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AS 2885.1—2007
Australian Standard®
Pipelines—Gas and liquid petroleum
Part 1: Design and construction
AS
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07
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This Australian Standard® was prepared by Committee ME-038, Petroleum Pipelines. It was approved on behalf of the Council of Standards Australia on 19 January 2007. This Standard was published on 25 May 2007.
The following are represented on Committee ME-038:
• APIA Research and Standards Committee • Australasian Corrosion Association • Australian Chamber of Commerce and Industry • Australian Institute of Petroleum • Australian Pipeline Industry Association • Bureau of Steel Manufacturers of Australia • Department of Consumer and Employment Protection (WA) • Department of Energy, Utilities and Sustainability (NSW) • Department of Mines and Energy (Qld) • Department of Primary Industries (Victoria) • Department of Primary Industry, Fisheries and Mines (NT) • Energy Networks Association • Gas Association of New Zealand • Primary Industries and Resources SA • Welding Technology Institute of Australia
This Standard was issued in draft form for comment as DR 04561. 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 public comment period.
Keeping Standards upKeeping Standards upKeeping Standards upKeeping Standards up----totototo----datedatedatedate 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 Standards may also be withdrawn.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.auwww.standards.org.auwww.standards.org.auwww.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]@[email protected]@standards.org.au, or write to Standards Australia, GPO Box 476, Sydney, NSW 2001.
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AS 2885.1—2007
Australian Standard®
Pipelines—Gas and liquid petroleum
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 2007.
COPYRIGHT
© Standards Australia
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.
Published by Standards Australia GPO Box 476, Sydney, NSW 2001, Australia
ISBN 0 7337 8241 8
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AS 2885.1—2007 2
PREFACE
This Standard was prepared by the Joint Standards Australia/Standards New Zealand
Committee ME-038, Petroleum Pipelines, to supersede AS 2885—1997, 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 Pipelines—Gas and liquid petroleum
2885.1 Part 1: Design and construction (this Standard)
2885.2 Part 2: Welding
2885.3 Part 3: Operation and maintenance
2885.4 Part 4: Submarine pipelines
2885.5 Part 5: Field pressure testing
Part 0: General requirements (in preparation)
BASIS OF THE AS 2885 SERIES OF STANDARDS
The purpose of the AS 2885 series of Standards is to ensure the protection of the general
public, pipeline operating personnel and the environment, and to ensure safe operation of
pipelines that carry petroleum fluids at high pressures.
The AS 2885 series of Standards achieve their purpose by defining important principles for
design, construction, operation and abandonment of petroleum pipelines. The principles are
expressed in practical rules and guidelines for use by competent persons. The fundamental
principles on which the AS 2885 series of Standards are based are as follows:
(a) The Standards exist to ensure the safety of the community, protection of the
environment and security of supply.
(b) A pipeline is to be designed and constructed to have sufficient strength, ductility and
toughness to withstand all planned and accidental loads to which it may be subjected
during construction, testing and operation.
(c) Before a pipeline is placed into operation it has to be inspected and tested to prove its
integrity.
(d) Important matters relating to safety, engineering design, materials, testing and
inspection have to be reviewed and approved by a responsible entity. The responsible
entity has to be the pipeline Licensee or its delegate. In each case, the responsible
entity has to be defined.
(e) Before a pipeline is abandoned, an abandonment plan has to be developed.
(f) The integrity and safe operation of the pipeline has to be maintained in accordance
with an approved safety and operating plan.
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3 AS 2885.1—2007
(g) Where changes occur in or to a pipeline, which alter the design assumptions or affect
the original integrity, appropriate steps have to be taken to assess the changes and to
ensure continued safe operation of the pipeline.
These fundamental principles, and the practical rules and guidelines that derive from them,
make the AS 2885 series of Standards a single and sufficient technical Standard.
The fundamental principles set out above, and the practical rules and guidelines set out in
the Standards, are the basis on which an engineering assessment is to be made where the
Standards do not provide detailed requirements appropriate to a specific item.
SCOPE OF THE AS 2885 SERIES OF STANDARDS
Inclusions
The AS 2885 series of Standards apply to 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 Standards apply where—
(a) the temperatures of the fluid are not more than 200°C nor less than −30°C; and
(b) either the maximum allowable operating pressure (MAOP) of the pipeline is more
than 1050 kPa, or at any one or more positions in the pipeline the hoop stress exceeds
20% of the SMYS.
Except for the exclusions listed below, the Standards apply to flowlines and gathering
pipelines on land. The Standards also apply to pipelines between terminals. The extent of
the pipelines extends only to where the pipeline is connected to facilities designed to other
Standards. In general, flowlines commence at the wellhead assembly outlet valve on a
wellhead, terminate at the inlet valve of the collection manifold, and include piping within
facilities integral to the pipeline, such as compressor stations, pump stations, valve stations
and metering stations.
This Standard also applies to modifications to a pipeline constructed to a previous Standard
or previous edition of a Standard. Modifications have to comply with the current edition of
the Standard in force at the time of the modification. Modifications include change of use,
change of MAOP and significant changes to the physical asset.
Exclusions
The AS 2885 series of Standards does not apply to the following:
(a) Petroleum production and processing plants, gas manufacturing plants and tank farms.
(b) Gas distribution pipelines complying with AS 1697, Installation and maintenance of
steel pipe systems for gas.
(c) Low pressure liquid pipelines (including pipelines containing low-pressure liquid-gas
mixtures).
(d) Auxiliary piping such as that required for water, air, steam, lubricating oil and fuel.
(e) Flexible pipes and risers.
(f) Equipment for instrumentation, telemetering and remote control.
(g) Compressors, pumps and their prime movers and integral piping.
(h) Heat exchangers and pressure vessels (see AS 1210, Pressure vessels).
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AS 2885.1—2007 4
(i) Design and fabrication of proprietary items.
(j) Wellhead assemblies and associated control valves and piping.
(k) Casing, tubing or piping used in petroleum wells.
ADMINISTRATIVE MATTERS
Departures from these Standards
Novel materials, designs, methods of assembly, procedures, etc., for which specific
requirements are not provided in this Standard, but which give equivalent results to those
specified, are not necessarily prohibited.
Such departures will have to be assessed, documented and approved.
Use of other Standards
Where this Standard permits the use of other Standards or codes, it is the intent of this
Standard that the other Standard or code be used in full and that the requirements of the
other Standard or code not be mixed with requirements of this Standard. Where the other
Standard or code requires the use of compatible Standards or codes for compliance, those
compatible Standards or codes have to be used.
Where this Standard imposes requirements that add to or override the requirements of a
permitted Standard or code, the additional requirements are explicitly stated in this
Standard and have to be met.
Interpretations
Questions concerning the meaning, application, or effect on any Part of the AS 2885 series
of Standards may be referred to the Standards Australia committee ME-038, Petroleum
Pipelines, for explanation. The authority of the committee is limited to matters of
interpretations and it will not adjudicate in disputes.
2007 REVISION
General
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.
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5 AS 2885.1—2007
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.
(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, 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.
(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.
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AS 2885.1—2007 6
(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) A calculation method for determining resistance to penetration by an excavator
is provided.
(v) 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.
(vi) 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.
(vii) The provisions for reduced cover for a pipeline constructed through ‘rock’ have
been revised.
(viii) The method for calculating reinforcement of branch connections in
AS 2885.1—1987 has been reinstated in full. (Amendment 1 to AS 2885.1—
1997 reinstated the requirement in part, but incorrectly reinforcement
calculation to AS 4041/ASME B31.3.)
(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 as-
constructed 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.
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7 AS 2885.1—2007
(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.
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.
Other text which was in AS 2885.1—1997 will be included in a new Part 0 (in preparation)
of the AS 2885 suite, which will include requirements that are common to AS 2885.1,
AS 2885.2. AS 2885.3 and AS 2885.5.
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.
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—2007 8
CONTENTS
Page
SECTION 1 SCOPE AND GENERAL
1.1 SCOPE ...................................................................................................................... 16
1.2 GENERAL ................................................................................................................ 16
1.3 RETROSPECTIVE APPLICATION ......................................................................... 16
1.4 REFERENCED DOCUMENTS ................................................................................ 17
1.5 DEFINITIONS .......................................................................................................... 17 1.5.1 Accessory .......................................................................................................... 17
1.5.2 Approved and approval...................................................................................... 17
1.5.3 As low as reasonably practicable (ALARP) ....................................................... 17
1.5.4 Buckle................................................................................................................ 17
1.5.5 Casing................................................................................................................ 17
1.5.6 Collapse ............................................................................................................. 17
1.5.7 Competent person .............................................................................................. 17
1.5.8 Common threats................................................................................................. 18
1.5.9 Component......................................................................................................... 18
1.5.10 Construction ...................................................................................................... 18
1.5.11 Control piping.................................................................................................... 18
1.5.12 Critical defect length.......................................................................................... 18
1.5.13 Defect ................................................................................................................ 18
1.5.14 Dent ................................................................................................................... 18
1.5.15 Failure................................................................................................................ 18
1.5.16 Fitting ................................................................................................................ 18
1.5.17 Fluid .................................................................................................................. 18
1.5.18 Gas..................................................................................................................... 18
1.5.19 Heat ................................................................................................................... 18
1.5.20 High consequence area ...................................................................................... 19
1.5.21 High vapour pressure liquid (HVPL) ................................................................. 19
1.5.22 Hoop stress ........................................................................................................ 19
1.5.23 Hot tap ............................................................................................................... 19
1.5.24 Inspector ............................................................................................................ 19
1.5.25 Leak test ............................................................................................................ 19
1.5.26 Licensee............................................................................................................. 19
1.5.27 Location class .................................................................................................... 19
1.5.28 May.................................................................................................................... 19
1.5.29 Mechanical interference-fit joint........................................................................ 19
1.5.30 Nominated Standard........................................................................................... 19
1.5.31 Non-credible threat ............................................................................................ 19
1.5.32 Non-location specific threat ............................................................................... 19
1.5.33 Petroleum........................................................................................................... 19
1.5.34 Pig ..................................................................................................................... 20
1.5.35 Pig trap (scraper trap) ........................................................................................ 20
1.5.36 Pipework, mainline ............................................................................................ 20
1.5.37 Pipework, station ............................................................................................... 20
1.5.38 Piping ................................................................................................................ 20
1.5.39 Pretested ............................................................................................................ 20
1.5.40 Pressure, design ................................................................................................. 20
1.5.41 Pressure, maximum allowable operating (MAOP) ............................................. 20
1.5.42 Pressure, maximum operating (MOP) ................................................................ 20
1.5.43 Pressure strength................................................................................................ 20
1.5.44 Propagating fracture........................................................................................... 20
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9 AS 2885.1—2007
1.5.45 Proprietary item ................................................................................................. 20
1.5.46 Protection measures, procedural ........................................................................ 20
1.5.47 Protection measure, physical.............................................................................. 20
1.5.48 Regulatory authority .......................................................................................... 20
1.5.49 Rupture .............................................................................................................. 21
1.5.50 Safety management study or process ................................................................. 21
1.5.51 Shall................................................................................................................... 21
1.5.52 Should................................................................................................................ 21
1.5.53 Sour service ....................................................................................................... 21
1.5.54 Specified minimum yield stress (SMYS) ........................................................... 21
1.5.55 Strength test ....................................................................................................... 21
1.5.56 Telescoped pipeline ........................................................................................... 21
1.5.57 Threat ................................................................................................................ 21
1.5.58 Wall thickness, design pressure ......................................................................... 21
1.5.59 Wall thickness, required..................................................................................... 21
1.5.60 Wall thickness, nominal..................................................................................... 21
1.6 SYMBOLS AND UNITS .......................................................................................... 21
1.7 ABBREVIATIONS ................................................................................................... 23
SECTION 2 SAFETY
2.1 BASIS OF SECTION ................................................................................................ 25
2.2 ADMINISTRATIVE REQUIREMENTS .................................................................. 25 2.2.1 Approval ............................................................................................................ 25
2.2.2 Documentation................................................................................................... 26
2.2.3 Implementation .................................................................................................. 26
2.2.4 Safety management study validation.................................................................. 26
2.2.5 Operational Review ........................................................................................... 26
2.3 SAFETY MANAGEMENT PROCESS ..................................................................... 27 2.3.1 General .............................................................................................................. 27
2.3.2 Threats ............................................................................................................... 28
2.3.3 Controls ............................................................................................................. 30
2.3.4 Failure analysis .................................................................................................. 31
2.3.5 Risk assessment ................................................................................................. 32
2.3.6 Demonstration of fault tolerance........................................................................ 32
2.4 STATIONS, PIPELINE FACILITIES AND PIPELINE CONTROL SYSTEMS ...... 32 2.4.1 General .............................................................................................................. 32
2.4.2 Safety assessments............................................................................................. 32
2.5 ENVIRONMENTAL MANAGEMENT .................................................................... 33
2.6 ELECTRICAL........................................................................................................... 33
2.7 CONSTRUCTION AND COMMISSIONING........................................................... 34 2.7.1 Construction safety ............................................................................................ 34
2.7.2 Testing safety..................................................................................................... 35
2.7.3 Commissioning safety........................................................................................ 35
SECTION 3 MATERIALS AND COMPONENTS
3.1 BASIS OF SECTION ................................................................................................ 36
3.2 QUALIFICATION OF MATERIALS AND COMPONENTS................................... 36 3.2.1 General .............................................................................................................. 36
3.2.2 Materials and components complying with nominated Standards ...................... 36
3.2.3 Materials and components complying with Standards not nominated in this
Standard............................................................................................................. 37
3.2.4 Components, other than pipe, for which no Standard exists ............................... 38
3.2.5 Reclaimed pipe .................................................................................................. 38
3.2.6 Reclaimed accessories, valves and fittings......................................................... 38
3.2.7 Identification of components.............................................................................. 39
3.2.8 Material and components not fully identified..................................................... 39
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AS 2885.1—2007 10
3.2.9 Unidentified materials and components ............................................................. 39
3.2.10 Hydrostatic test .................................................................................................. 39
3.3 REQUIREMENTS FOR COMPONENTS TO BE WELDED ................................... 39 3.3.1 Welding of prequalified materials...................................................................... 39
3.3.2 Materials specifications ..................................................................................... 39
3.4 ADDITIONAL MECHANICAL PROPERTY REQUIREMENTS............................ 39 3.4.1 Yield strength .................................................................................................... 39
3.4.2 Pipe Yield to Tensile Ratio ................................................................................ 39
3.4.3 Strength de-rating .............................................................................................. 40
3.4.4 Fracture toughness ............................................................................................. 40
3.5 REQUIREMENTS FOR TEMPERATURE-AFFECTED ITEMS ............................. 40 3.5.1 General .............................................................................................................. 40
3.5.2 Items heated subsequent to manufacture ............................................................ 40
3.5.3 Pipe operated at elevated temperatures .............................................................. 41
3.5.4 Pipe exposed to cryogenic temperatures ............................................................ 41
3.6 MATERIALS TRACEABILITY AND RECORDS................................................... 41
3.7 RECORDS................................................................................................................. 41
SECTION 4 DESIGN—GENERAL
4.1 BASIS OF SECTION ................................................................................................ 42
4.2 ROUTE...................................................................................................................... 43 4.2.1 General .............................................................................................................. 43
4.2.2 Investigation ...................................................................................................... 43
4.2.3 Route selection .................................................................................................. 44
4.2.4 Route identification............................................................................................ 44
4.3 CLASSIFICATION OF LOCATIONS ...................................................................... 45 4.3.1 General .............................................................................................................. 45
4.3.2 Measurement length........................................................................................... 45
4.3.3 Location classification ....................................................................................... 45
4.3.4 Primary location class ........................................................................................ 45
4.3.5 Secondary location class .................................................................................... 46
4.4 PIPELINE MARKING .............................................................................................. 47
4.4.1 General .............................................................................................................. 47
4.4.2 Sign location ...................................................................................................... 48
4.4.3 Sign design ........................................................................................................ 49
4.5 SYSTEM DESIGN .................................................................................................... 50 4.5.1 Design Basis ...................................................................................................... 50
4.5.2 Maximum velocity ............................................................................................. 51
4.5.3 Design life ......................................................................................................... 51
4.5.4 Maximum allowable operating pressure (MAOP).............................................. 52
4.5.5 Minimum strength test pressure ......................................................................... 52
4.6 ISOLATION.............................................................................................................. 53
4.6.1 General .............................................................................................................. 53
4.6.2 Isolation plan ..................................................................................................... 53
4.6.3 Review of isolation plan .................................................................................... 54
4.6.4 Isolation valves .................................................................................................. 54
4.7 SPECIAL PROVISIONS FOR HIGH CONSEQUENCE AREAS............................. 55
4.7.1 General .............................................................................................................. 55
4.7.2 No rupture.......................................................................................................... 55
4.7.3 Maximum discharge rate.................................................................................... 55
4.7.4 Change of location class .................................................................................... 56
4.8 FRACTURE CONTROL........................................................................................... 56
4.8.1 General .............................................................................................................. 56
4.8.2 Fracture control plan.......................................................................................... 57
4.8.3 Specification of toughness properties for brittle fracture control........................ 60
4.8.4 Specification of toughness properties for tearing fracture control ...................... 60
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11 AS 2885.1—2007
4.8.5 Critical defect length.......................................................................................... 62
4.9 LOW TEMPERATURE EXCURSIONS ................................................................... 63
4.10 ENERGY DISCHARGE RATE................................................................................. 64
4.11 RESISTANCE TO PENETRATION ......................................................................... 64 4.11.1 General .............................................................................................................. 64
4.11.2 Penetration resistance requirements ................................................................... 64
4.11.3 Calculation of resistance to penetration ............................................................. 65
SECTION 5 PIPELINE DESIGN
5.1 BASIS OF SECTION ................................................................................................ 66
5.2 DESIGN PRESSURE ................................................................................................ 66 5.2.1 Internal pressure ................................................................................................ 66
5.2.2 External pressure ............................................................................................... 66
5.3 DESIGN TEMPERATURES..................................................................................... 67
5.4 WALL THICKNESS................................................................................................. 67 5.4.1 Nominal wall thickness...................................................................................... 67
5.4.2 Required wall thickness ..................................................................................... 68
5.4.3 Wall thickness for design internal pressure ........................................................ 68
5.4.4 Wall thickness for design internal pressure of bends.......................................... 69
5.4.5 Wall thickness design for external pressure ....................................................... 69
5.4.6 Allowances ........................................................................................................ 70
5.4.7 Pipe manufacturing tolerance............................................................................. 70
5.4.8 Wall thickness summary .................................................................................... 70
5.5 EXTERNAL INTERFERENCE PROTECTION ....................................................... 72
5.5.1 General .............................................................................................................. 72
5.5.2 Depth of cover ................................................................................................... 72
5.5.3 Depth of cover—Rock trench ............................................................................ 73
5.5.4 Design for protection—General requirements.................................................... 74
5.5.5 Physical controls................................................................................................ 75
5.5.6 Procedural controls ............................................................................................ 76
5.5.7 Other protection ................................................................................................. 78
5.6 PREQUALIFIED PIPELINE DESIGN ..................................................................... 78
5.6.1 Minimum requirements...................................................................................... 78
5.6.2 Prequalified design coverage ............................................................................. 78
5.6.3 Prequalified design does not apply..................................................................... 79
5.6.4 Prequalified design not permitted ...................................................................... 79
5.6.5 Prequalified design special cases ....................................................................... 79
5.7 STRESS AND STRAIN ............................................................................................ 80 5.7.1 General .............................................................................................................. 80
5.7.2 Terminology ...................................................................................................... 81
5.7.3 Stresses due to normal loads .............................................................................. 81
5.7.4 Stresses due to occasional loads......................................................................... 83
5.7.5 Stresses due to construction ............................................................................... 83
5.7.6 Hydrostatic pressure testing ............................................................................... 83
5.7.7 Fatigue ............................................................................................................... 84
5.7.8 Summary of stress limits.................................................................................... 84
5.7.9 Plastic strain and limit state design methodologies ............................................ 84
5.8 SPECIAL CONSTRUCTION.................................................................................... 85 5.8.1 General .............................................................................................................. 85
5.8.2 Above-ground piping ......................................................................................... 86
5.8.3 Pipeline with reduced cover or above ground .................................................... 86
5.8.4 Tunnels and shafts ............................................................................................. 89
5.8.5 Directionally drilled crossings ........................................................................... 89
5.8.6 Submerged crossings ......................................................................................... 89
5.8.7 Pipeline attached to a bridge .............................................................................. 90
5.8.8 Road and railway reserves ................................................................................. 91
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AS 2885.1—2007 12
5.9 PIPELINES ASSEMBLIES....................................................................................... 94 5.9.1 General .............................................................................................................. 94
5.9.2 Scraper assemblies............................................................................................. 94
5.9.3 Mainline valve assembly.................................................................................... 94
5.9.4 Isolating valve assembly .................................................................................... 94
5.9.5 Branch connection assembly.............................................................................. 94
5.9.6 Attachment of pads, lugs and other welded connections .................................... 95
5.9.7 Special fabricated assemblies............................................................................. 96
5.10 JOINTING................................................................................................................. 96 5.10.1 General .............................................................................................................. 96
5.10.2 Welded joints..................................................................................................... 96
5.10.3 Flanged joints .................................................................................................... 96
5.10.4 Threaded fittings................................................................................................ 97
5.10.5 Other types......................................................................................................... 97
5.11 SUPPORTS AND ANCHORS .................................................................................. 98
5.11.1 General .............................................................................................................. 98
5.11.2 Settlement, scour, and erosion ........................................................................... 98
5.11.3 Design................................................................................................................ 98
5.11.4 Forces on an above-ground pipeline................................................................... 98
5.11.5 Attachment of anchors, supports, and clamps .................................................... 98
5.11.6 Restraint due to soil friction............................................................................... 99
5.11.7 Anchorage at a connection ................................................................................. 99
5.11.8 Support of branch connections........................................................................... 99
SECTION 6 STATION DESIGN
6.1 BASIS OF SECTION .............................................................................................. 100
6.2 DESIGN .................................................................................................................. 100 6.2.1 Location........................................................................................................... 100
6.2.2 Layout.............................................................................................................. 101
6.2.3 Other considerations ........................................................................................ 101
6.2.4 Safety............................................................................................................... 101
6.3 STATION PIPEWORK ........................................................................................... 104 6.3.1 Design standard ............................................................................................... 104
6.3.2 Pipework subject to vibration........................................................................... 104
6.4 STATION EQUIPMENT......................................................................................... 105 6.4.1 General ............................................................................................................ 105
6.4.2 Pressure vessels ............................................................................................... 105
6.4.3 Proprietary equipment...................................................................................... 105
6.4.4 Equipment isolation ......................................................................................... 105
6.4.5 Station valves................................................................................................... 105
6.5 STRUCTURES........................................................................................................ 106 6.5.1 General ............................................................................................................ 106
6.5.2 Buildings ......................................................................................................... 106
6.5.3 Below-ground structures .................................................................................. 106
6.5.4 Corrosion protection ........................................................................................ 107
6.5.5 Electrical installations...................................................................................... 107
6.5.6 Drainage .......................................................................................................... 107
SECTION 7 INSTRUMENTATION AND CONTROL DESIGN
7.1 BASIS OF SECTION .............................................................................................. 109
7.2 CONTROL AND MANAGEMENT OF PIPELINE SYSTEM................................ 109 7.2.1 Pipeline pressure control.................................................................................. 109
7.2.2 Separation of pipeline sections with different MAOP ...................................... 111
7.2.3 Pipeline facility control.................................................................................... 111
7.3 FLUID PROPERTY LIMITS .................................................................................. 111
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13 AS 2885.1—2007
7.4 SCADA—SUPERVISORY CONTROL AND DATA ACQUISITIONS
SYSTEM ................................................................................................................. 111
7.5 COMMUNICATION............................................................................................... 112
7.6 CONTROL FACILITIES ........................................................................................ 112
SECTION 8 MITIGATION OF CORROSION
8.1 BASIS OF SECTION .............................................................................................. 113
8.2 PERSONNEL .......................................................................................................... 113
8.3 RATE OF DEGRADATION ................................................................................... 113 8.3.1 Assessment ...................................................................................................... 113
8.3.2 Internal corrosion............................................................................................. 114
8.3.3 External corrosion............................................................................................ 114
8.3.4 Environmentally assisted cracking................................................................... 114
8.3.5 Microbiologically induced corrosion (MIC) .................................................... 114
8.4 CORROSION MITIGATION METHODS .............................................................. 114 8.4.1 General ............................................................................................................ 114
8.4.2 Corrosion mitigation methods.......................................................................... 114
8.5 CORROSION ALLOWANCE................................................................................. 115
8.6 CORROSION MONITORING ................................................................................ 115
8.7 INTERNAL CORROSION MITIGATION METHODS.......................................... 116
8.7.1 General ............................................................................................................ 116
8.7.2 Internal lining .................................................................................................. 116
8.7.3 Corrosion inhibitors and biocides .................................................................... 116
8.7.4 Corrosion-resistant materials ........................................................................... 117
8.8 EXTERNAL CORROSION MITIGATION METHODS......................................... 117
8.8.1 General ............................................................................................................ 117
8.8.2 Coating ............................................................................................................ 117
8.8.3 Cathodic protection.......................................................................................... 118
8.8.4 Design considerations ...................................................................................... 118
8.8.5 Measurement of potential................................................................................. 119
8.8.6 Electrical earthing............................................................................................ 120
8.9 EXTERNAL ANTI-CORROSION COATING........................................................ 120 8.9.1 Coating system ................................................................................................ 120
8.9.2 Coating selection ............................................................................................. 120
8.9.3 Coating application .......................................................................................... 120
8.9.4 Joint and coating repair.................................................................................... 121
8.10 INTERNAL LINING............................................................................................... 121 8.10.1 Pipeline lining.................................................................................................. 121
8.10.2 Joint and repair lining ...................................................................................... 121
SECTION 9 UPGRADE OF MAOP
9.1 BASIS OF SECTION .............................................................................................. 122
9.2 MAOP UPGRADE PROCESS ................................................................................ 122 9.2.1 Process stages .................................................................................................. 122
9.2.2 Upgrade Design Basis...................................................................................... 122
9.2.3 Data collection................................................................................................. 123
9.2.4 Engineering analysis ........................................................................................ 124
9.2.5 Safety management study ................................................................................ 126
9.2.6 Rectification .................................................................................................... 126
9.2.7 Revised MAOP................................................................................................ 126
9.2.8 Approval .......................................................................................................... 126
9.2.9 Commissioning and testing .............................................................................. 126
9.2.10 Records............................................................................................................ 126
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AS 2885.1—2007 14
SECTION 10 CONSTRUCTION
10.1 BASIS OF SECTION .............................................................................................. 127
10.2 SURVEY................................................................................................................. 127
10.2.1 General ............................................................................................................ 127
10.2.2 Survey accuracy............................................................................................... 127
10.2.3 Horizontal directional drilled installation......................................................... 127
10.2.4 Records............................................................................................................ 128
10.3 HANDLING OF PIPE AND COMPONENTS......................................................... 128
10.3.1 General ............................................................................................................ 128
10.3.2 Pipe transport................................................................................................... 128
10.3.3 Construction loads ........................................................................................... 129
10.4 INSPECTION OF PIPE AND COMPONENTS ...................................................... 129 10.4.1 General ............................................................................................................ 129
10.4.2 Ovality ............................................................................................................. 129
10.4.3 Buckles ............................................................................................................ 129
10.4.4 Dents................................................................................................................ 129
10.4.5 Gouges, grooves and notches ........................................................................... 129
10.4.6 Repair of defects .............................................................................................. 129
10.4.7 Laminations and notches.................................................................................. 130
10.5 CHANGES IN DIRECTION ................................................................................... 130
10.5.1 Accepted methods for changes in direction...................................................... 130
10.5.2 Internal access.................................................................................................. 130
10.5.3 Changing direction at a butt weld .................................................................... 130
10.5.4 Bend fabricated from a forged bend or elbow .................................................. 130
10.5.5 Roped bends .................................................................................................... 130
10.6 COLD-FIELD BENDS ............................................................................................ 130 10.6.1 General ............................................................................................................ 130
10.6.2 Qualification of cold-field bending procedure.................................................. 131
10.6.3 Acceptance limits for field bends..................................................................... 131
10.7 FLANGED JOINTS ................................................................................................ 132
10.8 WELDED JOINTS .................................................................................................. 132
10.9 COVERING SLABS, BOX CULVERTS, CASINGS AND TUNNELS.................. 132
10.10 SYSTEM CONTROLS............................................................................................ 132
10.11 ATTACHMENT OF ELECTRICAL CONDUCTORS............................................ 133
10.11.1 General ............................................................................................................ 133
10.11.2 Aluminothermic welding ................................................................................. 133
10.12 LOCATION............................................................................................................. 134 10.12.1 Position............................................................................................................ 134
10.12.2 Clearances........................................................................................................ 134
10.13 CLEARING AND GRADING................................................................................. 134
10.14 TRENCH CONSTRUCTION .................................................................................. 134 10.14.1 Safety............................................................................................................... 134
10.14.2 Separation of topsoil ........................................................................................ 135
10.14.3 Dimensions of trenches.................................................................................... 135
10.14.4 Bottoms of trenches ......................................................................................... 135
10.14.5 Scour................................................................................................................ 135
10.15 INSTALLATION OF A PIPE IN A TRENCH ........................................................ 135
10.15.1 General ............................................................................................................ 135
10.15.2 Installation requirement ................................................................................... 135
10.15.3 Development of specifications and procedures ................................................ 136
10.16 PLOUGHING-IN AND DIRECTIONALLY DRILLED PIPELINES ..................... 136 10.16.1 General ............................................................................................................ 136
10.16.2 Testing of coating integrity within directionally drilled installations ............... 137
10.17 SUBMERGED CROSSINGS .................................................................................. 137
10.18 REINSTATEMENT ................................................................................................ 137 Lice
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15 AS 2885.1—2007
10.19 TESTING OF COATING INTEGRITY OF BURIED PIPELINES ......................... 137
10.20 CLEANING AND GAUGING PIPELINES ............................................................ 138
SECTION 11 INSPECTIONS AND TESTING
11.1 BASIS OF SECTION .............................................................................................. 139
11.2 INSPECTION AND TEST PLAN AND PROCEDURES........................................ 139
11.3 PERSONNEL .......................................................................................................... 139
11.4 PRESSURE TESTING ............................................................................................ 139 11.4.1 Application ...................................................................................................... 139
11.4.2 Exemptions from a field pressure test .............................................................. 139
11.4.3 Pre-tested pipe ................................................................................................. 139
11.4.4 Test procedure ................................................................................................. 140
11.4.5 Strength test pressures ..................................................................................... 140
11.4.6 Testing with a gas ............................................................................................ 140
11.4.7 Pressure-testing loads ...................................................................................... 141
11.4.8 Acceptance criteria .......................................................................................... 142
11.5 COMMENCEMENT OF PATROLLING................................................................ 142
SECTION 12 DOCUMENTATION
12.1 RECORDS............................................................................................................... 143
12.2 RETENTION OF RECORDS.................................................................................. 144
APPENDICES
A REFERENCED DOCUMENTS .............................................................................. 145
B SAFETY MANAGEMENT PROCESS ................................................................... 150
C THREAT IDENTIFICATION ................................................................................. 156
D DESIGN CONSIDERATIONS FOR EXTERNAL INTERFERENCE
PROTECTION ........................................................................................................ 160
E EFFECTIVENESS OF PROCEDURAL CONTROLS FOR THE PREVENTION OF
EXTERNAL INTERFERENCE DAMAGE TO PIPELINES .................................. 163
F QUALITATIVE RISK ASSESSMENT................................................................... 170
G ALARP.................................................................................................................... 174
H INTEGRITY OF THE SAFETY MANAGEMENT PROCESS ............................... 176
I ENVIRONMENTAL MANAGEMENT .................................................................. 184
J PREFERRED METHOD FOR TENSILE TESTING OF WELDED LINE PIPE
DURING MANUFACTURE ................................................................................... 186
K FRACTURE TOUGHNESS TEST METHODS ...................................................... 187
L FRACTURE CONTROL PLAN FOR STEEL PIPELINES..................................... 189
M CALCULATION OF RESISTANCE TO PENETRATION..................................... 199
N FATIGUE................................................................................................................ 204
O FACTORS AFFECTING CORROSION ................................................................. 207
P ENVIRONMENT-RELATED CRACKING............................................................ 210
Q INFORMATION FOR CATHODIC PROTECTION............................................... 217
R MITIGATION OF A.C. EFFECTS FROM HIGH VOLTAGE ELECTRICAL
POWERLINES........................................................................................................ 219
S PROCEDURE QUALIFICATION FOR COLD FIELD BENDS............................. 227
T GUIDELINES FOR THE TENSIONING OF BOLTS IN THE FLANGED JOINTS
OF PIPING SYSEMS.............................................................................................. 232
U STRESS TYPES AND DEFINITIONS ................................................................... 248
V EXTERNAL LOADS .............................................................................................. 255
W COMBINED EQUIVALENT STRESS ................................................................... 259
X PIPE STRESS ANALYSIS...................................................................................... 269
Y RADIATION CONTOUR ....................................................................................... 274
Z REINFORCEMENT OF WELDED BRANCH CONNECTIONS ........................... 278
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AS 2885.1—2007 16
Standards Australia www.standards.org.au
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 carbon-
manganese 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.
The fundamental principles and the practical rules and guidelines set out in AS 2885.1,
AS 2885.2, AS 2885.3 and AS 2885.5 are the basis on which an engineering assessment is
to be made where these Standards do not provide detailed requirements appropriate to a
specific item.
NOTE: AS 2885.4 for offshore submarine pipeline systems is a standalone document.
1.2 GENERAL
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.
Where this Standard imposes requirements, which add to or override the requirements of a
permitted Standard or code, the additional requirements are explicitly stated in this
Standard and shall be met.
1.3 RETROSPECTIVE APPLICATION
The Australian Standards for pipelines are subject to continuous improvement, and when a
new edition of a Standard is published, the new edition should be reviewed by the Licensee
to identify opportunities for improvement of existing systems.
Publication of a new Standard or new edition of a Standard does not, of itself, require
modification of existing physical assets constructed to a previous Standard or edition to a
Standard.
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17 AS 2885.1—2007
www.standards.org.au Standards Australia
It is, however, the intention that operation and maintenance procedures and practices for
pipelines comply with the most recent edition of AS 2885.3 to the extent practicable. Where
AS 2885.3 refers to AS 2885.1, AS 2885.2 and AS 2885.5, the relevant provision of the
most recent edition will need to be complied with.
Notwithstanding the above, this Standard introduces 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 Clause 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.
The response to other changes shall be assessed in accordance with the provision of this
Clause.
1.4 REFERENCED DOCUMENTS
The documents referred to in this Standard are listed in Appendix A.
1.5 DEFINITIONS
For the purpose of this Standard, the definitions given in AS 1929, AS 2812, AS 2832.1 and
those below, apply.
1.5.1 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.
1.5.2 Approved and approval
Approved by the Licensee, 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.
1.5.3 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.
1.5.4 Buckle
An irregularity in the surface of a pipe caused by a compressive stress.
1.5.5 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.
1.5.6 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).
1.5.7 Competent person
A person who has acquired through training, qualification, or experience, or a combination
of these, the knowledge and skills enabling the person to perform the task required.
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AS 2885.1—2007 18
Standards Australia www.standards.org.au
1.5.8 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).
1.5.9 Component
Any part of a pipeline other than the pipe.
1.5.10 Construction
Activities required to fabricate, construct and test a pipeline, and to restore the right of way
of a pipeline.
1.5.11 Control piping
Ancillary piping used to interconnect control or instrument devices or testing or proving
equipment.
1.5.12 Critical defect length
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.
1.5.13 Defect
A discontinuity or imperfection of sufficient magnitude to warrant rejection on the basis of
the requirements of this Standard.
1.5.14 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).
1.5.15 Failure
Failure has occurred if one or more of the of the following conditions apply:
(a) There is 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.
1.5.16 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.
1.5.17 Fluid
Any liquid, vapour, gas or mixture of any of these.
1.5.18 Gas
Any hydrocarbon gas or mixture of gases, possibly in combination with liquid petroleum,
condensates or water.
1.5.19 Heat
Material produced from a single batch of steel processed in the final steel making furnace at
the steel plant.
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1.5.20 High consequence area
A location where pipeline failure can be expected to result in multiple fatalities or
significant environmental damage.
1.5.21 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.
1.5.22 Hoop stress
Circumferential stress in a pipe or cylindrical pressure-containing component arising from
internal pressure.
1.5.23 Hot tap
A connection made to an operating pipeline containing hydrocarbon fluid.
1.5.24 Inspector
A person appointed by the Licensee to carry out inspections required by this Standard.
1.5.25 Leak test
A pressure test that determines whether a pipeline is free from leaks.
1.5.26 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.
1.5.27 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.
1.5.28 May
Indicates the existence of an option (see also ‘shall’ and ‘should’).
1.5.29 Mechanical interference-fit joint
A joint for pipe, involving a controlled plastic deformation and subsequent or concurrent
mating of pipe ends.
1.5.30 Nominated Standard
A Standard referred to in Clause 3.2.2.
1.5.31 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 non-
credible threat is not the same as a credible threat that has been controlled.
1.5.32 Non-location specific threat
Threats that can occur anywhere along the pipeline (e.g. corrosion).
1.5.33 Petroleum
Any hydrocarbon or mixture of hydrocarbons in a gaseous or liquid state and which may
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1.5.34 Pig
A device that is propelled inside a pipeline by applied pressure.
1.5.35 Pig trap (scraper trap)
A pipeline assembly to enable a pig to be inserted into or removed from an operating
pipeline.
1.5.36 Pipework, mainline
Those parts of a pipeline between stations, including pipeline assemblies.
1.5.37 Pipework, station
Those parts of a pipeline within a station that begin and end where the pipe material
specification changes to or from that for the mainline pipework.
1.5.38 Piping
An assembly of pipes, valves and fittings associated with a pipeline.
1.5.39 Pretested
The condition of a pipe or a pressure-containing component that has been subjected to a
pressure test in accordance with this Standard before being installed in a pipeline.
1.5.40 Pressure, design
The pressure nominated in the Design Basis for the purpose of performing calculations on
the mechanical and process design of the pipeline.
1.5.41 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.
1.5.42 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.
1.5.43 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.
1.5.44 Propagating fracture
A fracture that is not arrested within the length of pipe in which the fracture initiated.
1.5.45 Proprietary item
An item made or marketed by a company having the legal right to manufacture and sell it.
1.5.46 Protection measures, procedural
Measures for protection of a pipeline that minimize the likelihood of human activities with
potential to damage the pipeline.
1.5.47 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.
1.5.48 Regulatory authority
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1.5.49 Rupture
Failure of the pipe such that the cylinder has opened to a size equivalent to its diameter.
1.5.50 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.
1.5.51 Shall
Indicates that a requirement is mandatory (see also ‘may’ and ‘should’).
1.5.52 Should
Indicates a recommendation (see also ‘may’ and ‘shall’).
1.5.53 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.
1.5.54 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.
1.5.55 Strength test
A pressure test that confirms that the pipeline has sufficient strength to allow it to be
operated at maximum allowable operating pressure.
1.5.56 Telescoped pipeline
A pipeline that is made up of more than one diameter or MAOP, tested as a single unit.
1.5.57 Threat
Any activity or condition that can adversely affect the pipeline if not adequately controlled.
1.5.58 Wall thickness, design pressure (tP)
The wall thickness of pipe required to contain the design pressure, based on steel grade and
design factor.
1.5.59 Wall thickness, required (tW)
The greatest of the wall thicknesses required to meet the various design requirements
nominated in Clause 5.4.2.
1.5.60 Wall thickness, nominal(tN)
The wall thickness nominated for pipe manufacture or certified on supplied pipe.
1.6 SYMBOLS AND UNITS
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 mm2
CDL Critical defect length mm
CVN Upper shelf Charpy V-notch energy (Full size equivalent) J Lice
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AS 2885.1—2007 22
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Symbol Description Unit
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
Dmax Greatest diameter mm
Dmin 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
Kc In plane stress intensification factor (fracture initiation toughness) MPa/mm0.5
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
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) MPa
SF Statistical factor used to calculate minimum toughness for any heat
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
t Wall thickness 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
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Symbol Description Unit
HS∆ Stress for longitudinal welds (consistent with API RP 1102) MPa
LS∆ Stress for girth welds (consistent with API RP 1102) MPa
σ Stress MPa
σc Combined equivalent stress MPa
Eσ Expansion stress MPa
flowσ Flow stress = SMYS + 10 ksi for fracture control MPa
Hσ Hoop stress MPa
Lσ Longitudinal stress MPa
Oσ Occasional stress MPa
SUSσ Sustained stress MPa
Uσ Ultimate tensile strength MPa
Yσ Specified minimum yield strength (SMYS) MPa
ν Poisson’s ratio (stress and strain)
1.7 ABBREVIATIONS
Abbreviations Meaning Unit
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
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
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AS 2885.1—2007 24
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LPG Liquefied petroleum gas
MAOP Maximum allowable operating pressure MPa
MLV Main line valve
MOP Maximum operating pressure MPa
O&M Operation and maintenance
P&ID Piping and instrumentation diagram
PDR Public draft
PRCI Pipeline research council international
QC Quality control
SAOP Safety and operating plan
SAW 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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25 AS 2885.1—2007
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S E C T I O N 2 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.
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 4360.
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 SAOP.
This Standard includes requirements for management of construction safety, electrical
safety and environmental impacts.
2.2 ADMINISTRATIVE REQUIREMENTS
2.2.1 Approval
The safety management study and its components shall be approved.
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AS 2885.1—2007 26
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2.2.2 Documentation
2.2.2.1 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).
2.2.2.2 Safety and operating plan (SAOP)
Where threat control requires actions by the Licensee, the obligations of the Licensee shall
be documented in the SAOP. The SAOP shall identify these actions including the
implementation of specific risk management actions as an integral part of pipeline safety
management.
NOTES:
1 Because the SAOP 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 SAOP.
2 The detailed requirements for the incorporation of the safety management study are provided
in AS 2885.3.
2.2.3 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.
2.2.4 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.
2.2.5 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.
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(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
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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Prel iminary descript ionof design and operation
Common threats/common threat location/
standard design
Location analysis
Threat identi f icat ionNon location
specif ic threats
Is threat credible?
Apply external interference protection(where applicable)
Apply design & procedures
Failure possible?Apply further design
&/or procedures
Canfurther threat controls
be applied?
AS 4360Residual threats r isk assessment
Final design & SAOP
Risk & design accepted
Risk acceptable
Th
rea
t id
en
tifi
ca
tio
nT
hre
at
co
ntr
ol
Re
sid
ua
l ri
sk
as
se
ss
me
nt
No
No
YesNo
Yes
Yes
Yes
No
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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The same safety management process applies to both location-specific and non-location-
specific 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
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.
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.
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 4360.
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.
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AS 2885.1—2007 32
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(h) Environmental effects at the location (e.g. wind).
(i) 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 4360.
Appendix F provides the requirements for qualitative risk assessment and it provides a risk
matrix to be used in an AS 4360 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.
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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33 AS 2885.1—2007
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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.
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 approved 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.
The environmental severity classes that apply to the pipeline project shall be defined and
approved. Specification of environmental impacts shall, as far as practicable, be expressed
in quantified terms.
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.
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AS 2885.1—2007 34
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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.
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.
At least the following shall be addressed:
(a) Approved 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.
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(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.
(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.
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
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.
Commissioning safety shall comply with AS 2885.3.
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AS 2885.1—2007 36
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S E C T I O N 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, 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 the nominated Standards 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.
3.2.2 Materials and components complying with nominated Standards
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:
(a) Pipe—Carbon/carbon manganese steel pipe. API Spec 5L, ISO 3183, ASTM A53,
ASTM A106 and ASTM A524. 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) Furnace welded (CW) pipe shall not be used for pressure containment.
(iii) The integrity of any seam weld shall be demonstrated by non-destructive
examination of the full length of the seam weld.
(iv) The integrity of each pipe length shall be demonstrated by hydrostatic testing as
part of the manufacturing process.
(v) Wall thickness tolerance—where the design factor exceeds 0.72—
(A) the minimum weight tolerance in API 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 5.4.4); and
(C) the minimum permissible wall thickness after grind repair or internal trim
for pipe manufactured by seamless, ERW or laser methods, shall be 90%
of nominal wall thickness for material with an SMYS up to 483 MPa
(X70) and 92% for material with an SMYS up to 552 MPa (X80).
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37 AS 2885.1—2007
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(b) Corrosion-resistant alloys—API SPEC 5LC and API 5LD
(c) Fibreglass pipe—API SPEC 15LR, API 15HR or ISO 14692-1 and ISO 14692-2
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 Section VIII, BS 5500,
AS/NZS 1200 ASME B16.11, ASME B16.25, ASME B16.28, ASTM A105,
ASTM A234, 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, API Std 602, API Std 603,
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 A194,
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.
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.
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AS 2885.1—2007 38
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(ii) Experimental stress analysis.
(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).
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).
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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.
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.
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 5L is given in Appendix J.
3.4.2 Pipe Yield to Tensile Ratio
For cold expanded pipe the API 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.
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AS 2885.1—2007 40
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3.4.3 Strength de-rating
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.
Where the pipeline design temperature is above 65°C the yield strength of the pipe steel
shall be derated. 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
For pipelines carrying gas or HVPL the following shall apply;
(a) Pipe of size DN100 and larger, and of wall thickness 6.1 mm and thicker, shall be
demonstrated to have a minimum Charpy toughness.
(b) The test temperature shall be 0°C or lower.
(c) The minimum specimen size shall be half size.
(d) Transverse specimens shall be tested where geometry permits, or longitudinal
specimens otherwise.
(e) The minimum toughness (average of 3) tested on a per heat basis 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.
NOTES:
1 Pipe that meets the toughness requirements of API 5L PSL2 meets this requirement.
2 The fracture control plan developed in accordance with Clause 4.8.2 may require more
stringent toughness, or different test temperatures from those nominated above, based on a
detailed analysis of the pipeline and its operating conditions.
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 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 derated 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.
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—2007 42
Standards Australia www.standards.org.au
S E C T I O N 4 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. Where required by this Standard, the design shall be
approved.
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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43 AS 2885.1—2007
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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.
Scraper launcher Inl ine scraper faci l i ty
Booster stat ion
Main l ine valve
Branch connection
Scraper receiver
Supply stat ion
Offtake stat ion
Station
Pipel ine
Receipt stat ion
Pipel ine
Station
1 1
1
NOTE: The break between pipeline and station shall be defined for each station.
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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AS 2885.1—2007 44
Standards Australia www.standards.org.au
4.2.3 Route selection
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. Lice
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45 AS 2885.1—2007
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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/m2 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.
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.
Land through which the pipeline passes shall be classified as follows:
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AS 2885.1—2007 46
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(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.
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.
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.
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47 AS 2885.1—2007
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(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.
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) Land defined as a Common Infrastructure Corridor (CIC), or which because of its
function results in multiple (more than one) 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 (eg, 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 they meet the design criterion.
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.
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.
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AS 2885.1—2007 48
Standards Australia www.standards.org.au
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
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.
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. Lice
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49 AS 2885.1—2007
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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.
NOTE: For guidance on the effectiveness of procedural measures, including signs, in contributing
to pipeline awareness, see Appendix E.
350-450
150
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 Lice
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AS 2885.1—2007 50
Standards Australia www.standards.org.au
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 shall be approved.
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.
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.
(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) Minimum design and installation criteria for the pipeline and stations
(f) Design requirements for internal inspection tools, including bend radius, internal pipe
diameter and scraper trap dimensions and design criteria.
(g) 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.
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51 AS 2885.1—2007
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(vi) Limiting conditions.
(vii) Corrosion mitigation strategy.
(h) Design principles established as the basis of detailed design.
(i) Design philosophies established to guide development of the detailed design.
(j) The location of facilities and their functionality.
(k) Communications and control principles.
(l) Inspection and testing principles.
(m) System reliability principles.
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:
(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 approved 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.
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AS 2885.1—2007 52
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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.
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 =M
TPE
P
F . . . 4.5.4(1)
The equivalent test pressure factor FTPE shall be calculated from the following formula:
FTPE = TP
P
P
t GF
t
+
. . . 4.5.4(2)
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.
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.
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
The minimum strength test pressure (PTMIN) of the pipeline system shall be calculated from
the following formula:
PTMIN =PDFTPE . . . 4.5.5
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53 AS 2885.1—2007
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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).
4.6 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.
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.
(vi) 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.
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AS 2885.1—2007 54
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(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 shut down 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;
(d) modifications are made to a pipeline which affect the isolation plan or require new
isolation facilities
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.
TABLE 4.6.4
GUIDE FOR THE SPACING OF MAINLINE VALVES
Location class Recommended maximum spacing of valves, km
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.
