable unsteady state hydraulic analysis model, and the relevant equivalent hole size. The calculation shall assume the pipeline is at MAOP at the time of gas release.

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Where the identified hole size is small relative to the diameter of the pipe (