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55 AS 2885.1—2007
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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.
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), Heavy Industry (HI) and Sensitive (S)
location classes, 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.
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.
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AS 2885.1—2007 56
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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, Industrial
and Sensitive locations or 1 GJ.s−1
in High Density 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.
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 land use planning (or land use) changes along the route of existing pipelines to
permit Residential, High Density, Industrial, Heavy Industry or Sensitive development in
areas where these uses were previously prohibited, a safety assessment shall be undertaken
and additional measures implemented until it is demonstrated that the risk from a loss of
containment involving rupture is ALARP.
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.
4.8 FRACTURE CONTROL
4.8.1 General
Except where the design of a pipeline provides for the carriage of a stable liquid where the
minimum design pipe temperature is above 0°C, the engineering design of the pipeline shall
include preparation of a fracture control plan. The fracture control plan shall apply only to
line pipe and shall define the measures to be implemented to limit propagation of fast
fracture.
NOTE: The following two fast fracture modes are known to occur in pipelines:
(a) A brittle fracture in which the fracture propagates in the predominantly cleavage mode at or
below the transition temperature of the pipe steel. The appearance of the fracture surface is
crystalline.
(b) A tearing fracture (commonly called ductile fracture) in which the fracture propagates 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.
Low temperatures caused during pressure changes in commissioning or in operation shall be
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57 AS 2885.1—2007
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The fracture control plan shall be approved.
Gas and l iquid petroleum f luids
Other f luids(eg. r ich gases,
other gases,other l iquids,
HVPL’s)Stablel iquids
Leannatural
gas
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 CO2.
FIGURE 4.8.1 CLASSIFICATION OF PIPELINE FLUIDS FOR THE FRACTURE
CONTROL PLAN
4.8.2 Fracture control plan
The requirements of the fracture control plan are as follows:
(a) The fracture control plan shall apply only to line pipe.
(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) The design fracture arrest length (expressed as the number of pipe lengths each
side of the point of initiation).
(iii) The methods of providing for crack arrest.
(iv) The method for ensuring that the longitudinal weld seam (weld metal and HAZ)
has adequate levels of fracture toughness to minimize the likelihood of fracture
initiation in T1, T2, I and S class locations.
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.
(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
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AS 2885.1—2007 58
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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.)
(e) 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).
(iii) For all pipelines in T1, T2, I and S class locations, the method for ensuring the
following:
(A) Rupture is not a credible failure mode in accordance with Clause 4.7.2.
(B) The maximum energy release rate is controlled to the limit defined in
Clause 4.7.3.
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.
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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59 AS 2885.1—2007
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Fracturecontrol
Control of bri t t lefracture
Yes
Yes
Yes
Stablel iquid
Control of tearingfracture
MAOP 40%SMYS
Use Battel le shortform equation
Use Battel le two curvemodel & fudge factor
1.4 i f X80
T1 or T2
Apply special provisionfor high consequence
areas (Clause 4.7)
Yes
Yes
Yes
Yes
Yes
Brit t le and tearingfracture arecontrol led
Stablel iquid
Td 0°C
FRACTURECONTROLPLAN NOTREQUIRED
t 5 mm or DN 300
DWTT FATTshall be Td
Lean gasMAOP 15.3 MPa
grade X70
DOCUMENTEDFRACTURE
CONTROL PLAN
Designstress
85 MPa
DN 200MAOP
10.5 MPa
Yes DN 300 orpressure 10.5 MPa
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
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AS 2885.1—2007 60
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4.8.3 Specification of toughness properties for brittle fracture control
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 pipe stress exceeds the threshold stress
for brittle fracture (see Appendix L, Paragraph L5. 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.
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.
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 (tW) 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.
1 1
5 2 3 3H w
2.836 10 ( ) ( )CVN D tσ−
= × . . . 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).
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.
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 specified arrest toughness shall be the highest toughness determined in
accordance with Clause 4.8.4.1(b).
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AS 2885.1—2007 62
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(e) The arrest length specified in Table 4.8.2.1 is determined from a statistical
assessment of the toughness distribution normally delivered in a project pipe order
(the toughness distribution by heat).
NOTE: For guidance on the statistical methodology required to determine the arrest length,
see Appendix L.
4.8.4.2 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.
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 = flow
TM
σ
. . . 4.8.5(1)
MT =
( )
0.5
2 4
2
2W
W
1 1.255 0.0135
2 2
c c
D Dt t
+ −
. . . 4.8.5(2)
CDL = 2c . . . 4.8.5(3)
Equation 4.8.5(1) applies to the limiting condition of flow stress or plastic instability,
recognising that increasing the steel toughness beyond a certain value will not increase the
size of a limiting defect. 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.
KC2 =
( )2
flow T H
flow
8ln.sec
2
c Mσ π σ
π σ
. . . 4.8.5(4)
KC may be estimated from the Charpy V-notch test toughness according to:
2
CK
E =
C
CVN
A . . . 4.8.5(5)Li
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63 AS 2885.1—2007
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For design and the safety management study, the CDL shall be defined for σH at MAOP
(see Note 1).
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.
σH = ( )
( )
W
W
flow
W
W T
1
1
d
t
d
t M
σ
−
−
. . . 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.
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.
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AS 2885.1—2007 64
Standards Australia www.standards.org.au
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.
Where the identified hole size is small relative to the diameter of the pipe (<25%), the fluid
discharge rate is relatively independent of the time from the initial release the energy
release rate may be calculated using steady state methods.
The radiation contour shall be calculated using the method described in API RP 521 for an
energy contour of 12.6 kW/m2 and 4.7 kW/m
2.
This calculation methodology is known to be conservative, but is considered appropriate for
the uses required by this Standard.
Radiation contours for various pipe sizes and ‘typical’ gases and the API RP 521 equation
are provided in Appendix Y.
NOTES:
1 For gas pipelines with a MAOP of 10.2 MPa the radiation contour in metres is usually
numerically equal to the pipeline diameter in millimetres.
2 For pipelines transporting hydrocarbon liquids the total volume of the release should be
considered.
3 For pipelines transporting HVPLs, the sustained energy release rate resulting from
vaporization of the liquid phase should be considered.
4 ASME B31.8S contains a simplified equation for radiation consequence distance, however
this equation must not be used in determining the radiation consequence distance for use in
AS 2885.1.
4.11 RESISTANCE TO PENETRATION
4.11.1 General
Pipeline wall thickness provides a measure of resistance to penetration by force from an
external interference threat. The resistance to penetration varies with thickness, pipe
material properties, and the physical parameters of the threat.
In some locations, resistance to penetration does not govern wall thickness selection
because there are no identified external interference threats, or because the consequences of
penetration does not cause a risk higher than low.
This Standard provides a method for calculating the resistance to penetration from
excavator threats and, within limits, the method may be used for calculating resistance to
threats from tractor-mounted rippers.
NOTE: While this Clause is focused on pipe damage by penetration, the usual consequence of an
excavator attack is a dent and gouge. Dent-gouge combinations work synergistically to
significantly lower the pressure at which a pipe fails and hence can be a particularly dangerous
form of damage. While there has been considerable research on the dent-gouge consequence of an
excavator attack, it has not developed to a stage where design information can be included in this
Standard. Section 10 of this Standard and AS 2885.3 have specific requirements relating to dent
and gouge combinations.
4.11.2 Penetration resistance requirements
Where resistance to penetration is selected as a physical threat control at a location, the
design methodology and requirements for resistance to penetration shall be defined.
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65 AS 2885.1—2007
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In R1 and R2 areas there is no mandatory requirement for penetration resistance beyond
that provided by the pressure design wall thickness although it may be selected as a
physical method of protection if required by the safety management study.
Where a pipeline route is deliberately chosen so that isolated buildings occur within the
12.6 and 4.7 kW/m2 radiation contours in R1 and R2 areas, localized increased protection
against external interference should be provided, including increased penetration resistance
where appropriate. The objectives for increased protection and the methods adopted shall be
defined within each radiation contour and shall be considered in the safety management
study.
In T1 and T2 areas, and in secondary location classes S and I, penetration resistance shall
satisfy the requirements of Clause 4.7 (high consequence areas) for the respective locations.
4.11.3 Calculation of resistance to penetration
The effectiveness of resistance to penetration may be determined using one of the following
methods:
(a) Calculation in accordance with Appendix M or other approved method
(b) Physical testing.
(c) Comparison with previous physical tests, provided the tests were performed on pipe
of similar or lower grade and wall thickness and with a similar or larger test machine.
The following parameters should be calculated for each wall thickness and tooth type in
order to provide reference data for the safety management study, regardless of whether
penetration resistance is selected as a physical control:
(i) Resistance to penetration from an excavator threat (i.e. minimum size of excavator
capable of puncturing the pipe).
(ii) Dimensions of the puncture hole resulting from the maximum identified threat, and
the resulting failure mode. The failure mode due to penetration may be:
(A) rupture if maximum hole length ≥ critical defect length;
(B) leak if maximum hole length < critical defect length; or
(C) no penetration.
NOTE: For information on determination of puncture hole sizes, see Appendix M.
The design threat at each location is identified through detailed research on threats to the
pipeline undertaken as part of the safety management study (see Appendix B). For
resistance to penetration calculation, the threat is usually expressed in terms of the
following parameters:
(1) Equipment type
(2) Equipment mass
(3) Penetrator (tooth) type
(4) Penetrator dimensions
(5) Factor B (see Appendix M)
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AS 2885.1—2007 66
Standards Australia www.standards.org.au
S E C T I O N 5 P I P E L I N E D E S I G N
5.1 BASIS OF SECTION
This Section sets out requirements for the design of the pipeline and fabricated assemblies
such as isolation valves, scraper stations and branch connections. Stations, including
compressor and pump stations, meter stations and regulator stations are covered in
Section 6.
The design requirements shall include, but are not limited to the following:
(a) The wall thickness shall be no less than that required for pressure containment
determined from the design pressure and a design factor.
(b) Additional wall thickness may be required to provide protection against damage by
external interference and for resistance to other load conditions and failure
mechanisms or to provide allowance for loss of wall thickness due to corrosion,
erosion or other causes.
(c) The pipeline shall be protected against corrosion and external interference.
(d) The pipeline shall be pressure-tested in accordance with AS 2885.5 to verify that it is
leak tight and has the required strength.
(e) A pipeline may be telescoped where the design pressure decreases progressively
along the pipeline and a suitable pressure control is provided.
(f) The pipeline should be designed so that its integrity can be monitored by the use of
internal testing devices without taking the pipeline out of service.
NOTE: Where a pipeline is constructed from fibreglass material, ISO 14692-3 provides guidance
on design procedures for this material.
5.2 DESIGN PRESSURE
5.2.1 Internal pressure
The internal design pressure of any component or section of a pipeline shall be not less than
the highest internal pressure to which that component or section will be subjected except
during transient conditions.
For all pipelines the internal design pressure shall consider the pressure effect of the head
associated with the density of the fluid.
Where the hydraulic gradient is used as the basis of establishing the internal design pressure
at any location the method of detecting and controlling the internal pressure at any location
within the design limit shall be documented in the Design Basis.
5.2.2 External pressure
Pressures from external loads and hydrostatic pressures shall be considered in the pipeline
design including the following:
(a) Soil load Where pipe is buried with a depth of cover of more than 3 m, stresses in the
pipe caused by soil loads shall be determined and combined with stresses due to other
loads. Where pipe is buried with a depth of cover of not more than 3 m, stresses in the
pipe caused by soil loads may be ignored.
(b) Hydrostatic pressure The pipeline shall be designed to accommodate the external
hydrostatic pressure.
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67 AS 2885.1—2007
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5.3 DESIGN TEMPERATURES
A number of design temperatures and their associated design pressures shall be determined.
The following conditions shall be considered and, where appropriate, a design temperature
selected for that aspect of the pipeline:
(a) Fracture control.
(b) Material strength.
(c) Coating performance.
(d) Stress Corrosion cracking.
(e) Fluid/phase changes.
(f) Temperature excursions during depressurization, repressurization and commissioning
activities.
(g) Temperature excursions associated with operating conditions, (e.g. temporary
pressure reduction by throttling using a MLV bypass valve).
(h) Stress analysis.
Consideration shall be given to the effect of temperature differential during installation,
operation and maintenance and, where appropriate, the temperature differential shall be
specified.
Consideration of ambient temperature is required for a pipeline wholly or partially above
ground, and during construction and maintenance.
Where a pipeline is above ground, the temperature resulting from the combined effect of
ambient temperature and solar radiation shall be specified for both operating and shut-in
conditions.
Special consideration may be required where the temperature of the fluid is changed by
pressure reduction, compression or phase change.
Design temperatures shall be approved.
5.4 WALL THICKNESS
At any location along the pipeline the wall thickness shall comply with the requirements of
this Clause.
5.4.1 Nominal wall thickness (tN)
The nominal wall thickness (tN) is—
(a) the thickness nominated on the pipe purchase order (design stage); or
(b) the thickness nominated on the manufacturer’s material certificates (for operating
pipelines).
The nominal wall thickness shall be not less than the greatest of the following:
(a) The required wall thickness plus any allowances plus any manufacturing tolerances:
tN ≥ tw + G + H . . . 5.4.1
(b) The thickness necessary for construct ability of the pipeline.
(c) The thickness necessary for initial hydrostatic testing plus manufacturing tolerance
where necessary.
NOTE: Where the nominal thickness is determined by calculating a value and then rounding up to
the nearest standard thickness the additional thickness due to rounding can be considered as a
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AS 2885.1—2007 68
Standards Australia www.standards.org.au
5.4.2 Required wall thickness (tW)
The required wall thickness (tW) shall be the greatest of the following:
(a) The thickness required for pressure containment (tP).
(b) The thickness required for resistance to penetration by the design threat, if this is
used as a method of providing external interference protection in accordance with
Clause 5.5. In T1 and T2 location classes, where thickness is the method chosen to
provide penetration resistance, the thickness necessary to provide a minimum level of
penetration resistance.
(c) The thickness required to provide the minimum critical defect length needed to
prevent rupture in location classes T1 and T2, or elsewhere if required by the Design
Basis.
(d) The thickness required to satisfy the stress and strain criteria.
(e) The thickness required to control fast running fracture.
(f) The thickness required for ‘special construction’.
(g) The thickness required to satisfy the stress criteria in Clause 5.7.3 for piplelines
crossing railways and roads.
(h) The thickness required to achieve a design stress level selected for its contribution to
SCC mitigation at locations where the SCC likelihood is increased by operation at
temperatures above 45°C, and at locations subject to high operating pressure range.
(i) The thickness required to achieve adequate fatigue life where this is determined to be
a consideration in the operating life of the pipeline.
(j) The thickness required to prevent collapse from external pressure.
NOTE: Where calculations in this standard include wall thickness as independent variable,
the value to be used is the required wall thickness (tW) unless specified otherwise.
5.4.3 Wall thickness for design internal pressure (tP)
The wall thickness for design internal pressure (tP) of pipes and pressure-containing
components made from pipe shall be the thickness determined by the following equation:
tP =
D
D Y2
P D
F σ
. . . 5.4.3
In Equation 5.4.3, σY shall be the specified minimum yield strength taken from the
nominated Standard for the material used for the pipe.
The design factor (FD) for pressure design of pipe shall be not more than 0.80, except for
the following for which the design factor shall be not more than the values nominated in
Table 5.4.3.
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69 AS 2885.1—2007
www.standards.org.au Standards Australia
TABLE 5.4.3
MAXIMUM VALUE OF DESIGN FACTOR
Location Maximum value of FD
Pipeline assemblies 0.67
Any section of a telescoped pipeline for which the
MAOP is based on a test pressure factor of less than
1.25
0.60
Pipelines on bridges or other structures 0.67
NOTE: Additional conservatism provided by the mandated design factor in Table 5.4.3
is considered an appropriate method of providing a specific safety allowance for loads
that might not be readily identified and calculated, and which as a result of
construction methods or operating conditions, may significantly exceed the design
load.
5.4.4 Wall thickness for design internal pressure of bends
The minimum wall thickness for design internal pressure of bends shall be determined by
the following equations:
2
D P
P
D Y
P D Ft
F σ
= . . . 5.4.4(1)
At the extrados of the bend:
( )M
M
P
rR
rRF
+
+
=
2
2 . . . 5.4.4(2)
At the intrados of the bend:
( )M
M
P
rR
rRF
−
−
=
2
2 . . . 5.4.4(3)
The variation of wall thickness from the extrados to the intrados and along the length of the
bend shall be gradual. The minimum pressure factor (FP) at the end tangents shall have a
value not less than unity uniformly around the pipe section. At the bend centre-line the
pressure factor FP has a minimum value of 1.0.
The value of the design factor for pressure containment (FD) shall comply with the
limitations of Clause 5.4.3.
5.4.5 Wall thickness design for external pressure
The permitted external pressure (PEXT) shall be determined from the minimum solution to
the following equation:
2
EXT P EL EXT EL P
W
1.51 0
f DP P P P P P
t
°
− + + + =
. . . 5.4.5(1)
where
PEL = ( )
3
W
2
M
2
1
tE
Dν
− . . . 5.4.5(2)
PP = W
D y
M
2t
FD
σ
. . . 5.4.5(3)
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AS 2885.1—2007 70
Standards Australia www.standards.org.au
fo = max minD D
D
−
. . . 5.4.5(4)
DM = D − tW . . . 5.4.5(5)
In Equation 5.4.5(3), σY shall be the specified minimum yield strength taken from the
nominated standard for the material used for the pipe.
5.4.6 Allowances (G)
Allowances shall be added to the required wall thickness of pipe to provide for identified
factors that may, during construction or over the life of the pipeline result in loss of
thickness. Allowance may be made to compensate for a reduction in thickness due to
corrosion, erosion, threading, machining and any other necessary additions. The allowance
G is the sum of all allowances made to the pipe wall thickness.
The hydrostatic test pressure requirements (see Clause 4.5.4) should be considered when
determining the total allowance applied to any part of the pipeline.
The components of the allowance shall comply with the following:
(a) Corrosion or erosion allowance Where a pipe or a pressure-containing component
made from pipe is subject to any corrosion or erosion, G shall include an amount
equal to the expected loss of wall thickness. A corrosion allowance is not required
where satisfactory corrosion mitigation methods are employed (see Section 8).
NOTE: Further requirements for corrosion allowance are specified in Clause 8.5.
(b) Threading, grooving and machining allowance Where a pipe or a pressure-
containing component made from pipe is to be threaded, grooved or machined, G
shall include an amount equal to the depth that will be removed. Where a tolerance
for the depth of cut is not specified, the allowance shall be increased by 0.5 mm.
5.4.7 Pipe manufacturing tolerance (H)
For line pipe manufactured from strip or plate to nominated standards, such as API 5L,
manufacturing tolerance shall not be added to the required wall thickness tW.
Seamless pipe manufacturing can result in local thinning or minimum thickness along the
length of one side whilst still complying with specified weight tolerance. Pipe manufactured
by the seamless process may require addition of a manufacturing tolerance (H) to the
required wall thickness (tW).
NOTE: This Standard limits the manufacturing tolerance for pipe manufactured for use at design
factors above 0.72 (see Clause 3.2.2(a)).
5.4.8 Wall thickness summary
Figure 5.4 illustrates the relationships between the various components of wall thickness.
Table 5.4.8 provides further illustration using hypothetical numerical values.
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71 AS 2885.1—2007
www.standards.org.au Standards Australia
Inte
rna
lp
res
su
re
Hy
dro
sta
tic
tes
tin
g
Co
ns
tru
cta
bil
ity
Cri
tic
al
de
fec
t le
ng
th
A l lowances
Manufactur ing to lerance (Note 2)
Pe
ne
tra
tio
nre
sis
tan
ce
Oth
ers
as
pe
rC
lau
se
5.4
.2
t P
t W
G
H
tN
NOTES:
1 In this example it happens that the nominal thickness is governed by the thickness required
for penetration resistance plus allowances, but any of the other requirements may govern
depending on the circumstances of the pipeline.
2 Manufacturing tolerance is zero except where the pipe is seamless and a tolerance is required
by the design.
FIGURE 5.4 WALL THICKNESS COMPONENTS
TABLE 5.4.8
EXAMPLES OF WALL THICKNESS DETERMINATION
Example 1 2 3 4
Location Remote outback
(R1)
Suburban (T1) Remote (R1) Scraper station
piping
Contents Sales gas Sales gas Raw gas Sales gas
Pipe manufacture ERW ERW ERW Seamless
tP mm (see Note) 2.2 7.9 6.7 10.9
Other components of
required thickness
Either not
applicable or <tP
Penetration
resistance
10.5 mm others
<tP
Either not
applicable or <tP
Either not
applicable or <tP
tw mm (max of above) 2.2 10.5 6.7 10.9
Allowances and
manufacturing tolerance
Nil Nil
Internal corrosion
allowance
G = 3 mm
12.5%
manufacturing
tolerance for
seamless pipe
H = 1.4 mm
Constructability and
hydrostatic test
4.0 mm min
practical
thickness
No special
requirement
No special
requirement
Round up to next
standard size,
12.7 mm
tN, mm (max of above) 4.0 10.5 6.7 + 3 = 9.7 12.7
NOTE: Example values for tP are realistic for commonly used values of diameter, design pressure,
SMYS and design factor, but details of these parameters are not central to this illustration.
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AS 2885.1—2007 72
Standards Australia www.standards.org.au
5.5 EXTERNAL INTERFERENCE PROTECTION
5.5.1 General
A pipeline shall be designed with the intent that identified activities of third parties will not
cause injury to the public or pipeline personnel, loss of contents that would damage the
environment, or disruption of service.
A pipeline shall be designed so that multiple independent physical controls and procedural
controls are implemented to prevent failure from external interference by identified threats.
The purpose of physical controls is to prevent failure resulting from an identified external
interference event by either physically preventing contact with the pipe, or by providing
adequate resistance to penetration in the pipe itself.
The purpose of procedural controls is to minimise the likelihood of external interference
activity, with potential to damage a pipeline, occurring without the knowledge of the
pipeline operator, and to maximise the likelihood of people undertaking such activity being
aware both of the presence of the pipeline and the possible consequences of damaging it.
A complete package of external interference protection controls also includes safe operating
procedures for working near a pipeline and an emergency response plan. These are covered
in AS 2885.3.
NOTES:
1 Guidance on design considerations for external interference protection is given in
Appendix D.
2 Guidance on effectiveness of procedural controls for the prevention of external interference
damage to pipelines is given in Appendix E.
5.5.2 Depth of cover
Burial is mandatory unless the conditions of Clause 5.8.2 or 5.8.3 and Figure 5.8.3 are met.
Table 5.5.2 specifies the minimum depth of cover for each location classification. The
minimum cover requirements may be reduced where other physical controls provide
effective physical protection to the pipeline.
Additional protection shall be provided where the minimum depth of cover cannot be
attained because of an underground structure or other obstruction, or maintained because of
the action of nature (e.g. soil erosion, scour).
The depth of cover over a pipeline shall be taken as the vertical distance from the top of the
pipeline or casing to the lower side of the finished trench.
Specific requirements are established for pipelines in road and rail reserves in
Clauses 5.7.3(c)(A) and 5.8.8.
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73 AS 2885.1—2007
www.standards.org.au Standards Australia
TABLE 5.5.2
MINIMUM DEPTH OF COVER
Minimum depth of cover (mm) Contents Location class
Normal excavation Rock excavation
(see Notes 1 to 5 to
Figure 5.5.3)
T1, T2, W 1200 900 HVPL (see Note 1)
R1, R2 900 600
W 1200 900
T1, T2, 900 600
Other than HVPL
R1, R2 750 450
NOTES:
1 HVPL or dense phase fluids.
2 The minimum depth of cover applying to the primary location class shall be applied to location sub-
classes.
5.5.3 Depth of cover—Rock trench
Figure 5.5.3 shall be used in applying the reduced cover provisions of Table 5.5.2 in areas
classified as continuous rock.
At locations where cover is reduced in rock, normal cover shall continue for a minimum
distance of 1200 mm into the rock. The minimum length of continuous rock over which a
reduction of the depth of cover for rock may be applied shall be 50 m.
1 200 min.1 200 min.
Normal cover(Table 5.5.2)
Rock cover(Table 5.5.2)
Rock cover(Table 5.5.2)
50 000 min.Naturalgroundelevation
SoilRock NOTES:
1 This Standard defines ‘rock’ as material with a uniaxial compressive strength greater than 50 MPa. For
field assessment, hand held specimens of the weakest material in this classification can be broken by a
single blow with a geological hammer. This material requires excavation by special ‘rock’ excavation
equipment, or by blasting. Material satisfying this criteria are defined as Class A—Strong rock in
AS 1170.4.
2 To provide effective physical protection, the rock forming the trench walls must be generally vertical,
unbroken, and containing few fractures.
3 Good practice requires that the trench design be based on the depth required to provide the minimum cover
at the lowest rock elevation. Pipe should be laid with the top of pipe at this elevation until changed by
another governing feature, rather than varying the elevation as the rock surface elevation changes.
4 Design measures should ensure that selected material specified to protect the pipeline coating and to ensure
continuity of an electrolyte for continuous cathodic protection will not erode with time when protected by a
porous crushed rock backfill.
5 Marker tape shall be installed above the pipe over the full extent of rock excavation.
DIMENSIONS IN MILLIMETRES
FIGURE 5.5.3 DEPTH OF COVER IN ROCK Lice
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5.5.4 Design for protection—General requirements
The pipeline design shall identify and document the external interference threats for which
design for pipeline protection is required. Activities which could occur during the design
life of the pipeline shall be considered.
NOTE: For guidance on the definition of design cases for protection, see Appendix D.
External interference protection shall be achieved by selecting a combination of physical
and procedural controls from the methods given in Table 5.5.4(A) and Table 5.5.4(B).
The following shall apply:
(a) A minimum of 1 physical control and 2 procedural controls shall be applied in R1 and
R2 location classes.
(b) A minimum of 2 physical control and 2 procedural controls shall be applied in T1 and
T2 location classes.
(c) For each control, all reasonably practicable methods shall be adopted.
(d) Physical controls for protection against high powered boring equipment or cable
installation rippers shall not be considered absolute.
(e) In CIC location class, agreements to control the activities of each user shall be
implemented with other users of the CIC wherever possible.
The adoption of minimum requirements for pressure design wall thickness, depth of cover
and marking shall not be assumed to constitute design for protection.
The effectiveness of each external interference protection design shall be reviewed by a
safety management study validation workshop.
TABLE 5.5.4(A)
EXTERNAL INTERFERENCE PROTECTION—
PHYSICAL CONTROLS
Controls Methods
Separation
Burial
Exclusion
Barrier
Resistance to penetration Wall thickness
Barrier to penetration
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75 AS 2885.1—2007
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TABLE 5.5.4(B)
EXTERNAL INTERFERENCE PROTECTION—
PROCEDURAL CONTROLS
Controls Methods
Pipeline awareness
Landowner
Third party liaison
Community Awareness program
One-call service
Marking
Activity agreements with other
entities
External interference
detection
Planning notification zones
Patrolling
Remote intrusion monitoring
5.5.5 Physical controls
Physical controls shall be selected from the following:
(a) Separation Protection of the pipeline may be achieved by separation of the pipeline
from the activities of third parties. Methods of separation include the following:
(i) Separation by burial Burial is a protective method that separates the pipeline
from most activities of third parties. Burial may be counted as a physical
control when the depth of burial is considered to preclude damage to the
pipeline by the defined external interference threats relevant to the location.
(ii) Separation by exclusion Exclusion is a physical protection method intended to
exclude external interference from access to the pipeline. Fencing is an example
of exclusion. Exclusion is considered to be effective where access to pipeline
facilities is controlled by the pipeline Licensee.
(iii) Separation by barriers Barriers are a physical protection method against
certain types of external interference events, particularly those involving
vehicles and mobile plant. Crash barriers on bridges carrying pipelines are an
example of separation by barriers.
(b) Resistance to penetration Resistance to penetration is a physical method for
protection when the resistance is sufficient to make penetration improbable.
NOTE: For fibreglass pipe, resistance to penetration is not considered to be an effective
control unless physical testing is undertaken.
Resistance to penetration may be achieved by the following methods:
(i) Wall thickness The required wall thickness to resist penetration by the defined
interference activities may be determined experimentally or from experience.
Wall thickness may be counted as a physical control where the thickness is not
less than the thickness required to prevent penetration for the external
interference threats relevant to the location.
NOTES:
1 Wall thickness for resistance to penetration is not determined directly by stress
calculations. An increase in penetration resistance may be achieved by changing
the grade of the pipe used, provided the resultant stresses in the pipe comply with
Clause 5.4.
2 Guidance on resistance to penetration calculations is provided in Clause 4.11. Lice
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(ii) Penetration barriers Physical barriers may be used to resist penetration.
Where a barrier prevents the design external interference threat (see
Clause 5.5.4) from access to the pipeline the barrier may be counted as a
physical control.
Barriers may be one of the following:
(A) Concrete slabs Where slabs are used to provide protection, they shall
have a minimum width of the nominal diameter plus 600 mm. They shall
be placed a minimum of 300 mm above the pipeline.
(B) Concrete encasement Where concrete encasement is used to provide
protection, it shall provide a minimum thickness of 150 mm on the top
and sides of the pipeline.
(C) Concrete coating Where concrete coating is used to provide protection,
it shall be reinforced and shall have a minimum thickness determined in
the protection design.
(D) Other barriers Other physical barriers may also be used.
Barriers shall have the mechanical properties necessary to provide the required
protection for the external interference threats, and have the electrical, chemical
and physical properties necessary to maintain the efficacy of cathodic
protection to be applied to the pipeline.
Where the performance of barriers cannot be established by calculation, the
performance may be established by testing.
5.5.6 Procedural controls
Procedural controls shall be selected from the following:
(a) Pipeline awareness Pipeline awareness controls are active or passive controls
implemented to inform external parties of the presence of and potential danger from
external interference to the pipeline. Pipeline awareness controls include:
(i) Marking Clause 4.4 defines the minimum requirements for marking. Where
marking is to be counted as a procedural control at any location, signs shall be
installed so that they are visible to any party undertaking a design external
interference event.
(ii) Buried marker tape Buried marker tape shall be installed so that the external
interference threats cannot damage the pipeline without first exposing the tape.
Marker tape is effective only when the external interference threats is of such a
nature that it is likely that at least one person involved in the activity will see
the marker tape immediately it is exposed.
Minimum requirements for buried marker tape are as follows:
(A) Tape shall be located a minimum of 300 mm above the pipeline.
(B) Tape shall be permanently coloured with a high visibility colour.
(C) Tape shall identify the nature of the buried pipeline.
(D) Tape shall have sufficient strength, ductility and slack to prevent it
breaking before it becomes visible.
(E) Tape shall have a lifespan not less than the design life.
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(iii) Landowner, occupier and public liaison Landowner, occupier and public (or
third party) liaison is an important control in maintaining the awareness of
landowners, authorities and the public of the presence of the pipeline and the
limitations on activities in the vicinity of the pipeline.
Liaison is considered to be effective when—
(A) systematic landowner and public (third party) liaison is carried out in
accordance with AS 2885.3;
(B) the liaison program includes liaison with the developer, local government
or other development approval authority, or contractor responsible for the
external interference threats and, in the case of a threat on private
property, the owner and occupier of the land; and
(C) the operator can demonstrate that the target audience has comprehended
the information provided.
In developing public liaison programs, landowners and occupiers should be
considered separately from public authorities such as shires, utilities, land use
planners and contractors because of the different ways that each group can
affect a pipeline.
(iv) Participation in one-call service A one-call service, which allows third parties
to obtain accurate information on the location and nature of buried services
before undertaking activities in the vicinity of a pipeline, is an important
control for preventing unauthorized activities. One-call systems may be less
effective in R1 and R2 areas and shall not be assumed to be effective protection
without confirmation.
Participation in a one-call service is considered to contribute to protection of
the pipeline when—
(A) the location of the design interference event is within the area covered by
the one-call service;
(B) the pipeline operator has systems in place to ensure an accurate and
timely response to one-call inquiries; and
(C) the pipeline operator has suitably qualified staff available to provide
assistance and advice in cases where work is to be performed near the
pipeline.
(b) External intrusion detection External intrusion detection is a procedural control that
can reduce the occurrence of potentially damaging events. It includes the following:
(i) Patrolling Patrolling is an important control in protecting the pipeline from
external activities and also protecting it from damage caused by natural events
such as erosion.
Patrolling of the pipeline route is considered to contribute to protection of the
pipeline when—
(A) systematic patrolling is carried out in accordance with AS 2885.3;
(B) the frequency of patrolling, and the methods of surveillance used, are
such that there is a high probability of detecting the design interference
event before the pipeline can be damaged.
(ii) Planning notification zones Planning notification zones may be counted as a
procedural control when—
(A) the external interference threat is part of a project that is required by law
to be notified to the pipeline operator at the planning stage; and Lice
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(B) the pipeline operator has systems in place to ensure that the progress of
the project is monitored regularly following notification.
(c) Remote intrusion monitoring Remote intrusion monitoring is considered to
contribute to protection of the pipeline when—
(A) the monitoring system is able to reliably detect the external interference
threat, and raise an alarm, before the pipeline is damaged;
(B) the alarm indicates the location of the activity with sufficient accuracy
that a person standing at the indicated location can readily see the
threatening activity;
(C) the pipeline operator has systems in place to ensure a patrol is mobilized
after an alarm is raised, and can reach the indicated location before
damage to the pipeline occurs; and
(D) the incidence of false alarms is low.
(d) Activity agreements with other entities An activity agreement is considered to
contribute to the protection of pipeline when there are adjacent assets and the parties
to the agreement have systems in place to ensure that their staff and contractors
comply with the provisions of the agreement, provided these provisions are reinforced
by periodic training programs.
5.5.7 Other protection
Other methods or controls that are effective in protecting the pipeline, or in preventing
events that could cause damage to the pipeline, may be used.
NOTE: Additional information on the effectiveness of awareness controls is given in Appendix E.
5.6 PREQUALIFIED PIPELINE DESIGN
This Clause sets out the basis for a conservative design of the pipe which, subject to the
conditions as set out below, shall be deemed to comply with this Standard.
5.6.1 Minimum requirements
The prequalified design requirements are the following:
(a) Nominal wall thickness not less than that given in Table 5.6.1(A), 5.6.1(B) and
5.6.1(C).
(b) MAOP for pipe diameter, thickness and grade not greater than those given in
Tables 5.6.1(A), 5.6.1(B) and 5.6.1(C).
(c) Pipe material of API 5L Grade B to X60 inclusive.
(d) Compliance with Section 3 (including minimum toughness).
(e) Depth of cover not less than 1200 mm in R2 and T1 areas.
(f) Hydrostatic strength test pressure at the highest point not less than 1.36 × MAOP.
NOTE: 1.36 is derived from the ratio between the test pressure factor for valves and flanges
(1.5) and the elevation range for hydrostatic testing of 1.1.
(g) The number of procedural external interference protection measures shall be not less
than the minimum number for the location class.
(h) Satisfactory corrosion mitigation measures implemented.
5.6.2 Prequalified design coverage
A prequalified design shall be deemed to satisfy the following requirements for pipelines
transporting non-corrosive natural gas and low vapour pressure liquids: Lice
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(a) Facture control plan.
(b) Resistance to penetration and for an assessment of resistance to penetration.
(c) Prevention of rupture in T1 class locations and for an assessment of prevention of
rupture in those class locations.
(d) Maximum tolerable energy release rate in T1 class locations and for an assessment of
prevention of rupture in those class locations.
(e) External interference threats typically encountered.
(f) Determination of wall thickness.
5.6.3 Prequalified design does not apply
Prequalified design does not apply to a pipeline if any of the following apply:
(a) The fluid in the pipeline is an HVPL or is corrosive.
(b) The pipe diameter is greater than DN 200.
(c) The pipeline length is greater than 10 km.
(d) Pipe material is API 5L X65 or higher.
(e) MAOP is greater than 10.2 MPa.
(f) Maximum pipe temperature is greater than 60°C.
(g) Minimum pipe temperature is less than 0°C.
5.6.4 Prequalified design not permitted
The design shall not be prequalified in any section of the pipeline where the following
occurs:
(a) It is apparent that there are unusual threats or severe threats or unusual complications
or extreme complications, other than those normally expected.
(b) There is any threading, grooving or machining of the pipe without a separate analysis
including consideration of additional thickness allowances and fatigue analysis.
(c) Fatigue cycling is likely and there are significant stress concentrators present, unless
separate fatigue analysis demonstrates the suitability of the design.
(d) Depth of cover is greater than 3 m without a separate combined stress analysis.
(e) There is significant external hydrostatic pressure without a separate analysis.
(f) The pipeline route is in a T2 location.
(g) The pipeline crosses fault lines or mining subsidence areas.
5.6.5 Prequalified design special cases
The prequalified design may be used—
(a) for corrosive fluids provided corrosion and required corrosion allowance are assessed
and the allowance is added to the minimum wall thicknesses in Tables 5.6.1(A),
5.6.2(B) and 5.6.3(C); and
(b) in areas of special construction where appropriate consideration is given to the factors
required in Clause 5.8.
The prequalified design shall otherwise comply with all other requirements of this Standard.
Use of a prequalified design shall be approved.
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AS 2885.1—2007 80
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TABLE 5.6.1(A)
MINIMUM NOMINAL WALL THICKNESS FOR PREQUALIFIED PIPE
Pipe nominal diameter DN (mm) 50 80 100 150 200
For an MAOP not greater than 10.2 MPa and greater than 5.1 MPa
Wall thickness (mm) for API 5L Grade B 6.3 7.1 9.0 10.6 11.8
Wall thickness (mm) for API 5L X42 to X60 6.3 6.3 8.4 9.4 11.2
For an MAOP not greater than 5.1 MPa
Wall thickness (mm) for API 5L Grade B to X60 6.3 6.3 6.3 8.4 8.4
TABLE 5.6.1(B)
MAOP OF PREQUALIFIED PIPE FOR API 5L GRADE B FOR
SPECIFIC WALL THICKNESSES
Pipe nominal diameter DN (mm) 50 80 100 150 200
Minimum prequalified wall thickness (mm) 6.3 6.3 6.3 8.4 8.4
MAOP (MPa) 10.2 8.9 6.1 7.4 6.4
Schedule 160 XS XS N/A N/A
Schedule wall thicknesses (mm) 8.74 7.62 8.56 11.1 12.5
MAOP MPa 10.2 10.2 9.7 10.2 10.2
TABLE 5.6.1(C)
MAOP OF PREQUALIFIED PIPE FOR API 5L X42 TO X60 FOR
SPECIFIC WALL THICKNESSES
Pipe nominal diameter DN (mm) 50 80 100 150 200
Minimum prequalified wall thickness (mm) 6.3 6.3 6.3 8.4 8.4
MAOP (MPa) 10.2 10.2 7.4 8.9 7.7
Schedule 160 XS XS N/A N/A
Schedule wall thicknesses (mm) 8.74 7.62 8.56 11.1 12.5
MAOP (MPa) 10.2 10.2 10.2 10.2 10.2
5.7 STRESS AND STRAIN
5.7.1 General
A pipeline shall be designed so that stresses, strains, deflections and displacements in
service from normal and other load types are controlled and are within the limits of this
Standard. Stresses, strains, deflections and displacements in service and during construction
shall be calculated by a recognized engineering method.
Loads whose magnitude is affected by wall thickness (e.g. pipe weight, expansion stresses)
shall be calculated using the wall thickness. Stresses shall be calculated using the nominal
wall thickness less any allowances for corrosion, erosion, threading, grooving or machining.
For a summary of the stress limits required by this Standard, see Table 5.7.8.
Calculation of stresses shall be in accordance with Appendix U.
NOTE: For further guidance on pipe stress analysis, see Appendix X.
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5.7.2 Terminology
The following general definitions apply to this Clause (5.7):
(a) Normal load Load conditions that are considered normal loads are as follows:
(i) Internal and external pressure.
(ii) Transverse external loads, such as those due to soil.
(iii) Weight of pipe, attachments and contents.
(iv) Thermal expansion and contraction.
(v) Imposed displacements, such as those due to movement of anchors or supports
subsidence due to mining, or displacement due to ground instability, where
these are defined as a design condition.
(vi) Local loads, such as contact stresses at supports.
(vii) Traffic loads at defined road and rail crossings.
Where the designer identifies a load not listed in Items (i) to (vii) above that might be
considered normal for the pipeline being designed, it shall be considered as a normal
load for the purpose of this Clause.
(b) Occasional load Loads that occur with a very low and possibly unpredictable
frequency. Occasional loads include wind, flood, earthquake, relief valve discharge,
transient pressures in liquid lines and land movement due to other causes, and may
also include other loads such as those due to vehicle crossings if they are not
expected to occur on a routine basis.
NOTE: Stresses due to occasional loads are also referred to as primary stresses but are only
present for a small fraction of the time.
(c) Sustained load A load that continues to act undiminished as the pipe undergoes
elastic or plastic strain.
NOTE: Stresses due to sustained loads are also referred to as primary stresses and are present
at all times.
(d) Self-limiting load A load where deformation of the pipe under the influence of the
load results in a reduction of the associated stresses. Self-limiting loads include those
due to thermal expansion and imposed displacements in unrestrained pipes.
NOTE: Stresses due to self-limiting loads are also referred to as secondary stresses.
(e) Restrained pipe A pipe installed so that axial movement is prevented or is fully
constrained.
(f) Unrestrained pipe Pipe that is free to undergo axial movement.
NOTE: Movement of pipe installed above ground is complex and requires analysis by visual
methods, hand calculation, or pipe stress analysis software as appropriate.
5.7.3 Stresses due to normal loads
The following calculation methods and limits shall be adopted, unless otherwise approved:
(a) Internal pressure Design for internal pressure shall be carried out in accordance
with Clause 5.4.3.
(b) External pressure Design for external pressure shall be carried out in accordance
with Clause 5.4.5.
(c) Transverse external loads Transverse external loads occur due to the pressure of a
soil load, plus the presence of superimposed loads (including impact), such as road
and rail vehicles and other miscellaneous sources.
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NOTES:
1 Guidelines on methods and criteria for assessing the acceptability of external loadings in
general is given in Appendix V.
2 Guidance on design of non-metallic pipes for external loads can be found in AS 2566.1
and AS 2566.1 Supp 1.
The following shall apply:
(i) Road and rail crossings Pipeline design at road and rail crossings shall
comply with the requirements of Section 4 of API RP 1102. Where
API RP 1102 formulae include a design factor the value used shall be as
follows:
(A) At designated road and rail crossings −0.72
(B) Elsewhere −0.9. (Applies to locations where there is no formed road or
track but a vehicle may nevertheless cross the pipeline on rare occasions,
such as farm paddocks used infrequently by agricultural vehicles.)
The hoop stress check to Clause 4.8.1.1 of API RP 1102 is not required.
The design for internal pressure and wall thickness shall be in accordance
with Clause 5.4 of this Standard.
The imposed loads for road crossing design shall be not less than the
maximum load permitted by the relevant road authority, and should
include appropriate allowance for dynamic load effects, illegal
overloading and identified future increases in legal road limits.
NOTE: For information on road vehicle loads, see Appendix V.
The imposed loads for railway crossings shall be determined from the
maximum rail loading at the crossing, and (in the terms used in
API RP 1102) shall not be less than the E80 load (356 kN per axle).
NOTE: This standard acknowledges that the E80 loading with its 20 × 8 ft
footprint is equivalent to the most severe 300-A-12 loading nominated by
AS 4799 and the very similar 300LA loading of AS 5100.2).
(ii) Other load sources Where transverse external loads are applied to the pipeline
from other sources or in situations that are not within the range of validity of
API RP 1102, the load and/or configuration shall where possible be converted
to an equivalent loading that can be analysed using API RP 1102.
Where transverse external loads cannot be converted to an equivalent suitable
for API RP 1102, without unreasonable extrapolation, an alternative calculation
method shall be used. Alternative calculation methods shall be approved.
(d) Axial/Bending loads—Restrained pipe Stress calculations shall be carried out for
axial and bending loads in restrained pipelines as follows:
(i) Longitudinal stresses (including effects due to temperature changes, bending
and imposed displacements) shall be calculated. The total longitudinal stress σT
shall not exceed 72% SMYS.
(ii) A combined equivalent stress shall be calculated by combining the longitudinal
stress with the hoop stress by means of either the Tresca or von Mises theory.
The combined equivalent stress σC shall not exceed 90% SMYS.
NOTE: Selection of von Mises or Tresca theory depends on the application but the
selected theory should be used consistently throughout the analysis. The von Mises
theory agrees best with experimental evidence. The Tresca theory leads to results
nearly the same and is simpler in application so is widely used as a basis for design.
Both theories give a good approximation for ductile materials but the von Mises theory
is preferred.
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(iii) Where restrained lengths of pipeline are not provided with continuous support
beneath the pipe the sum of the longitudinal stresses σSUS due to the sustained
loads, occurring in normal operation, shall not exceed 0.75 × 72% SMYS.
(e) Axial/Bending loads—Unrestrained pipe Stress calculations shall be carried out for
axial and bending loads in unrestrained pipelines as follows:
(i) Sustained loads The sum of the longitudinal stresses σSUS due to the sustained
loads occurring in normal operation shall not exceed 0.75 × 72% SMYS.
(ii) Self-limiting loads Stresses in unrestrained pipe due to temperature changes
and/or imposed displacements shall be combined for the thermal expansion
stress calculation. Expansion stresses may be calculated separately for
temperature excursions below and above the installation temperature. The
expansion stress (σE) for any excursion shall not exceed 72% SMYS.
NOTE: The expansion stress (σE) represents the variation in stress resulting from
variations in temperature and associated imposed displacements only. It is not a total
stress. The stresses to be calculated are those due to self-limiting loads only, and the
contributions of sustained and occasional loads need not be included.
5.7.4 Stresses due to occasional loads
The effect of occasional loads in service shall be assessed, and shall be included in the
calculation of stresses whenever it is reasonably foreseeable that occasional loads will
contribute significantly to the stress state.
Where an occasional load acts in combination with sustained loads, the maximum limit of
σo, the sum of the longitudinal stresses (see Clause 5.7.3 (d)(iii) or 5.7.3 (e)(i)) including
the effects of the occasional load, may be increased to 80% SMYS.
Occasional loads from two or more independent origins (such as wind and earthquake) need
not be considered as acting simultaneously.
5.7.5 Stresses due to construction
This Standard does not limit stresses prior to hydrostatic testing. Strains, deflections and
displacements shall be controlled so that—
(a) strain does not exceed 0.5% except where strain is displacement controlled, (e.g. cold
field bending within an approved procedure, forming of pipe ends for mechanical
jointing, weld contraction etc.); and
(b) diametral deflection does not exceed 5% of diameter.
Residual stresses left in the pipe after construction (e.g. roped bends) do not need to be
considered in the calculation of operating stresses, provided the pipe has good lateral
restraint (e.g. laid in soils of normal strength). Where lateral restraint is weak or absent,
consideration shall be given to preventing the possibility of uncontrolled strain due to the
combination of residual stresses with either hydrostatic pressure test stresses or operating
stresses.
NOTE: Pipe manufacture, girth welding and pipe-laying all result in residual stresses (potentially
as high as yield stress), which conventionally are neglected in pipe stress analysis because they
are not associated with any failure mode; however, it is conceivable that failure by deformation or
buckling during hydrostatic testing may occur in a pipe containing high longitudinal residual
stress but lacking lateral restraint (or during operation if lateral restraint is removed subsequent to
a successful hydrostatic test).
5.7.6 Hydrostatic pressure testing
Stresses and strains in hydrostatic pressure testing are limited in this Standard by the
requirement of AS 2885.5 that all hydrostatic testing that could cause yielding shall be
carried out under volume-strain control.
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AS 2885.1—2007 84
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Assessments of stresses, strains, deflections and displacements during hydrostatic pressure
testing shall be made taking into account the effects of all other load types acting together
with the hydrostatic internal pressure, in accordance with AS 2885.5.
5.7.7 Fatigue
This Standard requires consideration of the effect of fatigue on the pipeline integrity.
NOTE: For guidance on methods to assess when fatigue should be considered for the pipeline see
Appendix N.
Specific design requirements apply to stations (Section 6) and for parts of the pipeline,
covered in Section 5.8 (Special construction).
5.7.8 Summary of stress limits
Table 5.7.8 summarizes the allowable limits of stress for both restrained and unrestrained
pipelines.
NOTE: Refer to Clause 3.4.3 or the reduction of SMYS at a temperature above 65°C.
TABLE 5.7.8
SUMMARY OF STRESS LIMITS
Stress type symbol Stress limit Applicable pipeline
condition
Reference
Hoop
σH
FD SMYS All Clause 5.4.3
Circumferential due to
external loads
SEFF
72% SMYS Buried API RP 1102
Fatigue due to external
loads
∆SL (girth welds)
∆SH (longitudinal welds)
72% SFG (girth welds)
72% SFL (longitudinal
welds)
Buried API RP 1102
Sustained
σSUS
54% SMYS Restrained and
unrestrained
Clause 5.7.3(d)(iii)
Clause 5.7.3(e)(i)
Total longitudinal
σT
72% SMYS Restrained Clause 5.7.3(d)(i)
Combined equivalent
σC
90% SMYS Restrained Clause 5.7.3(d)(ii)
Thermal expansion stress
σE
72% SMYS Unrestrained Clause 5.7.3(e)(ii)
Occasional
σO
80% SMYS All Clause 5.7.4
5.7.9 Plastic strain and limit state design methodologies
It is intended that pipelines designed in accordance with Clause 5.7.3 will not experience
plastic strain during operation. Plastic strain in a pipeline may be acceptable under the
following conditions:
(a) The pipeline is designed in accordance with a recognized alternative Standard based
on limit state design principles. The alternative Standard shall be thoroughly
reviewed to confirm that it is applicable to the circumstances of the pipeline under
design. The review shall be documented and the alternative standard shall be
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85 AS 2885.1—2007
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(b) A pipeline exposed to possible plastic strain as a result of unforeseen circumstances
such as ground movement. Plastic strain in a pipe that is already in service may be
acceptable, provided a thorough engineering investigation and safety management
study demonstrates that the strain does not significantly increase the risk of failure,
and the engineering investigation and safety management study includes, but not
necessarily be limited to, consideration of the following:
(i) The stress-strain properties of the pipe steel (including strain ageing and work
hardening).
(ii) The extent of plastic strain.
(iii) The likelihood of further or continuing strain.
(iv) The likelihood of wrinkling or buckling.
(v) The likelihood of weld under matching (if longitudinal stress is tensile).
(vi) The possibility of cracks at points of stress concentration.
(vii) The effect of pipe deformation on operation (e.g. pigging).
(viii) The accuracy of the information on the cause of the strain.
(ix) The sensitivity of the analysis to variations in key parameters.
(x) The threats that may arise from alternative methods of dealing with the plastic
strain (such as exposing the pipe to release it from soil restraint, or cutting the
pipe and consequential stress/strain reversal).
NOTES:
1 ‘Plastic strain’ refers to plastic deformation that occurs at stresses above those permitted by
Clause 5.7.3, including stresses above SMYS.
2 Most pipe stress analysis software assumes that the pipe is fully elastic and may not produce
valid models of pipe behaviour if calculated stresses exceed SMYS.
3 In a properly designed pipeline it is possible in some circumstances (particularly unrestrained
pipe) that total stress may theoretically exceed yield on being first placed into service, but
this is not of concern provided that the stress limits of Clause 5.7.3 are met.
5.8 SPECIAL CONSTRUCTION
5.8.1 General
Special construction applies to sections of the pipeline that are not generally formed from
full pipes welded together and laid in a trench at normal cover. Because these sections are
location and pipeline specific, each application requires special consideration to identify
and analyse factors that exist at the location and to develop special designs that are
adequate to protect the pipeline from the threats that exist at that location.
This Clause provides guidance on issues that are known to typically require attention during
design for locations requiring special construction. It also provides rules for specific items
of special construction including pipeline assemblies and above-ground piping.
Special requirements shall apply where a pipeline is—
(a) above ground;
(b) buried with reduced cover;
(c) beneath a road (major or minor);
(d) within a reserve for a major road;
(e) beneath a railway;
(f) within a reserve for a railway; Lice
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AS 2885.1—2007 86
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(g) within a tunnel with permanent access;
(h) beneath a creek, river, stream or artificial waterway; or
(i) over piers or piles.
5.8.2 Above-ground piping
Piping may be installed above ground within a facility or other location where public access
is excluded by security fencing or equivalent measures.
Where piping is installed above ground, the engineering design shall be appropriate to the
specific location and shall include provision for at least the following:
(a) Corrosion mitigation.
(b) Displacements/expansion.
(c) Protection.
(d) Security.
(e) Electrical isolation of earthed piping from other cathodically protected pipelines.
(f) Access and egress.
(g) Thermal expansion of fluid.
5.8.3 Pipeline with reduced cover or above ground
This Standard makes provision for pipelines to be installed at reduced cover or above
ground, in exceptional circumstances.
NOTE: Exceptional circumstances may include short life pipelines, pipelines in very remote areas
or when burial is not practical for an engineering, or an environmental reason. Reduced cover or
above-ground construction may lessen environmental impact by smaller construction footprint,
providing for recovery and re-use of flowline materials, and cleaner abandonment and
reinstatement of landscape.
Reduced cover shall mean cover greater than 300 mm or one pipe diameter up to 750 mm.
This section recognizes that a reduced cover or above-ground pipeline is exposed to a range
of threats, and a range of consequences to which a buried pipeline is not normally exposed.
Special requirements shall be incorporated in the design and operation to achieve the safety
requirements of this Standard.
Figure 5.8.3.defines the circumstances where a pipeline may be installed with reduced
cover or above ground.
NOTE: Reduced cover refers to a pipeline installed with less than the minimum cover specified in
Table 5.5.2 and with no other physical controls added in compensation. The requirements
specified here do not apply to a pipeline that has less than normal cover but additional protection
such as concrete slabs.
For a pipeline carrying stable liquid, the safety management study shall demonstrate that
burial at normal depth is not required for control of external interference threats.
For a pipeline carrying a fluid other than a stable liquid, the safety management study shall
include a special investigation of the measures necessary to ensure the safety of installation
at reduced cover or above ground and shall demonstrate that any residual risk has a rank no
higher than low.
The engineering design of a reduced cover or above-ground pipeline shall be appropriate to
the specific location and shall include consideration of at least the following:
(a) Restraint against movement in the axial, transverse and vertical directions.
(b) Corrosion protection. Lice
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87 AS 2885.1—2007
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(c) Cathodic protection of pipelines laid directly on ground.
(d) Thermal expansion and displacement.
(e) Fatigue at supports.
(f) Thermal expansion of fluid.
(g) Protection against external interference.
(h) Protection against malicious damage.
(i) Restraint of leaking or ruptured pipe (pipe whip – pressure-volume energy).
(j) Isolation of the pipeline section.
(k) Provision for vehicle crossings.
(l) Electrical isolation of earthed piping from other cathodically protected pipelines.
(m) Lightning.
(n) Flood.
(o) Bushfire.
(p) Erosion of cover or at supports.
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AS 2885.1—2007 88
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Accessunder exclusive
control of Licensee(Note 1)
Special study(Clause 5.8.3)
Externalinterference threats
require burial
Residualr isk ( i f any)
is low
Zeropopulat ion,
negligible access(Note 3)
Phase(Note 2)
HVPL ordense phase
LocationClass R1
Yes
Yes
Safety mgt study
No
No
No
Candidate pipel ine forabove-ground instal lat ion
or shal low burial
Ful l burialmandatory
(Clause 5.5.2)
Above-groundinstal lat ion or shal low
burial acceptable
Yes
Yes
No
No
No
Yes
Yes
Stablel iquid Gas or mult iphase
NOTES:
1 Facility or pipeline requires security fence or equivalent to exclude any person not authorized by the
Licensee.
2 Unstabilized crude oil with low gas content may be treated as a stable liquid.
3 These conditions are met only in isolated outback locations remote from public roads and where the land
manager prohibits access except by authorized essential personnel.
FIGURE 5.8.3 DECISION PROCESS FOR PIPELINES INSTALLED AT REDUCED
COVER OR ABOVE GROUND
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5.8.4 Tunnels and shafts
Where a pipeline is installed in a tunnel or shaft, the engineering design shall be appropriate
to the specific location and shall include provision for at least the following:
(a) Support of the pipeline.
(b) Restraint of the pipeline movement.
(c) Venting of enclosed spaces.
(d) Access for maintenance.
(e) Corrosion.
(f) Cathodic protection.
(g) Backfilling.
(h) Hydrostatic testing.
(i) Assess for inspection
5.8.5 Directionally drilled crossings
Where a pipeline is installed by directional drilling technique, the engineering design shall
be appropriate to the specific location, and shall include provision for at least the following:
(a) Protection of the coating.
(b) Cathodic protection.
(c) Hydrostatic testing.
(d) Installation stresses.
(e) Geotechnical investigation.
(f) Subsidence (including mine subsidence).
(g) Environmental risk associated with soil failure under the drilling fluid hydrostatic
head and the consequential environmental damage.
(h) Annulus fill maintenance (for cathodic protection).
(i) Combined stresses.
NOTE: Guidelines are available in the report Installation of Pipelines by Horizontal Directional
Drilling—Engineering Design Guide PRCI project No. PR-227-9424 and Horizontal Directional
Drilling—Good Practices Guidelines, HDD Consortium March 2001.
5.8.6 Submerged crossings
5.8.6.1 General
Submerged crossings include the following:
(a) Permanent waterways, where the pipe is continuously submerged.
(b) Flood plains and ephemeral streams, where the pipe is submerged following specific
weather events.
(c) High water table areas, where the water table is higher than the top of the pipe for
extended periods.
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AS 2885.1—2007 90
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5.8.6.2 Design
Investigations shall be undertaken to develop design criteria for the crossing, including, as
applicable, the following:
(a) A hydrological investigation to determine the stream power under peak stream,
watercourse or waterway flows. Unless otherwise approved, the 1:100 year discharge
event shall be used as the basis for this assessment.
(b) A geotechnical investigation to determine the physical parameters of the crossing, and
using information from the hydrological investigation, the erosion potential. This
assessment should consider the meander potential of the watercourse so that the limits
of special construction can be defined.
(c) The requirements for external interference protection.
(d) The requirements for maintenance of pipe stability.
(e) An assessment of the construction methodology.
(f) An assessment of the environmental management measures required during
construction, and during subsequent restoration. Particular attention shall be given to
the condition of the stream banks, and methods by which the banks will be restored
and stabilised.
(g) An assessment of any specific requirements in relation to corrosion protection
(including the presence of low pH ground water in locations of high water table).
(h) In the case of pipelines transporting hydrocarbon liquids, an assessment of the need
for pipeline isolation facilities in the vicinity of the crossing.
Using the above criteria, engineering designs shall be developed on a generic or
location-specific basis, as applicable. The design shall detail the pipe location, wall
thickness and material, the methods of stabilizing the pipe in the trench, and protecting the
pipeline from external interference, the presence of adjacent structures and corrosion.
Where applicable, the design drawings shall show the relationship of the pipeline to the
natural bottom of the crossing. The engineering designs shall include generic and, where
applicable, specific methods of restoring the site after completion of construction. The
flotation design and safety margin against flotation shall be approved.
Unless otherwise approved, the pipe shall be laid horizontal at the design depth for the full
width of the crossing.
The design shall provide specific attention to the location of the pipeline in banks of
crossings and to the position of the pipeline across the bottom. In particular, the location of
over and sag bends shall be designed to accommodate the restoration method proposed at
each crossing. Where there is a potential for bank erosion, the design should locate these
bends beyond the extent of anticipated erosion.
5.8.7 Pipeline attached to a bridge
Where a pipeline is to be installed on or attached to a bridge, the engineering design shall
be appropriate to the specific location and shall include provision for the following:
(a) Installation methods.
(b) Thermal expansion and displacement.
(c) Inspection and maintenance.
(d) Corrosion protection.
(e) Cathodic protection/electrical isolation.
(f) Isolation of the pipeline section, if appropriate. Lice
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91 AS 2885.1—2007
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(g) Access to and effect on adjacent services.
(h) Consideration of transfer of loads to the structure.
(i) Prevention of traffic damage.
(j) Fatigue at supports.
(k) Differential movement between the pipe, bridge or surrounding grounds.
(l) Malicious damage.
(m) Bridge stability, including under floodwater load.
5.8.8 Road and railway reserves
Where a pipeline is to be installed in a road reserve or railway reserve, the engineering
design shall be appropriate to the specific location and shall include provision for the
following:
(a) Traffic in the reserve.
(b) Effects on the pipeline from an accident involving traffic.
(c) Effects on the traffic from a puncture, rupture or leak from the pipeline.
(d) Inconvenience to other parties during inspection or repair of the pipeline.
(e) Risk of external damage to the pipeline.
(f) Requirements for corrosion mitigation.
(g) Liaison with the authority responsible for the reserve.
(h) Liaison with authorities responsible for other utilities or infrastructure installed in the
reserve.
(i) Effect on pipeline of maintenance of the reserve.
Details of the requirements in road and railway reserves are shown in Figures 5.8.8(A) or
5.8.8(B), as appropriate.
NOTE: AS 4799 provides additional information on pipelines laid within railway reserves.
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AS 2885.1—2007 92
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Boundaryfence
Pipel inemarker
6000 min.6000 min.
Toe ofembankment
2000 min.
(b) Pipel ine paral lel to a rai lway
D2 pipel ine
300 min.
D2 600
Covering slabwhere specif ied
D1 pipel ine
300 min.
D1 600
10 000 min.10 000 min.
Top ofrai ls
Coveringslab
wherespecif ied
1200 min.1200 min.
Boundaryfence
Pipel inemarker
6000 min.6000 min.
2000 min. 2000 min.
(a) Pipel ine crossing a rai lway
300 min.
A 1000 B 1000
8000 min.8000 min.
Extent of encasing pipe where specif ied
Top ofrai ls
1200 min.
1200 min.
Covering slabwhere specif ied
Carrier pipeCovering slabwhere specif ied
Encasing pipewhere specif ied
A
Toe ofembankment
B
300 min.
Pipel inemarker
Boundaryfence
Pipel inemarker
Boundaryfence
FIGURE 5.8.8(A) COVER OVER A PIPELINE WITHIN A RAILWAY RESERVE
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93 AS 2885.1—2007
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(b) Pipel ine paral lel to a road
(a) Uncased and cased pipel ine crossing a road
Reinforced concretebarrier slab
Pipel ine marker
Pipel ine marker
Pipel ine or casing
a
1000 mm min.a
Road reserve—boundary or fence
D
A
B
Road reserve—boundary or fence
Pipel ine
Road reserve—boundary or fence
Pipel ine
Protectiveencasement barr ier
Pipel ine
Road reserve—boundary or fence
AC
B
B
B
B
NOTES:
1 Dimensions A, B and C shall be not less than those determined by the external interference design (see
Clause 5.5).
2 Where separation by burial is a selected physical measure, dimension A shall be not less than 1200 mm and
dimension B shall comply with Table 5.5.2.
3 Where separation by barrier is a selected physical measure, dimension C and dimension D shall be not less
than 300 mm without approval by the authority responsible for the road, and the operating authority.
4 Dimension A should be established in consultation with the authority responsible for the road, but shall not
be less than 1000 mm.
FIGURE 5.8.8(B) COVER OVER A PIPELINE WITHIN A ROAD RESERVE
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AS 2885.1—2007 94
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5.9 PIPELINES ASSEMBLIES
5.9.1 General
Pipeline assemblies are considered to be integral parts of the pipeline. They shall be
designed, fabricated and tested in accordance with this Standard.
Pipeline assemblies are 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. They are intended to take advantage of the properties of formed components and,
where applicable, high-strength materials. This enables the assemblies to be made from
materials of compatible thickness and grade to the pipeline, thus avoiding mismatched
internal diameter, transition pieces and special welding procedures.
Pipeline assemblies shall be designed, fabricated, inspected and tested in accordance with
Section 5, unless otherwise approved.
Welding procedures complying with AS 2885.2 may be used for shop or field fabrication
for pipeline assemblies designed in accordance with this Standard. Where these assemblies
are shop fabricated then suitably qualified procedures complying with another approved
standard may be used.
It is not intended to prevent an assembly being designed and fabricated in accordance with
another approved Standard (such as a pressure vessel Standard). When another Standard is
used, it shall be used in its entirety.
5.9.2 Scraper assemblies
Scraper assemblies, including scraper traps, closures and associated piping, shall be
designated as pipeline assemblies. Where a scraper trap within a scraper assembly is not
fabricated from pipe complying with a nominated Standard, the trap shall be designed,
fabricated, inspected and tested as a special assembly in accordance with Clause 5.9.7. The
tested trap shall be treated as a pressure-rated component in the assembly.
5.9.3 Mainline valve assembly
Mainline valve assemblies shall be designated as pipeline assemblies.
5.9.4 Isolating valve assembly
Isolating valve assemblies that are not included in designated stations shall be designated as
pipeline assemblies.
5.9.5 Branch connection assembly
Branch connection assemblies that are fabricated from pipe complying with a nominated
Standard and pressure-rated components (forged tees, extruded outlets, integrally reinforced
fittings, proprietary split tees) shall be designated as pipeline assemblies.
Branch connection assemblies that are not fabricated from pipe complying with a nominated
Standard and pressure-rated components shall comply with the requirements of Table 5.9.5.
Determination of the requirements for reinforcement and the design of the reinforcement (if
required) shall comply with Appendix Z.
Integrally reinforced branches of the O-let type shall not be attached to pipelines where the
pipe wall thickness is less than 6.4 mm.
Proprietary components of the thread-O-ring type specifically designed for attachment of
pipeline monitoring equipment to transmission pipelines (such as pig signallers and
corrosion coupons) may be used in accordance with the manufacturer’s design provided an
engineering assessment of the branch is made when these fittings are installed on pipe with
wall thickness less than 6.4 mm. Lice
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The design of branch connection support shall comply with Clause 5.11.8. The design shall
consider accidental damage, settlement (including differential settlement) and fatigue.
The welding of branch connections to pipelines shall be conducted in accordance with
AS 2885.2.
The size of welds used for the attachment of branch connections to pipelines shall be
determined as part of the design of the branch. Reference should be made to the
manufacturer’s instructions for the sizing of welds for attachment of proprietary forged
fittings.
NOTES:
1 Weld-O-lets were designed for heavy-walled pipe operating at low moderate stress (e.g. in
ANSI B31.1 and ANSI B31.3 applications) the reinforcement rules in these Standards differ
from those given in Appendix Z. The heavy wall O-let design encourages large weld deposits
that produce large residual stress from shrinkage and result in gross structural mismatches in
metal thickness between the pipe wall and branch. This produces high local stresses at the toe.
Wall tracks may develop when the branch is exposed to any external forces other than
pressure containment.
2 The integral reinforcing provided in some types of O-let fittings gives the appearance of a
machined weld preparation and it has become common practice to fill this apparent
preparation rather than to make a weld of a size appropriate to the design of the particular
branch under consideration. This practice can lead to welds that are much larger than required
and can produce deleterious effects.
3 Where a reinforced branch connection is made to an in-service pipeline, AS 1210 may be
used to assess the potential for buckling of the main pipeline by the test pressure.
TABLE 5.9.5
REINFORCEMENT OF WELDED BRANCH CONNECTIONS
d/D σH/σY
< 25% ≥25% <50% ≥50%
< 20% Reinforcement not mandatory (see Note)
≥ 20% < 50% Reinforcement is
required and may be
carried out by any of the
methods in Clause 5.9.5
If reinforcement is
required, and extends
around more than half
of header
circumference, full
encirclement sleeve
shall be used
≥ 50%
Reinforcement not
mandatory for branch
diameter ≤60.3 mm
(see Note)
Smoothly contoured
wrought steel tee of
proven design preferred.
If tee not used, full
encirclement
reinforcement is
preferred
Smoothly contoured
wrought steel tee of
proven design
preferred. If tee not
used, full encirclement
reinforcement shall be
used
NOTE: The design shall consider thin-walled headers and allow for the effects of vibration and external
loads.
5.9.6 Attachment of pads, lugs and other welded connections
The welding of pads, lugs and other welded connections shall be carried out in accordance
with AS 2885.2. The potential for fatigue shall be considered.
Attachment of electrical conductors shall be in accordance with Clause 10.11.
NOTE: The long sides of a rectangular lug shall be in the circumferential direction of the pipe.
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5.9.7 Special fabricated assemblies
Special fabricated assemblies that are fabricated from pipe complying with a nominated
Standard and pressure-rated components shall be designated as pipeline assemblies.
Where a component in a fabricated assembly is not included in a nominated Standard or is
not used within the manufacturer’s pressure/temperature rating, and for which design
equations or procedures are not given in Section 5, the suitability for service shall be
evaluated in terms of the pressure strength of the component at the design temperatures.
Satisfactory service experience of special fabricated fittings which are not included in the
nominated Standards, and for which design equations or procedures are not given in this
Standard, may be used where the design of similarly shaped, proportioned, and sized
components has been proven to be satisfactory 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 of this Standard, and
substantiated by one or more of the following:
(a) Proof tests as described in AS 1210.
(b) Experimental stress analysis.
(c) Theoretical calculations.
5.10 JOINTING
5.10.1 General
Joints shall be capable of withstanding the internal pressures and the external forces without
leaking.
5.10.2 Welded joints
Welded joints shall either comply with AS 2885.2 or, where of a different type of weld (e.g.
friction welding, explosion welding), shall be approved.
5.10.3 Flanged joints
Bolted flanges shall be of an appropriate rating and shall comply with at least one of the
following:
(a) A nominated Standard.
(b) AS 1210.
(c) An approved design method.
Bolted flanges should not be used on buried or submerged pipelines. Where such use is
unavoidable, each flange shall be listed specifically in the engineering design for inspection
and maintenance.
Flanged joints shall be tightened to the residual bolt tension necessary to satisfy the
performance requirement of this Clause.
NOTE: Guidelines for determining the torque required to tension bolts in flanged joints are
provided in Appendix T.
Permissible values of bolt stress levels in carbon steel bolts shall comply with the
following:
(i) The maximum residual bolt stress level in tension shall not exceed 2/3 of the
minimum tensile yield strength of the bolt material
(ii) The maximum combined shear stress level during tightening shall not exceed 90% of
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(iii) The maximum tensile stress level during tightening shall not exceed 90% of the
minimum yield strength of the bolt material
(iv) For operational loads, the predicted bolt tension under all load cases shall not exceed
54% of the minimum tensile yield stress of the bolt material for sustained loads, 72%
tensile yield for expansion stress and 80% tensile yield for occasional loads.
(v) The bolt stress levels from the operating load cases shall individually not exceed the
bolt stress level achieved during the hydrostatic pressure test of the flanged joint or of
the notional hydrostatic pressure test bolt stress level of the flanged joint where the
joint is not physically subjected to the hydrostatic pressure test.
For bolt temperatures up to 120°C no de-rating of allowable stress is required. For
bolt temperatures between 120°C and 200°C the permitted allowable bolt stress level
shall be de-rated in accordance with an approved standard.
NOTES:
1 Refer to ANSI B31.3 Appendix Table A-2. Design Stress Values for Bolting Materials for
materials other than carbon steel.
2 Where flanged joints are subjected to temperatures below the temperature rating of standard
flange and bolting materials, low temperature materials should be considered.
5.10.4 Threaded fittings
Threaded fittings shall be of the taper-to-taper type and aligned without springing of the
pipe. Any thread sealant shall be compatible with the fluid.
5.10.5 Other types
Where any other types of joints are proposed to be used, including mechanical interference-
fit joints, bells, spigots or proprietary joints, the joints shall—
(a) be the subject of a national or international Standard;
(b) have a documented history of successful use; and
(c) be approved.
The use of other joints is not precluded. However prototypes of these joints shall be
subjected to comprehensive tests to demonstrate the safety of the joint under simulated
service conditions. The design and use of such joints shall take account of the following;
(i) The installation process.
(ii) Pressure and structural loads including cyclic conditions, low temperature, thermal
expansion or other expected service conditions.
(iii) Where appropriate, provision shall be made to prevent a separation of joints and to
prevent longitudinal or lateral movement beyond the limits provided for in the joining
member.
(iv) A jointing qualification procedure test shall be performed and documented. The
jointing procedure specification shall include a set of essential variables which
specify the qualified range of the critical variables beyond which requalification of
the procedure shall be required.
(v) The essential variables shall include details of the dimensional tolerances and
potential defects in the mating components of the joint.
(vi) The design of the joint and the jointing procedure qualification test shall be approved.
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5.11 SUPPORTS AND ANCHORS
5.11.1 General
An anchor, support, or apparatus connected to pipework and piping shall be designed for
the service conditions. Supports shall be designed to support the pipe without causing
stresses that exceed those determined in accordance with Clause 5.7, or preventing the
required freedom of movement.
Where specified in the design of the cathodic protection system, supports and anchors shall
be electrically isolated from the pipe.
5.11.2 Settlement, scour, and erosion
A pipeline shall be adequately supported under all service conditions to counteract the
effects of settlement, scour, and erosion.
5.11.3 Design
Supports and anchors shall be designed to suit the service conditions, and be appropriate for
the design life.
Where anchors are provided, the pipe stress analysis and design shall include appropriate
recognition of the finite stiffness of the restraint structure. Appropriate structural and/or
geotechnical advice should be sought to determine the anchor stiffness.
NOTES:
1 No anchor is truly rigid. In some circumstances a pipeline anchor block under load may
experience a displacement of many millimetres, which may be sufficient to cause excessive
stress in the piping it is intended to protect. A rigid anchor may be assumed where it can be
shown that the piping is insensitive to anchor movements.
2 A clearance adequate for elastic strain during pressure testing and operation should be
maintained between the bore of a concrete anchor and the pipeline.
Supports shall be designed to control cyclic stresses (including vibrations) within the limits
established by the fatigue design in accordance with Appendix N.
5.11.4 Forces on an above-ground pipeline
The stresses from forces on the above-ground pipeline shall not exceed those specified in
Table 5.7.8.
5.11.5 Attachment of anchors, supports, and clamps
An anchor, support, or clamp shall be attached to a pipeline in such a way as will prevent
excessive local stress concentration in the pipe wall. The combined stress shall not be
greater than that specified in Table 5.7.8.
Where a pipeline is designed to operate at a hoop stress of less than 50% SMYS, a support
or an anchor may be welded directly to the pipe.
Where a pipeline is designed to operate at a hoop stress of greater than 50% SMYS, a
support and a clamp shall completely encircle the pipe. Where it is necessary to provide
positive attachment, the pipe may be welded only to an encircling member, and the support
or clamp shall be attached to the encircling member and not to the pipe. The weld between
the encircling member and the pipe shall be continuous.
Supports, anchors and clamps should be designed so that open crevices are not created
adjacent to the pipe. On buried pipelines, such crevices may cause shielding of cathodic
protection. On above-ground pipe, open crevices allow moisture and contaminants to
accumulate.
NOTE: Each of these conditions may result in accelerated corrosion rates within the crevice. Such
corrosion may not be visible externally.
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If design creates an open crevice it should also allow easy periodic removal of the support
so that the crevice area can be examined for corrosion and repaired as necessary. The need
for pipe removal and inspection should be highlighted in the pipeline safety management
study and the SAOP.
5.11.6 Restraint due to soil friction
The adequacy of anchorage by soil friction shall be determined and, where necessary,
additional anchorage shall be provided.
5.11.7 Anchorage at a connection
The interconnection of pipelines shall have the strength and flexibility to cater for possible
movement, or each pipeline shall be provided with anchors sufficient to develop the forces
necessary to limit the movement.
5.11.8 Support of branch connections
Branch connections shall be provided with a common foundation for the branch and run
pipe that will prevent differential settlement.
Where a branch connection is made to an existing pipeline and consolidated backfill is
removed, firm foundations shall be provided for both the branch and the pipeline. The
stresses shall not exceed those determined in accordance with Table 5.7.8.
Lateral forces at a branch connection may greatly increase the stresses in the branch
connection, unless the back fill is thoroughly consolidated or provision is made to resist the
force.
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S E C T I O N 6 S T A T I O N D E S I G N
6.1 BASIS OF SECTION
Stations are facilities that allow for control, measurement, storage or pressure maintenance
of pipeline fluids. Stations covered by this Section include compressor and pump stations,
storage facilities, pressure regulation and metering facilities. Other facilities that involve
frequent operational activity may also be designated stations for the purpose of this
Standard. Pipeline assemblies (see Clause 5.9) are not considered as stations in this
Standard. They may, however, be located within the physical boundaries of a station.
A Design Basis document shall record the criteria adopted for the design of each Station,
including relevant design standards, process, mechanical, civil, electrical and process
control criteria and philosophies.
This Standard establishes minimum requirements for Stations design however because the
process, design, operating and maintenance conditions differ from those in a pipeline,
nominated Standards that govern the specific design and operating condition in the Station
shall be adopted. Standards other than nominated standards, where used, shall be approved.
Safety studies (including fire safety) shall be undertaken for design (or modifications to a
design) in accordance with Section 2.
Stations shall be protected from damage caused by the environment and from external
interference.
Stations shall comply with regulatory requirements for the safety of personnel and the
public.
Station limits shall be defined in accordance with Section 4.
All pressure equipment shall comply with the conformity assessment requirements of
AS 3920.1.
6.2 DESIGN
6.2.1 Location
Stations shall be located on property controlled by the Licensee. The following shall be
considered in selecting the location of station sites:
(a) Compatibility of construction and operation of the station with existing and known
future land planning requirements.
(b) Minimization of the impact of noise or other emissions from the site on existing and
known future users of the adjacent land, irrespective of statutory requirements.
(c) Incorporation of natural features with or without the contribution of constructed
landscaping in the design to minimize the impact of the site on the adjacent land users
and the visual aesthetics of the area.
(d) Provision of continuous access to the site.
(e) Minimization of external interference threats external to the site, for example vehicle
impact.
(f) Risks to adjacent land users from fire or fluid release for the station site and the land
reserved for the site.
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(g) Suitability of voice and data communications for the specific station function.
NOTE: It is recognized that some pipelines operated by gas networks may be required to
construct stations on land not controlled by them (e.g. in road reserves and on customers
property). When this is necessary the security of these stations has to be of at least the same
standard as if the land was controlled by the Licensee.
6.2.2 Layout
To reduce risk from possible spread of fire, the separation distances from piping and
equipment to adjacent buildings, adjacent properties, vegetation and road boundaries shall
be considered.
A distance of at least 15 m should be observed between the fencing and the compressor or
pump station building (or the compressors or pumps, if these are not installed in a building)
in order to prevent the communication of fire from outside the fencing to this building or
the equipment, if the latter are installed in the open. Likewise a minimum distance of 15 m
should be observed within the area between the fencing and the installation for regulating
and shutting off the fluid flow in the station.
Combustible materials should not be stored within 10 m of the compressor or pump
building (or the compressor/pump) and of any isolating, regulating or metering installation.
Buildings within 10 m of a compressor or pump building shall be constructed of
non-combustible materials.
Sufficient open space shall be provided around the compressor building to permit the free
movement of firefighting equipment.
The minimum spacing between buildings within the site should be 4 m.
6.2.3 Other considerations
Station design shall consider the impact of the following:
(a) Spacing of equipment and facilities.
(b) Pollution control.
(c) Security.
(d) Noise control.
(e) Venting and drainage.
(f) Liquid separation and disposal.
(g) Confined spaces.
6.2.4 Safety
6.2.4.1 Hazardous areas
Hazardous areas shall be determined for each site in accordance with AS/NZS 60079.10 and
AS/NZS 2430.3.1 and AS/NZS 2430.3.4 or other approved Standard. No hazardous areas of
any site shall extend beyond the fenced or controlled boundary of the property controlled by
the Licensee unless specific approved plans are implemented to prevent public access to the
hazardous area.
NOTE: A check should be made to determine whether specific regulatory requirements apply at
each site.
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6.2.4.2 Personnel protection
Consideration shall be given to protection of operating personnel and visitors from hazards
in the station. Adequate protection shall be achieved by a combination of passive equipment
protection, guarding, isolation, layout and design. When adequate protection cannot be
provided by these means, personnel protective equipment (PPE) shall be provided in
sufficient quantity for the greatest possible number of people on the site.
6.2.4.3 Fire protection
The following requirements shall apply to fire protection:
(a) Firefighting equipment Adequate and approved firefighting equipment shall be
provided on site.
NOTE: For pit regulators portable firefighting equipment may be carried by maintenance
personnel rather than provided on site.
(b) Detection of gas and fire Detectors for flammable gas or flammable vapour shall be
installed at locations in buildings housing any compressor, pump or control, where an
accumulation of gas or vapours is considered to be hazardous. Smoke, fire detectors
or both shall be installed in such buildings.
Detectors shall initiate action intended to make the station safe.
NOTE: This action may include local alarms, remote alarms, automatic shutdown, automatic
firefighting, isolation of the station, initiation of an emergency shutdown (ESD), automatic
emergency depressurization and prevention of remote restart until safe conditions are
restored.
(c) Power supply Power supplies for fire protection systems and emergency lighting
shall be independent of any power supply that may be shut down during an
emergency.
(d) Hot surfaces Hot surfaces of engines and compressors shall be insulated or suitably
cooled to prevent ignition of flammable vapours or gases that may be present, or be
adequately ventilated to prevent the build-up of an explosive mixture of gases.
(e) Vegetation Vegetation within the station shall be controlled, so that it does not
become a fire hazard.
(f) Disposal of flammable liquids Flammable liquids shall be disposed of in a controlled
and safe manner.
6.2.4.4 Earthing/lightning
Station piping and equipment shall be properly earthed to discharge fault or induced
voltages safely. The equipment and facilities, including fencing, shall be earthed to protect
personnel and equipment from harm or damage in the event of lightning strike.
Station earthing design shall be compatible with the pipeline cathodic protection system and
with corrosion protection of any buried pipe within the station. Compatibility may be
achieved by electrical isolation of below-ground pipe in conjunction with suitable surge
diversion devices to protect the isolation mechanism.
Lighting damage to above-ground facilities or hazard to personnel can arise in four ways:
(a) Lightning strikes directly to the above ground-facilities
(b) Lightning strikes to ground near the facilities
(c) Lightning strikes to ground near the pipeline
(d) Lightning strikes to incoming electricity supply or telecommunications conductors
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Protection of station piping and equipment may be achieved by the installation of an
appropriate lightning protection system.
NOTE: Detailed information on design of lightning protection systems is given in AS/NZS 1768.
Transfer of energy from lightning strikes to ground in close proximity to the pipeline can be
largely mitigated by installation of suitable earthing.
NOTE: Further details on pipeline protection is given in AS/NZS 4853.
6.2.4.5 Lighting
Adequate illumination shall be provided on walkways, at exits, around critical locations of
a compressor or pump, and around control equipment, as determined by the requirement for
personnel access at night.
In a building where the station control system shuts down the station power system
automatically, emergency lighting shall be provided.
6.2.4.6 Fencing and exits
Stations shall be enclosed by a fence (or shall be within a property that is not accessible to
the public). The fence shall—
(a) be not less than 2 m high;
(b) restrict unauthorized entry;
(c) have at least two exits located so as to provide alternative widely-separated escape
routes; and
(d) carry appropriate warning and prohibition signs on each side complying with
AS 1319.
Personnel gates within the fencing shall open outwards and shall be either capable of being
opened from the inside without a key or the pipeline operating procedures shall require
personnel gates to be unlocked at any time that there is a person on site.
At least one of the gates shall be so dimensioned and constructed for accessibility for
firefighting equipment and ambulances.
Alternative methods of providing emergency exits that are equivalent to gates shall be
approved.
NOTES:
1 Fencing is not required for pit regulators, where restricted access to the pit is controlled by
locking the pit lid.
2 For smaller stations typically within networks, where a risk assessment has been carried out
and shows that there will be no increase to safety by having two exits in a fenced compound
one exit is satisfactory.
6.2.4.7 Venting
Where flammable gas is vented to atmosphere, the location of the vent systems shall take
into account the direction of the prevailing winds and minimize the possibility of gas
entering the air intake of combustion engine-driven equipment, the proximity of electric
transmission lines, areas normally zoned as non-hazardous or adjacent areas where low
concentrations of gas may represent a hazard or nuisance.
Consideration shall also be given to the threats posed by the vented plume to parties and
facilities beyond the station fence.
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6.2.4.8 Shutdown system
Each station shall be provided with a system that will safely isolate components of the
station, or the whole station, to prevent escalation of a potentially unsafe situation.
Usually, the shutdown system is implemented with a hierarchical structure. The highest
level is a station emergency shutdown (ESD) that isolates the station from its supply and
delivery points and, for gas systems, safely depressurizes the station. Lower levels in the
hierarchy include unit stop, isolation and depressurization, and unit stop without
depressurization.
The shutdown system should have provision for automatic, and/or local and remote
initiation, as appropriate.
Isolation valves shall be located outside building or enclosures to ensure that after
depressurization of process equipment, escalation is prevented by denial of the fuel source.
Where the shutdown system is designed to operate automatically, the consequence of the
immediate cessation of supply on downstream processes shall be considered.
6.2.4.9 Marking
Equipment and piping shall be painted or marked so that the safety of operation is enhanced
by clearly identified contents, purpose, or function within the station. Particular attention
shall be given to the following:
(a) Identification and location of emergency valves and controls.
(b) Identification of piping contents to AS 1345.
6.3 STATION PIPEWORK
6.3.1 Design standard
Except as provided in Clause 3.2 and Clause 3.4.3, design of station pipework shall comply
with AS 4041 or ASME B31.3. The use of any other Standard shall be approved.
Carbon steel flanges and flanged valves in station piping need not be derated at
temperatures up to 120°C as stated in Clause 3.4.3.
NOTE: 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.
6.3.2 Pipework subject to vibration
Station equipment operation may cause vibration and the possibility of fatigue failure in
pipework and pipe supports.
Piping design shall eliminate acoustical frequencies that coincide with piping or compressor
mechanical frequencies. It shall minimize forces due to pressure pulsations that will permit
piping to be restrained by conventional pipe guides, anchors or supports and remain within
allowable stress levels.
Pipe restraints shall be designed to prevent vibration but still allow freedom to
accommodate thermal movement.
Consideration of vibration shall be given in the design of piping near rotating equipment
and reciprocating machinery. Particular attention shall be given to the design and location
of all pipe and tubing supports. Small bore piping systems are prone to cyclic stress and
fatigue failure, they need more frequent support than that used for DN 50 and larger
systems.
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6.4 STATION EQUIPMENT
6.4.1 General
Forces applied by piping to equipment shall not exceed the maximum specified by the
manufacturer of the equipment.
6.4.2 Pressure vessels
Pressure vessels shall comply with AS 1210 or a nominated Standard.
NOTE: Australian Standards committee ME-001 is considering provisions that would allow the
flange temperature derating provision of Clause 3.4.3 to be applied to pressure vessels designed
in accordance with the AS 1200 Standards.
6.4.3 Proprietary equipment
Where proprietary equipment is used either directly or as part of a prefabricated system,
that equipment shall comply with an approved Standard, or the manufacturer’s standard
where no suitable approved Standard is available. Equipment normally supplied as
proprietary equipment includes the following:
(a) Meters.
(b) Regulators.
(c) Test or monitoring equipment.
(d) Turbines and engines (gas or liquid fuelled).
(e) Valves and pressure safety or relief valves.
(f) Heat exchangers.
(g) Tankage.
(h) Filters and strainers.
(i) Compressors.
6.4.4 Equipment isolation
All equipment shall be installed in a manner that allows effective isolation for maintenance.
Where equipment is of a size that allows full or partial personnel entry, the design shall
provide means of positively isolating the equipment during service, such as spectacle
blinds, removable spools or similar devices.
6.4.5 Station valves
Station isolating valves and where necessary station bypass valves shall be installed at each
meter, compressor, pump or regulator station, so that the station can be expeditiously
isolated. Such valves shall be designed to an approved Standard and identified for safe and
reliable operation.
Isolating valves that are installed above ground and intended to isolate all or part of a
station in the event of an emergency shall be ‘fire-safe’ to an approved Standard.
The failure position of each actuated valve shall be determined in the process design and
the design failure mode documented.
Isolating valves below relief valves shall be locked in the open position.
Where continuous supply is required, bypass valves shall be installed at meter, compressor
and pump stations.
Piping that is supplying process or fuel gas to a building shall have an isolating valve
located in an easily accessible position outside of the building.
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Consideration shall be given to providing a maintainable pressurizing bypass valve around
each station isolating valve and other valves that cannot be maintained without interrupting
flow.
6.5 STRUCTURES
6.5.1 General
Structures, including buildings and foundations, shall be designed to comply with the
appropriate Australian Standards. Wind and earthquake loads shall be considered for each
site.
6.5.2 Buildings
Buildings shall be designed in accordance with the following:
(a) Building materials Buildings that contain equipment or piping used to convey
hydrocarbons shall be constructed from non-combustible materials, as specified in
AS 1530.1.
(b) Lighting Lighting shall be provided in areas where access is required at night time
for operations and maintenance. Interior lighting shall comply with AS 1680.2.1 and
exterior lighting shall comply with AS 1158.1.
An emergency lighting system that is independent of any plant automatic shutdown
shall be provided in each building that houses operational plant or equipment.
(c) Emergency exits Where personnel are likely to be prevented from reaching a single
exit in an emergency, additional exits shall be provided as required.
The distance from any point in the building to the nearest exit shall be less than 25 m
measured along the centre-lines of the aisles, walkways and stairways.
Doors in emergency escape routes shall be hinged and shall open from the inside in
the direction of egress without the use of a key.
Exits and escape routes shall be clearly marked and kept free from obstructions at all
times.
(d) Ventilation Ventilation shall be provided in compressor buildings, pump buildings
and other buildings housing pipework containing hydrocarbons, to ensure that
personnel in the building are not endangered by the accumulation of dangerous
concentrations of flammable or toxic gases or vapours under normal operating
conditions.
Ventilation systems shall be appropriate for the fluid that may be released within the
equipment structure, and shall—
(i) discharge safely in a safe location;
(ii) safely exhaust any ignitable concentrations of flammable vapour or gas from
the equipment structure in a way that will make the internal atmosphere safe
within an approved time after the source of leakage has been isolated;
(iii) prevent sources of ignition reaching the interior of the equipment structure;
(iv) provide a means outside the equipment structure for checking its operation; and
(v) restrict entry of foreign matter.
6.5.3 Below-ground structures
(a) Pits and other below-ground structures that house components containing
hydrocarbon fluid shall be located, designed and constructed to provide the following:
(i) Limitation of stresses on pipework.
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(ii) Necessary protection of components from the elements.
(iii) Necessary support and constraint of components within equipment structures.
(iv) Protection against accidental ignition of flammable fluids within equipment
structures.
(v) Protection of components from damage caused by a third party or loads on pit
covers (e.g. from traffic and other external loads).
(vi) Prevention of unauthorized entry.
(vii) Sufficient space for safe and efficient installation, operation and maintenance of
the equipment, as specified in the engineering design.
Care shall be taken to ensure the design of the pit lid is such that it cannot fall into
the pit during removal or replacement.
Valves should be positioned so that the spindles will not present a hazard should an
operator slip or fall through an access to an underground pit.
Each equipment structure that has an internal volume of not more than 6 m3 and
located so that no part of the equipment structure is above the surface of the ground
shall be ventilated or sealed. Where a structure is ventilated it shall generally comply
with the requirements of Clause 6.5.2.
(b) Sealed equipment structures shall—
(i) be impervious to the passage of flammable vapour or gas;
(ii) be provided with necessary pressure and vacuum relief;
(iii) have on each opening a cover, hatch or door that is both gastight and
vapour-tight; and
(iv) have provision for testing the atmosphere within the equipment structure
without opening the cover, hatch or door.
6.5.4 Corrosion protection
Corrosion protection systems shall be applied to station piping and equipment consistent
with the design life.
When the station design requires pressurized pipes to be constructed below ground,
provision shall be made to protect them from external corrosion in accordance with
AS 2832.2. This should include a cathodic protection system similar to that required for the
pipeline.
6.5.5 Electrical installations
Electrical installations shall comply with AS/NZS 3000 or other approved Standard.
6.5.6 Drainage
6.5.6.1 General
The station site shall be designed to manage liquid effluent to prevent contamination of
offsite areas.
6.5.6.2 Process liquids
Process liquids emanating from drains, pressure relief systems and equipment leakage shall
be segregated and transferred to a storage vessel where they can be returned to the process
or transferred to an appropriate container for disposal.
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6.5.6.3 Rainfall runoff
The station site should be designed to segregate rainfall runoff (which may be
contaminated) and other runoff (which may be contaminated by the operation of the
facility).
Runoff that is contaminated should be discharged through a separator that will prevent
contamination from being discharged offsite. If there is a risk of the spillage volume
exceeding the capacity of the separator, consideration should be given to providing an
isolation valve at the point of discharge to retain all spillage within the site.
Uncontaminated runoff should be discharged to appropriate offsite drains.
6.5.6.4 Oily water
An oily water system shall be provided for those facilities where the normal operation of
the facility has the potential to discharge oil-water mixtures. Oily water shall be processed
to separate oil and water. The discharged water quality shall be nominated and approved.
The oily water system capacity should be sufficient for the greater of the following:
(a) Fire system water runoff.
(b) Rainfall runoff.
(c) Equipment discharge.
The oily water system shall be designed to prevent explosive vapour/air mixtures from
entering or forming in the drainage system. The drainage system shall be designed with fire
traps to prevent the spread of fire through the drainage system.
6.5.6.5 Sewage
Sewage and other sanitary waste shall be collected, treated and disposed of in an approved
manner.
6.5.6.6 Equipment below ground
Where an equipment structure is partly or wholly belowground and flooding would
endanger safe operation, an approved drainage system shall be installed. The drainage
system shall be appropriate to the fluid in the pipeline and to the site conditions.
Instrumentation linked to the facility control system shall be installed to monitor the safe
performance of the below-ground equipment drainage system.
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S E C T I O N 7 I N S T R U M E N T A T I O N A N D
C O N T R O L D E S I G N
7.1 BASIS OF SECTION
A pipeline shall be designed with an appropriate system for monitoring and managing its
safe operation, having regard to its location, size and capacity and obligations for data
recording and reporting. The system may include a range of pipeline facilities such as
stations, isolation valves, scraper traps and, generally, a communications and control
system, together with appropriate operations and maintenance procedures. The system
design shall incorporate any outcomes of the risk analysis, in as much as the control system
may be required to monitor, record and report operating data.
The control system may be used for functions related to commercial activities in addition to
its function in pipeline control. This Standard does not deal with the commercial functions.
Remote and unmanned facilities shall be designed with an appropriate local control system
capable of safely operating that section of the pipeline and if required, safely shutting it
down during any time that the communication and supervisory control system is
unserviceable.
The design parameters for the system shall be defined and approved.
NOTE: The engineering design life of some control components may differ from the system
design life of the pipeline. Control items of shorter life shall be identified.
The following factors should be considered in designing the control and management
system:
(a) Suitable facilities provided along the pipeline to allow isolation and inspection for
operating and maintenance purposes.
(b) Control of the pipeline in the overall context of the management system for the
business.
(c) Safety of operations for both personnel and assets.
(d) Compliance to regulatory requirements.
(e) Prolongation of asset life.
(f) Operations efficiency.
(g) Commercial obligations.
(h) Maintenance planning and dispatching.
(i) Integration of control systems with geographical information system.
7.2 CONTROL AND MANAGEMENT OF PIPELINE SYSTEM
7.2.1 Pipeline pressure control
7.2.1.1 General
Each pipeline is permitted to operate continuously at a pressure not exceeding MAOP at
any point in the pipeline, having regard to the pipeline elevation.
Pressure control systems shall be provided and shall control the pressure so that nowhere on
the pipeline does it exceed—
(a) the MAOP under steady-state conditions; and
(b) 110% of the MAOP under transient conditions. Lice
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7.2.1.2 MAOP under steady state conditions
For pipelines intended to be operated at a set point equal to MAOP, the control system shall
control the maximum pressure within a tolerance of 1%.
Pressure control and a second pressure-limiting system are mandatory. The second
(pressure-limiting) system may be a second pressure control or an overpressure shut-off
system or pressure relief.
7.2.1.3 Transient conditions
The transient pressure at any point in the pipeline shall not exceed 110% of the MAOP.
Transient pressure is the over pressure that is associated with an unsteady flow situation
when flow changes from one steady-state situation to another steady-state situation. This is
an event with a duration typically measured in seconds for liquids and seconds or minutes
for gases.
For a pipeline transporting liquids (including HVPL, two phase and dense phase fluids), a
transient hydraulic analysis shall be undertaken to confirm compliance with the
requirements of this clause under all credible operating scenarios.
For a pipeline transporting gas, an analysis shall be made of its control systems to
determine whether there are fast acting events that could cause transient pressures. Control
systems to be considered include shutdown and pressure control systems that may exist
downstream of the point of interconnection (i.e. customer controls). Where this analysis
suggests that the transient pressure limit may be exceeded, a transient hydraulic analysis
shall be undertaken.
7.2.1.4 Pressure control system performance
Pressure control and overpressure protection systems and their components shall have
performance characteristics and properties necessary for their reliable and adequate
operation during the design life of the pipeline.
Design of pressure control systems and overpressure protection systems for pipelines shall
include an allowance for—
(a) effective capacity of these systems;
(b) pressure differentials between individual control or protection systems; and
(c) pressure drops that occur between sources of pressure and the control and protection
systems.
7.2.1.5 Shut-in conditions
Consideration shall be given to the following conditions when a pipeline is shut-in between
isolation points:
(a) Pressure equalization.
(b) Fluid static head.
(c) Fluid expansion and contraction due to changes in fluid temperature, particularly in
above-ground pipelines.
7.2.1.6 Safety
Where any pressure control or overpressure protection will discharge fluids from the
pipeline, the discharge shall be safe, have minimal environmental impact and not impair the
performance of the pressure control or over pressure protection system. Particular care shall
be taken with the discharge of liquid and HVPL.
Accidental and unauthorized operation of pressure control and overpressure systems and
changes to settings of this equipment shall be prevented. Lice
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7.2.2 Separation of pipeline sections with different MAOP
Sections of a pipeline system that have different MAOP shall be designed to prevent the
MAOP of each section from being exceeded.
Where isolation is used to separate sections with a different MAOP, the minimum
requirement for separation by isolation shall be two isolation components, two valves or
one valve and a blind. A method of venting the space between the two isolation components
shall be provided.
Where pressure control is used to separate sections with a different MAOP, the minimum
requirement for isolation by pressure control is a pressure control system complying with
the requirements of Clause 7.2.1.
Where hydraulic gradient is used to control the pressure, the pipeline control system shall
ensure that the MAOP of each section is not exceeded.
7.2.3 Pipeline facility control
Most facilities are remote from their point of operation and generally designed for
unattended operation. Each facility shall be designed with a local control system to manage
the safe operation of the facility.
The local control system shall—
(a) continue to operate in the event of a communications failure;
(b) if electric powered, be provided with an uninterruptible power supply with sufficient
capacity to ensure continuous operation through a reasonable power outage;
(c) use reliable technology;
(d) be designed to fail in a safe manner; and
(e) be designed with appropriate security.
Each facility may also be configured to enable remote monitoring or control of the facility.
7.3 FLUID PROPERTY LIMITS
Where the properties of the fluid may exceed the limits for which the pipeline was
designed—
(a) appropriate instrumentation shall be installed on a pipeline to enable each relevant
fluid property to be monitored; or
(b) where suitable data is available from upstream systems, that data may be used.
Where the pipeline facility does not incorporate equipment to control the quality, the
control system shall be capable of excluding non-complying fluid from the pipeline.
The Design Basis should document the maximum fluid property excursion and duration of
that excursion, which, if exceeded, will require the exclusion system to be activated. The
maximum excursion and duration of that excursion should be assessed in the pipeline safety
management study prior to commencement of operation.
7.4 SCADA—SUPERVISORY CONTROL AND DATA ACQUISITIONS SYSTEM
Where a pipeline is provided with a SCADA system, it shall—
(a) be reliable;
(b) supervise the operation of the pipeline system;
(c) be capable of issuing operating and control commands;
(d) be capable of collecting and displaying data, facility alarms and status;
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(e) when specified, gather operating data and present it in a form which can be used by
system operators and managers, including data required for the commercial operation
of the pipeline;
(f) not prevent control systems at remote facilities operating safely, irrespective of the
condition of the SCADA system; and
(g) be fail-safe on loss of power or communication.
It may also incorporate, a leak detection system, business management systems and
personnel management systems.
The SCADA system design shall be assessed to determine the consequence of system
failure to system safety, supply continuity, and business viability.
Consideration shall be given to the ability of the pipeline system to continue safe operation
following an event that results in complete loss of the control room and associated
computer hardware, software and data storage.
Redundant equipment and/or a hot standby SCADA master station may be necessary to
maintain safe, continuous operation of the pipeline network and business management
systems.
7.5 COMMUNICATION
A communication system is normally required for the operation of a SCADA system. The
communication system shall be reliable and have an appropriate speed, considering the data
acquisition, control response and emergency/safety response required for the pipeline.
The designer shall consider the use of multiple communication routes.
Distributed devices shall be capable of safely operating the process systems and equipment
under their control, and acquiring data for future recovery by the SCADA system in the
event that communication with the SCADA master station and control room is lost.
The designer should consider the need for voice communication between the operations
centre(s) and field personnel.
7.6 CONTROL FACILITIES
A control facility should be designed with adequate functionality to ensure the operator is
fully informed of the status of the entire system, and where required, of each component of
the system.
When designing a control room, consideration should be given to its accessibility from the
emergency control centre.
Appropriate security systems shall be provided to assure the safe and reliable operation.
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S E C T I O N 8 M I T I G A T I O N O F C O R R O S I O N
8.1 BASIS OF SECTION
Measures shall be taken to mitigate corrosion and other destructive processes, such as
environment-related cracking, which could affect the integrity of the pipeline.
When determining necessary measures, consideration shall be given to the potential for
both internal and external corrosion and degradation.
The corrosion mitigation strategy shall address the design of corrosion and condition
monitoring programs to provide assurance that the measures implemented are successfully
achieving their objectives.
Any changes to the operation of the pipeline, which could result in a change in the potential
for corrosion, shall be reviewed and their impact assessed. Appropriate changes to the
mitigation program shall be implemented.
The corrosion mitigation strategy shall be approved.
Where this standard is used for construction of pipelines using corrosion-resistant alloy
pipe, the corrosion design shall take full account of the materials used.
The provisions of this Section should not be applied to CRA materials without expert
advice.
8.2 PERSONNEL
The design, installation, operation and maintenance of corrosion mitigation systems shall be
carried out by, or under the direction of, persons qualified by experience and training in the
appropriate aspects of corrosion mitigation in pipelines. Where the pipeline is influenced by
stray electrical currents, the persons shall have had experience with the mitigation of such
currents.
8.3 RATE OF DEGRADATION
8.3.1 Assessment
An assessment shall be made of degradation mechanisms that could affect the pipeline, and
the rate of degradation estimated. The result of this assessment shall be documented in the
Design Basis. In making the assessment, consideration shall be given to—
(a) internal and external conditions, and
(b) changes expected to occur over the life of the pipeline.
NOTE: A list of factors that should be taken into consideration in the assessment, together with a
discussion of the impact of each item, is contained in Appendix O.
In cases where it is not possible to accurately assess the rate of degradation, or to ascertain
if corrosion could impact on pipeline integrity within the design life of the pipeline,
appropriate provision should be made for corrosion mitigation.
Information on rates of degradation should be gathered from pipelines in similar locations
and service and taken in to consideration. Alternatively, an estimate of the corrosion rate
may be developed from published or experimental data. After commissioning a pipeline the
predicted and a measured rate of degradation should be compared to establish adequacy of
the design.
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8.3.2 Internal corrosion
8.3.2.1 Gas pipelines
Where free water is present or is likely to form in a hydrocarbon gas pipeline, the gas shall
be considered to be corrosive. Appropriate measures to mitigate the corrosion shall be
adopted unless the system can be demonstrated to be non-corrosive. Gas that is dry (i.e. free
of liquid water) shall be considered non-corrosive. Hydrocarbon gases transported at
temperatures that are at all times 8°C higher than the water dewpoint of the gas may also be
considered non-corrosive.
8.3.2.2 Liquid hydrocarbon pipelines
The corrosiveness of liquid hydrocarbons shall be assessed to establish likely corrosion
rates. Where the corrosiveness is not already known from previous tests, investigations or
experience, testing shall be conducted and shall simulate the most aggressive conditions
expected over the life of the system. Appropriate mitigation methods shall be selected.
8.3.3 External corrosion
Where the rate of external corrosion is assessed to affect the integrity of the pipeline over
the expected life of the system, an approved coating system shall be applied. For
underground pipe, the coating system shall be supplemented by cathodic protection and
shall be selected in conjunction with the cathodic protection design, taking into account
pipeline environment, operating conditions and required design life. Where appropriate,
provision shall be made for stray current drainage.
8.3.4 Environmentally assisted cracking
The potential for environment related cracking of the pipeline shall be assessed and, if
warranted, appropriate control measures shall be incorporated in the design or operation of
the pipeline to prevent failure within its design life.
NOTE: Guidance on environment related cracking of carbon steels is given in Appendix P.
8.3.5 Microbiologically induced corrosion (MIC)
MIC can be present both internally (wet gas pipelines or liquid pipelines) and externally.
Sulphate reducing bacteria (SRB) and acid producing bacteria (APB) are the main threats.
The potential for the presence of bacteria shall be assessed and if warranted, appropriate
mitigation shall be provided.
8.4 CORROSION MITIGATION METHODS
8.4.1 General
Where corrosion could affect the integrity of a pipeline during its design life, the pipeline
shall be provided with one or more of the methods set out in this Section.
8.4.2 Corrosion mitigation methods
Corrosion may be mitigated by one of the methods listed in Table 8.4.2.
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TABLE 8.4.2
APPLICABLE METHODS FOR MITIGATING CORROSION
External corrosion (see Clause 8.8) Mitigation
measure
Internal corrosion
(see Clause 8.7) Buried Submerged Above ground
Lining X
Inhibitor and/or
biocide
X
Coating X X X
Cathodic protection
(with stray current
mitigation in stray
current areas)
X X
X = applicability
NOTES:
1 Cathodic protection would normally only be used in conjunction with an appropriate coating system;
however, in specific circumstances, such as temporary lines and gathering lines, cathodic protection may
be applied to uncoated pipelines.
2 Where the pipeline is externally coated, cathodic protection would normally be applied.
3 The addition of a corrosion allowance to the pipe wall thickness does not mitigate corrosion, but is a valid
method for providing for its effect during the design life of the pipeline.
8.5 CORROSION ALLOWANCE
A corrosion allowance is an increase in the wall thickness of the pipe by an approved
amount in excess of that required to withstand internal pressure, external loads and other
defined requirements.
A corrosion allowance may be used as all or part of the corrosion mitigation measures for
both internal and external corrosion. Where internal corrosion is expected, a corrosion
allowance should be used in conjunction with other active corrosion mitigation methods to
provide additional protection against unexpected corrosion rates or failure of the other
methods.
A corrosion allowance may be appropriate for above-ground pipelines, particularly where
the conditions are conducive to minimal or general external surface corrosion, and in
particular where external coating systems may be difficult or impractical to maintain. An
external corrosion allowance would be unusual on buried pipelines, except in conjunction
with other corrosion mitigation methods, unless it can be shown that the external corrosion
is uniform and generalized.
A corrosion allowance is not an effective means of mitigating pitting corrosion and will
provide little surety of long-term integrity in situations where pitting corrosion is likely.
Where a corrosion allowance is used, systems capable of determining the corrosion rate or
loss of wall thickness shall be employed.
A corrosion allowance shall be approved.
8.6 CORROSION MONITORING
A strategy for detecting, monitoring and mitigating corrosion shall be developed. The
frequency of monitoring shall be appropriate to the anticipated corrosion rate.
The corrosion monitoring strategy shall be approved.
The strategy and specific procedures developed or required to be implemented shall be
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The effectiveness of the corrosion mitigation systems shall be assessed by at least two
independent methods. Where corrosion is detected or anticipated, systems capable of
determining the corrosion rate or loss of wall thickness shall be employed.
The corrosion monitoring and assessment measures shall ensure corrosion is detected before
it adversely affects the integrity of the pipeline. Monitoring systems may include physical
inspection, removable coupons, proprietary instrumentation, and internal inspection devices
and equipment.
Corrosion monitoring programs shall be maintained for the life of the pipeline.
The frequency of monitoring shall be appropriate to the expected corrosion rate.
NOTES:
1 An example of multiple measures for monitoring external corrosion is monitoring of cathodic
protection levels plus coating defect surveys and examination of defects detected.
2 An example of multiple measures for monitoring internal corrosion is monitoring of process
chemistry, corrosion probes or coupons or inline inspection and assessment of defects
detected.
8.7 INTERNAL CORROSION MITIGATION METHODS
8.7.1 General
The interior surface of a pipeline conveying a corrosive or potentially corrosive fluid shall
be protected against corrosion.
When internal corrosion is anticipated, and provision is made in the design to mitigate
internal corrosion, the design shall include an appropriate method for the operator to easily
monitor the rate of internal corrosion. The monitoring method shall be maintained for the
life of the pipeline.
8.7.2 Internal lining
Any lining applied to mitigate internal corrosion shall be rated by tests appropriate for the
service conditions of the pipeline and for the design life of the pipeline. A lining used for
the purpose of preventing corrosion shall be continuous across welds and repairs to the
pipeline.
NOTES:
1 Linings prevent corrosion while they are physically intact. As it is difficult to assure this in
service, it is normal practice to supplement the lining with inhibitor addition. No inhibitor is
considered necessary if the lining is installed solely to reduce friction.
2 Lining selection should take account of any intended pigging program for the pipeline, to
prevent mechanical damage to the lining.
8.7.3 Corrosion inhibitors and biocides
Selection of corrosion inhibitors and/or biocides to be added to the process stream shall be
based on the effectiveness of the chemical under the operating conditions of the pipeline.
Effectiveness of the chemicals shall be determined in laboratory tests or by previous
experience. Such tests shall take into account the levels of turbulence in the system.
Chemicals added to the fluid in this way shall be—
(a) chemically and physically compatible with the pipeline components and linings, with
any other chemicals added to the pipeline and with the downstream facilities; and
(b) injected at sufficient concentrations and intervals to achieve the desired purpose.
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8.7.4 Corrosion-resistant materials
In corrosive environments materials that are inherently resistant to corrosion may offer life
cycle cost benefits. For example corrosion-resistant alloys or fibreglass line pipe. Corrosion
resistance of such materials shall be determined and proven by laboratory tests or by
previous experience.
8.8 EXTERNAL CORROSION MITIGATION METHODS
8.8.1 General
Where external corrosion is expected to affect the integrity of the pipeline over the life of
the system, appropriate corrosion control methods shall be implemented.
Corrosion control on buried pipelines shall be by two independent measures, such as
protective coatings in conjunction with cathodic protection. In specific circumstances such
as temporary lines or gathering lines, cathodic protection may be applied to uncoated
pipelines, or protective coating may be used as the sole protective measure.
Use of only one protective measure shall be approved.
8.8.2 Coating
External anti-corrosion coatings, and materials used for the repair of defects or for
protection of site field welds shall have physical, electrical and chemical properties that
have been demonstrated by tests, investigations or experience to be suitable for the
installation and service conditions of the pipeline and the environment for the duration of
the design life of the pipeline.
NOTE: A factory-applied coating is preferred for all pipeline components, to ensure adequate
surface preparation and coating application under controlled conditions.
Repair material shall be compatible with the original coating and shall provide similar
performance capabilities. Where cathodic protection is to be applied, the coating and repair
material shall be compatible with the level of protection envisaged.
Procedures for preparation of the surface of the pipe and application of the coating and
repair material shall be developed. Criteria for acceptance of the coating prior to
installation shall be developed. The application of the coating and of site repairs shall be
subject to a quality assurance program.
The integrity of the coating on buried pipelines shall be tested in accordance with
AS 3894.1 using the high voltage method immediately prior to final placement, and any
coating defects detected shall be repaired.
For buried pipelines, the integrity of the coating should be confirmed by coating defect
survey once the soil has been allowed time to settle and stabilize around the pipe, and the
significance and need for repair of any defects evaluated. Coating defect surveys carried out
using soil contact electrodes shall be conducted when soil surface conditions are suitable to
allow adequate electrical contact between electrode and soil. Appropriate techniques shall
be employed to ensure the survey is carried out directly above the pipeline.
Repairs shall be carried out using approved materials and procedures.
Where the coating is liable to damage from stones and rocks in the ditch, the long-term
integrity of the coating shall be assured by use in the ditch of sand padding, selected
backfill or protective outer wraps, or a combination of these.
NOTES:
1 For an above-ground pipeline, painting may be suitable.
2 Where a coated pipe is to be installed by thrust boring, directional drilling or similar methods,
an abrasion resistant coating should be used.
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8.8.3 Cathodic protection
Design, operation, commissioning, monitoring, documentation requirements and protection
criteria for cathodic protection shall comply with AS 2832.1.
Levels of protection shall be controlled, so that potentials that could be deleterious to the
structure or to the coating are avoided.
Steel may be protected from corrosion by the application of direct current to maintain the
potential of the metal sufficiently negative with respect to its environment. Direct current
may be provided by the use of galvanic anodes, or by means of an impressed current
system. The potential of a structure with respect to its environment can provide a reliable
measure of the degree of protection.
Cathodic protection systems for pipelines shall not cause unacceptable levels of
interference on other underground or submerged structures. The cathodic protection system
shall be compatible with the coating used on the pipeline.
Cathodic protection shall be applied to each section of a pipeline. The method and timing of
the installation of temporary and permanent cathodic protection systems shall be
documented and approved.
Stray currents from traction systems, other impressed current systems or telluric sources
shall be investigated and appropriate mitigative measures implemented, as necessary. It
may not be possible to determine the necessary mitigative measures until pipeline laying is
complete and the backfill fully consolidated.
NOTES:
1 Further information for cathodic protection is given in Appendix Q.
2 In some Australian states, the installation and/or operation of cathodic protection systems
requires approval from a regulatory authority.
8.8.4 Design considerations
8.8.4.1 Cathodic protection current requirements
The current requirement for cathodic protection shall be determined by trial or by
calculation. Calculations may draw on experience with the pipeline coating being used. The
assumptions used for the derivation of the total current requirement shall be clearly
documented. Allowance shall be provided—
(a) to cater for structure coating deterioration over the life of the system; and
(b) to mitigate interference effects with any secondary structures.
8.8.4.2 Environment resistivity
The environment resistivity at the site of each cathodic protection installation shall be
determined and documented.
8.8.4.3 Anode characteristics
The performance characteristics of the anodes to be used for the system shall be determined
by test or reference to previous experience and shall be documented. In particular, the
actual consumption rate of the anode in the particular environment shall be determined and
confirmation made that the anode will achieve the system requirements in terms of current
output and life.
8.8.4.4 Pipeline layout
Details of the structure shall be collected and documented. Features that could affect the
successful implementation of the cathodic protection system shall be documented and
considered in the design.
NOTE: A list of items that may need to be considered is given in Appendix Q. Lice
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In addition, relevant details of the following features shall be gathered and assessed:
(a) System features Structure isolation points, coating details and road and rail crossings.
(b) Other features Any d.c. traction systems, foreign structure crossings, foreign
corrosion protective systems and neighbouring a.c. power systems.
8.8.4.5 Test points
A sufficient number of test points shall be installed at appropriate locations to obtain the
necessary electrical measurements to adequately monitor the cathodic protection system.
Consideration shall be given to the installation of additional test points at road, rail,
waterway and foreign structure crossings.
Cable attachments shall be made in accordance with Clause 10.11 and the connection and
any damage to the coating repaired with an approved material that is compatible with the
structure coating and the cable insulation.
8.8.4.6 Materials
Materials shall comply with the appropriate codes and Standards and shall be suitable for
the installation in the proposed environment.
8.8.4.7 Reference electrodes
Permanently installed reference electrodes shall last the life of the structure, or provision
shall be made for replacement. The potential of a reference electrode shall be able to be
verified, so that passivation of the electrode is detectable.
8.8.4.8 Electrical isolation joints
Electric isolation joints shall be designed to take account of the operating conditions of the
pipeline in terms of vibration, fatigue, cyclic conditions, temperature, thermal expansion
and construction installation stresses. The materials selected shall be resistant at the
pipeline design temperature to the fluids in the pipeline, including any corrosion inhibitors
or flow modifiers that may be added to the product. Before installation into the pipeline, the
joint shall pass—
(a) a hydrostatic pressure test without end restraint at a pressure equal to the pipeline test
pressure; and
(b) an electric insulation test at ambient temperature and the pipeline test pressures.
8.8.4.9 Electrical isolation
Where specified in the design of cathodic protection systems, supports and anchors shall be
electrically isolated from the pipe by insulating materials.
8.8.5 Measurement of potential
During measurement of the potential, the reference electrode shall be positioned as close as
practicable to the pipeline.
On buried pipelines where galvanic anodes are used, the potential shall be measured at test
points that are electrically remote from the anodes.
Means shall be provided to enable the potential to be measured while the cathodic
protection system is operating. Such means also apply to a submerged pipeline.
In areas where stray traction currents occur, the measurement and recording of potential
shall include times when there are extreme adverse effects of the stray current on the
pipeline. For example, in an urban area, the morning and evening transit peaks should be
included.
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In areas subject to telluric current influences, the measurement and recording of potential
should include periods when major telluric activity is occurring. Information on levels of
telluric activity can be obtained from the Ionosphere Prediction Service.
NOTES:
1 Provision should be made to enable earthing systems to be decoupled during measurements.
2 Where possible, the potential should be measured by the use of cyclic on/off techniques, and
the instantaneous off or polarization potential of the pipe should be compared with the
−850 mV criterion.
3 For guidance on the measurement of instantaneous off-potential, see AS 2832.1.
4 For guidance on telluric influences, see AS 2832.1.
8.8.6 Electrical earthing
Where potentially hazardous rises could occur with respect to the neighbouring earth, the
pipeline shall be electrically earthed or otherwise protected by a suitable means that does
not compromise the effectiveness of the cathodic protection system. Such potential rises
could occur by virtue of parallelisms with high voltage a.c. powerlines, proximity to power
earthing systems or due to lightning.
NOTE: For guidance on mitigation of a.c. effects from power lines, see Appendix R.
8.9 EXTERNAL ANTI-CORROSION COATING
8.9.1 Coating system
The performance of a coating system is not solely dependent on the materials used, but also
on the standard of surface preparation achieved and the method used for application.
Therefore, surface preparation, coating material, application methods and testing methods
shall be subject to quality control. The procedures for quality control shall be approved.
8.9.2 Coating selection
The coating used for corrosion protection of a pipeline shall have physical and chemical
properties suitable for the engineering design. It shall be compatible with the pipeline
service and its environment for the full design life.
Consideration shall be given to the possibility of coating damage occurring in handling,
installation, pressure testing and in service, due to environmental or operating temperatures
and loads.
The suitability of the material for the service and environmental conditions of the pipeline
shall have been demonstrated by tests, investigations or experience.
NOTES:
1 For a list of the chemical and physical properties that a coating should possess and guidance
on the types of coating available, see AS 2832.1. Additional guidance is provided in
AS/NZS 1518 and AS/NZS 3862.
2 For an above-ground pipeline, a thin film ‘paint’ coating may be suitable; however, thicker
and more robust coating systems are generally required for underground or submerged
applications.
8.9.3 Coating application
Procedures for application of the coating shall be developed so that the desired physical and
chemical qualities are obtained. The application thereafter shall be in strict accordance with
the procedures. Surface preparation, application and testing of the coating shall be subject
to an approved quality control program.
Factory-applied coatings generally achieve a higher standard than site applied coatings, due
to the better control of ambient conditions.
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8.9.4 Joint and coating repair
Where a joint is made in a pipeline or the external coating is repaired, the material used
shall be compatible with the original coating and shall have been demonstrated by test,
investigation or experience to be suitable for the method of installation, the service
conditions and the environment.
Procedures for application of the coating to a joint and for making a repair shall be
developed so that the desired physical and chemical qualities are obtained. The application
thereafter shall be in strict accordance with the procedures. Surface preparation, application
and testing of the coating shall be subjected to an approved quality control program.
8.10 INTERNAL LINING
8.10.1 Pipeline lining
The purpose of the lining (e.g. short-term corrosion protection, long-term corrosion
protection and friction reduction) shall be specified and documented and the materials used
shall achieve the specified purpose. The need to apply lining to welds and site repairs is
dependent on the purpose of the lining and shall be clearly specified in the project
documentation.
The suitability of the material for the service and environmental conditions of the pipeline
and of the application method shall have been demonstrated by tests, investigations or
experience.
Procedures for application of the lining shall be developed, so that the desired physical and
chemical qualities are obtained and the application thereafter is in strict accordance with the
procedures. Surface preparation, application and testing of the coating shall be subjected to
an approved quality control program.
Where a two-component catalyzed epoxy lining is specified, the methods of application and
inspection and the criteria of acceptance should comply with API RP 5L2.
8.10.2 Joint and repair lining
Materials used for the lining of joints and repairs to the lining shall be compatible with the
original lining. The suitability of the material and the application methods for the service
conditions and the environment shall have been demonstrated by tests, investigations or
experience.
Procedures for application of the repair material shall be developed and shall be subject to
an approved quality control program.
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S E C T I O N 9 U P G R A D E O F M A O P
9.1 BASIS OF SECTION
This Section sets down a systematic process for upgrading a pipeline to an MAOP that is
higher than the pressure for which it is approved.
The following principles shall apply for upgrading the MAOP of a pipeline, or segment of a
pipeline:
(a) The pipeline shall be treated as a new pipeline, and shall comply with all of the
requirements of the current edition of this Standard.
(b) The increased MAOP shall not be higher than the value determined in accordance
with the hydrostatic testing principles in this Standard.
(c) The ability of the pipeline to operate safely at an increased operating pressure shall be
demonstrated by an engineering review of each element of the pipeline system to
determine its suitability for the increased pressure. The engineering review shall
identify and analyse pipe degradation, including time-dependent degradation to
provide the basis for assessing fitness for safe operation at an increased pressure. The
engineering review is to be undertaken by a competent person.
(d) The design factor for the upgraded MAOP shall not exceed the lower of the design
factor permitted by this Standard and 0.72. The increased MAOP shall not result in
the hoop stress at the new MAOP to exceed 72% of the SMYS.
(e) The upgraded MAOP shall be approved.
9.2 MAOP UPGRADE PROCESS
9.2.1 Process stages
Each MAOP upgrade shall be implemented through a structured engineering review
process, which shall include at least the following:
(a) Preparation of an upgrade Design Basis.
(b) Data collection or, where necessary, development.
(c) Analysis of the data and assessment against the requirements of the upgrade Design
Basis.
(d) Safety management study.
(e) Rectification.
(f) Establishing the revised MAOP that can be achieved.
(g) Approval of the upgraded MAOP.
(h) Commissioning and testing.
(i) Records.
9.2.2 Upgrade Design Basis
An Upgrade Design Basis shall be prepared in accordance with the Design Basis
requirements of Clause 4.5.1.
The upgrade Design Basis shall—
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(a) state the target MAOP and define the segment or segments of the pipeline and other
parts of the pipeline system related to those segments that will be incorporated in the
MAOP upgrade;
(b) identify those items and defects for which limiting criteria have to be established
either as a basis for specifying the selection criteria for inspection tools, or for
assessing the findings of the analysis; and
(c) identify the methods by which the investigation and analysis of the MAOP upgrade
process will be verified.
9.2.3 Data collection
Current and historical data of the original design and construction, historical operating and
maintenance data, and time-dependent integrity data shall be collected or, where necessary,
developed. The data shall be sufficient to allow the assessment of the integrity of each
component of the pipeline system, and its suitability for operation at the changed MAOP.
The following applies to data collection:
(a) Design and construction At least the following data related to the design and
construction of the original pipeline system and of any pipeline system alteration or
repairs shall be gathered or, where necessary, developed:
(i) For pipelines designed and constructed to a previous edition of AS 2885, or to
another standard, each departure from the current revision of this Standard.
(ii) The latest hydrostatic strength test records for each part of the pipeline, for
each pipeline station, each component and for each pressure vessel. Where the
hydrostatic test record of a part of the pipeline of component cannot be sighted,
the component strength shall be re-established by hydrostatic test in accordance
with this Standard.
NOTE: The hydrostatic strength test records may be used to calculate the maximum
defect size remaining in the pipeline after construction for use in ECA and fatigue
analysis.
(iii) All material certificates for the pipe, for each component of station piping and
for each pressure-containing component. Where material certificates do not
exist, the suitability of the component shall be established in accordance with
Section 3.
(iv) The quality assurance applied to the pipeline construction.
NOTE: The radiographic defect acceptance criteria can be used to calculate the
maximum defect size remaining in the pipeline after construction for use in ECA and
fatigue analysis of girth weld defects.
(b) Operating and maintenance history Current and historical data relating to the
operation and maintenance of the pipeline system shall include at least the following:
(i) Operating condition history including the fluid being transported, pressure,
pressure profile, pressure range and cycle period, and temperatures.
(ii) Changes in operating conditions from those for which the pipeline was
designed.
(iii) Historic pipeline integrity data that shall identify each threat known or likely to
exist in the pipeline.
(iv) Controls and control set-points required to control the pressure and temperature
of the pipeline together with each associated system including transient
pressure control, throughput and gas quality measurement, and associated
business system.
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(c) Physical examination The pipeline shall be examined using effective inspection
techniques to locate each defect that may affect pressure containment, including time
dependent degradation.
Prior to the examination, limiting conditions for defect size at the proposed MAOP
shall be established as criteria for assessment of defects. As a minimum, limiting
criteria shall be stated for—
(i) metal loss due to general corrosion or pitting corrosion;
(ii) stress corrosion cracking (SCC);
(iii) fatigue cracking; and
(iv) damage due to external interference.
The examination shall be undertaken using one or more in-line inspection tools.
The sensitivity, discrimination and reliability of the inspection tool(s) shall be sufficient to
permit defect dimensions to be assessed against the limiting criteria.
The sensitivity, discrimination and reliability of the inspection tool(s) shall be confirmed by
excavation and direct examination.
Special care shall be taken in the collection of data related to SCC defects. Investigation as
to the appropriateness of in-line inspection tools and their discrimination against the
limiting criteria shall be undertaken.
Where it is not practicable to examine the pipeline by in-line inspection, the pipeline
fitness-for-pressure containment at the target MAOP shall be demonstrated by a hydrostatic
strength test in accordance with the requirements of this Standard.
The coating condition shall be established over the length of the pipeline.
NOTES:
1 Special care should be taken in the assessment of dents. It is recommended that every dent
discovered by in-line inspection be exhumed to ensure that gouging is not present.
2 If adequate in-line inspection or hydrostatic testing has been carried out within a timeframe
less than that for deterioration due to the identified time-dependent mechanisms, additional
in-line inspection or hydrostatic testing may not need to be undertaken.
3 Data relevant to developing an assessment of the condition of the pipeline is available from a
wide range of sources. All sources that reasonably contribute to developing an understanding
of each aspect of the pipeline condition are considered as an input to the integrity analysis.
Sources may include aerial photos, ground movement/topography surveys, GIS systems, in-
line geometry inspections, direct current voltage gradient survey, and Pearson surveys.
9.2.4 Engineering analysis
Engineering analysis of the data shall be undertaken to determine the ability of the pipeline
to operate in accordance with the criteria as outlined in the Upgrade Design Basis and
identify items that require rectification to satisfy the Design Basis.
Reliability (limit state) analyses may be undertaken to provide additional knowledge on the
ability of the pipeline to sustain the target MAOP. The results of the analyses shall not be
used as the sole basis for establishing the target MAOP.
The analysis shall include the following:
(a) Characteristics related to target MAOP All characteristics that are affected by
operation at the target MAOP shall be identified and documented for rectification if
non-compliant, including at least the following:
(i) Each regulatory compliance requirement that may be affected by the changed
operating condition. Lice
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(ii) Fluid properties for the changed operating condition.
(iii) Effect of fluid property changes for associated downstream conditions,
including temperature effects at pressure reduction facilities.
(b) Previous pipeline standards For pipelines designed and constructed to a previous
edition of AS 2885, or to another Standard, each departure from this Standard shall be
analysed and, where significant, a plan for rectification of the departure developed.
(c) Pipeline segments The data shall be analysed to establish compliance with each
design criteria at the target MAOP. Each item identified as non-compliant shall be
documented for rectification or a revised MAOP for which compliance is achieved
shall be identified. The analyses shall include, at least:
(i) Time-dependent degradation Data shall be analysed for time-dependent
degradation. This analysis shall include the pipeline maintenance history, and
its operation to assess the likelihood of it containing these mechanisms.
Conditions examined shall include at least the following:
(A) Metal loss due to general corrosion.
(B) Stress corrosion cracking (SCC).
(C) Fatigue cracking.
Any discovered defects and potential time-dependent mechanical damage,
fatigue, and environmental degradation mechanisms shall be subjected to an
engineering critical analysis.
(ii) Pipe wall damage Pipe wall damage such as dents, gouges, grooves and
notches, which are non-time-dependent, shall be assessed by defect analysis
based on the target MAOP.
(iii) Pipeline design and safety The requirements in Sections 4 and 5 of this
Standard for a new pipeline including fracture control, pipeline isolation and
special provisions for high consequence areas shall be reviewed using the target
MAOP. Compliance criteria for each requirement shall be established for each
revised condition and rectifications implemented accordingly.
(iv) Stress The stresses at the target MAOP shall be analysed and limited in
accordance with Clause 5.7 of this Standard.
(d) Pressure-rated components Where a pressure-rated component is included in a
pipeline assembly or station piping whose MAOP is to be increased above the
manufacturer’s pressure rating for that component, an analysis shall be conducted of
the suitability of the component to meet the target MAOP for the remaining life.
Components not suitable shall be replaced. The following applies:
(i) Use of pressure-rated components at pressures above their pressure rating is
subject to the following absolute limitations:
(A) The target MAOP shall not exceed the pressure rating by more than 25%.
(B) The component shall have been subjected to a hydrostatic strength test of
at least 2 h at a pressure 1.25 times the target MAOP or higher. The
strength test may be the original strength test or a new test.
(ii) The analysis shall include consideration of the following:
(A) The prior hydrostatic test history of the component.
(B) The condition of the component. Any reduction in wall thickness or
change in material properties from new shall be accounted for in
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(C) The effect of the target MAOP on the functionality and operability of the
component. Where the functionality or operability of the component at
the target MAOP is not equivalent to the functionality or operability of
the component required, the component shall be modified or replaced.
(D) The stresses applied to the component at the target MAOP. Stresses,
strains and displacements shall comply with Clause 5.7.
(e) Documentation Documentation shall include the following:
(i) The methodologies underpinning the engineering review shall be based on this
Standard or on other Standards, and shall be detailed and approved. The
document shall explain the background and rationale for the proposed MAOP
upgrade, each assumption, and any change or extension of service life.
(ii) Each calculation and analysis prepared to demonstrate the fitness for operation
at the target MAOP shall be documented.
(iii) The results of the engineering review and the proposed actions in relation to
pipeline systems and pressure-related components shall be approved.
9.2.5 Safety management study
The safety management study shall be revised to assess compliance of the pipeline with the
requirements of this Standard when it is operated at the target MAOP.
9.2.6 Rectification
Each pressure-containing component identified as not complying with the requirements for
pressure containment at the target MAOP shall be rectified or replaced.
Where required by the engineering review, safe pressure containment of the pipeline at the
target MAOP may be established by a hydrostatic strength test in accordance with this
Standard.
9.2.7 Revised MAOP
After completion of the analysis, safety management study and rectification work, a revised
MAOP shall be established and the basis for the revised MAOP shall be documented. The
document shall explain the background and rationale for the MAOP upgrade proposed, and
any change or extension of service life.
9.2.8 Approval
The MAOP upgrade shall be approved prior to any change to the MAOP being
implemented.
9.2.9 Commissioning and testing
Prior to commencing operation at a new MAOP, a commissioning and testing plan shall be
developed to manage the safe implementation of the changed operating conditions. The plan
shall address at least—
(a) the setting and testing of each instrument and control;
(b) the number and magnitude of pressure increments used in the transition from the
original operating condition to the new condition;
(c) the requirements for leakage testing during the transition; and
(d) other minimum requirements of AS 2885.3.
NOTE: AS 2885.3 contains the minimum requirements for commissioning and testing.
9.2.10 Records
Records complying with the requirements of this Standard for a new pipeline shall be
developed and integrated with existing records of the pipeline.
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S E C T I O N 1 0 C O N S T R U C T I O N
10.1 BASIS OF SECTION
The Licensee shall be responsible for ensuring that the pipeline construction and the
completed installation are in compliance with the engineering design and the following:
(a) Construction shall be carried out to ensure the safety of the public, construction and
operating personnel, equipment, adjacent property and the pipeline (see Section 2).
(b) During construction, care shall be taken to prevent damage to the environment. On
completion of construction, any necessary restoration along the route shall be carried
out to minimize long-term degradation of the environment.
(c) Construction personnel shall be competent and where required, qualified for their
task.
10.2 SURVEY
10.2.1 General
A survey shall be made to locate the pipeline relative to permanent marks and benchmarks
complying with Mapping Grid of Australia (MGA94) or other approved datum. The
construction survey shall adopt the same marks and benchmarks as used in the engineering
design unless otherwise approved.
The survey shall develop sufficient information on the constructed pipeline to satisfy the
materials traceability requirements of Section 3. Where the pipeline centre-line is straight,
the survey shall establish the location of at least every sixth weld, the weld sequence, and
the pipe number sequence.
The existence of services, structures and other obstructions in or on the route shall be
checked, identified and recorded before construction begins, and the location of these shall
be recorded in the as-constructed survey record.
10.2.2 Survey accuracy
The survey shall establish the coordinates that locate the pipeline as suited to the location
and the engineering design. The accuracy of the X-Y coordinates shall not exceed
±100 mm. The accuracy of the as-built cover shall not exceed ±50 mm. Where approved in
R1 Location Classes remote from third-party activity this tolerance may be relaxed, but
where relaxed, the X-Y accuracy shall not exceed ±1 m.
Where the survey is required to establish the elevation of the pipe, the accuracy of the
elevation measurement shall be documented.
NOTE: Where survey is by GPS methods, the accuracy of the elevation measurement is poor
unless high quality differential GPS instrumentation is used.
10.2.3 Horizontal directional drilled installation
Where a section of the pipeline is installed by horizontal directional drilling an as-built
survey shall be undertaken to establish the position of the installation in X-Y-Z coordinates.
As a minimum—
(a) the deviation from the design X-Y coordinates shall not exceed 0.4 degrees measured
from the coordinates of the pipe string at the start and the end of the drill;
(b) the survey shall be coordinated with the survey coordinate system used for the
pipeline; and
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(c) the accuracy limits of the as-built survey shall be defined on the as-built alignment
sheets (and/or GIS).
HDD contractors should be required to use a magnetic field generator laid along the design
alignment of the pipeline to provide a reference for directional drill guidance tools, to
significantly improve the accuracy of both the drilled hole and the as-built survey.
10.2.4 Records
A record of surveys shall be made so that, after the pipeline has been constructed, an
accurate record of the constructed pipeline can be made to show the precise location of the
pipeline and its related facilities.
NOTES:
1 Data should be in digital format, suitable for incorporating in a geographic information
system (GIS).
2 Electronic and paper records of the as constructed design may also be required.
10.3 HANDLING OF PIPE AND COMPONENTS
10.3.1 General
Pipes, including any coatings, coating material, welding consumables and other components
shall be handled, transported and stored in a manner that will provide protection from
physical damage, harmful corrosion and other types of deterioration. In particular—
(a) pipes shall be stacked to prevent excessive localized stresses and to minimize
damage;
(b) supporting blocks and bearers shall not damage pipes or anti-corrosion coatings;
(c) pipes that may be subjected to damage from traffic shall be located either at a safe
distance from the traffic or be guarded by protective barriers;
(d) temporary stockpiles shall be designed, operated and managed to protect the pipe and
anticorrosion coating from damage during storage and handling;
(e) temporary stockpiles should not be located in areas where environmental damage
(e.g. corrosion from flooding) may occur; and
(f) stringing joining and lowering-in operations, shall be designed and managed to
protect the pipe and anti-corrosion coating from damage.
NOTE: Requirements for protection of coating on pipes coated with extruded polyethylene or
fusion bonded epoxy are given in AS/NZS 1518 and AS/NZS 3862 respectively.
10.3.2 Pipe transport
Pipe shall be loaded, transported and unloaded in a manner that does not cause damage to
the pipe or coating. Transport shall comply with the requirements of the appropriate API
recommendations, unless otherwise approved.
Pipes shall be lifted and lowered by suitable and safe equipment. Care shall be taken to
prevent pipes from being dropped or to protect them from striking objects. Hooks and slings
shall be designed so that they will not—
(a) damage anti-corrosion coatings;
(b) damage pipe ends;
(c) slip; and
(d) allow pipes to drop.
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10.3.3 Construction loads
The loading condition during construction shall comply with Clause 5.7.5. Where
necessary, construction loads and the resultant stresses and strains shall be determined and
assessed.
10.4 INSPECTION OF PIPE AND COMPONENTS
10.4.1 General
Pipes and components shall be inspected before any anti-corrosion coating is applied. Anti-
corrosion coatings shall be inspected and subjected to a holiday test immediately before the
pipe is installed. Requirements for inspection and repair of coating on pipes coated with
extruded polyethylene or fusion-bonded epoxy are given in AS/NZS 1518 and
AS/NZS 3862 respectively.
Damage judged to be a defect shall be removed or repaired.
10.4.2 Ovality
The minimum internal diameter of pipes shall be approved and shall be not less than 95% of
the nominal internal diameter of the pipe being examined.
10.4.3 Buckles
Except for ripples or buckles formed during cold-field bending, a buckle shall be deemed to
be a defect where—
(a) it reduces the internal diameter to less than the approved minimum;
(b) it does not blend smoothly with the adjacent pipe as evidenced by an identifiable
notch (see Clause 10.4.5); and
(c) the height of the buckle is greater than 50% of the wall thickness.
10.4.4 Dents
Pipelines shall not contain any dents that—
(a) will impede the passage of any pig that may be used for operations or surveillance;
(b) occur at a weld;
(c) contain a stress concentrator, such as an arc burn, crack, gouge or groove; or
(d) have a depth that exceeds—
(i) 6 mm in a pipe having a diameter not more than 323.9 mm; and
(ii) 2% of the diameter in a pipe having a diameter of more than 323.9 mm.
Dents shall be repaired in accordance with Clause 10.4.6(c).
10.4.5 Gouges, grooves and notches
A gouge, groove or notch in a pipe is deemed to be a defect where it is deeper than 10% of
the nominal wall thickness or has an angular profile.
10.4.6 Repair of defects
A defect shall be repaired by—
(a) grinding, provided the remaining wall thickness is not less than 87.5% of the nominal
wall thickness sufficient to withstand the strength test; or
(b) installing an encirclement sleeve over the defect; or
(c) replacing the section of pipe containing the defect.
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10.4.7 Laminations and notches
Where a lamination or a notch occurs on the end of a pipe, the damaged end shall be
removed as a cylinder and the weld preparation remade.
10.5 CHANGES IN DIRECTION
10.5.1 Accepted methods for changes in direction
Changes in direction, including sags and overbends required to enable pipelines to follow
the required routes and the bottoms of trenches, shall be made by—
(a) bowing the pipe, without the need of an external force to keep the pipe in position
before backfilling;
(b) springing the pipe, to follow the line of the trench;
(c) cold bending the pipe in accordance with Clause 10.6;
(d) use of induction bends;
(e) use of forged fittings;
(f) use of a butt-welded joint; or
(g) use of another approved method.
10.5.2 Internal access
Where it is intended to use internal inspection tools, bends shall not impede a free passage
of those tools.
The type and radius of a bend shall not impede the passage of pigs of a type and size that
may be specified by the Design Basis.
10.5.3 Changing direction at a butt weld
A change of direction of less than 3° at the intersection of the centre-lines of two straight
pipes is permitted at a butt weld.
10.5.4 Bend fabricated from a forged bend or an elbow
Where a bend is fabricated from transverse sections that are cut from a forged bend or an
elbow—
(a) the bend shall be used within the specified pressure rating of the forged bend or
elbow; and
(b) the length of the arc measured along the crotch shall be not less than six times the
nominal wall thickness of the fitting.
10.5.5 Roped bends
The longitudinal bending stresses induced by roping are not limited by this Standard, but
strain shall comply with Section 5. External forces shall not be used to add to the self-
weight of the pipe in the roping operations.
NOTE: The strain limit in Section 5 (0.5%) is equivalent to a roping radius of 100D. In practice it
is difficult to achieve this radius because of the prohibition above on the use of external force and
possible buckling of the pipe. The recommended minimum roped bend radius is 250D.
10.6 COLD-FIELD BENDS
NOTE: The basis of this Clause is given in Paragraph S2, Appendix S.
10.6.1 General
Cold-field bends in line pipe complying with this Standard shall be made by qualified and
experienced operators using a cold-field bending procedure qualified and approved in
accordance with this Clause before production bending commences.
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10.6.2 Qualification of cold-field bending procedure
The qualification of cold-field bending procedures shall be as follows:
(a) One or more test bends shall be made in each bending machine to be used for
production bends. Pipes having metallurgical characteristics sufficiently different to
affect the stress-strain behaviour of the steel should be tested separately. Pipes and
coatings should be representative of the pipes that will be bent in the field.
NOTE: The bend procedure qualification should be made in accordance with Appendix S.
(b) The qualification test shall be fully documented and the qualified procedure shall be
approved.
(c) The bend qualification procedure shall establish—
(i) the acceptance limits for buckles, surface strains and ovality for field bends;
(ii) the methods for measuring buckle height and length and pipe ovality; and
(iii) the methods to be used during production bending for ensuring that acceptance
limits are not exceeded.
(d) Where surface strain may affect the integrity of an anti-corrosion coating, calculation
or measurement of surface strain is recommended.
10.6.3 Acceptance limits for field bends
Unless approved by the pipeline Licensee on the basis of a specific test program,
acceptance limits defined in the cold-field bending procedure shall be as follows:
(a) The height of any buckle shall not exceed 5% of the peak-to-peak length dimension in
Figures 10.6.3(A) and 10.6.3(B).
(b) Ovality shall not exceed that specified in Clause 10.4.2.
(c) Surface strain shall not exceed the lesser of the strain tolerance of the coating being
used, or 5%.
Pipe wall
STRAIGHT EDGE
Height 1
Length
Height 2
NOTES:
1 Height is the average of height 1 and height 2, measured at the length
2 Length is the trough to trough dimension
FIGURE 10.6.3(A) MEASUREMENT OF A SINGLE BUCKLE
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Pipe wall
STRAIGHT EDGE
Height
Length
NOTES:
1 Height is the peak-to-trough dimension
2 Length is the peak-to-peak or trough-to-trough dimension
FIGURE 10.6.3(B) MEASUREMENT OF MULTIPLE BUCKLES
10.7 FLANGED JOINTS
Flanged joints shall be installed in accordance with the following requirements:
(a) Bolt holes in flanged joints shall be aligned without springing of the pipes.
(b) Flanges in assemblies shall bear uniformly on the gasket.
(c) Bolts and stud-bolts shall be uniformly stressed.
(d) Gaskets shall be compressed in accordance with the design principles applicable to
the type of gasket.
(e) Bolts and stud-bolts shall extend not less than one thread beyond the nut.
NOTE: Guidelines for calculation of bolt tightening are given in Appendix T.
10.8 WELDED JOINTS
Welded joints shall comply with AS 2885.2.
10.9 COVERING SLABS, BOX CULVERTS, CASINGS AND TUNNELS
Installation of pipelines in casings, culverts and tunnels and beneath covering slabs and
their construction shall be in accordance with the engineering design.
Damage to the pipeline and its anti-corrosion coating shall be prevented.
10.10 SYSTEM CONTROLS
Control devices, safety devices, instruments and equipment required for a pipeline shall be
installed in accordance with the recommendations of the manufacturer and the engineering
design.
Forces applied to equipment shall not exceed those specified by the manufacturer.
Instruments shall be located and installed so as to enable inspection and calibration, without
undue interruption to operation of the pipeline.
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10.11 ATTACHMENT OF ELECTRICAL CONDUCTORS
10.11.1 General
Any copper electrical conductor that is connected to a pipe or to another
pressure-containing component (including conductors used for cathodic protection) shall be
installed so that the connection will remain mechanically secure and electrically conductive
throughout the design life of the pipeline. Stress concentrations should be minimised. The
conductor shall be installed without tension.
Any buried bare conductors and other buried metallic items at the point of connection shall
be coated with an electrical insulating material that is compatible with the insulation of the
conductor and the anti-corrosion coating of the pipeline.
NOTE: The preferred methods for attaching conductors to pipelines or other pressure-containing
components are aluminothermic welding or fillet welding a lug, boss or pad to the pipe or
component (see AS 2885.2). The latter method is preferred when the nominal wall thickness of
the pipe is less than 6 mm.
10.11.2 Aluminothermic welding
10.11.2.1 General
An aluminothermic weld on a pipeline may be made without qualification where it is in
accordance with Clause 10.11.2.2. An aluminothermic weld not in accordance with
Clause 10.11.2.2 shall be qualified and tested in accordance with Clause 10.11.2.3.
10.11.2.2 Aluminothermic welding without qualification
Aluminothermic welding without qualification shall comply with the following:
(a) The wall thickness of the pipe shall be not less than 4.8 mm.
(b) The size of the aluminium powder and copper oxide cartridge for aluminothermic
welding shall be not more than 15 g.
(c) The cross-sectional area of the cable conductor for each weld nugget shall be not
more than 10.5 mm2 or the equivalent of four wires each of 1.78 mm diameter.
(d) The depth of insertion of the conductor shall be sufficient for the weld material to
contact the conductor and at the same time obtain a good weld to the pipeline.
(e) The surface of the pipe for an area of not less than 50 mm square shall be cleaned by
filing or grinding to remove all surface coatings.
10.11.2.3 Aluminothermic welding with qualification
Aluminothermic welding with qualification shall comply with the following:
(a) An aluminothermic weld not carried out in accordance with Clause 10.11.2.2 shall be
qualified separately for each material composition, size of conductor, cartridge size
and type of surface preparation.
(b) A procedure test shall be conducted on three nuggets, each of which shall pass a test
of one firm side blow from a hammer having a mass of approximately 1 kg, after
which each nugget shall be visually examined for adequate bonding and the absence
of lifting. One of the test nuggets shall then be sectioned and metallographically
examined for copper penetration (including penetration of the grain boundaries) using
optical microscopy at a magnification of at least 100X. Copper penetration shall be as
follows:
(i) For nominal wall thicknesses of 4.8 mm or greater ........ not more than 0.50 mm.
(ii) For nominal wall thicknesses of less than 4.8 mm................. not more than 10%
of the nominal wall thickness.
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10.11.2.4 Inspection
A production aluminothermic weld shall be subjected to the hammer test specified in
Clause 10.11.2.3(b).
An unsatisfactory weld shall be removed and remade in a new location at least 75 mm
distant.
NOTE: The use of copper aluminothermic welding for welding directly onto pipe carries the risk of copper
liquid metal embrittlement of the steel by penetration of molten copper into the grain boundaries of the
steel. Experience indicates that problems are unlikely to exist unless the pipe wall thickness is less than
approx. 5 mm, and other contributory factors such as worn moulds or inadequate conductor insertion exist.
10.12 LOCATION
10.12.1 Position
Pipe shall be positioned in the pipeline as required by the engineering designs according to
wall thickness, SMYS, diameter and coating.
10.12.2 Clearances
Pipelines shall be installed at a safe distance from any underground structure, service or
pipeline. Precautions shall be taken to prevent the imposition of external stresses from or on
any other underground structure or pipeline.
Where a pipeline is laid parallel to or crosses an underground structure, service or pipeline
with a clearance of less than 300 mm, the pipeline shall be protected from damage that
might be caused by the other structure or pipeline and protected from electrical contact.
Unless otherwise approved, there shall be no electrical contact between a pipeline and any
other underground structure, service or pipeline.
Where practicable, there shall be sufficient clearance for any maintenance or repairs to be
carried out on the pipeline.
NOTE: In a Class T1 or Class T2 location, a pipeline should be installed below any existing
underground services, except those services designated as deep sewers or deep drains.
10.13 CLEARING AND GRADING
The route shall be cleared to the width necessary for the safe and orderly construction of the
pipeline.
The requirements specified for the protection of the environment shall be observed at all
times.
Where a route is graded, permanent damage to the land shall be minimized and soil erosion
prevented.
In developed farmland, liaison with property owners is to be maintained to minimize
disruption to farming activities.
10.14 TRENCH CONSTRUCTION
10.14.1 Safety
Excavation shall be performed in a safe manner. Damage to buried services, structures and
other buried pipelines shall be avoided.
Blasting shall be carried out in a safe manner and in accordance with AS 2187.2 and
statutory requirements.
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10.14.2 Separation of topsoil
Where required, topsoil from trenches shall be stored separately from other excavated and
backfill materials.
NOTE: Consideration should be given to preventing the transfer of noxious weeds.
10.14.3 Dimensions of trenches
The width of trenches shall be sufficient to allow pipelines to be installed in position
without being damaged and to permit full consolidation of padding and backfill material.
10.14.4 Bottoms of trenches
Where a pipe is installed in a trench, the bottom of the trench shall be free from cave-ins,
roots, stones, rocks, welding rods and other debris that could cause damage to anti-
corrosion coatings the on installed pipe.
10.14.5 Scour
Where scour could occur in a trench, barriers shall be installed to prevent scour. Barriers
shall be built of masonry, non-degradable foam, sandbags or an approved material.
Anti-corrosion coatings should be inspected for holidays immediately before any barrier is
installed around a pipe. Where required, repairs shall be made.
10.15 INSTALLATION OF A PIPE IN A TRENCH
10.15.1 General
The installation methods, materials, compaction and restoration shall support and protect
the pipeline for its design life.
A pipeline shall have a firm continuous bearing on the bottom of the trench or padding and
rest in the trench without the use of an external force to hold it in place, until the backfilling
is completed. This should be achieved by a combination of trench excavation and pipe
shape (bending).
10.15.2 Installation requirement
A typical pipe installation requires the following:
(a) The trench profile to be designed to achieve the design cover and to minimize
bending, while recognising landform and other constraints, including environmental
objectives
(b) Bending the pipe so that its shape mirrors that of the trench. Overbends should ‘ride
high’, sag bends and side bends should rest on the bottom of the trench and well away
from the trench wall.
(c) Placing bedding material to support the pipe with its coating undamaged.
(d) Installing the pipe.
(e) Covering with shading material to secure the pipe in position and protect the coating
from damage.
(f) Application of backfill.
(g) Backfill compaction.
NOTE: Techniques that support the installed pipe and place bedding and padding in a single
operation may be used.
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10.15.3 Development of specifications and procedures
The following criteria shall form the basis for developing specifications and procedures for
installing a pipeline in a trench, and covering it:
(a) Unless other provisions are made, the installed pipe shall be supported (restrained) in
its intended position by the trench and the compacted backfill.
(b) Any settlement that occurs after installation, or when loaded with hydrostatic test
water shall not impose stresses on the pipe as a result of differential settlement.
(c) The backfilling materials surrounding the pipe shall protect the pipe coating both
during installation and through subsequent operation. This may be selected material
or a barrier coating. Barrier coatings, when used, shall maintain their properties for
the design life of the pipeline.
(d) The properties, including resistivity, of the backfilling materials surrounding the pipe,
shall permit the cathodic protection system to work effectively over the full surface of
the pipe.
(e) The permeability of the backfilled and compacted trench shall be similar to that of the
unexcavated material, to minimize drainage along the trench invert, and potential
‘tunnel’ erosion.
(f) The standard of compaction shall be sufficient to deliver the required engineering
properties of the backfill.
(g) Soil inversion during backfill shall be prevented and, where specified, backfilling
shall control excavated material and return it to the trench in the sequence that it was
removed.
NOTES:
1 To ensure the efficacy of a cathodic protection system, padding and shading should be as
homogeneous as practicable and be in continuous contact with the pipeline.
2 The excavated subsoil, screened where necessary, may be suitable for padding and shading.
3 Screening machines may require the screen size to be changed as the particle size distribution
in the spoil being processed varies with soil and excavation type. Periodic field testing by
screen analysis may be required. When screening machines process spoil in two passes (to
provide bedding material prior to pipeline installation and padding after pipe installation), the
particle size distribution of material in the padding pass should be monitored to ensure that
the specified particle size is delivered, with particular concern to the percentage of material
passing a 2.36 mm screen.
4 When screening machines apply bedding and padding in a single pass machine the pipe
support should be designed to deliver firm continuous bearing to the pipeline recognizing the
soil load imposed on the pipe, and the difficulty of completely filling the gap beneath the
pipe. The support should allow the pipeline to settle as the bottom padding compacts to
ensure that there is proper support, and voids that could compromise cathodic protection are
not present. Some experience suggests that ‘foam pillow’ support may shield the pipe from
cathodic protection.
5 The engineering properties of cement-stabilized backfill materials, including ‘flowable’ fill
should be considered and specified for the locations where their use is nominated. The factors
to be considered include compressive strength for external loadings, resistance to external
interference and the ability for the material to be removed, if required, for pipeline
maintenance.
10.16 PLOUGHING-IN AND DIRECTIONALLY DRILLED PIPELINES
10.16.1 General
Where a pipeline is to be installed by ploughing-in or directional drilling procedures shall
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10.16.2 Testing of coating integrity within directionally drilled installations
If directional drilling is employed for pipeline installation in situations where the pipe
cannot be readily accessed to repair corrosion, which may result if coating is damaged
during installation, tests shall be conducted to determine the integrity of the pipeline
coating. The method of testing and the acceptance criteria to be achieved shall be agreed
prior to installation of the pipeline. If test results fail to meet the acceptance criteria the
defective section(s) of coating shall be located and repaired or replaced.
NOTES:
1 The method of testing usually requires measurements to be taken prior to tying-in the drilled
installation section to other sections of pipeline.
2 Repair may require removal of the pipe from the directionally drilled section.
10.17 SUBMERGED CROSSINGS
Procedures shall be developed for the construction of each submerged crossing. Specific
procedures shall be developed for crossings for which a location specific design is
developed. The procedures shall be approved.
The procedures shall address the following:
(a) The construction method
(b) Pre-testing (where applicable)
(c) Buoyancy control
(d) Installation loads and their management
(e) Pre-installation investigation
(f) Measures to comply with the environmental management plan
(g) Restoration measures
10.18 REINSTATEMENT
After backfilling has been completed, construction tools, equipment and debris shall be
removed. Areas that have been disturbed by the installation shall be reinstated. Appropriate
measures shall be taken to prevent erosion (e.g. the construction of contour banks or
diversion banks) and minimize long-term degradation of the environment.
Fences that have been removed to provide temporary access to the route shall be re-erected.
Reserves shall be reinstated in accordance with the requirements of the appropriate
authority.
In developed farmland, it shall be ensured that topsoil is being replaced without
contamination, and drains and general contours are reformed.
NOTE: Reinstatement should be completed as soon as is practicable.
10.19 TESTING OF COATING INTEGRITY OF BURIED PIPELINES
Subsequent to pipeline installation, the integrity of coating on buried sections shall be
examined. The method and timing of examination shall be selected so that the test system
employed is capable of reliably detecting coating defects.
NOTE: Methods of testing of coating integrity on buried pipelines include Pearson and direct
current voltage gradient (DCVG) surveys. The method of survey and assessment criteria should
be determined prior to pipeline construction. All coating defects that exceed the acceptance
criteria should be repaired in accordance with approved repair procedures appropriate to the type
of coating on the pipeline.
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10.20 CLEANING AND GAUGING PIPELINES
After completion of the construction and before pressure testing, the inside of a pipeline
shall be cleared of foreign objects. Suitable inspection pigs should be used to determine
whether the pipeline contains dents or ovality in excess of that specified in Clause 10.4.
NOTE: When a pipeline contains multiple wall thickness, a gauging plate sized on the basis of the
thickest wall may not demonstrate compliance with Clause 10.4 in the thinner wall pipe.
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S E C T I O N 1 1 I N S P E C T I O N S A N D T E S T I N G
11.1 BASIS OF SECTION
The integrity of the pipeline shall be established through an inspection testing program
undertaken concurrently with construction. The pipeline Licensee shall ensure that
inspection and testing are undertaken as necessary during manufacture, transport, handling,
welding, pipeline construction and commissioning, to ensure that the completed pipeline
complies with the engineering design and relevant Standards and has the intended quality
and integrity.
11.2 INSPECTION AND TEST PLAN AND PROCEDURES
The pipeline Licensee shall prepare and document a plan and procedures covering all
inspections and tests required by this Standard and the engineering design. Inspections and
tests shall be made in accordance with the documentation.
Corrective action shall be taken where an inspection or test reveals that specified
requirements are not satisfied.
11.3 PERSONNEL
Inspectors shall have appropriate training and experience.
Inspectors shall be qualified in accordance with the relevant requirements of this Standard
and as determined by the pipeline Licensee.
Each aspect of construction shall be inspected by a competent inspector to assure
compliance with the engineering design.
11.4 PRESSURE TESTING
11.4.1 Application
Except for components that are exempted from field pressure testing, pipelines shall pass an
approved strength test and an approved leak test.
11.4.2 Exemptions from a field pressure test
The following items may be exempted from field pressure tests:
(a) Pipes and other pressure-containing components that have been pre-tested to a
pressure that is not less than that specified for the strength test.
(b) Components that have not been pre-tested, but have an adequate design pressure or an
appropriate pressure rating complying with the Standard used for their manufacture.
(c) Tie-in welds made between hydrostatic test sections after they have been
hydrostatically tested.
(d) Small-bore controls, instruments and sampling piping.
11.4.3 Pre-tested pipe
Where access for repair of any potential field pressure test failure is difficult or impractical,
or where there is an unacceptable threat to an adjacent facility or the public, pipe should be
pre-tested in accordance with this Standard, prior to installation. Locations that should be
considered include—
(a) submerged crossings (permanent waterways);
(b) rail and major road crossings; Lice
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(c) directionally drilled crossings; and
(d) high consequences areas.
11.4.4 Test procedure
Approved strength tests and approved leak tests shall comply with AS 2885.5.
Notwithstanding the requirements of AS 2885.5 the scope of AS 2885.5 does not include
testing with air or gas; however, air or a gas may be used as a test fluid, where the use of a
liquid is impracticable and subject to the requirements of Clause 11.4.6.
The approved test procedure shall include—
(a) the maximum and minimum strength test pressures (see Clause 11.4.5);
(b) the methods for monitoring and controlling the tests;
(c) the precautions necessary to ensure the safety of the public and testing personnel; and
(d) the criteria for assessment of leak tightness.
11.4.5 Strength test pressures
The minimum target pressure for strength tests of pipelines shall be determined in
accordance with Clause 4.5.5.
The maximum value of the strength test pressure shall not exceed an end point selected in
accordance with AS 2885.5.
NOTE: Tests for which the maximum pressure has the potential to result in yielding of any pipe
under test are required to be conducted in a manner that monitors the amount of straining during
the test. This is called a volume/strain-controlled test, for which the end-point is determined
during the test. The maximum pressure may be limited by the acceptable amount of strain
(defined by a volume/strain end-point), by a maximum pressure or a maximum stress.
The current edition of AS 2885.5—2002 recommends that volume/strain end point used for pipe
that is not cold-expanded be the 0.4% offset end-point. Until the next revision of AS 2885.5 it is
suggested that this recommendation be treated with caution and that a volumetric strain of 0.2%
not be exceeded.
The maximum value of hydrostatic test pressure in a test section shall take into account the
pressure arising from the elevation difference. Guidance on the design of test sections,
including the choice of maximum elevation difference, is given in AS 2885.5.
For all pipelines which are to be hydrostatically tested at a pressure exceeding 90% SMYS
at any part of the test section, the design of the section including the elevation difference,
shall be assessed using the principles set out in AS 2885.5.
NOTE: Engineering software, which has been developed for this purpose under the auspices of
the APIA Research Program, is recommended. Australian Pipeline Industry Research Report:
CRC Project 200097 Final Report: Understanding Hydrostatic Strength Testing Behaviour, M.
Law and L. Fletcher, May 2003.
11.4.6 Testing with a gas
11.4.6.1 General
Whenever possible, pipelines should be pressure-tested using liquid as the test fluid, for
safety reasons; however, it is recognized that under certain circumstances, air or gas may
have to be used where it is not possible to use a liquid. The use of air or gas can be
hazardous.
11.4.6.2 Safety
Where the test fluid for pressure-testing is air or some other gas, a safety management study
in accordance with Section 2 shall be carried out to demonstrate that risk associated with
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The failure analysis shall consider the effect of the following on the fracture control plan:
(a) The test pressure being higher than the MAOP of the pipeline.
(b) The decompression performance of air and other gases being different from that of
natural gas.
Where the test fluid is air or a flammable gas, the potential for an explosion or for a fire
shall be considered, including the risk of explosion from a mixture of air and hydrocarbon
that may be in the pipeline or from other sources such as compressor or lubricating oil.
To ensure public safety, the test procedure shall include the following precautions:
(i) A preliminary test at a pressure within the range of 10% to 30% of the design
pressure.
(ii) Locating and eliminating leaks occurring during the preliminary test and, if
necessary, repeating the preliminary test.
(iii) Controlling the test fluid temperature so as not to damage the coating.
(iv) Keeping people who are not involved in making the test at a safe distance from the
test section, from when pressure is first applied until it is either reduced to
atmospheric pressure or, following a successful test, to the MAOP.
(v) Choosing a test pressure appropriate to the volume and location of the test section.
The safety management study and the procedures to be implemented to ensure safety shall
be approved.
NOTE: AS/NZS 3788, Appendix D, provides guidance on application, control and exclusion
zones for pneumatic testing of pressure equipment.
Limitations
Testing with gas may be used within the limits of Table 11.4.6.3 in Location Class R1 and
R2.
Testing with gas in locations Classes T1 and T2 is restricted to the testing of instrument
piping, except that in T1 locations testing with gas is permitted when the volume of the test
section is less than 2 m3 and the maximum hoop stress is less than 30% of SMYS.
The limits in Table 11.4.6.3 may be extended in Location Class R1 where the safety
management study demonstrates that the risk class is negligible and the facture resistance of
the pipe is determined to be sufficient to prevent fracture propagation at the proposed test
pressure.
TABLE 11.4.6.3
MAXIMUM HOOP STRESS WHEN PRESSURE TESTING WITH GAS
Maximum hoop stress allowed as
a percentage of SMYS
Location
Class
Natural gas Inert gas or air
R1 80 80
R2 30 75
11.4.7 Pressure-testing loads
AS 2885.5 specifies that where yielding is likely to occur during the strength test, the test
shall be monitored by volumetric or other strain measurements. For a pipe acting as a beam,
superimposed bending stresses require consideration in deciding where volumetric or strain
control is necessary.
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11.4.8 Acceptance criteria
The criteria for the acceptance of strength tests and leak tests may be summarized as
follows:
(a) A strength test in which the pipe withstands a specific pressure period to demonstrate
the required pressure strength.
(b) A leak test consisting of one of the following:
(i) Visual assessment in which no leakage of fluid can be observed with the naked
eye at the end of the hold period.
(ii) Small volume test section in which change in pressure during the hold period
does not indicate leakage.
(iii) Large volume tests for which the unaccountable pressure change is less than
that nominated in the test procedure. (Determination of the acceptable
unaccountable change is included in the development of the test procedure as
specified in AS 2885.5.)
11.5 COMMENCEMENT OF PATROLLING
Operational patrolling of the pipeline in accordance with AS 2885.3 shall commence
immediately the leak and strength tests of the pipeline are completed.
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S E C T I O N 1 2 D O C U M E N T A T I O N
12.1 RECORDS
At completion of construction, survey data and as-built drawings complying with
AS 1100.401, that identify and locate the pipeline, stations, crossings, valves, pipe fittings
and cathodic protection equipment, shall be prepared.
All spatial data shall be referenced against MGA94 or another approved datum. Where
necessary, permanent reference marks and benchmarks shall be provided. The scale and
detail shall be appropriate to the location class and complexity of that location. In addition
to survey data and drawings the following design and construction records shall be
prepared:
(a) Design and approval records The design and approval records are the following:
(i) Design Basis.
(ii) Design drawings revised to as-built status.
(iii) Relevant project specifications and data sheets.
(iv) Design calculations.
(v) Fracture control plan and the isolation plan.
(vi) Location class.
(vii) Records of land ownership.
(viii) Safety management study, including supporting documents, and the location
and type of protection measures and operating procedures that form part of the
safety and operating plan.
(ix) Operating procedures that form part of the design.
(x) Safety and environment related records.
(xi) Approvals and relevant correspondence with regulatory authorities.
(xii) Materials and components used in the pipeline
NOTE: The name of the manufacturer and process of manufacture should be included.
(b) Manufacturing and construction records The manufacturing and constructions
records are the following:
(i) Manufacturing data records including the traceability of all materials and
components , and all associated test results and inspection reports.
(ii) Hydrostatic test records (including pressurization and strength test records).
(iii) All other tests and inspections that are required to verify the integrity of the
pipeline in accordance with AS 2885 series.
(iv) Any construction information that may be relevant to maintenance of the
pipeline.
(c) Commissioning records Commissioning records include all records from the
commissioning activity relevant to the ongoing operation and maintenance of the
pipeline.
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Electronic records that can be accessed by common text, database or spreadsheet
programs, including geographic information systems, are preferred since electronic
data is readily stored with a level of security not possible with paper-based
documentation. Where documents are only available on paper, they should be scanned
into an appropriate format.
While the use of proprietary programs is discouraged, where they are required to
interpret the data these should become part of the project record.
12.2 RETENTION OF RECORDS
A record of the results of the inspections and tests shall be retained by the pipeline
Licensee, until the pipeline is abandoned or removed.
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145 AS 2885.1—2007
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APPENDIX A
REFERENCED DOCUMENTS
(Normative)
A1 IDENTIFICATION OF DOCUMENTS
The name of the issuing body of documents is identified by the prefix letters in the number
of the document as follows:
ANSI American National Standards Institute
API American Petroleum Institute
APIA Australian Pipeline Industry Association
AS Standards Australia
AS/NZ Standards Australia/Standards New Zealand
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BS British Standards Institution
ISO International Organization for Standardization
MSS Manufacturers Standardization Society of the Valve and Fitting Industry, USA
NACE National Association of Corrosion Engineers, USA
A2 REFERENCED DOCUMENTS
The following documents are referred to in this Standard:
AS
1100 Technical drawing
1100.401 Part 401: Engineering survey and engineering survey design drawing
1170 Structural design actions
1170.4 Part 4: Earthquake loads
1210 Pressure vessels
1319 Safety signs for the occupational environment
1330 Metallic materials—Dropweight tear test of ferritic steels
1345 Identification of the contents of piping, conduits and ducts
1349 Bourdon tube pressure and vacuum gauges
1530 Methods for fire tests on building materials, components and structures
1530.1 Part 1: Combustibility test materials
1544 Methods for impact tests on metals
1544.2 Part 2: Charpy V-notch
1680 Interior lighting
1680.2.1 Part 1: Circulation spaces and other general areas
1697 Installation and maintenance of steel pipe systems for gas
1855 Methods for the determination of transverse tensile properties of round
steel pipes Lice
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AS
1929 Non-destructive testing—Glossary of terms
2187 Explosives
2187.2 Part 2: Storage and use—Use of explosives
3920 Assurance of product quality
3920.1 Part 1: Pressure equipment manufacture
2528 Bolts, studbolts and nuts for flanges and other high and low temperature
applications
2812 Welding, brazing and cutting of metals—Glossary of terms
2832 Cathodic protection of metals
2832.1 Part 1: Pipes and cables
2885 Pipelines—Gas and liquid petroleum
2885.2 Part 2: Welding
2885.3 Part 3: Operation and maintenance
2885.5 Part 5: Field pressure testing
3894 Site testing of protective coatings
3894.1 Part 1: Non-conductive coatings—Continuity testing—High voltage
(‘brush’) method
3920 Assurance of product quality
3920.1 Part 1: Pressure equipment manufacture
4041 Pressure piping
4799 Installation of utility services and pipelines within railway boundaries
5100 Bridge design
5100.2 Part 2: Design loads
AS/NZS
1158 Lighting for roads and public spaces
1158.1 Vehicular traffic (category V) lighting (all parts)
1200 Pressure equipment
1518 External extruded high-density polyethylene protective coating for pipes
1768 Lightning protection
2312 Guide to the protection of structural steel against atmospheric corrosion by
the use of protective coatings
2430 Classification of hazardous areas—Example of an area classification
2430.3.1 Part 3.1: General
2430.3.4 Part 3.4: Flammable gases
2566 Buried flexible pipelines
2566.1 Part 1: Structural design
2566.1 Supp 1: Structural design—Commentary (Supplement to AS/NZS 2566.1:1998)
2885 Pipelines—Gas and liquid petroleum
2885.4 Part 4: Offshore submarine pipeline systems
3000 Electrical installations (known as the Australian/New Zealand Wiring
Rules)
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AS/NZS
3788 Pressure equipment—In-service inspection
3862 External fusion-bonded epoxy coating for steel pipes
4360 Risk management
4853 Electrical hazards on metallic pipelines
60079 Electrical apparatus for explosive gas atmospheres
60079.10 Part 10: Classification of hazardous areas (IEC 60079-10:2002 MOD)
ANSI
B16.47 Large diameter steel flanges
B18.2.1 Square and hex bolts and screws—inch series
ANSI/ASME
B16.5 Pipe flanges and flanged fittings
B16.9 Factory-made wrought steel buttwelding fittings
B16.11 Forged fittings, socket-welding and threaded
B16.21 Non metallic flat gaskets for pipe flanges
B16.25 Buttwelding ends
B16.28 Wrought steel buttwelding short radius elbows and returns
B16.34 Valves—Flanged, threaded and welding end
B31.1 Power piping
B31.3 Process piping
ASME
B16.47 Large diameter steel flanges
B16.49 Factory-made wrought steel buttwelding induction bends for transportation
and distribution systems
API
5LR Reinforced thermosetting resin line pipe
API 5LR Specification For Low Pressure Fibreglass Line Pipe and Fittings
API 15HR Specification for High Pressure Fibreglass Line Pipe
API 15LR Specification for low CRA clad or lined steel pipe
API RP 14E Recommended Practice for Design and Installation of Offshore Products
Platform Piping Systems
PUBL 581 Base resource document on risk-based inspection
RP 5L2 Internal coating of line pipe for non-corrosive gas transmission services
RP 5L3 Conducting drop-weight tear tests on line pipe
RP 14E Design and installation of offshore production platform piping systems
RP 521 Guide for pressure-relieving and depressuring systems
RP 579 Fitness-for-service
RP 1102 Steel pipelines crossing railroads and highways
RP 1162 Public awareness programs for pipeline operators
Spec 5L Specification for line pipe
Spec 5LC Specification for CRA line pipe
Spec 5LD Specification for CRA clad or lined steel pipe Lice
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API
Spec 6D Specification for pipeline values (gate, plug, ball and check valves)
Spec 11P Packaged reciprocating compressors for oil and gas production services
Spec 15HR High pressure fibreglass line pipe
Spec 15LR Specification for low pressure fibreglass line pipe
STD 600 Bolted bonnet steel gate valves for petroleum and natural gas industries
STD 602 Steel gate, globe and check valves for sizes DN 100 and smaller for the
petroleum and natural gas industries
STD 603 Corrosion-resistant, bolted bonnet gate valves-flanged and butt-welding
ends
STD 618 Reciprocating compressors for petroleum, chemical, and gas industry
services
STD 619 Rotary-type positive-displacement compressors for petroleum,
petrochemical, and natural gas industries
STD 1163 In-line inspection systems qualification standard
ASTM
A 53 Specification for pipe, steel, black and hot-dipped, zinc-coated welded and
seamless
A 105 Specification for forgings, carbon steel, for piping components
A 106 Specification for seamless carbon steel pipe for high-temperature service
A 193 Specification for alloy-steel and stainless steel bolting materials for high-
temperature service
A 194 Specification for carbon and alloy steel nuts for bolts for high-pressure and
high temperature service
A 234 Specification for piping fittings of wrought carbon steel and alloy steel for
moderate and elevated temperatures
A 307 Specification for carbon steel bolts and nuts, 60 000 psi tensile
A 320 Specification for alloy-steel bolting materials for low-temperature service
A 325 Specification for structural bolts, steels, heat treated, 120/105 ksi minimum
tensile strength
A 350 Specification for forgings, carbon and low-alloy steel, requiring notch
toughness testing for piping components
A 354 Specification for quenched and tempered alloy steel bolts, studs and other
externally threaded fasteners
A 420 Specification for piping fittings of wrought carbon steel and alloy steel for
low-temperature service
A 449 Specification for quenched and tempered steel bolts and studs
A 524 Specification for seamless carbon steel pipe for atmospheric and lower
temperatures
E 1049 Standard practices for cycle counting in fatigue analysis
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BS
1560 Circular flanges for pipes, valves and fittings (class designated)
1560.3 Part 3: Steel, cast iron and copper alloy flanges
1560.3.1 Part 3.1: Specification for steel flanges
1560.3.2 Part 3.2: Specification for cast iron flanges
1640 Specification for steel butt-welding pipe fittings for the petroleum industry
1640.3 Part 3: Wrought carbon and ferritic alloy steel fittings. Metric units
1640.4 Part 4: Wrought and cast austenitic chromium-nickel steel fittings. Metric
units
3183 Method for the determination of wool fibre diameter by the air flow
method
3381 Specification for spiral wound gaskets for steel flanges to BS 1560
3799 Specification for steel pipe fittings, screwed and socket-welding for the
petroleum industry
5351 Steel ball valves for petroleum, petrochemical and allied industries
7910 Guide on methods for assessing the acceptability of flaws in metallic
structures
ISO
14692 Parts 1 to
4:
Petroleum and Natural Gas Industries
Glass reinforced plastics (GRP) piping
15590-1 Petroleum and natural gas industries—Induction bends, fittings and flanges
for pipeline transportation systems—Part 1: Induction bends
MSS
SP6 Standard finishes for contact faces of pipe flanges and connectinend
flanges of valves and fittings
SP25 Standard marking system for valves, fittings, flanges and unions
SP44 Steel pipe line flanges
SP67 Butterfly valves
SP75 Specification for high test wrought butt welding fittings
SP97 Integrally reinforced forged branch outlet fittings—Socket welding,
threaded and butt welding ends
NACE
MR175/ISO 151556 Parts 1 to 4—Petroleum and Natural Gas Industries—Material for use
in H2S containing environments in oil and gas production
B31.1 Power piping
CSA Z245.21 External polyethylene coating for pipe
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APPENDIX B
SAFETY MANAGEMENT PROCESS
(Normative)
B1 GENERAL
The safety management process is integrated and continuous. It requires consideration of
design aspects and operating procedures in a combined, holistic way so that the pipeline can
be operated safely. Analysis is updated and refined using information as it becomes
available throughout the life cycle of the pipeline.
The essential outcomes of the safety management process are—
(a) assurance that the threats to the pipeline and associated risks are identified and
understood by those that are responsible for addressing them; and
(b) appropriate plans are made to manage these risks.
The pipeline safety management process requires the application of multiple independent
controls to protect the pipeline from each identified threat.
Route selection shall be the primary control for avoiding threats to the pipeline and
consequences to the public and environment.
Physical and procedural and/or design methods are applied to all threats with the objective
of preventing failure of the pipeline.
Those threats that result in failure are subject to risk assessment in accordance with the
requirements of AS 4360.
In any safety management study it is necessary to be aware of a number of inherent pitfalls.
An excellent reference for information is provided in a UK HSE Research Report* on risk
assessment, which identifies a number of pitfalls that are equally applicable to pipeline
safety management studies as follows:
(i) Carrying out a risk assessment to attempt to justify a decision that has already been
made.
(ii) Using a generic assessment when a site-specific assessment is needed.
(iii) Carrying out a detailed quantified risk assessment without first considering whether
any relevant good practice was applicable, or when relevant good practice exists.
(iv) Carrying out a risk assessment using inappropriate good practice.
(v) Making decisions on the basis of individual risk estimates when societal risk is the
appropriate measure.
(vi) Only considering the risk from one activity.
(vii) Spreading the risk from a hazardous activity between several individuals.
(viii) Not involving a team of people in the assessment or not including employees with
practical knowledge of the process/activity being assessed.
(ix) Ineffective use of consultants.
(x) Failure to identify all hazards associated with a particular activity.
* Health & Safety Executive, 2003. ‘Good Practice and Pitfalls in Risk Assessment’. Research Report 151
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(xi) Failure to fully consider all possible outcomes.
(xii) Inappropriate use of data.
(xiii) Inappropriate definition of a representative sample of events.
(xiv) Inappropriate use of risk criteria.
(xv) No consideration of ALARP or further measures that could be taken.
(xvi) Inappropriate use of cost benefit analysis.
(xvii) Using ‘reverse ALARP’ arguments (i.e. using cost benefit analysis to attempt to argue
that it is acceptable to reduce existing safety standards).
(xviii)Not doing anything with the results of the assessment.
(xix) Not linking hazards with risk controls.
B2 WHOLE OF LIFE PIPELINE SAFETY MANAGEMENT
Pipeline safety management to this Standard is an integral component of the planning,
design, construction, operation and abandonment of the pipeline. Figure B2 illustrates the
components of the process and their interrelationship.
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Whole of l ife pipeline safety managementP
reli
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d
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an
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De
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ain
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Co
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tru
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an
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Prel iminary design
Route selectionEnvironmental impactassessment
System design Feasibi l i ty study
Init ial pipel ine safety management study
Pipel ine l icence approval
Design and residual r isk acceptance / approval
System design
Commercial design - del ivery pointsHydraul ic design - compressor stat ions
Scraper stat ionsIsolat ion plan - MLVs and SLVs
Detai led safety management study
Avoid by route selectionApply physical and procedural controls
Apply designFailure analysis
AS 4360 residual r isk assessmentALARP Loop
Pipel ine design
Process design
P&I-D, equipment layout
Process safety - HAZOPControl system safety - CHAZOPElectronic systems safety - SIL
Societal safety - HAZAN
Construction safety
Construction safety plan, environmental management planJSA, pre-construction safety management study review
Approval to construct
Commissioning safety
Commissioning plan, safety and operating plan,pre-construction safety management study review
Approval to commission
Approval to operate
Operations safety
Safety and operating plan, environment plan, training, audits, integri ty inspections, safety management study review
Approval to abandon
Abandon pipel ine
Abandonment plan, environment plan, maintenance plan,safety assessment
FIGURE B1 WHOLE OF PIPELINE SAFETY MANAGEMENT
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B2.1 Project phases
B2.1.1 General
Safety management studies shall be undertaken at intervals during the pipeline design,
construction and operational phases to facilitate periodic re-assessment of threats and the
implementation of controls as knowledge of the threats is gained over time.
As a minimum, a safety management study shall be undertaken during the following phases:
(a) Preliminary design and approval The initial design is typically developed as part of
a feasibility study undertaken early in the life of the project. It is also generally used
as the basis to obtain regulatory approvals for the project. The initial design shall
generate sufficient information to allow the initial safety management study to be
carried out effectively.
The initial safety management study shall—
(i) identify high consequence events that impose major risks to the project,
community and environment, and their proposed controls;
(ii) deliver sufficient information to allow stakeholders involved in the regulatory
approvals process to make informed decisions about the risks associated with
the project; and
(iii) recognize that detailed design will identify detailed threats and develop specific
controls.
NOTE: The initial safety management study should be consistent with the requirements of the
relevant licensing authority. These may vary from jurisdiction to jurisdiction and should be
clarified at the earliest opportunity.
(b) Detailed design A detailed safety management study that complies with this
Standard shall be undertaken in parallel with the detailed design.
NOTE: The application of the safety management process is an integral part of pipeline
system design, and cannot be performed independently from the design process. This allows
the pipeline design to be continually refined on the basis of pipeline safety management
information.
(c) Pre-construction review A pre-construction review of the detailed safety
management study and the design shall be undertaken. The review shall specify any
corrective actions required for the design to comply with this Standard prior to
construction.
Each corrective action that relates to the pipeline design shall be implemented prior to
or during the construction of the affected part of the pipeline.
(d) Pre-commissioning review A pre-commissioning review of the detailed safety
management study and the constructed pipeline shall be undertaken. The review shall
specify any corrective actions required for the constructed pipeline to comply with
the requirements of this Standard prior to commissioning.
Where the pipeline route or its design has been changed during construction, the
compliance of each change with the requirements of this Standard shall be established.
The review shall confirm that the requirements of the safety management study have been
incorporated into the safety and operating plan.
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B3 Pre-requisites for safety management studies
B3.1.1 Initial safety management study
An initial safety management study shall be undertaken to provide for regulatory approvals.
The initial safety management study shall consider at least the following:
(a) Location and zoning information/location class/environmental sensitivity
assessments/leading to definition of high consequence areas.
(b) Typical threats in typical locations.
(c) Location-specific threats, particularly in high consequence areas.
(d) Basic pipeline design parameters.
(e) The energy release rate and the contour radius for a radiation intensity of 4.7 and 12.6
kW/m2 in the event of a full bore rupture.
NOTE: A thermal radiation level of 4.7 kW/m2 will cause injury, at least second degree burns,
after 30 seconds exposure. A thermal radiation level of 12.6 kW/m2 represents the threshold of
fatality, for normally clothed people, resulting in third degree burns after 30 seconds exposure.
B3.1.2 Detailed safety management study
A robust safety management study requires detailed preparatory information and analysis to
provide consistency of approach across the pipeline and to provide all of the tools necessary
to correctly identify all threats and facilitate their assessment and control.
The safety management study shall be undertaken by personnel with expertise in each
component of the design, construction and operation of the pipeline, including, or with the
support of, personnel closely familiar with the land uses and environments along the entire
route.
The following information shall be generated and used for the detailed safety management
study:
(a) Design Basis and description including—
(i) basic pipeline properties; and
(ii) engineering design guidelines for non-standard construction (crossings,
facilities etc).
(b) Design calculations (e.g. thickness).
(c) Typical design drawings (crossings, facilities etc).
(d) The initial safety management study
(e) The corrosion mitigation strategy
(f) Safety management study of common threats to typical designs
(g) Initial pipeline alignment.
(h) Location classifications
(i) An assessment of current land uses, and plans for future land use (based on
information from landowners and land planning authorities).
(j) Documented investigations of external threats including information from land
owner/holder, public/planning authority, construction contractor
(k) Documented investigations of external threats from existing and planned buried and
above ground infrastructure crossing and parallel to the pipeline.
(l) Construction line list (list of construction and landowner constraints).
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(m) Environmental line list (list of environmental constraints).
(n) Preliminary safety and operating plan (which provides first drafts of standard
procedural controls, such as patrolling, land access procedures etc).
(o) Isolation plan.
(p) HAZOP and other design review studies applied to stations, pipeline facilities and
pipeline control systems.
(q) Fracture control plan.
(r) Critical defect length/rupture case/resistance to penetration.
(s) Consequence modelling, which shall—
(i) include an assessment of the impacts of a fluid release on people, property and
the environment;
(ii) take into account factors such as the nature of the fluid released, topography
and prevailing weather conditions; and
(iii) include the energy release rate and the contour radius for a radiation intensity
of 12.6 and 4.7 kW/m2 in the event of a full bore rupture.
(t) Environmental studies and information developed specifically for the pipeline project
or as otherwise may be available for the route traversed by the pipeline.
NOTE: Electronic tools (e.g. threat database, GIS) can greatly assist both in the process of the
safety management study and its validation, documenting outcomes and allowing decisions to be
made transparently.
For in-service pipelines, in addition to the foregoing, the information shall also include:
(A) Land use changes
(B) Changes in surface topography and structures
(C) Changes in population density
(D) As-built drawings
(E) Inspection and integrity management history
(F) Maintenance history
(G) Previous safety management studies
If any of the above items are considered to be not applicable, the reason for exclusion from
the safety management study shall be documented and approved.
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APPENDIX C
THREAT IDENTIFICATION
(Informative)
C1 GENERAL
Threat identification consists of the identification of all threats to the pipeline including the
following types of threats:
(a) Threats that are unique to a particular location, such as a threat of external
interference from third parties, or due to topographical features at the location.
(b) Threats that could exist along the whole length of the pipeline and which are not
specific to a location. These threats may include internal corrosion from the fluid
being transported, external corrosion or possible threats from maintenance activities.
(c) Location-specific threats, which become apparent from a detailed metre-by-metre
review of the route. However, non-location-specific threats require a separate
identification process to be undertaken. In both cases, the details recorded for threat
analysis need to be sufficient such that the appropriate design and controls can be
implemented,
The following list presents some of the most commonly identified threats:
(i) External Interference
(ii) Corrosion.
(iii) Natural events.
(iv) Operations and maintenance.
(v) Design defects.
(vi) Material defects.
(vii) Construction defects.
(viii) Intentional damage.
This list should not be considered exhaustive.
The following sections describe in detail the nature and types of threats and provides
examples of each category.
C2 DESCRIPTION OF THREATS
C2.1 External interference
External or mechanical interference is the major cause of pipeline failure. Interference is a
significant threat to pipelines with smaller diameters because they generally have thinner
walls.
The nature of external interference involves the removal of the protective ground cover and
contact with the pipe which may or may not penetrate the pipe wall.
The potential sources of external interference include the following:
(a) Excavation, such as occurs during construction or maintenance of buried services,
construction or maintenance of roads, mining, transport, and building construction.
(b) Power augers and drilling operations (vertical, horizontal and directional). Lice
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(c) Ripping and ploughing for cable installation.
(d) Maintenance activities on the pipeline.
(e) Installation of posts or poles for fences or power cable installation.
(f) Land use development, such as grading of land for irrigation.
(g) Deep ploughing activities.
(h) Damage from impacts by vehicles or vessels, including road, rail and aircraft crashes.
(i) Damage from bogged vehicles or plant over the pipeline.
(j) Excessive external loads from backfill or traffic.
(k) Blasting.
(l) Anchor dropping and dragging.
C2.2 Corrosion
Corrosion is a significant cause of pipeline failure. It is a time-dependent threat. Scenarios
that may cause corrosion of pipelines include the following:
(a) External corrosion/erosion due to environmental factors, such as salinity, type of soil
and moisture content, and the abrasive action of sand and soil particles.
(b) Internal corrosion due to contaminants, such as chlorides, nitrates, hydrogen sulfide,
hydroxides and carbon dioxide, present with water in the gas or liquid contained
within the pipeline.
(c) Internal erosion caused by the abrasive action of solids inside the pipeline.
(d) Environmentally assisted cracking.
(e) Bacterial corrosion.
C2.3 Natural events
Natural events include the following:
(a) Earthquake.
(b) Ground movement, due to land instability for a range of causes.
(c) Wind and cyclone.
(d) Bushfires
(e) Lightning.
(f) Floods, leading to erosion or impact damage.
(g) Inundation, leading to flotation.
(h) Erosion of cover or support, either on land or in rivers and waterways.
C2.4 Operations and maintenance
There is a wide range of risks arising from operations and maintenance activities. These are
generally controlled by the implementation of a detailed operating and maintenance plan.
Examples of potential risks include the following:
(a) Operations:
(i) Exceeding MAOP of pipeline.
(ii) Incorrect operation of pigging.
(iii) Incorrect valve operating sequence.
(iv) Incorrect operation of control and protective equipment.
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(v) Bypass of logic, control or protection equipment, followed by incorrect full or
partial manual operation.
(vi) Fatigue from pressure cycling for which the pipeline is not designed.
(b) Maintenance:
(i) Inadequate or incomplete maintenance procedures leading to equipment failure.
(ii) Maintenance actions contrary to maintenance procedures.
(iii) Inaccurate test equipment, leading to incorrect control and safety equipment
settings.
(iv) Inadequate servicing of equipment.
C2.5 Design defects
Design defects are those deficiencies in the configuration of the pipeline and its facilities,
or in the selection of materials. This covers a very wide range of problems. Some examples
of this type include the following:
(a) Failure to specify the correct material, component and equipment characteristics.
(b) Incorrect design or engineering analysis of the pipeline and associated piping. This
includes stress analysis, analysis of branch connections and thermal loading of the
pipeline.
(c) Failure to define the correct range of operating conditions, leading to incorrect
settings on control or protective devices, or unacceptable pressures, temperatures and
loads.
(d) Failure of design configuration and equipment features to allow for safe operations
and maintenance.
C2.6 Material defects
Material defects include the following:
(a) Incorrectly identified components.
(b) Incorrect specification, supply, handling, storage, installation or testing which allow
faults to remain undetected, or which damage the item and render its operation
inadequate.
(c) Under-strength pipe.
(d) Manufacturing defect.
(e) Lack of adequate inspection and test procedures to confirm the acceptability of
material and equipment.
C2.7 Construction defects
Construction defects, resulting in pipeline failure, are predominantly caused by a failure to
follow defined procedures and plans. These threats to pipeline integrity include:
(a) Undetected or unreported damage to the pipe, coating or equipment.
(b) Undetected or unreported critical weld defects.
(c) Failure to install the specified materials or equipment.
(d) Failure to install equipment using the correct procedures or materials.
(e) Failure to install equipment in accordance with the specified design.
(f) Failure to install the pipeline in the specified location, or in the specified manner.
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C2.8 Intentional damage
Intentional damage is extremely rare in Australia but may be considered credible in certain
situations. Examples of intentional damage include:
(a) Sabotage.
(b) Terrorism.
(c) Malicious damage.
C2.9 Other threats
Other threats are those that do not fit into the above categories or are a combination of the
other categories, such as:
(a) Seismic survey, resulting in blast or equivalent external pressure loads.
(b) Induced voltages, arising from parallel electricity transmission lines.
(c) Fault voltages from nearby electricity transmission towers.
(d) Mine subsidence.
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APPENDIX D
DESIGN CONSIDERATIONS FOR EXTERNAL INTERFERENCE PROTECTION
(Informative)
D1 INTRODUCTION
This Appendix provides information for use in the design of pipelines to achieve
compliance with the requirements of Clause 5.5. The explicit requirements for external
interference protection design in this Standard recognize that the most common cause of
pipeline failure is damage by external interference.
External interference protection design provides protection for the pipeline and the public
from such events. This Standard provides no mechanism for rule-of-thumb design for
protection and no provision for deeming adequate protection based on design factor or
external interference factor.
Design for protection is required over the whole length of the pipeline.
D2 DEFINITION OF DESIGN EVENTS
The process of design requires definition of the events for which external interference
protection is to be provided in each location, followed by protection design.
Definition of the external interference threats involves systematic assessment along the
pipeline of the activities of parties which could damage the pipeline, together with an
assessment of the type(s) of plant or equipment which those activities would involve in the
location. This assessment requires considerable knowledge of the land uses at all points
along the pipeline, and knowledge of the plant, equipment, and practices of entities that
may conduct activities in the vicinity of the pipeline route.
The definition should include assessment of the probable changes to land use and external
interference threats that may occur along the pipeline route throughout the design life of the
pipeline, to enable a cost effective protection design strategy to be developed.
Example:
Consider a pipeline in Location Class R1. The following situations may occur:
(a) Portions of the route may be ploughed for agriculture, and for these the design event
would be determined from the largest equipment in use for such ploughing
operations. Along fence lines, the design event could be determined by the largest
posthole borer in use.
(b) Portions of the route may be used for grazing in fenced paddocks. The design events
would include posthole boring at fence lines and, in some isolated locations, dam
construction for stock water.
(c) Portions of the route may be in land that is not farmed at all; desert, national
parkland, forest, scrubland and the like, for which no mechanized plant activities are
current or anticipated. Nil design events would be the logical and valid description.
(d) The route would cross easements of other services, such as powerlines and
communications cables and public and private transport corridors such as roads,
tracks and railways. The design events would be determined by current practices for
maintenance of such corridors, future plans for new construction and would include
such events as derailment of the heaviest locomotive that currently uses the railroad
or a heavy-vehicle accident from the road.
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A similar systematic assessment of the design events is required in Location Classes R2, T1
and T2.
D3 EXTERNAL INTERFERENCE PROTECTION DESIGN
External interference protection design is required over the full length of the pipeline even
where the consequences of failure would not impact on humans. Design is required in each
location for all of the design events identified for that location.
NOTE: Human population density in some locations may vary greatly from time to time, for
example near sporting venues or on roads.
External interference protection design in accordance with Clause 5.5 involves the selection
of physical and procedural controls to minimize the potential for the threat to cause failure.
Clause 5.5.4 specifies the minimum number of controls of each type which are to be
provided. Methods that may be counted as controls are also specified.
The typical design response to the threats in the above example would be as follows:
(a) Burial with a cover sustainability larger than the maximum depth of ploughing would
provide an effective physical control by separation.
If the maximum ploughing depth is 400 mm, a minimum cover of 1000 mm might be
defined. In addition, since ploughing is an annual activity conducted at much the
same time of the year, appropriately timed annual landowner liaison would provide a
meaningful procedural control.
For the fence lines, where ploughing does not take place but fence posts are buried to
600 mm, 1000 mm cover may be sufficient; however, because the replacement of
fence posts is not an annual event, conspicuous marking at all points where the
pipeline crosses a fence line would be added to the annual landowner liaison.
Patrolling in the R1 Location Class would probably be from the air, but the patrolling
schedule could be made specific to determine any change in the location, extent or
practice of the annual ploughing and to assess when the condition of the fences make
installation of new fence posts likely.
For pipelines requiring a wall thickness for pressure design that cannot be penetrated
by either the ploughing equipment in use or the post-hole boring equipment in use,
the external interference protection design may reduce the depth of cover to the
minimum allowed where cover is not used as a control (e.g. 750 mm in Table 5.5.2),
since resistance to penetration, wall thickness would be the physical control, not
cover. The procedural controls would probably be unchanged.
(b) No threats would apply for most of the route but, at fence lines, the threats and
external interference design would be the same as in Item (a) above.
In locations where dam construction is a possibility, the level of threat would be
determined by the largest earthmoving plant used for such dam construction in that
area. Since dam construction is likely to involve heavy machinery excavating to
depths similar to or larger than pipeline cover, physical controls may not be capable
of providing total protection. This event may never actually take place but, if the dam
is built, it is a once-only event in each location. The primary focus of external
interference protection design is to avoid construction activities over the pipeline.
Selection of physical controls would probably be limited to standard depth of cover,
but re-routing may be required in some instances.
The external interference protection design would concentrate on procedural controls.
Landowner liaison and patrolling would be particularly important, and pipeline
marking at the potential dam site would be appropriate.
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Once such a dam is built and no further construction is contemplated at the location,
future reviews of threats would not include dam construction at the same location but
may include dam maintenance and potential failure. This would alter the focus of
landowner liaison and patrolling.
(c) Except at roads and tracks, there would be nil design events, so that minimum
external interference protection design, burial to minimum depth of cover, marking at
required spacing and patrolling would be the controls adopted.
(d) At track, roads and railways, the design event would be specified to the location and
the responsible authority, and procedural and physical controls would be specific to
the design event. Increased depth of cover to provide separation by burial, thus
placing the pipeline below any equipment activities, is the commonest physical
control, supplemented in some locations with concrete slabs as a resistance to
penetration physical control.
Liaison with an authority should be linked to patrolling so that the pipeline operator
is aware of the timing of construction or maintenance activities of the authority at the
location of the pipeline crossing.
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APPENDIX E
EFFECTIVENESS OF PROCEDURAL CONTROLS FOR THE PREVENTION OF EXTERNAL INTERFERENCE DAMAGE TO PIPELINES
(Informative)
E1 GENERAL
This Appendix provides information and advice on development of the procedural controls
required by Clause 5.5.6 of this Standard, which form part of the overall package of
controls to prevent, or minimize the consequences of, damage to buried pipelines caused by
activities such as excavation, boring, horizontal directional drilling, cable ploughing, etc.
The information in this Appendix is based largely on the following reference:
Cooperative Research Centre for Welded Structures Report on Project 1999/69, The
Prevention of Damage to Buried Pipelines Caused by Unsupervised Excavation.
This Standard requires that effective procedural controls be put in place against every
identified external interference threat to the pipeline. Methods that may be counted as
procedural controls are specified. The effectiveness of each procedural method that is to be
implemented is to be evaluated in respect of each individual threat, and not solely in an
overall or statistical manner.
Procedural methods are dependent, for their effectiveness, on human action, and thus
cannot be guaranteed to be completely effective in every set of circumstances. Therefore, in
this Standard—
(a) criteria are given for assessment of the effectiveness of a method to control a
particular threat; and
(b) at least two procedural controls, which meet these criteria, are required to be in place
for every identified external interference threat.
The greater the number of effective procedural methods that are in place, the lower is the
probability that all will fail. Where multiple independent procedural methods are in place
this probability is very low, but it can never be zero. This Standard requires that all
reasonably practicable methods be adopted.
Certain methods, for example pipeline markers, are mandatory, and minimum standards are
prescribed for them. The minimum standard may, or may not, provide effective protection
against a particular threat. Where a method is being relied on for protection against a
particular threat it has to comply with both the minimum standard and the criteria for
effectiveness.
The purpose of procedural controls is to—
(i) make the pipeline operator aware of activity with potential to damage a pipeline,
(ii) make organizations and individuals that carry out such activity aware of the presence
of a pipeline, and of the possible consequences of damaging it; and
(iii) enable supervision by the pipeline operator of activity over the pipeline.
A full package of damage protection controls includes the following:
(A) Procedural controls as defined above.
(B) Rules and procedures for working safely close to a pipeline.
(C) Physical controls to prevent or minimize damage to the pipeline if items A or B fail.
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(D) An emergency response plan to minimize injury, damage to property and the
environment, and interruption to supply, in the event of serious damage to the
pipeline.
E2 EFFECTIVENESS OF PROCEDURAL CONTROLS
The procedural controls can be considered to be completely effective if every person or
organization intending to undertake excavation, or similar activities—
(a) contacts the pipeline operator, either directly or via a one-call service, prior to
commencing work;
(b) does not commence work until either—
(i) advised by the pipeline operator that it has no assets in the area; or
(ii) in conjunction with the pipeline operator, it has developed a safe procedure for
the work, and a representative of the pipeline operator is present; and
(c) all personnel involved in the work are thoroughly familiar with the work procedure.
Landowner liaison, third party liaison, planning notification zones, and one-call service
membership may be effective in bringing about this ideal behaviour.
In case the excavator fails to contact the pipeline operator before commencing work, other
control methods need to be in place.
Pipeline markers may be effective in alerting an excavator to the presence of a pipeline
before excavation commences nearby.
Buried marker tape may be effective, and buried marker tape plus concrete slabbing is
normally effective in alerting an excavator, who has commenced work close to a pipeline,
that contact with the pipeline is imminent.
Pipeline patrols may be effective in detecting un-notified excavation activity before any
damage can be done.
Remote intrusion monitoring may be effective in alerting the pipeline operator that
potentially dangerous activity is taking place near its pipeline, while there is still time to
intervene and prevent any damage occurring.
E3 CAUSES OF FAILURE OF PROCEDURAL CONTROLS
All procedural controls can be rendered ineffective by human failures. There are four types
of human failure:
(a) Failures of attention.
(b) Failures of memory.
(c) Failures of knowledge.
(d) Deliberate violations of safety rules.
Some procedural methods are more susceptible to a particular type of human failure than
others. For example, signposting may be useful against the threat from an excavator
operator who has forgotten to check for the presence of buried pipes and cables, but may
not be very effective against the threat from an excavator operator who believes he has the
knowledge and skill to carry out his work without help from the operators of buried
facilities.
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E4 LIAISON
It has been shown that the effectiveness of methods such as pipeline markers, buried marker
tape and one-call systems is greatly enhanced if effective liaison is maintained with the
owners and occupiers of land through which a pipeline runs, and with those organizations
and individuals who are involved, in any capacity, with activities that could threaten the
pipeline.
Landowner and third-party liaison is the heart of the external interference protection
system.
E4.1 Landowner liaison
In this Paragraph, for simplicity, the word ‘landowner’ includes the occupiers of land,
whether they own it, or are tenants or employees of the owner.
Landowners are both potential victims of a pipeline accident and patrol personnel who are
on duty at all hours. Good liaison with the landowners has been found to be very effective
in preventing external interference damage to pipelines on private property.
Face to face contact is more effective than supplying information by post. Persons who
carry out pipeline patrols are often the best persons to make contact with the landowners in
the area they cover. Where possible a semi-formal contact should occur at least annually,
preferably on the property. During this contact, important safety information may be
reviewed, and materials such as a handbook for landowners and informative materials, may
be distributed. Informal contact from time to time, possibly during patrols, helps to
reinforce the safety message.
In rural areas it may be more effective to provide landowners with a direct contact number
for the person responsible for their area, than to require them to make contact via the
operating company’s office. In an emergency, the emergency number for the pipeline
should be the first point of contact and it is important to ensure that the emergency number
is also provided to the landowner.
Effective landowner liaison requires up to date information on land ownership and
occupancy. Arrangements can be made with the relevant land title office, or other
appropriate authorities so that the pipeline operator receives timely notification of changes
to the ownership of properties on which it has an easement.
An effective landowner liaison program should include comprehensive records of contacts
made. The records should be reviewed at regular intervals to assess the effectiveness of the
program in reaching the target audience.
These records become more effective when entered into a GIS developed for the pipeline.
E4.2 Third-party liaison
The number of organizations and individuals that could potentially be involved in activity
that damages a pipeline is very large, and the first problem of third-party liaison is to
discover who they are. The threat analysis, as required by this Standard, lists all the
identified threats to the pipeline, and is therefore a good place to begin the search. As well
as those directly involved in the activities that threaten the pipeline, liaison should be
maintained with the planning authorities, which must approve development work in the
area. AS 2885.3 contains lists the various classes of people and organizations that should be
included in an effective third-party liaison program. It also details the types of information
that should be communicated.
The information needs of different organizations are not the same, nor are the needs of
different groups of people within large organizations. The information provided should be
targeted to the particular audience.
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It is not wise to assume that information provided to one person, or one level, in an
organization will be effectively transferred to others in the organization who need to have
it.
There are thousands of small contractors who undertake work, such as excavation and
boring, that could damage a buried pipeline. To liaise with all of these, and their employees,
is probably impossible. Effort spent on liaising with the planning authorities, the larger
contractors, and the organizations (such as local government, roads authorities, and utility
companies) that employ them will be more effective.
During the risk analysis, required by this Standard, it may be found that the risks associated
with some threats to the pipeline are acceptable, but cannot be reduced to zero or be
negligible. Giving high priority to liaison with the people and organizations involved in
these threats enhances the effectiveness of the external interference prevention program.
Liaison may, and should, take many forms. These include formal processes such as toolbox
meetings, distribution of safety literature, and processes for advising of new development
plans, and informal processes such as an occasional telephone call to ask if anything
interesting is happening. Regardless of the method of communication it is necessary that the
target groups are made aware that damaging a pipeline can be both dangerous and
expensive, and that they must contact the pipeline operator, either directly or via a one-call
service, prior to commencing work at a new site.
In some legal jurisdictions working near a pipeline without notifying the pipeline operator
is an offence, and substantial penalties, such as fines, can be imposed. These penalties can
be effective in deterring unsafe behaviour; however, persons detected performing un-
notified work near a pipeline, and members of their organization, are prime candidates for
education, and education may be more effective than penalties in many cases.
An effective third-party liaison program includes comprehensive records of contacts made.
The records are analysed regularly to evaluate the effectiveness of the program.
API RP 1162, contains useful guidance for the development of both third-party and
landowner liaison. API RP 1162 was written with the regulatory framework of the USA in
mind, and allowance needs to be made for differences between this and the environment in
which a pipeline designed in accordance with AS 2885 series will operate.
E5 COMMUNITY AWARENESS PROGRAMS
A program that makes the community in the vicinity of a pipeline aware of its presence, the
possible consequences of damaging it and the need for supervision by the pipeline operator
of activity over the pipeline can increase the effectiveness of targeted liaison programs. A
community awareness program can help to get information to smaller contractors who are
difficult to identify individually and can augment information transfer within larger
organizations. Community awareness programs should always include the provision of
information to local police and emergency services.
E6 ONE-CALL SERVICES
Participation in a one-call service has been shown to be effective for notifying pipeline
operators, in good time, of any activity that could damage their facilities. A high proportion
of all notifications and inquiries is received via the one-call system. One-call services are
effective for pipelines located on both public and private land, but are most effective for
public land in populated areas. One-call services are available to cover the whole of
Australia. Where a one-call service is available, AS 2885.3 makes it mandatory for a
pipeline operator to participate in it.
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The effectiveness of a one-call system is highly dependent on the pipeline operator’s
internal systems being able to respond accurately and rapidly to all inquiries, and to follow
up, when necessary, with competent and timely assistance and advice.
Operators of pipelines located in densely populated areas can expect to receive many
inquiries every day. In such cases, the efficiency and speed of response can be enhanced by
employing simple computerized systems to generate standardized responses.
Inquiries are of two main types, those generated during the planning or design stages of a
project, and those generated shortly before construction work is to be carried out. Working
with developers, architects, and engineering consultants, to design out problems at the
planning stage, can save trouble and expense later.
It is poor practice to issue drawings showing the location of a pipeline to a person who is
about to commence excavation close by.
The issuing of drawings to competent engineering and architectural organizations, for use
during the planning and design phases of a new development, is appropriate, and can help
avoid major problems when the work eventually goes ahead, which could be months or
even years later; however, when this is done it is important to stress the need to place a new
inquiry, preferably using the one-call service, shortly before work at the site is to begin.
Where the response to a one-call inquiry indicates that there is a pipeline near the proposed
work, it is more effective to give the name and direct contact number of the person who will
be responsible for providing assistance to the inquirer, than to only provide the telephone
number of the operating company’s office.
It is better to contact an inquirer in person, soon after the response to the inquiry has been
forwarded via the one-call system, than to wait for a contact from him.
E7 MARKING
E7.1 Pipeline markers
This Standard mandates the placement of markers at a wide range of specific locations. The
purpose of pipeline markers is to alert people, who are planning to work near a pipeline but
have not contacted the pipeline operator, to the presence of the pipeline, and the possible
consequences of damaging it.
Pipeline markers are considered to be effective against a particular threat if at least one
marker can be seen by the person undertaking the threatening activity.
Where structures that might require maintenance or replacement (e.g. power poles) are
located close to a pipeline, attaching a suitable sign to the structure will enhance the
effectiveness of the marking system.
Effective pipeline marking applies these rules regardless of land use in the area, and
including in remote areas.
Commonly used marker styles, listed in descending order of effectiveness, are the
following:
(a) Large cylindrical signs mounted at eye level.
(b) Large double-sided flat signs mounted at eye level.
(c) Large single-sided signs mounted at eye level.
(d) Small flat signs at low level, or short tubular signs.
(e) Stencilled kerb signs.
(f) Adhesively attached kerb signs.
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The difference in effectiveness between the first three styles listed above is not very great.
In some locations (e.g. residential areas) pipeline markers may be considered unsightly, and
there have been cases where markers have been removed or relocated by people who found
them offensive. Choice and placement of signs should be considered carefully.
Where practicable, it is more effective to locate markers directly above the pipeline, within
a reasonable tolerance of say 1 m. It has been observed that most people assume that this is
the case. If persons carry out unauthorized excavation believing that they know exactly
where the pipeline is, it is best to ensure that the pipeline is where they thinks it is.
Experience has shown that it is impossible to guarantee that every marker will be installed,
and will remain for the life of the pipeline, in precisely the correct location. Therefore,
while markers should be placed accurately, and preferably directly above the pipeline, it is
unwise to indicate on a marker the precise location of the pipeline relative to the marker.
Doing this may encourage unauthorized excavation by people who do not wish to wait for
help from the pipeline operator. It is much better to state simply that there is a pipeline in
the vicinity, or words to that effect. Accurate location of a pipeline has to be carried out,
before commencement of excavation or similar activity, by the pipeline operator using
appropriate equipment and procedures.
Special markers are often provided for the assistance of land or aerial patrols. These include
kilometre posts that can be read from the air, and brightly coloured fences where pipelines
cross property boundaries. These markers can be very useful, but are not considered to be
effective against external interference threats.
E7.2 BURIED MARKER TAPE
Buried marker tape is considered to be effective against a particular threat if it is not
possible to damage the pipeline without first exposing the tape, and if a person carrying out
the threatening activity is likely to see the tape immediately it is exposed.
There are some threats, for example horizontal directional drilling or deep ripping, where
buried marker tape is clearly not effective; however, it is necessary to carefully study the
operation of any type of equipment against which tape is intended to provide protection, to
confirm that the criterion for effectiveness will be met, before relying on buried marker tape
as a protective method.
Consideration should also be given to how the equipment is likely to be operated. Buried
marker tape is more effective when the equipment operator has an assistant standing on the
ground who can watch the progress of the work and who may see the exposed tape earlier
than the equipment operator himself. This is often the case when work is being conducted
on congested sites where there is a possibility of finding buried obstructions, but is less
common in open areas.
The greatest benefit is derived from buried marker tape when it is used in developed areas,
or in particularly vulnerable areas such as crossings.
E8 AGREEMENTS WITH OTHER ENTITIES
Where a pipeline is located in a shared easement or other common infrastructure corridor,
there is an increased likelihood of damage to the pipeline from maintenance activities or
failures associated with adjacent assets. Similarly, pipeline maintenance activity or failure
poses a corresponding threat to the other assets in the easement or corridor. In this standard,
road reserves are considered to be common infrastructure corridors.
Agreements between the various asset operators can be effective in reducing the likelihood
of un-notified or uncontrolled excavation in the vicinity of pipelines in these locations. This
standard requires that, wherever possible, agreements be implemented with other users of
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E9 PLANNING NOTIFICATION ZONES
There are a variety of legislative provisions in Australian jurisdictions for the recording of
pipelines on planning schemes and notifying pipeline operators of planned development that
may affect the pipeline. These can be very effective in facilitating early discussions
between pipeline operators and developers so as to avoid activities that may threaten the
pipeline or development outcomes that may create an unacceptable risk to the community.
Where uniform provisions do not exist across a jurisdiction, it is good practice to apply to
local planning authorities that must approve development work in the area for inclusion of
pipelines in local planning schemes and notification arrangements.
E10 PATROLLING
Patrolling has many functions. The only function considered here is the detection of un-
notified activity before the pipeline is damaged. The external interference protection
functions are as follows:
(a) Contributes to protection from third-party damage in three ways:
(i) Regular patrolling keeps the patrol personnel up to date with activity in their
patrol area such as land development and seasonal agricultural activity.
(ii) Patrol personnel get to know the people and organizations that live and work in
the area and with whom it is necessary to maintain liaison.
(iii) Patrol personnel may become aware of future excavation activity long before it
poses any threat to the pipeline.
(b) Identifies missing, damaged, or defaced pipeline markers and allows repair or
replacement to be carried out in a timely fashion, so that the marking system remains
as effective as possible.
(c) May discover activity, with potential to damage the pipeline, that has not been
notified to the pipeline operator in advance.
While the value of (a) and (b) is very real, there are circumstances where a threat to a
pipeline may only be detectable for a short period before the danger becomes immediate.
To be effective against threats, the patrol frequency and timing needs to be such that the
activity will be detected before any damage is done. Daily patrols can be effective against
many threats. Patrols at less than daily intervals may not be effective, as defined in this
Standard. Where an area is patrolled daily, on working days only, particular attention
should be given to liaison with organizations likely to carry out work on weekends and
public holidays. These include the emergency repair departments of utility companies. Each
case should be considered on its merits.
In rural and remote areas, the resources required to mount daily patrols would, in most
cases, be more effectively used for landowner and third-party liaison.
E11 REMOTE INSTRUSION MONITORING
There is little experience in applying remote intrusion monitoring to the protection of a
buried pipe; however, it is clear that the ability to detect a potentially dangerous activity on
a buried pipe, and raise an alarm at an appropriate remote location, is not sufficient to
constitute an effective method. The pipeline operator must also have the ability to mobilize
a patrol, and reach the location of the threat, before any damage occurs.
Systems that generate a significant number of false alarms are not likely to be effective.
Remote intrusion monitoring on pipeline stations with related alarms and callouts have
decreased intrusion activity on these stations and can be an effective procedural method.
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APPENDIX F
QUALITATIVE RISK ASSESSMENT
(Normative)
F1 GENERAL
This Appendix provides requirements for qualitative risk assessment conducted in
accordance with AS 4360.
Where a failure event may have several outcomes, the consequence and frequency of each
outcome shall be considered. Full evaluation of every outcome may not be necessary, but
sufficient outcomes shall be evaluated to identify the outcome with the highest risk ranking.
NOTE: The highest energy release rate may not give rise to the highest consequence or the
highest risk (e.g., a small LPG leak, which is initially unignited, may well have a higher
consequence or higher risk ranking than a large immediately ignited release).
F2 CONSEQUENCE ANALYSIS
The severity of the consequences of each failure event shall be assessed. Consequences to
be assessed shall include the potential for—
(a) human injury or fatality;
(b) interruption to continuity of supply with economic impact; and
(c) environmental damage.
NOTES:
1 Other factors, such as property damage and loss of reputation, may also be considered.
2 Gas pipelines and some liquid petroleum pipelines may be identified as ‘essential
infrastructure’ where the consequence of a loss of supply is significant. This may be in
terms of the potential for economic impact, and in some cases significant fatalities may
result from the cascading consequence of loss of the energy supply.
A severity class shall be assigned to each failure event based on the consequences at the
location of the failure. The severity class shall be selected from Table F2.
Where necessary to make the severity classes applicable to the pipeline under study the
measures of severity in Table F2 may be modified with the agreement of the stakeholders.
Modification should be minimized. The severity classes shall be maintained for consistency
with Table F4.
The reasons for any changes to the measures of severity shall be documented and approved.
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TABLE F2
SEVERITY CLASSES
Severity class
Catastrophic Major Severe Minor Trivial
Dimension Measures of severity
People
Multiple
fatalities result
Few fatalities;
several people
with life-
threatening
injuries
Injury or illness
requiring
hospital
treatment
Injuries
requiring first
aid treatment
Minimal impact
on health and
safety
Supply
Long-term
interruption of
supply
Prolonged
interruption;
long-term
restriction of
supply
Short-term
interruption;
prolonged
restriction of
supply
Short-term
interruption;
restriction of
supply but
shortfall met
from other
sources
No impact; no
restriction of
pipeline supply
Environment
(see Note)
Effects
widespread;
viability of
ecosystems or
species affected;
permanent
major changes
Major off-site
impact; long-
term severe
effects;
rectification
difficult
Localized
(<1 ha) and
short-term
(<2 y) effects,
easily rectified
Effect very
localized
(<0.1 ha) and
very short-term
(weeks),
minimal
rectification
No effect; minor
on-site effects
rectified rapidly
with negligible
residual effect
NOTE: Significant environmental consequences may occur in locations that are relatively small and isolated.
F3 FREQUENCY ANALYSIS
A frequency of occurrence of each failure event shall be assigned for each location where
risk estimation is required. The frequency of occurrence shall be selected from Table F3.
The contribution of operations and maintenance practices and procedures to the occurrence
or prevention of failure events shall be considered in assigning the frequency of occurrence.
The frequency class for a threat that exists for a limited period should be assessed against
the exposure period rather than the life of the pipeline.
TABLE F3
FREQUENCY CLASSES
Frequency class Frequency description
Frequent Expected to occur once per year or more
Occasional May occur occasionally in the life of the pipeline
Unlikely Unlikely to occur within the life of the pipeline, but possible
Remote Not anticipated for this pipeline at this location
Hypothetical Theoretically possible but has never occurred on a similar pipeline
F4 RISK RANKING
Table F4 shall be used to combine the results of frequency analysis and consequence
analysis and determine the risk rank.
Risks determined to be low or negligible or demonstrated to be ALARP are accepted risks.
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TABLE F4
RISK MATRIX
Catastrophic Major Severe Minor Trivial
Frequent Extreme Extreme High Intermediate Low
Occasional Extreme High Intermediate Low Low
Unlikely High High Intermediate Low Negligible
Remote High Intermediate Low Negligible Negligible
Hypothetical Intermediate Low Negligible Negligible Negligible
F5 RISK TREATMENT
F5.1 General
Action to reduce risk shall be taken in accordance with Table F5 based on the risk rank
determined from Table F4.
The action(s) taken and its effect on safety management shall be documented and approved.
TABLE F5
RISK TREATMENT ACTIONS
Risk rank Required Action
Extreme Modify the threat, the frequency or the consequences so that the risk rank is reduced to
‘intermediate’ or lower
For an in-service pipeline the risk shall be reduced immediately
High Modify the threat, the frequency or the consequences so that the risk rank is reduced to
Intermediate or lower
For an in-service pipeline the risk shall be reduced as soon as possible, typically within
a timescale of not more than a few weeks
Intermediate Repeat threat identification and risk evaluation processes to verify and, where possible,
quantify the risk estimation; determine the accuracy and uncertainty of the estimation.
Where the risk rank is confirmed to be ‘intermediate’, if possible modify the threat, the
frequency or the consequence to reduce the risk rank to ‘low’ or ‘negligible’
Where the risk rank can not be reduced to ‘low’ or ‘negligible’, action shall be taken
to—
(a) remove threats, reduce frequencies and/or reduce severity of consequences to the
extent practicable; and
(b) demonstrate ALARP
For an in-service pipeline, the reduction to ‘low’ or ‘negligible’ or demonstration of
ALARP shall be completed as soon as possible; typically within a timescale of not more
than a few months
Low Determine the management plan for the threat to prevent occurrence and to monitor
changes that could affect the classification
Negligible Review at the next review interval
F5.2 ALARP
A risk cannot be demonstrated as ALARP until consideration has been given to—
(a) means of further reducing the risk; and
(b) the reasons why these further means have not been adopted.
ALARP is achieved when the cost of further risk reduction measures is grossly
disproportionate to the benefit gained from the reduced risk that would result.
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Additional risk reduction measures considered and the reasons they have not been adopted
shall be documented.
NOTE: Guidance on demonstration of ALARP is provided in Appendix G.
F5.3 Risk treatment during design
Risk treatment actions at design stage may include the following:
(a) Relocation of the pipeline route.
(b) Modification of the design for any one or more of the following:
(i) Pipeline isolation.
(ii) External interference protection.
(iii) Corrosion prevention.
(iv) Operational controls.
(v) Establishment of specific procedural methods for prevention of external
interference.
(vi) Establishment of specific operations measures.
F5.4 Risk treatment during operation
Risk treatment actions at operating pipeline stage may include one or more of the
following:
(a) Installation of modified physical external interference protection methods.
(b) Modification of procedural external interference protection methods in operation.
(c) Specific actions in relation to identified activities (e.g., presence of operating
personnel during activities on the easement).
(d) Modification to pipeline marking.
(e) Changes to the isolation plan.
(f) Changes to the design or operation to satisfy the requirements of this Standard when
there is a change to the location class of the pipeline.
(g) Specific operational or maintenance procedures.
Threat treatment for operating pipelines shall consider interim control measures (e.g.
reduction in operating pressure, access restrictions) to allow time for the implementation of
permanent control measures (e.g., repair).
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AS 2885.1—2007 174
Standards Australia www.standards.org.au
APPENDIX G
ALARP
(Informative)
G1 GENERAL
In the Standard, risk levels are classified as follows:
(a) NEGLIGIBLE—No further action is required for this level of risk beyond regular
reviews.
(b) LOW—The risks are considered manageable through the application of risk
management measures detailed in the safety and operating plan to ensure appropriate
measures are in place to keep the risk at an acceptable level.
(c) INTERMEDIATE—The risks are higher than desired and actions are required to
reduce the risk to LOW, NEGLIGIBLE or at least ALARP.
(d) HIGH—The risks are considered intolerable and have to be reduced to
INTERMEDIATE or lower.
(e) EXTREME—The risks are considered intolerable and have to be reduced to
INTERMEDIATE or lower and, for an in-service pipeline, have to be reduced
immediately.
This Standard defines the acceptable level of risk as being NEGLIGIBLE, LOW, or
INTERMEDIATE (if it is ALARP). Risks ranked as EXTREME, HIGH or
INTERMEDIATE (but not ALARP) are considered intolerable and have to be addressed by
further measures.
G2 THE CONCEPT OF ALARP
The term ALARP is widely used throughout risk assessment and management.
Safety regulators worldwide require hazardous industries to evaluate the risks associated
with the plant or processes of those industries. Generally, the philosophy is that the risks
from threats should be eliminated wherever possible. If this is not possible, the risk should
be reduced to ALARP.
In broad terms, risks are either TOLERABLE, INTOLERABLE or TOLERABLE IF
ALARP. (Refer to the terminology used by the UK Heath and Safety Executive, see
Reference.)
Hence, in relation to the Standard, LOW and NEGLIGIBLE risks are considered
TOLERABLE, HIGH risks are INTOLERABLE and INTERMEDIATE risks are
TOLERABLE IF ALARP. Often, numerical methods are used to define the boundaries
between these regions, although this is not universal, and qualitative criteria are also used
where appropriate.
Defining what is reasonable is the difficult issue and is often determined by the courts. In
the case of Edwards v The National Coal Board the UK Court of Appeal held that:
‘...in every case, it is the risk that has to be weighed against the measures necessary to
eliminate the risk. The greater the risk, no doubt, the less will be the weight to be
given to the factor of cost.’
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and
‘Reasonably practicable’ is a narrower term than ‘physically possible’ and seems to
me to imply that a computation must be made by the owner in which the quantum of
risk is placed on one scale and the sacrifice involved in the measures necessary for
averting the risk (whether in money, time or trouble) is placed in the other, and that,
if it be shown that there is a gross disproportion between them - the risk being
insignificant in relation to the sacrifice - the defendants discharge the onus on them.’
Determining if the risk from a specific threat has been reduced to ALARP involves an
assessment of the risk to be avoided, the cost (in money, time and trouble) involved in
avoiding the risk and a comparison of the two. Determining ALARP is in effect a
cost-benefit analysis.
The measure of whether ALARP has been achieved is if the cost of reducing the risk is
GROSSLY DISPROPORTIONATE to the benefit gained. The reduction in risk has to be
insignificant when compared to the cost required. HSE have developed extensive guidance
material to assist in determining ALARP (see Reference).
G3 CONSIDERATION OF ALTERNATIVES
The concept of ALARP contains an implicit assumption that there are alternative designs or
measures that can reduce the risk but that some of these alternatives may not be
‘practicable’. (There is always at least one alternative—abandon the project or pipeline.)
Any attempt to demonstrate ALARP that does not consider any alternatives, or at least
search for them, is not convincing.
An important part of the process of demonstrating ALARP is the identification and
evaluation of alternative designs that offer lower risk. Two questions illustrate the process:
(a) What else could we do to reduce risk?
(b) Why have we not done it?
ALARP has been demonstrated when the answer to the second question, for each physically
possible alternative, is ‘because the cost is grossly disproportionate’.
The level of analysis required in establishing the relevant costs and safety benefits depends
on the severity of the consequences.
Where the consequences could include fatalities, there should be an exhaustive search for
alternatives, detailed evaluation of the resulting risk reductions (qualitative or numeric),
and realistic estimates of the associated cost increments.
Where there could be multiple fatalities, a numeric risk assessment may be necessary to
determine the risk reductions achieved by alternative designs.
In all other cases, there should be at least a listing of all alternatives considered and the
reasons for their rejection including basic cost estimates.
The analysis demonstrating ALARP should be documented in full.
REFERENCE
UK Health and Safety Executive, “Guidance on ‘AS Low As Reasonably Practicable’
(ALARP) Decisions in Control of Major Accident Hazards (COMAH) –
(SPC/PERMISSIONG/12)”
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AS 2885.1—2007 176
Standards Australia www.standards.org.au
APPENDIX H
INTEGRITY OF THE SAFETY MANAGEMENT PROCESS
(Informative)
H1 INTRODUCTION
The pipeline safety management process required by this Standard is of fundamental
importance to pipeline design, operation and maintenance. It is the means by which pipeline
safety is demonstrated. It also forms the basis for the operations and maintenance of the
pipeline, which provide for ongoing pipeline safety. Therefore, all parties with an interest in
any form of ‘approval’ of the pipeline (be it technical, financial or regulatory) require
assurance that that the pipeline safety management process has been carried out in rigorous
and competent manner, i.e. has integrity.
To support this, Section 2 requires that all aspects of the safety management process 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 identified threats and the reasoning behind the assessment of the effectiveness of
the controls applied.
This section provides a framework for a competent reviewer to make a reasonable
assessment as to the integrity of a pipeline safety management study.
H2 INTEGRITY REVIEW CONCEPTS
The pipeline safety management process is founded on a number of principles, adherence to
which should be demonstrated by the safety management study documentation.
H2.1 Approval
One of the principles upon which the AS 2885 series is based is that important matters
relating to safety, engineering design, materials, testing and inspection are required to be
reviewed and approved by a responsible entity.
The intent is to confirm that all steps in the process have been completed and reviewed. The
presence or absence of explicit, written approvals is the first step to gaining assurance that
all of the process elements have indeed been implemented.
H2.2 Specific information for specific threats
The pipeline safety management process for design against external interference threats is
predicated on the understanding that specific threats to pipeline integrity occur at specific
locations using specific equipment, undertaken by specific parties at specific times.
Effective mitigation can only be developed and implemented if there is a high level of
detailed information regarding the specific threat.
It is common practice to develop typical designs for common threat situations. At each
location where typical designs are applied, this Standard requires that an assessment to
determine whether there are other threats to be considered is carried out.
The level of specific information that can be identified in a report provides an indication of
the degree of rigour applied to the pipeline safety management process.
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H2.3 Effective controls
Any control is required to be demonstrated to be effective. Guidance on the effectiveness of
controls is provided in this Standard. The validation workshop should critically assess
whether a proposed control is effective against a specified threat. This should be
documented in the safety management study.
H2.4 Positive confirmation
Where possible, information should be positively confirmed and documented, rather than
assumed. Where assumptions are made, these should be documented. It is preferable to
explicitly discount an issue rather than infer it by silence. This demonstrates that any given
issue has been thought of and discounted rather than simply forgotten.
H3 INTEGRITY CHECKING
H3.1 General
A suggested pro-forma for integrity checking pipeline safety management studies is
provided in Table H1.
The integrity checking process concentrates on three major aspects:
(a) Methodology—the methodology has been followed correctly (see Paragraph H3.2).
(b) Personnel—the safety management process has been conducted by the correct
personnel (see Paragraph H3.3).
(c) Information—the safety management process has identified, developed, or collated
information that is sufficient for the process to be carried out (see Paragraph H3.4).
H3.2 Methodology
Assurance on adherence to the pipeline safety management methodology is gained if it is
clear from the report that the process has been followed and that all key steps have been
approved.
A review of study integrity should confirm that—
(a) all elements of the process requiring approval have been appropriately approved; and
(b) the safety management process in Section 2 has been followed, with care taken to
differentiate between the stated process and the actual process demonstrated by
review of the report.
H3.3 Personnel
Personnel requirements for pipeline safety management studies and validation workshops
are listed in Appendix B.
Every effort should be made to involve operations personnel in the safety management
workshop(s). This is important for facilitating transfer of information between the operators
and the designers (including documentation transfer from design to the safety and operating
plan and other procedures). Operators familiar with the location-specific issues are
particularly important for critical assessment of the effectiveness of procedural controls.
While not necessarily apparent from documentation, it is important to recognize that the
chair of the safety management validation workshop has a bearing on its effectiveness. The
chair should be thoroughly familiar with the pipeline safety management process, and also
have the ability to ensure that each issues is debated openly and thoroughly. The chair
should have skills in drawing information out of all attendees in a workshop environment.
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The following check question applies:
Is the safety management study conducted by personnel who are sufficiently familiar
with the pipeline design operation, maintenance, management and environment so
that an effective safety management study has been carried out?
H3.4 Data and documentation
Information is the raw material that dictates the success of the pipeline safety management
process. A pipeline safety management study cannot be considered to have integrity unless
it is based on information specific to the pipeline, which is sufficient to allow informed
decision-making on design against specified threats.
The information required for a detailed safety management study is listed in Appendix B.
The outcome of the study is a documented design that demonstrates that effective controls
are applied to all identified threats.
The safety management study may result in a series of action items to be closed out at a
later date. This should be clearly documented.
The documentation should also generate a list of items to be transferred to the safety and
operating plan.
Follow-up on the close out of actions items should be conducted to confirm they have been
completed.
A review of study integrity should confirm that—
(a) all information requirements are present and documented with sufficient detail to
allow for effective design; and
(b) the resulting design is documented with sufficient details to demonstrate that
effective controls have been developed for all identified threats, in accordance with
the guidance provided in the Standard.
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179 AS 2885.1—2007
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TABLE H1
SAFETY MANAGEMENT INTEGRITY CHECKLIST
ITEM
COMMENT
No
t a
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Un
accep
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Cla
rif
y
Accep
tab
le
Methodology (Adherence to
AS 2885.1 process)
Has safety management process been
followed and, where appropriate, approved?
Location analysis
Threats identification
External interference protection
Design and/or procedures
Failure analysis
Risk severity classes approved
Risk evaluation
Risk management actions
Process
Stations, pipeline facilities and
pipeline controls systems—HAZOP
and other methodologies
People (Safety management
workshop)
Is the safety management study conducted by
personnel who are sufficiently familiar with
the pipeline design operation, maintenance,
management and environment (i.e., so that
an effective safety management study will be
carried out)?
Designers
Operators
Maintenance
Field personnel
Environmental
Chair
Other
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AS 2885.1—2007 180
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ITEM
COMMENT No
t a
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Un
accep
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Cla
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Accep
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INFORMATION Is the information generated sufficient for the
purposes of the safety management study?
Does the location analysis generate sufficient
information to determine:
Location analysis
The types of threats that will occur
The consequences of any loss of integrity
event
Environment
Crossings
Population
Land use
Location class
Threat identification Does the threats analysis generate sufficient
information about each threat to allow effective
design against that threat to take place?
All threats considered?
Who? (Identification of the person
responsible is essential for having a
source of information to determine
what activity is carried out;
developing effective liaison)
What? (Detailed specification is
essential for determining the EIP
design requirements. Information
required typically includes: the power
of the equipment; the depth of the
excavation, etc.)
Where? (Essential to determine
where EIP is applied. Essential to
determine consequence information)
When? (Essential for determining
procedural controls, e.g., patrolling
frequency, timing of liaison, etc.
Essential for consequence analysis)
Why? (e.g.,routine, emergency—can
be used for determining procedural
controls, e.g. patrolling frequency,
timing of liaison etc. May provide a
‘leading indicator’ for
patrollers/liaison)
Threats to typical design identified?
Other threats at typical design
locations considered?
Non-credible threats
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ITEM
COMMENT No
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Accep
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Design information Has location-specific pipeline property
information been developed for the full length
of the pipeline?
Pipeline properties
Wall thickness
MAOP
Grade
Depth of burial
Special protection measures
Special crossings
Other
Loss of containment information
Equipment
Failure mode
Energy release rate
Thermal radiation contours
Spill volumes
Documentation
Alignment sheets/As-built diagrams
Typical design drawings
Safety and operating plan
Fracture control plan
Isolation plan
Construction line list
Environmental line list
Isolation plan
Corrosion mitigation plan
GIS
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AS 2885.1—2007 182
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ITEM
COMMENT No
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Cla
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Accep
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External interference protection
design
Location class identified
Physical controls—number sufficient?
Physical controls—effective?
Physical controls—all reasonably
practicable methods?
Procedural controls—number
sufficient?
Procedural controls—effective?
Procedural controls—all reasonably
practicable methods?
Failure analysis
Threats resulting in failure identified?
Failure mode identified?
All location-specific information
included?
RISK EVALUATION How have estimates of frequency and
consequence been developed? Do they seem
reasonable?
Frequency
Consequence
Risk evaluation
RISK MANAGEMENT Have appropriate risk management actions been
taken?
Extreme risk
Extreme risks are unacceptable and
need to be re-engineered. They need
to be addressed immediately on in-
service pipelines
High risk
High risks are unacceptable and need
to be re-engineered
Intermediate risk
ALARP demonstrated
Low risk
Management plan recorded?
Negligible risk
Recorded for future review?
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ITEM
COMMENT No
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Un
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Cla
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Accep
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ACTION ITEMS
Action list developed
Actions for design changes
Actions for safety and operating plan
Actions closed out
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AS 2885.1—2007 184
Standards Australia www.standards.org.au
APPENDIX I
ENVIRONMENTAL MANAGEMENT
(Informative)
I1 GENERAL
Pipeline construction, operation maintenance and abandonment have potential to impact on
the environment. This Standard requires the threats to the environment of each part of the
life cycle of the pipeline to be identified and controlled using the methodology of Section 2
so that they are effectively managed.
Environmental impact assessment is not simply a vehicle to obtain regulatory approval. It is
a critical element of the planning for design, construction and operation of the pipeline.
Experience shows that many construction and rehabilitation problems can be avoided where
appropriate attention is paid to developing detailed environmental information and ensuring
that this information is integrated into design and construction planning. It is important that
personnel experienced in construction are involved at this early stage. The greatest
environmental impacts occur during the construction phase, and construction personnel are
in the best position to advise on this.
An environmental impact assessment does not remove the obligation of compliance with
statutory and project-specific requirements to manage environmental threats. Rather it
provides a basis for determining the appropriateness of a mitigation approach, particularly
to a construction activity, where the consequence and the frequency (or duration of the
consequence) is a direct result of the approach taken to control the threat.
Effective environmental impact assessment requires gathering basic environmental data and
includes consultation with key stakeholders (prior to any statutory consultation
requirements). Stakeholder consultation at an early stage is critical to the process of
gathering all relevant information required for all subsequent planning. Sources of data may
include the following:
(a) Field survey information.
(b) Landholder survey information.
(c) Stakeholder survey information.
(d) Experienced pipeline construction personnel.
(e) Externally sourced data resident in the project environmental impact assessment.
(f) Other publicly available information including papers, studies, reports, assessments
and data libraries on flora, fauna and eco-systems in the pipeline route or ecologically
similar environments.
An objective of the pipeline development process, including pipeline route selection, is that
the environmental threats are managed through careful investigation, assessment and
selection of the pipeline route such that, to the greatest extent possible, environmental
threats are minimized by avoidance (route selection) and, where necessary, specific
construction techniques, together with appropriate environmental management procedures.
The environmental impact assessment has to be based on data that is sufficient to form
informed decisions about the impacts of the pipeline project and the efficacy of the
environmental controls.
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I2 ENVIRONMENTAL MANAGEMENT PROCESS
The process for managing environmental threats using the AS 2885 series principles are as
follows:
(a) Divide the route into sections with similar environments and threats, such as level
cropping land, undulating grazing land, steeply dissected bushland, etc., and then
identify specific locations where adverse environmental consequences may occur,
such as creek crossings, paddocks (e.g., weed impacts), bushland (e.g., vegetation
clearance), etc.
(b) Specify each activity (e.g., right-of-way clearance) that has the potential to create a
threat to the environment. As far as practicable, specification of the activity has to be
expressed in quantified terms (e.g., width of clearance, period of disturbance).
(c) Specify the potential impacts of each activity on each component of the environment
[(fauna, flora, soil, groundwater, surface water, drainage, landholders and land use,
emissions (air and noise)], cultural heritage, public safety and visual amenity.
(d) Identify and apply all reasonably practicable control measures for each threat
(including rehabilitation), and assess whether the controls will meet the
environmental objectives (i.e., can reduce the impact to an acceptable level).
(e) Where the environmental objectives are not met, determine the frequency of each
adverse consequence of the threat (taking into account the duration of the activity at
the specified location and the robustness of the specific controls). At each location,
identify the environment. The analysis has to also recognize that some consequences
(e.g., weed infestation) have the potential to create an impact whose duration is
significantly greater than the duration of the activity, and the consequence may
propagate well beyond the easement.
(f) Evaluate the residual environmental risk in accordance with the requirements of
Appendix F and, where required, AS 4360. Apply further control measures until all
residual environmental risks are ALARP.
The following are important:
(i) The environmental management plan has to take a holistic view of the environment
and the activities that may impact on the environment (e.g., construction). The net
effect of the mitigation measures (taking into account the environmental impact of the
mitigation measures) has to be considered. Concentration on specific issue may create
greater overall environmental impact while minimizing the impacts of a particular
threat.
(ii) The environmental objectives set at the approval stage have to be achievable within
practicable construction processes.
(iii) The environmental objectives have to be established sufficiently early in the process
for the bulk of the objectives to be satisfied by route selection.
(iv) Occasional impacts (e.g., sedimentation at stream crossings) may be an acceptable
outcome if the duration of the release is small. The impact has to be considered in the
context of other land uses in the immediate vicinity of the project.
(v) Environmental management is ongoing through the operational phase and needs to be
addressed during the approval and design process.
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AS 2885.1—2007 186
Standards Australia www.standards.org.au
APPENDIX J
PREFERRED METHOD FOR TENSILE TESTING OF WELDED LINE PIPE DURING MANUFACTURE
(Informative)
J1 APPLICABILITY
This method of determining the tensile properties is applicable to pipe having an outside
diameter of not less than 168.3 mm and manufactured in all other respects in accordance
with API Spec 5L.
J2 METHOD FOR DETERMINING TENSILE PROPERTIES
The tensile properties of pipe should be determined as follows:
(a) Yield strength The yield strength of pipe should be determined in accordance with
the method set out in AS 1855.
The frequency of testing should include at least one test for each production batch.
NOTES:
1 The use of this method normally results in a more correct determination of yield strength.
The reported ratio of yield strength to tensile strength may be higher than that determined
when other methods are used.
2 The lot size is determined by reference to the Standard to which the pipe is manufactured.
(b) Tensile strength and elongation The tensile strength and the elongation of a
rectangular specimen taken transversely from the strip, skelp or plate should be
determined. The minimum frequency of testing should be one of each heat.
NOTE: The tests on strip or plate fulfil the requirements of the mill control tensile test. The
results of these tests are also applicable to the pipe.
(c) Weld The tensile strength of a rectangular specimen taken transversely from a
longitudinal or spiral weld made with electrodes or wire should be determined. The
frequency of testing should be one for each production batch.
The weld tensile test is not required for welds made without electrodes or wire.
J3 CRITERIA OF ACCEPTANCE
The criteria for acceptance of tensile properties should be as specified in API Spec 5L
unless otherwise approved.
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187 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX K
FRACTURE TOUGHNESS TEST METHODS
(Normative)
K1 SCOPE
This Appendix gives test methods for determining the resistance of pipe material to brittle
fracture and low energy tearing ductile fracture.
K2 SAMPLING
Test specimens for determining fracture appearance and transverse energy absorption shall
be removed from a sample so that the length of the test specimens is in the circumferential
direction, in the approximate position shown in Figure K1. Samples may be taken from a
finished pipe, strip or plate with the same orientation, providing any changes in properties
are determined and taken into account. A test specimen showing material defects or
incorrect preparation, whether observed or after breaking, may be replaced by another. The
replacement test specimen shall be considered as the original.
K3 FRACTURE APPEARANCE TESTING FOR CONTROL OF BRITTLE
FRACTURE
K3.1 General
Fracture appearance testing for control of brittle fracture shall be performed using the drop-
weight tear test (DWTT) in accordance with AS 1330 or an alternative Standard for the
same test method. No other method is approved for this purpose.
K3.2 Test specimens
Two test specimens shall be taken from one sample from each heat.
K3.3 Test temperature
The test temperature shall be as specified in Clause 4.8.4.
K3.4 Criteria of acceptance
If the average value of the shear fracture appearance of the two test specimens taken from
the sample representing the heat is not less than 85%, all pipes from that heat shall be
acceptable.
If the average shear fracture appearance of the two specimens is less than 85%, two more
samples shall be selected and two test specimens taken from each sample shall be tested. If
the average shear fracture appearance of these four additional test specimens is not less than
85%, all pipes from that heat shall be acceptable.
If the average shear fracture appearance for the four additional test specimens is less than
85%, two test specimens taken from each sample in the heat may be tested. If the average
shear fracture appearance of 80% of all the test specimens is not less than 85%, all pipes
from that heat shall be acceptable.
If the average value of the shear fracture appearance of the two specimens representing a
pipe is not less than 85%, that pipe shall be acceptable.
NOTE: Neither AS 1330 or API RP 5L3 contain a requirement that in order for a test to be
considered valid, there should be a region of cleavage fracture within the area directly beneath the
notch. Strictly speaking, such a requirement should exist. However, until agreement is reached on
alternative methods of test for steels in which fracture initiation is difficult, no such action can be
taken.
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AS 2885.1—2007 188
Standards Australia www.standards.org.au
K4 ENERGY ABSORPTION TESTING FOR CONTROL OF LOW ENERGY
TEARING DUCTILE FRACTURE
K4.1 General
Energy absorption testing for control of low energy tearing ductile fracture shall be
performed using the Charpy V-notch impact test in accordance with AS 1544.2 or
alternative Standards for the same test method.
K4.2 Test specimens
Three test specimens (see Figure K1) shall be taken from one sample from each heat. The
thickness of each test specimen shall be the greatest of 5 mm, 6.7 mm, 7.5 mm and 10 mm
that can be obtained by cutting and machining from unflattened pipe, strip or plate.
K4.3 Test temperature
The test temperature shall be as specified in Clause 4.8.4.
K4.4 Criteria of acceptance
The average absorbed energy shall exceed the requirement calculated according to
Clause 4.3.7.2 after taking into account the thickness of the test specimens. The method of
allowing for the thickness of the test specimen may be either the ratio of the thickness of
the test piece used to the standard 10 mm × 10 mm test specimens, or alternatively on the
basis of an experimental correlation for the material under consideration.
90˚
(b) Spiral welded pipe(a) Longitudinal welded pipe
90˚
or
Weld Weld
or
FIGURE K1 FRACTURE TOUGHNESS—ORIENTATION OF TEST SPECIMENS
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189 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX L
FRACTURE CONTROL PLAN FOR STEEL PIPELINES
(Informative)
L1 GENERAL
This Appendix provides information on the development of the fracture control plan
required by Clause 4.8. Fracture control plans are required for all pipelines other than those
restricted to use with stable liquids with a minimum design temperature greater than 0ºC.
This Appendix only deals with carbon and carbon manganese steels.
This Standard nominates the minimum requirements for control of fracture in pipelines
covered by this Standard. It is not a text on fracture control. The Standard references a
number of documents that provide detailed information on the development of knowledge
on materials performance and fracture control. Worldwide research is continuing to add to
this knowledge.
Two modes of propagating fracture have been recognized in pipelines. These are brittle
fracture and tearing fracture. Tearing fracture is commonly referred to as ductile fracture.
The fracture control plan is required to define the measures to be implemented to limit the
extent of fracture propagation in the event that a pipeline rupture occurs.
A pipeline rupture will occur when there is a flaw larger than the critical size determined by
the pipeline operating parameters and the resistance of the pipe material to fracture
initiation. Fracture mechanics analysis methods provide a method of assessment of the
critical size.
L2 THE BASIS OF FRACTURE CONTROL
The subject of fracture control is complex and is not amenable to simple analysis.
The properties that are relied on for fracture control are measured in empirical tests such as
Charpy and drop weight tear tests (DWTT). These tests are relatively small scale and
inexpensive and so can be used for quality control purposes; however, because they are
empirical, they need to be calibrated against full scale tests in order to show that they fulfil
their purpose of providing the design and control data necessary to avoid fracture in full
size pipelines under field conditions.
Full scale tests are very expensive, and for this reason the database of test results
correlating small scale quality control tests with full scale tests is limited and is mostly
confined to design regimes that embrace the majority of gas transmission pipelines that
have been built in countries such as North America and Europe. The original database was
weighed towards larger diameter pipelines designed for operating pressures less than
12 MPa and for the carriage of lean gas. This database has now been expanded to include
some exceptions to this generalization, and new tests are being undertaken from time to
time, which extend the envelope. Significant gaps remain in the data and design methods
for the control of tearing fracture, especially for individual cases or combinations of—
(a) high operating pressures above about 12 to 15 MPa;
(b) rich gas and multi-phase fluids;
(c) pipeline diameters less than about DN 600; and
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(d) predicted arrest toughness levels using the Battelle Two Curve Model without fudge
factors higher than about 100—125 J (full size) Charpy energy.
NOTE: The term ‘fudge factor’ is used in the pipeline fracture literature to describe the
process of multiplying the predicted arrest toughness derived from the Battelle Two Curve
model to provide better fit with experimental results.
There is also a gap in the knowledge of how to design against brittle fracture in small
diameter thick-walled pipe where it becomes difficult or impossible to perform DWTT
tests, and where the Charpy test represents only a small proportion of the pipe wall
thickness. The methods for fracture control in thick-walled pressure vessels and structures
may be used in these circumstances to give protection against fracture initiation; however
some uncertainty will remain concerning brittle fracture propagation whenever the DWTT
requirements for transition temperature cannot be shown to be met in the diameter wall
thickness combination under consideration.
When the operating conditions referred to above are under consideration, designers are
advised to undertake additional research, and to engage independent expert advice to assist
in developing appropriate solutions. Since a significant number of Australian pipelines that
have been built in the last decade or so have involved design conditions that include more
than one of these conditions, the need for additional research and independent expert advice
is particularly appropriate in this country.
L3 FACTORS AFFECTING BRITTLE AND TEARING DUCTILE FRACTURE
L3.1 General
The following factors are recognized in the control of propagation and arrest of fracture in
petroleum pipelines:
(a) The fluid parameter speed-of-decompression wave, which is determined by the type
of fluid and the pressure.
(b) Decompression velocity.
NOTE: The methods for predicting the decompression velocity are based on the composition
of the fluid and ignore the pipe diameter. There is experimental evidence from shock tube
decompression tests in different diameter pipe that this assumption is incorrect.
(c) The operating parameters pipe wall stress and temperature.
(d) The pipeline parameters—pipe fracture toughness, pipe wall thickness, pipe diameter
and pipe backfill or water depth.
L3.2 Fluid parameters
The phase of the fluid (i.e., gas, liquid, or mixture of gas and liquid) and the actual
composition of gases and liquids affect the speed of propagation of a fracture and the
conditions of arrest. Fracture arrest is sensitive to the ratio of the speed of propagation of
the fracture and the speed of the decompression wave in the fluid. The speed of the
decompression wave can be measured experimentally or calculated from the physical
constants for most fluids. It can also be influenced by the presence of small droplets of
hydrocarbon liquids carried as a mist or vapour, which change phase during decompression.
In a pipeline that is conveying only a stable liquid (including water), the low energy tearing
fracture mode cannot be supported because of the high speed of the decompression wave in
the liquid. Also, the pressure in a ruptured pipeline conveying a liquid falls rapidly with a
loss of relatively small amounts of liquid, because of the high bulk modulus of the liquid.
For these reasons, a fracture control plan for a pipeline that conveys only liquid is only
required if there is potential for fast fracture propagation in the brittle mode. This is only
deemed to occur if the design temperature is 0ºC or lower.
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In a pipeline that is conveying compressed gas, a decompression wave travels slower than it
would in a liquid. As brittle fractures have fracture speeds faster than the decompression
wave speed for most operating conditions of gas pipelines, neither the stress in the steel nor
the temperature of the steel ahead of the crack is affected by decompression. A fracture
control plan is required to ensure that arrest occurs by reduction of the fracture speed below
the decompression wave speed. This is affected by the change of fracture mode from brittle
fracture to tearing (ductile) fracture, which occurs above the fracture appearance transition
temperature. Sufficient fracture energy absorption capacity must also be present above the
fracture appearance transition temperature to slow the fracture velocity; otherwise the
fracture may propagate in the low energy ductile tearing mode.
A pipeline conveying a mixture of liquids and gases can be expected to closely follow the
behaviour of a gas pipeline, and for fracture control purposes, should be treated as such.
The fracture control plan for a pipeline conveying an HVPL should be based on the
decompression behaviour of the fluid being transported.
For fast tearing fracture, the most demanding arrest condition generally occurs at the
combination of design pressure (MAOP) and minimum operating temperature; however
some fluid compositions and, in particular, compositions that contain liquid fractions
exhibit the most demanding arrest condition at elevated temperatures, or at mid range
(operating) pressures. Analysis should test the arrest toughness requirements over the range
of design pressure and temperature to ensure that the most demanding arrest conditions are
established.
Where a pipeline is initially intended to convey petroleum liquids and is later to convey
gas, mixed fluids or HVPL, the fracture control plan should reflect the future use. This
Standard requires a pipeline intended to convey HVPL to be designed as a gas pipeline.
The fracture control plan for a pipeline that is intended to convey gas or a mixture of gas
and liquid should prevent both brittle fracture propagation and low energy ductile tearing
fracture propagation.
L3.3 Operating parameters
L3.3.1 Introduction
Both forms of fracture propagation are affected by the operating stress in the pipe wall. The
inherent fracture toughness of pipe steels shows a marked change over a transition
temperature range. The change is from brittle fracture below the transition range to ductile
fracture (tearing) above the transition range. The change is usually characterized by the
fracture appearance transition temperature (FATT), measured by the DWTT as the
temperature at which 85% of the surface appearance of a propagating fracture is shear.
NOTE: The fracture propagation transition temperature (FPTT) discussed in Paragraph L5 is the
same as the FATT.
L3.3.2 Brittle fracture
Provided the stress level is above the threshold level, brittle fracture propagation is not very
sensitive to operating stress and, therefore, different FATT requirements are not required
for different operating stresses. The energy to propagate a brittle fracture is derived from
the elastic energy of the steel, which is derived from the fluid pressure. Where the operating
stress is less than the threshold stress, usually taken as 85 MPa in this Standard, the fracture
control plan need not specify FATT requirements. The operating stress has to be assessed at
the lowest pipe body temperature, which will exist concurrently with a stress greater than
the threshold stress.
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AS 2885.1—2007 192
Standards Australia www.standards.org.au
Propagating brittle fractures in longitudinal welds (ERW or SAW) have not been recorded
in operating pipelines to date. The fracture appearance tests that have been developed to
determine the resistance to fracture propagation in the body of the pipe are not applicable to
the weld metal or the heat-affected zone. In many weld metals it is not possible to interpret
the fracture appearance as shear or ductile fracture zones. This Standard requires that the
longitudinal joints be offset at butt welds. Therefore, it is not necessary for the fracture
control plan to specify fracture appearance properties for longitudinal welds or the heat-
affected zones for the purpose of controlling fracture propagation.
Clause 4.8.2(d) defines circumstances under which the toughness of seam welds is required
to control fracture initiation, and Clause 4.8.4.2 defines the requirement.
L3.3.3 Ductile tearing
Operating stress and diameter are significant for ductile fracture. The higher the operating
stress and the larger the diameter, the greater the driving force for tearing fracture.
This Standard adopts DN 200 as the diameter below which tearing fracture need not be
considered except when the pipeline MAOP is above 10.5 MPa. The minimum toughness
required by Section 3 (27 J) will provide protection against tearing fracture below this
pressure limit for typical pipeline gases.
Operating stresses below a threshold stress defined for the purposes of this Standard as 30%
of the flow stress (Figure 4.4 adopts 40% SMYS as a default approximation) are not
regarded as capable of supporting low energy ductile tearing. Calculation methods for
determining the level of pipe body toughness required to arrest a propagating fracture have
been developed by several authorities.
The level of toughness to be specified in the fracture control plan is affected by the length
of the pipeline within which the fracture has to be arrested either side of the point of
initiation, and by the expected spread of toughness results in the pipe relative to the arrest
value. For a pipeline comprised of a large number of heats, the all-heat average toughness
has to be not less than the calculated arrest toughness. For pipe grades up to X70, the
minimum toughness for any heat may be nominated as 0.75 times the calculated toughness
for immediate arrest. For pipe of X80 grade (550 MPa), a unique value has to be
established.
The use of the default value of 0.75 is designed to provide more than a 95% chance of arrest
within two pipe lengths by ensuring that 50% of pipes in an order meet the predicted arrest
requirement. Where the pipeline is comprised of an insufficient number of heats for there to
be a statistically valid normal distribution the value has to be increased. For a pipeline
comprising a single heat, the specified minimum toughness should be calculated arrest
toughness.
The choice of fracture arrest length should be appropriate for the pipeline design and in
particular the location class. The fracture control plan may define a different control
strategy e.g. the use of crack arrestors.
AGA Committee NG 18, Report No. 208 (Section A4, reference (c)) recommends a
statistical method to determine the toughness specification (all-heat, average and minimum
toughness, any heat) required to establish the arrest length from knowledge of the number
of heats and the toughness distribution in the heat population. This method may be used
when the number of heats is small, or when the proposed arrest length differs from the
requirements of this Standard.
Ductile tearing fractures are not known to have occurred in either the weld metal or heat-
affected zones of longitudinal weld seams. In addition, AS 2885.2 requires longitudinal
welds to be staggered. For these reasons, the energy absorption properties that are specified
by this Standard are limited to the pipe body (with the exception for fracture initiation as
noted in Paragraph L5.3.2).
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193 AS 2885.1—2007
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L3.3.4 Temperature
The local temperature of pipeline steel is dependent on the climate (for submerged pipeline
this is the temperature of the water), the location relative to the surface of the ground and
the contents of the pipeline, which may be modified by thermodynamic effects. Except
where stress is lower than the threshold stress for brittle fracture, a pipeline should be
pressure-tested and operated at a temperature above the fracture appearance transition
temperature.
L3.3.5 Limitations on testing
Meaningful tests for fracture appearance and energy absorption become more difficult as
the diameter decreases and the wall thickness reduces. This Standard requires that fracture
appearance testing be conducted using the drop weight tear test method set out in AS 1330.
AS 1330 states that the drop weight tear test is intended for the line pipe, or strip or plate
intended for line pipe, having an outside diameter of not less than 300 mm and that
difficulty may be experienced in applying the test to material of less than 5 mm thickness.
AS 1330 excludes testing of weld metal.
This Standard permits the testing of pipe materials for fracture properties to be carried out
on strip, plate or finished pipe. With modern pipe steels, the effect of pipe forming on
fracture properties is usually very small.
L3.4 Diameter limits
Pipes whose diameter and thickness do not permit testing by the DWTT method one of the
following solutions may be used:
(a) Select a thickness where the hoop stress at the design pressure is ≤30% of SMYS.
(b) Establish the FATT using the Charpy impact test. Provided this is 30°C lower than
the design minimum temperature, brittle fracture may be considered as controlled.
(c) For pipe ≤300 mm with lean gas and hoop stress ≤72% of SMYS, minimum Charpy
toughness complies with Clause 3.4.4.
Specific analysis is required for all other pipe and operating conditions. This may require a
range of specific tests in order to establish that the material will control both brittle and
ductile tearing fracture.
L3.5 Calculation of Charpy energy requirements for the arrest of ductile tearing
fracture
The Charpy energy requirements of the fracture control plan for the arrest of ductile tearing
fracture has to be determined by an appropriate method based upon the Battelle Two Curve
model taking into account the pipeline design, especially the MAOP, SMYS, diameter, the
conveyed fluid, the backfill conditions, and the required arrest length. Suitable methods for
most pipeline designs are given in the references listed in this Appendix.
L4 GUIDANCE ON TEST TEMPERATURE SPECIFICATION
The following provide guidance on means for compliance with the Standard when selecting
test temperatures:
(a) This Standard requires that brittle and fast tearing fractures be controlled at all
temperatures at which the pipeline can operate. Brittle fracture is not permitted under
any condition. Fast tearing fracture requires arrest within a nominated length.
(b) The primary consideration is control at combinations of temperature and pressure to
which the pipeline is exposed in normal operation (that is, combinations that can
occur as a result of the pipeline being operated at conditions permitted by its control
system, or normally by its trained operators).
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AS 2885.1—2007 194
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(c) Transient (short duration and abnormal) conditions that occur during depressurization
and repressurization of a gas pipeline have to be considered in establishing the limits.
(d) Some piping Standards recognize that steel pipe manufactured to one of the Standards
nominated in AS 2885.1 (this Standard) are suitable for operation down to a minimum
temperature of −29°C depending on stress without toughness testing (e.g. B31.3,
AS 4041). This results from an understanding that modern pipe has adequate
toughness to withstand those conditions.
(e) The drop weight tear test (DWTT) is used to demonstrate the presence of adequate
toughness for the thickness of interest at the minimum operating temperature so that
propagating brittle fracture can never occur at the lowest service temperature.
(f) DWTTs made at increasing temperatures from a low temperature are used to establish
the fracture propagation transition temperature (FPTT) (the temperature at which the
fracture appearance is 85% shear). This is the temperature below which a fracture,
once initiated, can propagate rapidly by a brittle fracture mechanism.
(g) The Charpy impact test is used to demonstrate the presence of adequate toughness to
arrest fast tearing fracture (within the limits of correlations).
(h) The Charpy impact test is also used to demonstrate that the steel will control the
initiation of a fracture from growth of an existing defect. The defect may be from
manufacture, construction, or from an in-service defect.
(i) For most transmission pipelines, the Charpy toughness required for arrest of fast
tearing fracture exceeds the toughness required to control fracture initiation.
(j) The upper shelf Charpy toughness is retained at an essentially constant or slowly
falling value as the temperature is reduced, until some value, below which it falls
rapidly with reducing temperature.
(k) Charpy tests made at reducing temperatures from a high temperature are used to
establish the fracture initiation transition temperature (FITT) (the temperature at
which the Charpy toughness starts to decrease from upper shelf value).
NOTE: An appropriate fudge has to be applied to the FITT established using sub-sized
Charpy impact specimens, to establish the FITT of the full material thickness.
(l) Research undertaken by the American Gas Association has shown that the FITT
occurred in steels that were investigated at approximately 33°C lower than the FPTT.
From a fundamental point of view, there is no reason why the shift should be constant
for all steels, but it could be expected that there will always be a shift. If required for
a particular design, this could be verified for the steel concerned by testing.
(m) To lower the temperature by 40°C (from a minimum operating temperature of 10°C,
typical of winter conditions in southern Australia to −30°C), the pressure typically
has to drop by 8 MPa. For a typical ANSI Class 600 pipeline, the hoop stress after
this pressure reduction will be close to or less than 85 MPa.
For a typical ANSI Class 900 pipeline, the hoop stress after a rapid pressure reduction
of 8 MPa from MAOP will still be about twice the threshold stress for brittle fracture.
NOTE: For most natural gases, the Joule-Thompson coefficient at 15 MPa is lower than at
10 MPa, and the pressure change to produce a 40°C change is a little more than 8 MPa.
Consequently, there is a potential for a Class 900 pipeline to experience a propagating
brittle fracture if initiation does occur at a defect site following rapid
depressurization. Note that this is a localized zone and the fracture will be arrested as
soon as it runs out of the cooled zone.
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This potential can be controlled as follows:
(i) Controlling the rate of depressurization/repressurization so that temperature
drop is lessened by heat gain from the soil and, if necessary, stopping the
depressurization/repressurization process to allow temperature recovery from
the surrounding soil. Resuming the operations after temperature recovery will
probably start from a new initial pressure, lower than MAOP. For
depressurization, a new 8 MPa pressure drop is likely to result in the
temperature after the second stage not being reduced below −30°C. Similar
logic applies to control during repressurization.
(ii) Providing adequate toughness to ensure that initiation at a defect will not grow
under the temperature and stress conditions at the limit conditions.
(iii) Ensuring that there are no other potential causes of initiation such as external
interference at the time that the controlled pressure reduction occurs.
When fracture initiation is shown to be controlled at the low temperature and,
provided there are no other sources of fracture initiation during these controlled
operations, there is no requirement to limit the pipe hoop stress to 85 MPa at times
that the temperature is less than design minimum temperature.
The designer/operator is responsible for developing the appropriate controls.
NOTE: An adequately sized depressurization system will maintain relatively high pressures in
the pipework in the vicinity of a pipeline vent. An oversized depressurization system can
cause a large reduction in pressure close to the vent and this will cause large temperature
drops. Where oversized depressurization systems are required, the depressurization rate
should be controlled, and the pressure and temperature in the associated pipes monitored and
appropriate material specifications imposed.
(n) Attention is drawn to the fact that relatively complex heat transfer conditions exist
during transient pressure events. For thin wall buried pipeline, heat flows from the
soil at ambient temperatures during depressurization and repressurization events. For
an above ground pipe, heat flows from the relatively thick pipe (or component) wall,
from the surrounding environment, and for discrete pressure drop devices like
repressurizing valves, from the ‘warm’ pipe and fluid upstream of the device to the
low temperature on the downstream of the device.
Furthermore, heat flows through a piping component (e.g. a valve, flange, or flange
bolt) are usually insufficient to maintain the metal temperature at the same
temperature as the fluid. Where required, more complex analysis, experimentation or
both, may be required to validate predictions made from computer models.
(o) This Standard intends the following:
(i) It is not essential for a fracture control plan to include materials testing to
establish the FPTT and the FITT; however, this does represent good practice
since it does provide considerable knowledge of the material properties.
(ii) Where required by the Standard and where the material thickness and diameter
permits, the DWTT has to be undertaken to demonstrate that the steel is ductile
at the design minimum temperature.
(iii) Where required by the Standard, Charpy impact testing is undertaken to
demonstrate that the material has sufficient toughness to arrest fast tearing
fracture. The test temperature nominated is the design minimum temperature.
(iv) It is recognized that when there is no defect or threat that can initiate fracture, it
will not occur.
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(v) Under controlled transient conditions, including depressurization and
repressurization, the temperatures and pressure conditions that will exist during
those operations should be determined and/or controlled. In these circumstances
the ability of the steel to resist fracture initiation and fracture propagation by
brittle fracture has to be established.
(vi) The limiting pressure and temperature conditions during these activities has to
be determined and documented, typically in a plan for depressurization and
repressurization (which may be a part of the isolation plan).
Limiting the temperature to −29°C (or −30°C) at times that the hoop stress
exceeds 85 MPa has historically represented safe operation, and is provided as a
limit, which, if applied, requires no special investigation. Codes are changing to
include the effect of stress and this may impact on the need to specify
toughness. ASME Standards, such as ASME B31.3, have changed from
specifying a minimum temperature of −29°C for non-impacted tested materials.
Below 55 MPa (8 ksi) primary stress there is no minimum temperature limit,
above 55 MPa the minimum temperature is calculated on a sliding scale, and
may be greater than −29°C.
(vii) For most pipelines it is expected that when the FPTT is less than the design
minimum temperature, and where the Charpy toughness is sufficient to control
fast tearing fracture, the pipeline will have sufficient toughness to control
fracture initiation under the pressure and temperature conditions that occur
during typical transient pressure events.
(viii) Some designs (pipelines with low design minimum temperatures e.g., those in
cold climates, and pipelines designed for very rapid depressurization or
repressurization) may produce very low temperatures at pressures where the
hoop stress exceeds the threshold stress.
For these pipelines, specific studies should be undertaken to establish the
conditions, and it may be necessary to verify that the steel supplied to the
project has the properties needed to control initiation and propagation at the
limiting conditions.
This may include additional materials testing to establish either the FITT of
FPTT, or both.
The results may be anticipated in the plan for depressurization and
repressurization, provided the measured results are compared with the
anticipated values, and if required, the plan for depressurization and
repressurization is modified accordingly.
L5 OTHER CONSIDERATIONS
L5.1 Smaller diameter—High pressure pipe
Small diameter pipes used in very high-pressure applications, such as hydrocarbon
production of hydrocarbon fluid re-injection, require fracture control specification using the
principles and minimum requirement of this Standard.
Even though the quantity of pipe required for these applications is small, ‘random’, off the
shelf purchasing of pipe should not be permitted. Appropriate pipe material specifications
(chemistry and manufacturing process, etc.) that reflect present day manufacturing
technology have to be applied in each case. Although there are no supporting full-scale tests
for these pipes, the fundamentals of the fracture behaviour are understood. Measuring the
fracture resistance will not necessarily be possible but control on chemistry and addressing
the stress-strain curve should be achievable.
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L5.2 Decompression behaviour and rich and multi-phase gases
This Appendix clearly outlines the influence of the pipeline fluid and its effect on acoustic
velocity and the rate of pipeline decompression and ultimately the requirement to achieve
fracture arrest. Although there is information on pure gases and pure liquids, much less is
available for multi-component mixtures. Recent research has started to quantify their
behaviour and their acoustic velocity. Typically the richer the gas the lower the acoustic
velocity and the higher the toughness required for arrest.
Theoretical work and recent experimental work has shown that at a single-phase/two-phase
boundary, the acoustic velocity is always slower in the two-phase region than in the
single-phase region. Hence, knowledge of the phase diagram of the pipeline fluid and how
it decompresses for any multi-component system is important. This is particularly true if the
fluid exhibits two-phase behaviour that shows a discontinuity in the gas decompression
behaviour.
Unfortunately a general model is not available and there is little published data on full-scale
behaviour that can be used to verify the model. There have been some recent full-scale tests
on richer gases, which have utilized decompression models to predict behaviour but they
are not in the public domain. An approach can be utilized to infer the added level of
toughness required based on velocities and decompression behaviour.
L6 REFERENCES
The following references provide detailed information on the development of knowledge on
materials performance and fracture control. Industry worldwide is continuing to conduct
research that adds to this knowledge.
1 Fracture Control in Gas Pipelines, Proceedings of the WTIA/APIA/CRC for
Materials Welding and Joining Int'l Seminar, Edited by A B Rothwell, WTIA, Sydney
1997.
2 Eiber R J & Bubenik T J, Fracture Control Methodology, Proceedings of the Eighth
Symposium on Line Pipe Research: American Gas Association, Houston 1993.
3 Eiber R J, Bubenik T J and Maxey W A, Fracture Control Technology for Natural
Gas Pipelines, American Gas Association NG18, Report No. 208, December 1993.
NOTE: The original document contained many errors including errors in the equations and
caution should be used when accessing this document, however at the date of publication of
this standard. PRCI has prepared a revision of this report 208 however it is only in the draft
for review.
4 Rothwell A B, Fracture Propagation Control for Gas Pipelines – Past, Present and
Future, Proceedings of the 3rd International Pipeline Technology, Brugge, Belgium,
May 2000, Elsevier Press.
5 Leis B N & Eiber R J, Fracture Propagation Control in Onshore Transmission
Pipelines, Invited Paper, Onshore Pipeline Technology Conference, Istanbul,
December 1998.
6 Botros et al, Gas Decompression and Wave Speed in Rich Gases – Canadian Journal
of Chemical Engineering, 2004.
7 Botros et al, Dense and Rich Gas Decompression – 2001 International Gas
Conference, Amsterdam 2001, and AGA OPS Conference Orlando 2003.
8 Maxey W A ‘Fracture initiation control concepts’ Proc 6th
Symposium on Line Pipe
Research, AGA, Houston 1979.
9 Piper J, Morrison R and Fletcher L ‘The integrity of ERW welds in high strength line
pipe’ WTIA/APIA Panel 7 Research Seminar ‘Welding high strength thin-walled
pipelines’ WTIA, Wollongong 1995’. Lice
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AS 2885.1—2007 198
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10 Piper J and Morrison R ‘The international database of full-scale fracture tests and its
applicability to current Australian pipeline designs’ WTIA/APIA International
Seminar ‘Fracture Control in Gas Pipelines’ Sydney, 1997’.
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APPENDIX M
CALCULATION OF RESISTANCE TO PENETRATION
(Informative)
M1 GENERAL
Understanding of the resistance of pipelines to penetration is developing through research
in various parts of the world. This Appendix contains information that is current at the time
of publication of this Standard but which is expected to be progressively superseded as
research provides improved accuracy. Penetration resistance calculations should be based
on the best information available at the time of analysis.
M2 CALCULATIONS
The ability of an excavator or other machine to penetrate a pipe is assessed by comparing
its force capacity with the force required for the tool to penetrate the pipe. In principle,
penetration should not occur if the following condition is met:
RP > F . . . M1
where
F = force applied to the pipe by the machine
However because of wide distribution of F through the range of possible attack
configurations, it is more appropriate to modify this equation by inclusion of a factor B:
RP > BF . . . M2
Equation M2, when used with appropriate values for RP, B and F, is the fundamental
equation for calculation of penetration resistance.
The force RP required to penetrate the pipe can be calculated with good accuracy for any
given pipe and tooth dimensions. The research shows excellent agreement between
laboratory experiments, finite element modelling and the following equation:
RP = ( )( )W U0.0007 410 22.4
3.14
Wt L
Wσ
+ + +
. . . M3
The maximum force delivered by an excavator has been reasonably correlated against the
excavator mass:
FBucket = 7.5WOP − 0.045(WOP)2 . . . M4
Usage of Equations M3 and M4, and factor B, are discussed in Paragraphs M3 to M6.
M3 TOOTH AND HOLE DIMENSIONS
Tooth dimensions for used in Equation M3 may be taken from Table M3.
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AS 2885.1—2007 200
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TABLE M3
EXCAVATOR TOOTH DIMENSIONS
Dimensions in mm
General purpose tooth Single point penetration tooth and twin
pointed ‘tiger’ teeth
Hole dia
Excavator
weight (t) Max. tooth
length (i.e.,
max hole
length) L
at
point
W
at
point
Hole
dia.
L
at
point
W
at
point Pen.
tooth
Single
point of
T tooth
Tiger
tooth
5 70 51 4 55 6 5 40 15 55
10 70 56 14 60 8 7 45 20 60
15 85 63 13 65 11 9 55 20 70
20 95 76 13 75 13 10 60 25 80
25 100 89 18 85 11 17 65 25 85
30 110 102 21 95 12 20 70 30 95
35 125 121 23 110 14 22 80 30 110
40 135 127 24 115 16 25 90 35 120
55 145 143 30 125 17 25 90 35 125
The tooth dimensions in Table M3 are based on an analysis of the range of teeth that are
used on excavators of each size group. Generally, they represent the dimensions of the
smaller teeth supplied for the size group.
Alternative dimensions may be used where they are determined in the threat investigation.
The teeth most commonly found on excavators are twin pointed ‘tiger’ teeth and chisel style
‘general purpose’ teeth. Single pointed penetration teeth are usually restricted to machines
used specifically in locations where hard ground conditions require that style of tool to
penetrate the soil.
Tiger teeth have twin points of equal dimensions. Table M3 assumes that the dimensions of
each point are the same as the dimensions of a penetration tooth fitted to the same machine
size. Because it is easy for such a tooth to be positioned so that only a single point contacts
the pipe the dimensions of a single point should be used for the calculation of penetration
force; however, once the second tooth contacts the pipe the resistance force increases. The
following considerations should be observed:
(a) If the excavator force is insufficient to drive the second tooth through the pipe, the
maximum hole size is limited to the tip diameter of a single tooth (and not the
equivalent diameter at half tooth penetration).
(b) Because puncture by one tooth will damage the steel, the force to tear the steel and
puncture the pipe with the second tooth is likely to be less than 2. This Appendix
recommends the use of a force multiplier of 1.75. Where both teeth penetrate the
pipe, the equivalent hole diameter in Table M3 should be used.
The hole diameter in Table M3 represents a circular hole whose circumference equals the
perimeter of a tooth calculated for penetration to 50% of the tooth length, and may be used
for calculation of release rates, as follows:
(i) The column ‘Pen tooth’ represents the hole from a penetration tooth.
(ii) The column ‘Single point of T tooth’ represents the hole from puncture by a single
tooth of a tiger tooth, where the machine does not have sufficient power to create a
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(c) The column ‘Tiger tooth’ represents the hole from penetration to 50% depth of a tiger
tooth
M4 TOOL FORCE
Equation M4 gives the nominal force capacity for average excavators under static
conditions and applies to the force exerted by the bucket alone.
The formula for excavator force is based on the best information available at the time of
preparation of this Standard. The basic form of the equation was obtained through research
undertaken for the Australian Pipeline Industry Association. It is consistent with similar
research by the European Pipeline Research Group.*
The research recommends that the correlated excavator force be increased by a multiplier of
around 1.8 to 2.0, to provide an upper bound to the maximum force that can be applied in
the most severe static or dynamic load condition.
The maximum force that an excavator can actually exert on the pipe is limited by the
following:
(a) The force balance around an excavator calculated from statics. (Experience shows
that an excavator is usually capable of lifting its tracks off the ground, that is the
maximum static force at any excavator arm extension is limited by instability of the
machine).
(b) The dynamic response of the pipe to impact from the bucket at the maximum angular
velocity in any geometric configuration.
(c) The multiplying effect from bucket rotation against the support from the ground (for
example, where the bucket contacts the underside of the pipe).
Experience from field puncture testing, and from European research using instrumented
excavators has shown that simply multiplying the correlated excavator force by 2, when
calculating the pipe thickness required to resist penetration, is excessively conservative for
the reasons given above.
The methodology proposed in this Appendix is to recommend values of a force multiplier B
for identified locations based on the consequence of failure.
Australian research has also examined the force capacity of dozer rippers. The work has not
been validated. The following equation may be used for rippers:
FRipper = 16WOP − 0.03(WOP)2 . . . M5
Experience has shown that while most excavator hits do not penetrate, many ripper hits do
penetrate. This is likely to be partly due to the fact that a dozer can more easily apply its
maximum force capacity, and partly due to the way that a ripper tyne is presented rigidly to
obstacles in its path. These factors should be considered in the application of Equation M5
and the safety management study.
M5 FACTOR B
Factor B in Equation M2 is a multipurpose parameter that combines into a single value the
bucket force multiplier, empirical experience and a safety factor.
* Brooker D, Pipeline Resistance to External Interference Phase III – Final Report; CRC for Welded
Structures/Australian Pipeline Industry Association Research Project 2003-339.
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Many factors contribute to selection of values for B, as exemplified by the following:
(a) Limited Australian field trials suggest that highly conservative results are produced
by use of the total excavator force based on a bucket force multiplier of 1.8 to 2.0, as
discussed in more detail in Paragraph M6. This suggests that B need not be large.
(b) Even when a pipe is struck by a machine that is theoretically capable of puncture,
puncture will not necessarily occur for a variety of reasons including the machine
variables mentioned previously as well as the geometry of the contact. This reinforces
the observation that a large value for B may be unnecessarily conservative.
(c) The process of tool contact and pipe damage is stochastic rather than deterministic,
but calculation methods based on a stochastic approach are not yet sufficiently
developed for presentation in this Standard so, for the time being, a determinist
method is necessary. This reinforces the observation that it may be reasonable to vary
B so that the likelihood of penetration is reduced in locations where the consequences
may be more severe.
NOTE: Brooker’s research report includes a methodology for assessing the frequency of
puncture based on a Monte Carlo analysis. While this analysis is not recommended as a
Design Basis, the methodology does provide useful information for assessing the likelihood
of puncture from the whole population of possible force combinations, when considering the
effectiveness of alternative combinations of wall thickness and pipe grade in providing
resistance to penetration.
(d) The consequences of penetration vary depending on the location of the pipeline (e.g.,
rural or suburban), and hence different circumstances may require varying degrees of
conservatism in the calculation. This suggests that B may vary between location
classes.
(e) It is unreasonable to require design for a malicious attack when, in practically all
circumstances, an excavator is operated by a trained machine operator whose purpose
is to excavate the ground, not deliberately continue to attack a resistant object without
investigating it.
Based on the Australian field trials and the above reasoning, the values in Table M5 are
recommended for the factor B to be used with the excavator bucket force FBucket in
Equation M2.
The factor B for dozer rippers should be evaluated and confirmed by the safety management
study.
In assessing the relative resistance to penetration of combinations of wall thickness and
steel grade it has been found useful to calculate the resistance to penetration for a range of
excavator sizes, a range of tooth types and a range of wall thickness and steel grade
combinations, and from this, calculating the factor B, and presenting the data in graphical or
tubular form.
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203 AS 2885.1—2007
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TABLE M5
RECOMMENDED VALUE OF FACTOR B FOR
EXCAVATORS
Circumstances B
In locations where penetration resistance is not a
governing factor in pipeline wall thickness selection <0.75
Where penetration resistance provides adequate resistance
to penetration against typical excavator threats, but where
puncture may occur under aggressive excavator operation
0.75
Where penetration resistance can be reasonably relied on
to satisfy the requirements of the safety management study
for ‘no puncture’
1.0
Where penetration must never occur, such as may
sometimes be necessary to meet the special requirements
for high consequence areas (e.g., where the release rate
from a hole would exceed the permitted value, or where
the size of a hole would exceed the critical defect length)
≥1.3
NOTE: A value of 1.3 for B appears to provide a reasonable level
of assurance that even dynamic loads will not result in penetration,
based on the field trials discussed below.
M6 AUSTRALIAN FIELD TRIALS
The Australian field trials that led to the above recommendations on factor B for
excavators, were as follows:
(a) 6.4 mm WT pipe of Grade X42 should, in theory, have been readily penetrated by a
20 t excavator fitted with tiger teeth since the bucket force is 130% of the penetration
resistance; however, penetration did not occur in several attempts at various contact
configurations. (Puncture did eventually occur in an unusual wedging configuration
where the pipe was contacted by a corner of the tool in an offset position while the
bucket was prevented from lateral deflection by a rock.) This suggests that for this
case even if the factor B is as low as 0.75 (approx. reciprocal of 130%) then
penetration is quite unlikely.
(b) 12.7 mm WT pipe of Grade X42 should in theory have had marginal penetration
resistance against a 36 t excavator fitted with penetration teeth since the basic
excavator force is 86% of the penetration resistance and, if a bucket force multiplier
of 1.8 or 2.0 was applied as suggested by the research, then the total excavator force
may have been substantially greater than the penetration resistance; however, no
penetration occurred under either static loading or aggressive dynamic conditions and
in the static tests the damage to the pipe was relatively superficial. This suggests that
for this case a value of B = 1.0 produces results that are conservative.
Although to date there have been only these two field trials, they span wall thickness which
cover most of the range expected to be selected for penetration resistance on Australian
pipelines. (Wall thickness less than 6.4 mm is commonly used, but not where it is required
to contribute to penetration resistance.) The field trials did not involve steel grades other
than X42, but this is the lowest grade in common use. As steel grade makes only a modest
contribution to penetration resistance it seems unlikely that the conclusions drawn here
would be less valid for higher grades. Penetration resistance is not affected by pipe
diameter or internal pressure (as can be seen from Equation M3) so the conclusions should
be valid for all diameters and design pressures.
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AS 2885.1—2007 204
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APPENDIX N
FATIGUE
(Informative)
N1 GENERAL
Fatigue is generally not considered in most pipeline designs, principally because the
number of stress cycles that occur in the pipeline life are typically fewer than required to
initiate a fatigue-related failure in the pipe shell.
Special consideration should be given where—
(a) there are welded or threaded connections of any kind onto the pipe because as-welded
or threaded connection joints have no fatigue crack initiation life;
(b) the pipeline experiences significant pressure-cycling range and/or frequency; and
(c) welded connections onto the pipe are subject to cyclic structural or inertial loads
An engineering assessment undertaken to revalidate the pipeline for changed operating
conditions, including an extension of the design life, should include an assessment of the
fatigue life of a pipeline.
Fatigue may be an issue in station piping design. The nominated piping standards, AS 4041
and ASME B31.3 each contain methods for considering, and designing for fatigue.
Compliance with these Standards will ensure that that the matter is properly addressed.
The guidance in this Appendix reproduced with permission of the British Institution of Gas
Engineers (IGE) from their document IGE/TD1 – Steel Pipelines for High Pressure Gas
Transmission – Edition 4. It may be used as reference information in assessing conditions
where fatigue may require more detailed assessment. Changes have been made to the
numbering and cross-referencing used in TD1 to ensure its consistency with AS 2885, and
to reflect the hydrostatic test requirements of AS 2885.
NOTE: The TD1 guidance information applies to plain pipe shells and not to welded connections.
Welded connections should be assessed in accordance with AS 1210 or other approved Standard.
N2 MATERIALS
Provided linepipe steels are purchased in accordance with the specifications referenced
Section 3 of this Standard, the design complies with Section 5 of this Standard and the
pipeline is tested in accordance with Section 11 of this Standard, all prerequisite fatigue
design requirements should be satisfied.
N3 DESIGN
N3.1 General
Consideration should be given to the fatigue life of any pipeline, to ensure that any defect
which survives the hydrostatic test, or which is not detected by subsequent internal
inspection, does not grow to a critical size under the influence of pressure-cycling.
Special consideration should be given to the adequacy of fittings.
NOTE: Generally, fittings are designed to a standard which will ensure that they experience lower
stress ranges than linepipe when a pipeline is pressure-cycled. Where such circumstances prevail,
fittings need not be subjected to a fatigue evaluation.
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Consideration should be given to other sources of cyclic stressing, for example thermal
loading immediately downstream of a compressor station, which may affect the fatigue life
of the pipeline. Specialist advice should be obtained if these are likely to be significant, as
the guidance in Paragraph N3.2 is appropriate only for pressure-cycling.
N3.2 Definition of fatigue life
Fatigue life should be defined by the simplified approach described in Paragraph N3.2.1
provided the pipeline has been hydrostatically tested to the requirements of this Standard
and is constructed from linepipe purchased to Section 3 of this Standard. Alternatively, a
detailed fracture mechanics calculation, as described in Paragraph N3.2.2 may be used if
the pipeline will experience maximum stress ranges in excess of 165 MPa.
The required fatigue life of the pipeline should be defined in terms of allowable pressure
(stress) ranges and associated numbers of cycles. For the purposes of these
recommendations, a 40-year life has been assumed but other lives may be appropriate in
which case they should be documented.
NOTE: Where the maximum daily hoop stress range is less than 35 MPa, a fatigue assessment is
not required.
N3.2.1 Simplified approach
(a) Constant daily pressure-cycling Where the magnitude of daily pressure-cycling is
constant, the fatigue life should be determined from the following equation:
S3N = 2.93 × 10
10 . . . N3.2.1(1)
S = constant amplitude stress range (MPa)
N = number of cycles
Where S exceeds 165 MPa, specialist advice should be obtained or the method given
in Paragraph N3.2.2 used.
NOTES:
1 For example, if a life of 15 000 stress cycles is required (equivalent to one cycle per day
over 40 years), the equation limits the maximum daily variation in hoop stress to
125 MPa.
2 The relationship between stress range and the number of cycles is shown in
Figure N3.2.1.
(b) Variable pressure-cycling Where the magnitude of daily pressure-cycling is not
constant, the fatigue life may be evaluated on the basis of Item (a) above, by totalling
the usage of fatigue life from each stress range.
The following condition for the damage fraction should be satisfied to obtain an acceptable
fatigue life:
DF = i
i
n
N∑ . . . N3.2.1(2)
where
ni = actual number of cycles accumulated at stress range Si
DF = damage fraction
Si = stress range
Ni = number of stress cycles allowed at stress range Si (Paragraph N3.2.1(a))
If the anticipated value of DF exceeds 0.5, the actual cycles accumulated during operation
should be recorded in accordance with Paragraph N3.3.
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AS 2885.1—2007 206
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30
40
50
60
70
80
165
200
90100
1 000 2 4 5 6 73
10 000
2 4 5 6 73
1 000 000
35
CYCLES
ST
RE
SS
RA
NG
E,
MP
a
FIGURE N3.2.1 RELATIONSHIP BETWEEN STRESS RANGE AND NUMBER OF
CYCLES
N3.2.2 Detailed fracture mechanics approach
Where the maximum daily stress range exceeds 165 MPa, and/or the simplified method in
Paragraph N3.2.1 is not appropriate or where it is required to assess the fatigue life of
defects detected in service, a detailed fracture mechanics calculation may be used to
determine the fatigue life.
NOTE: Recommended methods for such calculation are given in BS 7910.
Account should be taken of the deleterious effects of pipe ovality and local shape
deviations.
The analysis method, material properties and other input data used in the assessment should
be documented and fully justified.
The actual cycles accumulated during operation should be recorded in accordance with
Paragraph N3.3.
N3.3 Definition of stress cycles
Any complex (variable amplitude) stress cycles should be recorded and then converted to an
equivalent spectrum of constant amplitude stress cycles using a documented algorithm such
as the reservoir or rainflow method. The appropriate method from Paragraph N3.2 should
then be used to define the fatigue life.
NOTE: Further details of these algorithms may be found in ASTM E1049.
N3.4 Revalidation
When records or estimates show that the design fatigue life has been reached, the pipeline
should be revalidated by hydrostatic testing, or by internal inspection using a tool capable
of the detection of longitudinal crack-like defects, particularly in or near the seam weld. If
inspection is used, the detection limits of the inspection tool for crack-like defects should
be taken into account when establishing the future fatigue life of the revalidated pipeline.
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207 AS 2885.1—2007
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APPENDIX O
FACTORS AFFECTING CORROSION
(Informative)
O1 GENERAL
The internal and external surfaces of a steel pipeline are potentially subject to corrosion.
Whether corrosion will occur to any significant extent depends on many environmental and
operational factors. The total effect of these factors on the likely rate of corrosion usually
cannot be assessed until the pipeline has been installed. Even then, a complete assessment
may not be possible because the corrosive effects of many of the factors may vary daily or
seasonally, and some of the factors may have a synergistic effect when taken in
combination. The principal factors that should be considered when assessing the rate of
corrosion are given in Paragraphs O2 to O4.
O2 INTERNAL CORROSION
Factors to be considered for internal corrosion are as follows:
(a) Features of fluid transported, to include—
(i) chemical composition;
(ii) hydrogen sulfide, carbon dioxide and other acidic components;
(iii) oxygen content;
(iv) water content/water dewpoint; and
(v) microbiological organisms.
(b) Operation, to include—
(i) frequency and magnitude of fluctuations of pressure and temperature;
(ii) maximum, minimum and average pressures and temperatures; and
(iii) flow rate and regimes.
O3 EXTERNAL CORROSION
Factors to be considered for external corrosion are as follows:
(a) Environmental factors, to include—
(i) chemical composition of dissolved salts;
(ii) degree of aeration;
(iii) moisture content;
(iv) presence of sulphate reducing bacteria, and their state of activity;
(v) the pH value; and
(vi) resistivity.
(b) Abnormal environmental factors, to include—
(i) ash, cinders or other corrosion-inducing material in the right of way;
(ii) mineral ores in the pipeline route that are cathodic to steel;
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(iii) the presence of large quantities of organic material, including marine growth;
and
(iv) termites, rodents and other pests that may attack coatings and other pipeline
materials.
(c) Electrical currents, to include—
(i) occurrence of d.c. currents from traction systems and other man-made sources;
(ii) occurrences of telluric currents from solar and other celestial sources;
(iii) induced a.c. currents;
(iv) a.c. voltage gradients as may exist near power stations; and
(v) lightning strikes.
(d) Climate and tides, to include—
(i) atmospheric pollution;
(ii) frequency of wetting and drying of the surface of the pipe;
(iii) fluctuations in watertable level,
(iv) humidity; and
(v) presence of mist and spray.
(e) Operation, to include—
(i) maximum, minimum and average surface temperatures of the pipe;
(ii) frequency and magnitude of fluctuations of temperature; and
(iii) stress level of the pipeline, and magnitude and frequency of stress variations.
(f) Other factors, to include—
(i) incompatibility of materials (e.g. those in earthing systems and concrete
reinforcement);
(ii) dissimilar metals in contact;
(iii) deterioration of protective coatings;
(iv) resistance to ageing of the corrosion protection system in air, water and
sunlight; and
(v) abrasion and erosion.
O4 ENVIRONMENTALLY ASSISTED CRACKING
Steel pipelines can experience environmentally assisted cracking by the following different
mechanisms:
(a) Hydrogen-induced cracking (HIC).
(b) Sulfide stress corrosion cracking (SSCC).
(c) Stress corrosion cracking (SCC) (high and low pH types).
(d) Hydrogen-assisted cold cracking (HACC).
NOTE: Further information on environmental related cracking is given in Appendix P.
O5 CORROSION PRIOR TO COMMISSIONING
Pipe may be subject to corrosion in the period between manufacture and the commissioning
of the pipeline. Measures should be taken to protect against this corrosion.
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209 AS 2885.1—2007
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Pipe that is properly stored or installed in a dry environment usually does not suffer
significant corrosion.
Factors that can cause corrosion include:
(a) Stockpile sites located in a corrosive atmospheric environment (including marine and
coastal environments).
(b) Exposure to salt water during marine transport.
(c) Poor stockpile management, which allows moisture-retaining material (such as dust
and grass) to accumulate between and inside the pipe.
(d) Storage in stockpile for an extended period.
(e) Pipes stored in direct contact with sand or soil.
(f) Water accumulation in pipe while in stockpile.
(g) Exposure to floodwater while in stockpile.
(h) Poor construction practice that allows water to enter the installed pipe during the
construction period.
(i) Floodwater entering the installed pipe.
(j) Improperly managed hydrostatic test water.
(k) The presence of sulphate-reducing or acid-producing bacteria in water used for
hydrostatic test.
(l) Incomplete drying of the pipeline after hydrostatic testing.
(m) A prolonged period between hydrostatic testing and pipeline commissioning,
particularly if the pipe is not filled with an inert atmosphere, or is allowed to
‘breathe’ during the period.
(n) Failure to install an adequate temporary cathodic protection system on pipe that is
installed in the ground.
Pipe that is damaged by corrosion prior to commissioning must be assessed for its structural
integrity in accordance with AS 2885.3 prior to being approved for service at its design
conditions.
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AS 2885.1—2007 210
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APPENDIX P
ENVIRONMENT-RELATED CRACKING
(Informative)
P1 GENERAL
This Appendix provides guidelines on the assessment of environmentally assisted cracking,
as required in Clause 8.3.4.
Environmentally assisted cracking occurs as a result of the exposure of stressed steel to a
specific environment. There are five main types of environmentally assisted cracking that
can affect steels commonly used in pipelines, as follows:
(a) Stress corrosion cracking (SCC) in high pH carbonate/bicarbonate solutions that can
be generated by the action of cathodic protection in the environment around the pipe
and affect the external surface of the pipe at regions of coating defects.
(b) SCC which occurs in low pH (<7.5) anaerobic environments containing dilute carbon
dioxide solutions. Carbonic acid and bicarbonate ions are usually present in proximity
to the steel surface.
(c) Hydrogen-induced cracking (HIC) due to hydrogen sulfide in the fluids within the
pipeline.
(d) Sulfide stress corrosion cracking (SSCC); a different form of stress corrosion
cracking, which is primarily related to the hardness of the steel.
(e) Hydrogen-assisted cold cracking (HACC) due to generation of hydrogen caused by
high cathodic protection current density in conjunction with a susceptible steel.
P2 HIGH pH (CLASSICAL) STRESS CORROSION CRACKING
P2.1 Description
High pH stress corrosion cracking is a form of cracking caused by dissolution of grain
boundaries in stressed metals that are in contact with aqueous solutions. Stress corrosion
cracking is most frequently observed in the form of intergranular cracking and generally
occurs as a group or ‘nest’ of small cracks parallel with the axis of the pipe. It has been
found most commonly on pipes coated with field-applied coal tar enamel, tape or asphalt, or
in similar factory-applied coatings where the surface preparation did not involve grit
blasting. It is generally accepted that abrasive blast cleaning together with application of
high quality coating materials is a significant factor in reducing the likelihood of SCC
initiation.
P2.2 Conditions
Pipeline steels can develop high pH stress corrosion cracking if the following conditions are
present:
(a) The stress level is in excess of a value of stress called the threshold stress. The
threshold stress is determined in laboratory tests conducted under conditions that
greatly accelerate the initiation and propagation of cracking. The value of the
threshold stress determined in that way should not be used to determine a safe value
of pressure stress in an operating pipeline. Cyclic variations of stress in pipe steel
have the effect of reducing the threshold stress (see Note 1).
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(b) The surface of the pipe is in contact with an alkaline aqueous solution of carbonate,
bicarbonate, nitrate or hydroxide and having a pH in the approximate range of 8 to
12.
(c) The pipe-to-soil potential is within the range of −550 mV to −750 mV, measured
against a calomel electrode or −625 mV to −825 mV measured against a
copper/copper sulphate electrode.
NOTES:
1 SCC will not occur below some value of operating stress (not numerically the same as the
‘threshold stress’ as defined above) unique to the particular conditions in a given pipeline;
however, when the mean operating stress and any superimposed cyclic stresses are such as to
allow the initiation and propagation of SCC, then any further increase in stress will accelerate
the rate of cracking. The corollary of this is that reductions in operating stress will have the
effect of reducing the rate of cracking.
2 The potentials stated are those measured at the steel-to-electrolyte interface at coating defects
or within crevices beneath disbonded coating, not those taken at the soil surface as with
conventional pipe-to-soil potential measurements. Application of cathodic protection will
usually shift the conventional pipe-to-soil potential to more negative than −850 mV with
respect to copper/copper sulphate, but the interface potential may still lie within the cracking
range.
3 The range of potential over which cracking can initiate is temperature dependent. Increasing
the operating temperature leads to a more rapid crack growth and widens the range of critical
pipe-to-soil potential for the initiation of cracking.
Under normal conditions SCC usually takes some years to initiate. In some cases the rate of
growth may accelerate and lead to failure of the pipeline. In other cases the cracks may
slow down and even stop. The growth rate through the wall usually slows considerably with
an increase in depth. Adjacent cracks may join others to form a single defect having a
critical length, which may leak or (more frequently) result in a burst.
P3 LOW pH (NEAR NEUTRAL) STRESS CORROSION CRACKING
P3.1 Description
Low pH SCC is a form of mainly transgranular cracking occurring in a near neutral
(pH 5– 7.5) environment of dilute bicarbonate/carbonic acid solution and is characterized
by very high densities of cracks in localized regions.
Low pH SCC was first recognized in 1985 in Canada but has since been found on pipelines
in the USA, Italy and parts of Russia. It has been associated predominantly with the use of
tape coatings, only occasionally on asphalt coated pipes. Extensive investigations into this
form of cracking have been carried out on pipelines in Canada.
P3.2 Conditions
Pipeline steels can develop low pH stress corrosion cracking if the following conditions are
present:
(a) The stress level is above 40% SMYS, although crack growth rates appear to be
independent of applied stress. Fluctuating stresses are important in the growth of SCC
cracks.
(b) The surface of the pipe is in contact with low conductivity near neutral pH trapped
water containing carbonic acid, bicarbonate and several other species.
(c) The cathodic protection potential is below the fully protected level.
The severity of SCC appears to be increased by the presence of bacteria including sulphate
reducers and the absence of oxygen.
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The occurrence of low pH SCC usually involves disbondment of the anti-corrosion coating.
In some circumstances the cathodic protection current penetrates only a short distance
under a disbonded coating. For tape coatings, soils such as heavy clay type soils, which
enhance disbondment, are associated with SCC sites. Susceptible locations are generally
anaerobic and have poor soil drainage.
It has been suggested that the mechanism of low pH SCC is a hydrogen-related process with
the source of hydrogen believed to be dissolved carbon dioxide.
P4 HYDROGEN SULFIDE CRACKING
P4.1 General
Hydrogen sulfide in the presence of free water can cause cracking and failure of pipeline
steels in two unrelated ways, known as hydrogen-induced cracking (HIC) and sulfide stress
cracking (SSCC). In both cases, the hydrogen generated by the corrosion reaction between
the pipeline steel and the hydrogen sulfide enters the steel matrix and causes cracking. Only
low levels of hydrogen sulfide are necessary for attack to occur; however, free water must
also be present. In the absence of water, the corrosion reaction, which releases hydrogen,
cannot occur and no cracking results.
P4.2 Hydrogen-induced cracking (HIC)
HIC is also called stepwise cracking or blistering, and is caused by a migration of hydrogen
ions formed in the hydrogen sulfide corrosion reaction into suitable sites within the steel
microstructure. The hydrogen ions combine to form hydrogen molecules, which are then too
large to diffuse out of the steel. The resulting hydrogen pressure build-up at sites within the
steel lattice exceeds the material yield strength and causes blisters and cracks to develop.
Inclusion stringers in ‘dirty’ steels provide sites for the hydrogen to gather and recombine.
‘Clean’ steels contain no such sites and are immune to HIC attack.
The catalytic action of the sulfide ion causes a several-fold increase in the amount of
hydrogen diffusing into the steel and, without the presence of iron sulfide on the steel
surface, HIC is unlikely to occur.
The best approach to preventing HIC in new structures is to use ‘clean’ steels or steels with
modified inclusion shape that do not have suitable sites in their microstructure for hydrogen
to accumulate and cause cracking. NACE TM0284 describes procedures for evaluating the
resistance of pipeline steels to stepwise cracking. Steels passing this test are referred to as
HIC-resistant steels.
P4.3 Sulfide stress corrosion cracking (SSCC)
SSCC results from the embrittling effect of hydrogen penetration and is typically observed
in regions of reduced ductility in high-strength steels or hardened zones in the lower
strength steels used for pipelines. These hardened zones may be the heat-affected zone of
welds, or hard spots due to problems in the rolling of the steel.
The susceptibility of steels to SSCC is indicated by a hardness of more than 22 HRC
(Hardness Rockwell C). By limiting the hardness of the pipeline steel to this value, failure
by SSCC can be completely avoided.
Further information on preventing SSCC is contained in NACE Standard Materials
Requirements MR0175.
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P5 HYDROGEN-ASSISTED COLD CRACKING (HACC)
Levels of cathodic protection applied to pipelines in accord with AS 2832.1 are generally
insufficient to result in significant evolution of hydrogen; nevertheless hydrogen may be
evolved from small, narrow coating defects in lower resistivity soils in some situations. If
the pipeline contains regions in which the microstructure is susceptible to HACC due to the
presence of hard spots or mechanical damage the evolution of hydrogen from the cathodic
protection system may become a problem and could cause failure.
With modern pipeline steel manufacture, hard spots would not be expected to be present,
and are only likely to arise from causes subsequent to pipe manufacture.
Mechanical damage may be caused by inadvertent and unobserved contact of equipment
working in the vicinity of the pipeline. It is therefore important to avoid excessive levels of
cathodic protection and to avoid or repair instances of mechanical damage as far as
practicable.
NOTE: On pipelines subject to stray current fluctuations or telluric effects it may not be possible
to avoid intermittent periods of highly negative potentials and the hydrogen evolution that may
result.
P6 DESIGN CONSIDERATIONS TO MITIGATE STRESS-CORROSION
CRACKING
P6.1 General
Stress-corrosion cracking has to be carefully considered during the design of a pipeline,
particularly where the pipeline will be subjected to cyclic stresses and to high temperatures
(e.g. downstream of a compressor station in a gas pipeline).
Stress corrosion cracking requires the presence of a cracking environment, a stress, and a
susceptible steel. If one of these parameters is absent SCC cannot occur. All pipeline steels
have been found to be susceptible to SCC to some extent. Mitigating the risk of SCC by
selection of steels based upon threshold stress tests is not recommended. Because at least
two of the remaining conditions need to be simultaneously present for external
stress-corrosion cracking to occur, the pipeline design should eliminate or at least minimize
the effect of some or all of these conditions.
Research studies in recent years have produced methods for estimating SCC susceptibility
based on analysis of the various contributing factors. The effects of the various contributing
factors are weighted, allowing the pipeline designer to trade off one factor against another
in the design process to produce a given susceptibility outcome. The chief factors to be
included in the analysis are as follows:
(a) Surface preparation prior to coating.
(b) Hoop stress.
(c) Stress fluctuations.
(d) Pipeline operating and maximum temperatures.
(e) Type of coating.
(f) Age of pipeline.
(g) Type of soil.
(h) Soil resistivity.
(i) Soil moisture.
(j) Level of cathodic protection.
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AS 2885.1—2007 214
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(l) Pipeline contents/fluid composition
When designing a pipeline to meet a given requirement in terms of SCC risk, it is essential
that both the current and future operating regimes of the pipeline be taken into account. The
design parameters should be clearly documented and SCC risk re-evaluated if any of the
operational conditions move outside of these constraints.
P6.2 Stress
The threshold stress levels determined in accelerated laboratory tests are not applicable to
the pressure stress of the operating pipeline. Such threshold stresses can only be used for
comparing different steels. Since no systematic investigation has ever been conducted
within laboratory and between laboratory reproducibility of the test method, no conclusion
can be drawn upon the slight differences that are observed on different steels. The values
that are measured are typically measured in the range 75% to 85% of the actual yield stress,
as measured in the longitudinal direction.
On this basis, whilst reductions in growth rate, and a lengthening in service life can be
expected to result from reductions in mean operating pressure stress and cyclic stress range,
it is not possible to use material selection as a means of mitigating SCC.
P6.3 Cyclic variation of stress
The frequency and the range of cyclic stresses strongly influence the growth rate and
initiation life of both high and low pH SCC.
Cyclic variations of pressure are often inevitable in gas pipelines that serve mixed
industrial, commercial and domestic markets, or where line pack is used to assist in meeting
daily gas demand fluctuations. The effect of these variations has to be taken into account
when evaluating the overall SCC susceptibility of a given section of pipeline.
P6.4 Pipeline anti-corrosion coating
Since it has been shown that the pipe-to-soil potential is likely to remain within the critical
range for SCC under disbonded coating, a well applied, good quality anti-corrosion coating
will reduce the risk of stress-corrosion cracking.
The bond between the anti-corrosion coating and the pipe must resist mechanical and
cathodic disbonding, particularly in the regions adjacent to holidays. Coatings that are
prone to cathodic disbonding and include a highly insulating layer, such as polyethylene,
should not be used when other SCC risk factors are high.
P6.5 Age of pipeline
Stress corrosion cracking of a pipeline is a phenomenon that follows phases of initiation
and growth prior to reaching a state where pipeline failure can occur. The initiation phase
generally occurs over several years, followed by growth of cracks in length and depth.
Cracks then continue to initiate and grow over time, generally in ‘nests’ where conditions
are favourable. Failure usually occurs when cracks grow sufficiently to link together to
extend beyond a critical length, resulting in pipe rupture. Other factors being equal, older
pipelines are at greater risk of failure due to SCC. Most SCC failures have occurred on
pipelines that have been in service for 20 years or more, although failures have been known
to occur in as little as 6 years after commissioning.
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P6.6 Soil environment
The soil surrounding a pipeline can play a part in many ways in establishing conditions that
are conducive or otherwise to development of SCC. For example, expansive soils such as
some clays can damage coatings susceptible to soil stress, resulting in exposure of the pipe
surface or causing loss of coating adhesion. In some situations, high resistivity soils may
reduce the flow of protective current, allowing the potential to fall to within the cracking
range. In other situations, low resistivity soils may result in high current density at coating
defects, causing accelerated disbonding of susceptible coatings. Soils that are in locations
where wet/dry cycling can occur may provide a damp environment in crevices beneath
disbonded coating but may block protective current at times when the surrounding soil is
dry. The likely impact of the soil environment has to be considered on a case-by-case basis.
P6.7 Surface preparation
The presence of corrosion pits on the pipe surface accelerates the onset of SCC. Because an
oxidized surface has a greater propensity for stress-corrosion cracking than a clean grit-
blasted surface, close attention should be paid to surface preparation prior to applying anti-
corrosion coatings. Furthermore, grit-blasted surfaces that are free from contamination
(such as chlorides) produce better coating adhesion and lower susceptibility to cathodic
disbonding. Contamination and especially residual oxide films adversely affect the native
potential of the steel surface. Blast-cleaned surfaces that have not developed oxide films
exhibit free corrosion potentials generally more negative than the SCC range. Application
of cathodic protection would move the potential further away from that range.
P6.8 Cathodic protection system
Cathodic protection systems are essential for protection against general corrosion; however,
where too negative a potential is applied to a pipeline, it is possible for hydrogen to be
evolved on the surface of steel. The presence of hydrogen has the effect of limiting the flow
of current to steel under a disbonded coating and allowing the potential on the surface to
remain at or near the cracking potential. Where stress-corrosion cracking may occur,
pipe-to-soil potential should be maintained at a voltage of not more negative than −1.2 V
(instant off copper/ copper sulphate half-cell potential) as far as practicable. On pipelines
subject to stray current fluctuations or telluric effects it may not be possible to avoid
intermittent periods of more negative potentials.
NOTE: The instant off potential measured on a pipeline represents an (approximate) average
value of the instant off potential of all exposed steel at coating defects on the pipeline in the
broad region of where the measurement is taken. Some defects will be more negative than this
value, whilst others will be less negative. In pipeline sections at higher risk of SCC it may be
prudent to limit the nominal off potential to less negative values.
P6.9 Pipe wall temperature
For high pH SCC, the initiation life and the rate at which cracking progresses is
temperature-dependent. Thus, reduced operating temperature will slow the onset of
cracking and the rate of crack growth. Where pipeline temperatures are high, such as
downstream of compressor stations, the increased likelihood of SCC can be compensated by
measures such as using thicker wall pipe to reduce stress levels.
For low pH SCC there is a lack of correlation between temperature and cracking. One
possible explanation put forward is that the solubility of carbon dioxide in solution
increases with decreasing temperature thus acidifying the solution and concentrating the
carbonic acid species in the solution, which increases the probability of SCC occurring. The
effect of lower chemical activity associated with low temperatures may be offset by the
increased corrosivity of the solution.
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P7 REFERENCES
The documents listed below contain material relevant to this Appendix.
1 Protocol to Prioritize Sites for High pH Stress-Corrosion Cracking in Gas
Pipelines Pipeline Research Council International, Project No. PR-3-9403, published
September 1998.
2 Conditions that Lead to the Generation of SCC Environments - A Review Pipeline
Research Council International, Project No. PR-230-9914, published January 2000.
3 Assessment of the Effects of Surface Preparations and Coatings on the Susceptibility
of Line Pipe to Stress Corrosion Cracking. Pipeline Research Council International,
Project No. PR-186-917, published February 1992.
4 Cathodic Protection Conditions Conducive to SCC. Pipeline Research Council
International, Project No. PR-186-9807, published October 2002.
5 Stress Corrosion Cracking – Recommended Practices – Canadian Energy Pipeline
Association. Published May 1997
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APPENDIX Q
INFORMATION FOR CATHODIC PROTECTION
(Informative)
The design of a cathodic protection system for a pipeline requires details about the pipeline
and its route to be gathered, documented and considered. Full details required are listed in
AS 2832.1; however, as a minimum, the following should be determined:
(a) Structure details The diameter, length, and wall thickness of the pipeline is required
for design calculations. The life requirement of the pipeline should also be clearly
established as this has very substantial impact on many aspects of the design.
(b) Coating details The type and quality of coating used, including the coating used for
field joints and repairs, has a significant bearing on the effectiveness of cathodic
protection and on the amount of current that needs to be provided to protect the
pipeline. In addition, the impact of handling on the coating and the nature of the
pipeline backfill (i.e. the material immediately in contact with the pipeline) need to be
understood, so that an assessment of coating integrity can be made. The coating
selection process should take into consideration the design life of the pipeline,
requirements for factors such as stress corrosion cracking, the operating environment
of the coating and the cathodic protection design.
(c) Structure isolation points For cathodic protection to be successfully applied, the
pipeline to be protected has to be electrically continuous and should be electrically
isolated from other structures. Certain pipeline fittings and joint couplings are
naturally isolating, and these may need to be electrically bonded to allow the cathodic
protection to extend to the whole structure. Additionally, isolating joints or insulating
flanges may need to be installed, to limit the cathodic protection to the pipeline and
prevent its effect being dissipated to other underground structures.
(d) Road, rail and river crossings Details of crossings need to be considered, to ensure
that effective cathodic protection is provided at such locations. Steel casings may
shield the carrier pipeline from the cathodic protection if the casing comes into
metallic contact with the carrier, and measures to electrically insulate the casing from
the carrier pipe have to be implemented. Bridged crossings may need to be
electrically insulated from the support structure, to prevent excessive current drain to
the support structure. In all cases, provision for test connections needs to be made in
the design.
(e) Pipeline route Features along the pipeline route that may impact on the cathodic
protection system need to be identified, and provision incorporated in the design.
Typical features include the following:
(i) Soil types and soil resistivity along the pipeline route.
(ii) The presence of abnormal backfill material, such as cinders, ashes or highly
acidic soils.
(iii) Presence of a.c. or d.c. transmission systems within close proximity to the
pipeline.
(iv) Proximity of d.c. transportation systems.
(v) Proximity of other cathodic protection systems.
(vi) River crossings.
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AS 2885.1—2007 218
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(f) Water levels Any fluctuation of water levels both diurnally and seasonally should be
noted and possible effects on cathodic protection determined.
(g) Pipeline operating conditions Elevated temperatures result in increased rates of
corrosion and may alter the nature of the backfill.
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219 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX R
MITIGATION OF A.C. EFFECTS FROM HIGH VOLTAGE ELECTRICAL POWERLINES
(Informative)
R1 GENERAL
R1.1 a.c. effects
Modern pipelines are usually coated with high quality anti-corrosion coatings that have
highly effective electrically insulating properties. Pipelines are often laid in roadway
easements that also carry high voltage electricity distribution lines, and in recent times
there has been an increasing trend to run pipelines and powerlines together in energy
transmission corridors. The overall result is that pipelines are now much more prone to
being subject to electrical effects as a result of the powerlines. Significant voltages can be
induced under normal steady-state powerline operating conditions and more substantial
effects can occur under fault conditions when surges of very high currents can flow.
Electrical fault conditions are not uncommon and can occur at frequencies ranging from
less than once per year up to several times per year, depending on factors such as location
and type of powerline construction. They can cause electric shock to personnel working on
pipelines adjacent to the powerlines, and can present a number of possible hazards to the
pipelines, such as—
(a) damage to electrical insulation in devices such as monolithic isolation joints, isolating
flanges, isolating couplings and isolating unions;
(b) damage or puncture of protective coatings;
(c) damage to electrical and electronic equipment; and
(d) electrical arcing, which can fuse the pipeline steel, or can act as a source of ignition
for escaping product.
R1.2 Mitigative measures
Mitigative measures employed to control or minimize the effects of powerlines include the
following:
(a) Surge diversion devices such as varistors, spark gaps and polarization cells coupled
with—
(i) electrical earthing in the form of discrete electrodes, earthing beds or lengths of
earthing cable or ribbon; or
(ii) earth safety mats or grids to limit step and touch potentials adjacent to
accessible points on the structure.
(b) Measures that restrict access to direct contact with the structure or its appurtenances.
The protective measures employed need to be appropriate to the specific circumstances and
to the level of exposure.
Although most electrical hazards arise under powerline fault conditions, effects that can
cause risk to integrity of structures or safety of personnel can also arise during normal
powerline operation. Further information on requirements for electrical safety on pipelines
subject to power system influences can be found in AS/NZS 4853.
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AS 2885.1—2007 220
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R2 NATURE OF ELECTRICAL HAZARDS
R2.1 General
The presence of alternating current on metallic structures can result in a number of types of
potential hazards.
R2.2 Physical damage to the structure or its coating.
High energy electric arcing can result in metal loss, and possible fusion of the steel, to the
extent that escape of product occurs.
High voltage can cause dielectric breakdown of the coating, resulting in formation of
through-penetration defects in the coating.
High voltage surges can also cause damage to electrical equipment and electronic control
systems that are connected to the structure.
R2.3 Risk to personnel who may be in contact with or close proximity to the structure
Persons in contact with the structure may be subject to electric shock when high voltages
are present, both under powerline operating and powerline fault conditions. Voltage levels
due to lightning strikes on the powerline may be sufficient to result in arcing to personnel
or equipment in close proximity.
Persons who could possibly be at particular risk from electric shock, such as personnel
requiring heart pacemakers or with known heart conditions, should consider seeking
medical advice prior to engaging in work on metallic structures where voltages may be
present which could deliver electric shock.
R2.4 Cathodic protection
The presence of high levels of alternating current on a pipeline, which may arise under
normal powerline operating conditions, can result in a reduction in the effectiveness of
cathodic protection. This reduction may be sufficient for corrosion to occur, even though
the standard cathodic protection criteria have been met.
R3 HAZARD MECHANISMS
R3.1 General
Electrical hazards can arise on metallic structures through a number of sources. Conductive
coupling occurs when actual contact is made with a powerline or a live powerline
appurtenance, or when an object is sufficiently close for an electrical arc to become
established.
Low frequency induction arises due to the electrical coupling between long structures, such
as between pipelines and powerlines where they run parallel for some distance.
Earth potential rise occurs when current discharges from a powerline earth, such as from a
transmission tower footing when there is a fault on that tower.
Capacitive coupling occurs when an insulated above ground section of pipe is in close
proximity to a powerline, such that a powerline and structure can be considered to form the
two plates of a capacitor. Although the capacitance of this ‘capacitor’ is small, if a person
touches the structure sufficient current may flow to ground to cause electric shock, or to
cause a small spark if metallic contact to the structure occurs.
The principal means whereby an electrical hazard may arise on an existing pipeline are
through low frequency induction (LFI) and earth potential rise (EPR).
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221 AS 2885.1—2007
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R3.2 Low frequency induction under operating conditions
Under normal operating conditions a three-phase powerline can be expected to be operating
as a balanced system such that the surrounding electromagnetic field is small, however,
some induction will result due to the slightly different distances of each phase conductor
from a nearby pipeline, or due to current imbalance between phases. Long distances of
exposure, typically of the order of several kilometres, may result in voltage levels sufficient
to reduce the effectiveness of cathodic protection system, or possibly result in voltages
sufficient to present a risk to personnel.
R3.3 Low frequency induction under fault conditions
Under powerline fault conditions substantial voltages can be induced on adjacent parallel
structures such as pipelines. Phase to earth fault currents can be of the order of tens of
thousands of amperes, flowing from the substation(s) via the faulted power conductor and
returning via earth. This presents a highly unbalanced condition to any nearby pipeline, and
electromagnetic induction can result in induced voltages of many thousands of volts unless
mitigation is installed.
Severe LFI conditions can also occur on single-phase power transmission systems utilising
an earth return. Such systems include a.c. traction systems using the rails as a return
conductor, and single wire earth return (SWER) power distribution systems that are used
extensively in some rural areas.
R3.4 Earth potential rise
Rise in potential of local earth results when a powerline fault to earth occurs. Under these
conditions a high potential gradient exists due to the radial flow of current in the vicinity of
the fault location, which is typically a powerline tower or earthed pole. The voltage rise of
the earth near the fault can be of the order of tens of thousands of volts, decreasing
inversely with distance from the fault. Extended structures, such as pipelines, generally
adopt the potential of remote earth. Any such structure intercepting the gradient will thus be
subjected to the rise in local earth potential in the vicinity of the fault. Earth potential rise
will be reduced, often by orders of magnitude, if the electricity supply is earthed into a
distributed earthing system.
R3.5 Capacitive coupling
Capacitive coupling occurs when an insulated above ground part of a structure is in
proximity to a powerline, such that a powerline and structure can be considered to form the
two plates of a capacitor. Although the capacitance of this ‘capacitor’ is small, if a person
touches the structure, sufficient current may flow to ground to cause electric shock, or to
cause a small spark if metallic contact to the structure occurs. In general, mitigation of
capacitive coupling is required mainly during the construction phase of structures such as
pipelines, when they are strung above ground during operations such as welding. In most
circumstances the current that can flow to ground due to capacitive coupling is insufficient
to be lethal. The electric shock that can occur if a person touches the pipe may result in a
reflex action that might cause a hazard. Mitigation may also be required on above ground
structures that are not earthed and isolated from buried sections, such as may occur at line
valves, scraper stations, etc., if they are in close proximity to overhead powerlines. Often
the mitigation devices installed to protect insulated fittings will reduce voltages due to
capacitive coupling to low levels, although additional measures, such as direct earthing,
may at times be required. Note, however, that in many situations above ground steelwork
will be earthed via the electric supply earth on electrically operated equipment.
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AS 2885.1—2007 222
Standards Australia www.standards.org.au
R3.6 Conductive coupling
Conductive coupling occurs when actual contact is made with a powerline or a live
powerline appurtenance, or when an object is sufficiently close for an electrical arc to
become established. In most instances, conductive coupling is only likely to arise when
machinery, such as cranes and other lifting equipment, are operating under powerlines.
Machinery of this nature is usually only required during construction activities or during
major maintenance operations. It should be noted that conductive coupling might also
become relevant during those instances where a powerline conductor short circuits or arcs
to a tower. Under these conditions the tower itself and any associated earthing can become
live and can present a hazard to anyone who happens to be in near or direct contact with it.
R3.7 Lightning
The major problem with a lightning hazard in high voltage transmission corridors is that the
overhead earth wires on the transmission lines act as a ‘collector’ for lightning incidents in
the corridor. Such flash attachments do not proceed further than the nearest tower, because
of the effective wire impedance and the fast rise time of the lightning surge. The net result
is that during a thunderstorm the towers are caused to discharge about 15 times more often
than the flash density for that area. Thus the hazard to pipeline and personnel is increased
near the towers.
Apart from sheltering in an all-metal vehicle cabin, paradoxically the most shielded
location in a thunderstorm is under the power transmission line, mid span.
A pipeline is very different to other structures in its behaviour on receiving lightning flash
current. The pipe is essentially a very long capacitor which, when covered with most
modern coatings, can withstand very high voltages. The capacitance of the pipeline may be
around 5 microfarads per kilometre, although this figure is reduced on segments where the
backfill is nearly chemically dry.
The outcome is that a partial charge from a lightning side flash, or a charge from a very
small lightning flash, can be contained on this pipeline resulting in the storage of upwards
of half a coulomb at 1000 V. This storage of electricity is potentially lethal at any point
over the whole length (say 100 km), and it should be noted that this point might be far from
where any storm is visible.
A large direct flash to the pipeline at an exposed point, or to the ground directly above
where the pipeline is laid is more likely to damage the coating, but may then arc to earth.
This arcing results in the draining away of most of the charge, but it may destroy nearby CP
or telemetry equipment. The local risk to personnel is no worse than would be when
standing in the open during the storm. This risk, although small, is by no means fully
negligible.
Field experience on pipelines suggests that an earth resistance of 5 Ω, installed at each end
of each isolated section is satisfactory mitigation. A 5 Ω electrode at each end of a 100 km
pipeline section would discharge any lightning charge to a safe value in around 0.01 s. Such
discharge systems need to be capable of carrying high currents for a very short time and the
conductors should have a cross-sectional area of at least 25 mm2.
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223 AS 2885.1—2007
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R4 ACCEPTABLE VOLTAGE LIMITS
R4.1 General
Acceptable voltage limits as specified in AS/NZS 4853 are summarized as below. In
addition, the breakdown voltage of the structure coating should not be exceeded.
It should also be noted that continuous application of relatively low levels of a.c could
cause reduction in the effectiveness of cathodic protection and even corrosion. It has been
generally accepted that no more than 15 V a.c. should be continuously present, although
recent research indicates that a significantly lower limit should be applied in many
situations.
R4.2 Category A (see AS/NZS 4853)
Touch voltage limits for pipelines or appurtenances accessible to the public or to unskilled
staff are shown in Table R4.2.
TABLE R4.2
TOUCH VOLTAGE LIMITS FOR PUBLIC AND UNSKILLED STAFF
Protection fault clearance time Volts a.c. Volts d.c.
≤100 ms – 350 500
>100 ms – ≤150 ms 300 450
>150 ms – ≤300 ms 200 400
>300 ms – ≤500 ms 100 300
>500 ms – ≤1 s 50 200
>1 s, including continuous 32 115
NOTE: Buried sections of pipeline, or pipeline facilities that are securely locked and can
only be accessed by authorised personnel, are considered to be not accessible to the public.
R4.3 Category B (see AS/NZS 4853)
Touch voltage limits for pipelines with restricted public access and only access by
authorized personnel are shown in Table R4.3.
TABLE R4.3
TOUCH VOLTAGE LIMITS FOR AUTHORIZED PERSONNEL
Protection fault clearance time Volts a.c. Volts d.c.
≤1 s 1 000 1 000
>1 s, including continuous 32 115
Category B touch voltage limits are applicable to accessible parts of pipelines that have
restricted public access. (Such parts include compounds with security fences, buried
sections, etc.) They may also be applied when Category A touch voltage limits are
technically or economically not achievable and when the hazards are deemed to be
negligible or controllable.
Prior to applying Category B touch voltage limits, a risk assessment should be carried out in
accordance with AS/NZS 4853. (Section 2 describes risk assessment principles applicable
to pipelines.)
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R4.4 Voltage limits during construction or maintenance activities.
Compliance with AS/NZS 4853 requires that precautions be taken to limit touch voltages to
Category A limits during construction or maintenance activities. Measures include
restricting the length of welded or jointed pipeline prior to application of earthing, use of
equipotential surface mats and wearing of appropriate protective clothing and footwear.
R4.5 Voltage limits on buried sections of pipeline.
Where a section of pipeline is underground, the voltage rise on that section of pipeline
should not exceed the breakdown voltage of the pipeline coating. Coating breakdown
voltages can vary widely and should be assessed individually.
R5 ASSESSMENT OF HAZARD
It is not possible to specify in simple terms the minimum safe separation from sources of
electrical hazard. Many factors determine the extent of the hazard zone due to induced
voltages and each case requires an assessment to be made.
Factors to be considered in the assessment include but are not limited to the following:
(a) Fault current at the location in question, plus likely future fault current within the
expected life of the structure.
(b) Typical maximum operating current at the location in question, plus likely future
operating current within the expected life of the structure.
(c) Separation distance between powerline and structure.
(d) Structure geometry—size and depth of burial.
(e) Electrical parameters of structure coating.
(f) Earthing systems (both intentional and otherwise) installed on the structure.
(g) Length of structure running (approximately) parallel to powerlines.
(h) Powerline geometry—separation between phase conductors, height of conductors
above ground, presence and position of shield wires, etc.
(i) If shield wires are present, average distance between pylons/poles that are earthed.
(j) Soil resistivity at and in the vicinity of the affected location.
(k) Resistance per unit length of phase and shield wires
(l) Phase angle of each conductor on multi-circuit systems.
(m) Location of any phase transpositions within the area under study.
(n) Resistance to earth of pylon footings, pole earthing electrodes, etc.
(o) Powerline operating voltage.
(p) Fault clearance time.
(q) Fault frequency.
NOTE: Fault and steady-state currents on HV distribution powerlines (e.g. 22 kV) can be
more than sufficient to result in potentials requiring mitigation on adjacent structures. It
should not be assumed that only HV power transmission lines require consideration.
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225 AS 2885.1—2007
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R6 PROTECTIVE MEASURES
Protective measures should be designed to render the structure safe for operations personnel
and for the general public, and to avoid damage to the structure and its facilities. Earthing
should be designed to limit the voltage gradient that might exist across the structure coating
a value appropriate to the coating employed. At locations with exposure to voltages greater
than 1000 V due to LFI or EPR, earthing grids should be installed at accessible locations
such as at CP test points and within facilities compounds to reduce touch and step
potentials. In addition, public access to exposed steelwork or cabling should be prevented
by means of fencing or locked covers over equipment and monitoring points. Long-term
exposure of the structure to alternating current induced from electric powerlines should be
designed to a limit value of no greater than 15 V a.c.
Protective measures that might be applied include the following:
(a) Provision of earthing grids around accessible plant, exposed steelwork or CP test
points where necessary to limit touch and step potentials to safe values
(b) Use of Faraday cage principles to limit touch and step potentials within underground
pits.
(c) Installation of structure earthing in the form of discrete electrodes or runs of zinc
ribbon or other suitable metallic conductor. Earthing of this nature can be installed in
relatively short lengths to provide a localised point of low resistance to ground, and in
other locations long sections may be required extending along several kilometres to
provide distributed grounding.
(d) Installation of above-ground appurtenances within security compounds that prevent
public access.
(e) Use of lockable cathodic protection test point boxes that prevent public access to
terminals or leads connected to the pipeline buried below.
(f) Surge protection devices fitted across insulated joints, to protect the joint from
electrical damage and to control voltage differentials to safe limits.
In order to prevent direct current flow between earthing and structure, test point earthing
grids and metallic ribbon earthing may need to be connected to the structure via suitably
rated surge diverters. In the case of cathodically protected structures, such DC isolation
may be essential to enable effective operation of the CP system. Possible CP shielding
effects from earthing grids and Faraday cages should also be taken into account in the CP
design.
R7 PERSONNEL SAFETY DURING PIPELINE OPERATION AND
MAINTENANCE
R7.1 General
In areas classified as Category B in AS/NZS 4853 the provisions given in Paragraphs R7.2
to R7.6 are recommended.
R7.2 Operational activities
All normal operational work that may result in personnel making contact with the protected
pipeline, such as CP monitoring or work in facilities, will require measures as follows, or
otherwise provide equivalent levels of personnel safety.
(a) Personnel to wear either 1000 V rated rubber soled boots or 1000 V rated rubber
gloves in dry conditions.
(b) Personnel to wear both 1000 V rated rubber soled boots and 1000 V rated rubber
gloves in wet conditions.
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AS 2885.1—2007 226
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(c) No work should be carried out if there is evidence of lightning within 50 km of the
site or if advice from weather forecasting services indicates lightning activity.
R7.3 Pipe excavation
Where pipe is to be excavated, measures as follow are to be applied, or equivalent measures
that provide equivalent levels of safety:
(a) If the pipe is to be left unattended it should be provided with a fence and locked gate
that will prevent unauthorized access.
(b) All personnel that may contact the pipe should use either 1000 V rated rubber soled
boots or 1000 V rated rubber gloves in dry conditions.
(c) In wet conditions, all personnel that may contact the pipe should use either 1000 V
rated rubber soled boots or 1000 V rated rubber gloves, plus an equipotential mat.
(d) No work should be carried out if there is evidence of lightning within 50 km of the
site or if advice from weather forecasting services indicates lightning activity.
R7.4 Equipotential mats
If an equipotential mat is required it should comply with the following, or otherwise
provide equivalent levels of safety:
(a) The mat should be sufficiently robust to resist damage due to the service conditions,
sufficiently flexible to conform to the ground surface so as not to cause trips or falls,
and of a type of construction that ensures good electrical continuity to all parts of the
mat.
(b) Connection to the mat should be made at least at two points, which are in turn
connected to the pipe, either directly or via suitable surge diverters, by two separate
cables.
(c) The mat has to extend at least 1 m beyond the working area so that it is not possible
to contact the pipe without standing on the mat.
R7.5 Protective equipment
Care has to be taken to ensure that if gloves or boots are worn, no other part of the body can
make contact and provide a conductive path for the fault current, and—
(a) if rubber-soled boots are worn to isolate from earth, no other part of the body should
contact the earth if contact is also being made with the pipe; and
(b) if rubber gloves are worn to isolate from the pipe, no other part of the body should
contact the pipe if contact is also being made with the earth.
R7.6 Pipe continuity
If the pipe is to be cut, or broken by other means such that one section is isolated from
another—
(a) bonding cables should be run across the break during cutting, welding and at other
times unless appropriate personnel isolation or surge diversion is provided; and
(b) 1000 V rated rubber gloves should be used when making the bonding cable
connections.
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227 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX S
PROCEDURE QUALIFICATION FOR COLD FIELD BENDS
(Informative)
S1 INTRODUCTION
Modern thin-walled pipes made from low carbon steels of excellent weldability cannot
sustain high levels of field bending without forming buckles. Acceptance levels for such
buckles, based on functional and structural considerations, are aesthetically unacceptable.
Control of field bending by means of a qualified procedure involves establishing the
practical details of the procedure, the agreed acceptance criteria and the agreed method of
measuring or assessing buckles against the acceptance criteria.
The procedure development method described in this Appendix is advisory. Users are
invited to record their experiences and advise Standards Australia, so that subsequent
revisions of the Standard may benefit.
As there may be variations in the stress-strain behaviour between nominally identical pipes,
the operator should exercise judgement during bending. The angle limits given should be
treated as the maximum that are permitted. It is possible that bending to these limits may
cause higher levels of buckling than the agreed acceptance levels. In this case, the
maximum bend angles should be reduced, to ensure that the maximum buckle height stays
within the agreed acceptance limit.
S2 BASIS OF REQUIREMENTS FOR COLD FIELD BENDS
Over the last 30 years, pipeline design and materials have developed to the point where
currently high strength, highly weldable and fracture-resistant line pipes with medium to
high D/tN ratios are normally specified and used. These developments have been driven by
the need for more economical pipeline designs involving the use of less materials and
higher pressures.
Recent experiences in Australia led to the initiation of a research program into the cold
field bending of modern line pipe. The results of this research are detailed in APIA/TN1. A
number of the important conclusions reached are as follows:
(a) It is reasonably difficult to bend modern high D/tN line pipe without forming small
buckles.
(b) The presence of small buckles does not have any effect on the integrity of a pipeline,
if minimal pressure-cycling is occurring.
(c) The peak to peak wavelength of a buckle was shown to approximate the value given
by the equation—
Lb = ( )
0.25
2
N
21.6
12 1
r tπ
ν
×
S2(1)
where
r = peak radius, in millimetres
tN = nominal wall thickness, in millimetres
ν = poisson’s ratio
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(d) The height at which a buckle was deemed to be unacceptable was set by workmanship
standards at 5% of the length of the buckle.
(e) The achievable bend angle per diameter at which a buckle becomes unacceptable can
vary significantly between 0.5 and 4 degrees per diameter.
(f) The best method of determining the maximum achievable bend angle is by a test on a
length of the pipe to be bent.
(g) Residual ovality is significantly reduced by a high level hydrostatic test.
Figure S1 provides a method for making a preliminary assessment of the development of
compression buckles during pipe bending by conventional methods. It may be used to
determine a starting point for procedure development and qualification.
S3 OBJECTIVES
The aims of the bending procedure qualification laid out in this Appendix are the following:
(a) To determine the following:
(i) The bend angle at which buckles first form on the compression surface of the
pipe.
(ii) The height of the buckles on the compression surface of the pipe that are
deemed to be unacceptable for both single and multiple push bends.
(iii) The maximum allowable loaded bend angle and the residual bend angle for any
single push.
(iv) The maximum allowable loaded bend angle and residual bend angle that are
made as part of a sequence (excluding the first and last pushes of any sequence,
which should be treated as single pushes).
(v) The spacing between pushes.
(vi) The die radius to be used.
(vii) Whether an internal mandrel is required and, if so, the operating pressure and
details of any shimming on the mandrel.
NOTE: If the use of the mandrel is to be optional, separate procedures should be
qualified with and without the mandrel.
(viii) The maximum operating pressure of the hydraulic system.
(ix) The final procedure to be used in production field bending.
(b) To verify that a section of pipe that has been bent using the maximum bend angle
allowed under the field bending procedure results in a bend, is deemed to be
acceptable to the pipeline Licensee and complies with Clauses 10.6.2 and 10.6.3.
(c) To qualify operators for production bending.
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229 AS 2885.1—2007
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0-1%
0
20
0
60
40
DIA
ME
TE
R T
O T
HIC
KN
ES
S R
AT
IO D
/tN
80
120
100
Code l imit
BEND ANGLE DEGREES PER DIAMETER
21 3 4 65
Lines represent buckle heightas a percentage of peak to peak
buckle length
3%2% 5%4%
NOTE:To use the chart in Figure S1, the following sequence should be followed:
(a) Calculate the D/tN ratio for the pipe.
(b) Calculate the peak to peak buckle length from the equation given in Paragraph S2(c).
(c) Select the agreed buckle height as a percentage of the buckle length.
(d) From the chart, determine the bend angle from D/tN ratio and the buckle height ratio.
(e) Multiply the bend angle from the chart by each of the factors indicated below, to give
the achievable bend angle.
Steel grade Steel
grade
factor
Pipe diameter
mm
Pipe
diameter
factor
X42
X52
X70
X80
or lower
− X60
× 1.3
× 1.1
× 0.9
× 0.8
88.9
168.3
273.1
355.6
508
to
to
to
to
to
114.3
219.1
323.9
457.0
711
×
×
×
×
×
1.4
1.3
1.1
1.0
0.9
Greater than 763 × 0.8
The yield stress to ensile strength (σy/σu) ratio of the pipe
steel can also influence the achievable bend angle.
(a) Use the achievable bend angle as a starting point in a bending procedure
qualification, to determine the actual bending performance.
FIGURE S1 INDICATOR CHART FOR D/tN RATIO VERSUS BEND ANGLE FOR
DIFFERENT BUCKLE HEIGHT RATIOS
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S4 SUGGESTED METHOD
A suggested method for qualifying a bending procedure is as follows:
(a) All information and data pertinent to the testing, as listed under Item (m) below.
(b) Establish the nominal acceptance limits for buckle height, ovality and surface strain.
(c) Ensure that instrumentation is accurate to within 20% of the amount being measured.
(d) Prepare the bending machine in accordance with the manufacturer's specifications,
using bending shoes suitable for the pipe to be bent.
(e) Set the relief valve on the hydraulic circuit to zero, adjusting it during the course of
the qualification to the pressure required to make the bend.
(f) Load the test pipe into the machine and set up instrumentation suitable for measuring
the bend angle.
(g) Where an internal mandrel is used, position and energize it in accordance with the
maker’s instructions.
(h) Make the first push to establish the loaded and residual bend angles at which buckles
first appear. A number of pushes may be made to determine these angles.
(i) Make the second push at a distance of not less than two pipe diameters from the first
push, to establish the loaded and residual bend angles at which the size of any buckle
equals the agreed nominal acceptance limit. This push may be repeated if required. At
the conclusion of this Step, the contractor and the pipeline Licensee should agree on
the acceptance limits for buckle heights.
The height of a buckle is normally reduced by subsequent pushes, thus the limiting
angle for a single push may be increased when the push is made as part of a sequence.
The first and last pushes in any sequence should be treated as single push bends.
(j) Establish the loaded and residual angles for multiple push bends by making a series of
6 pushes at a suitable spacing; the first and last pushes to a loaded angle as defined in
Items (h) and (i) above, and the middle 4 pushes to a constant loaded angle, which it
is felt will ensure that the buckle heights do not exceed the agreed acceptance limit.
The contractor may use the loaded and residual angles given in Items (h) and (i)
above for all pushes in the bend. When the bend is made, measure the buckle heights.
If they exceed the agreed acceptance limit, repeat the test at a lower bend angle. Once
a satisfactory bend is made, the pipe may be removed from the machine.
(k) Measure the pipe for ovality in the centre of the bend produced by (h) and (i) above.
On the basis of this result, establish and agree on the acceptance limit for ovality.
(l) Calculate the surface strain for the agreed maximum bend angle. On the basis of this
result, establish and agree on the acceptance limit for surface strain.
(m) Record the test results and agreed acceptance limits. The records form should include
the following information and should be signed by an authorized representative of the
contractor and the pipeline Licensee:
(i) Date of procedure tests.
(ii) Pipe specification, pipe grade, nominal wall thickness and manufacturer.
(iii) Bending machine make, model, serial number, die radius and operating
pressure.
(iv) Mandrel make, model, serial number, level of shimming and operating pressure.
(v) Pipeline Licensee.
(vi) Contractor.
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(vii) Operator(s).
(viii) Maximum allowable loaded bend angle and residual bend angle for any single
push bends and any multiple push bends.
(ix) Spacing to be used between pushes.
(x) Procedure for cold field bending.
(xi) Results from section of pipe bent during the procedure qualification test; to
include—
(A) buckle heights; and
(B) ovality.
(n) Agreed acceptance limits; to include—
(i) buckle heights;
(ii) ovality; and
(iii) surface strains.
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APPENDIX T
GUIDELINES FOR THE TENSIONING OF BOLTS IN THE FLANGED JOINTS OF PIPING SYSEMS
(Informative)
T1 INTRODUCTION
This Appendix has been written to provide a guideline basis for the derivation of the value
of torque necessary to provide adequate tension in the bolts of a flanged joint for an
effective gasket seal after the nuts have been tightened up by a torque wrench. It also
provides information relating to the consideration of applied loads during operation as this
aspect of bolt tension is related in some instances to the remaining allowable stress after
pre-tensioning the bolt prior to being put into service.
Current Standards limit the design strength of bolts to a relatively low value of stress,
typically 24% yield for ASTM A193-B7 steel bolts. The construction industry has found
that when the bolts of some flanged joints are tensioned to the full permitted stress levels
the gaskets do not provide a tight seal during service.
This Standard permits higher allowable bolt stresses than the values permitted by other
current standards. These guidelines recognize therefore that additional precautions should
be taken to calculate the sealing and operating bolt stress levels to ensure that yielding of
the bolts does not occur. In this respect it is considered necessary that the design of the
joints take into account fully all of the applied loads that may exist during the operating life
of the pipeline system and in particular the stress levels during installation.
A worked example is provided in Paragraph T15 of this Appendix to demonstrate the
methodology of these guidelines.
Additionally, calculations have to be carried out to ensure that gasket and thread loading
and flange strength are within acceptable limits.
Leak-tight flange joints require the correct residual bolt tension to be achieved in all bolts.
The residual bolt tension may be achieved by—
(a) direct tensioning of the bolts; or
(b) torque wrench tightening of the bolts to achieve a bolt extension.
Where the torque wrench method is used, calibration of the applied torque against bolt
extension is strongly recommended to ensure the correct residual tension is achieved.
T2 NOTATION
The following notation has been adopted throughout this Appendix:
Symbol Description Units
A Nominal bolt area mm2
Ab Stress area of bolt mm2
Ag Internal area at gasket force reaction load diameter mm2
Ar Root area of bolt mm2
b Effective gasket seating width mm2
bo Basic gasket seating width mm
BCD Bolt circle diameter mm Lice
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c Radius of minor bolt diameter mm
oC Degree Celsius degree
d Nominal bolt diameter mm
db Minor diameter of bolt mm
dc Mean radius of nut face mm
dp Pitch diameter of bolt mm
e Bolt extension during installation mm
E Young’s modulus MPa
Fac Factor used to correlate torque and applied axial load
F Applied force on flanged joint from piping N
Fd Design factor
Fe Equivalent force from bending moment N
Fs Factor of safety of fatigue stress to yield stress
G Reaction load diameter mm
h Projected thread height mm
J Polar moment of inertia of cross section mm4
Kf Stress intensification factor of the bolt thread
kb Stiffness of bolt material N/m
kj Stiffness of joint material N/m
ksi Stress in bolt kips/inch2
L Lead of threads mm
Lu Length of unthreaded bolt carrying load mm
Ls Total length of bolt threads carrying load mm
m Gasket factor
M Bending moment applied to a flanged joint from piping N.m
N Number of bolts in a joint
N Gasket width
NPS Nominal pipe size mm
p Pitch of thread
P Static internal fluid pressure MPag
Pd Dynamic internal fluid pressure increment above static MPag
psi Pressure or stress lb/in2
P Load capacity of bolt N
Pres Resultant load N
Pd Dynamic load from internal pressure liquid surge N
Pe Pressure equivalent MPa
Pem Equivalent pressure from externally applied forces and
moments
MPa
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Pext External load N
Pi Initial load or preload N
Pm Recommended preload for a tight joint N
Pp Load from hydrostatic pressure test N
Ps Force in bolt from static fluid internal pressure in joint N
Q Axial load in bolt N
S1 Stress in bolt from tensile load MPa
S2 Stress in bolt from applied torque MPa
Sa, Sall Allowable stress MPa
Sav Average stress MPa
Sb Stress in bolt from required preload MPa
Sc Stress in joint from applied loads from piping MPa
Sd Stress in joint from surge pressure in liquid lines MPa
SE Stress range of a cyclic load MPa
Se Endurance limit MPa
Sg Compressive stress in bolt to compress a flexible gasket MPa
Sp Static stress in bolt from pressure in joint MPa
Spr Principal stress MPa
Sr Alternating stress MPa
Ss Shear stress MPa
St Total stress MPa
Stf Total fatigue stress MPa
Su Ultimate tensile strength MPa
Sy Yield strength MPa
SMYS Specified minimum yield stress MPa
T Torque N.m
Tt Torque on threads N.m
TPI Threads per inch
Y Gasket contact surface seating stress; minimum design seating
stress
MPa
µt Coefficient of friction of threads
µc Coefficient of friction of face of nut or bolt head
λ Lead angle of the helix of the bolt threads degree
α Angle between flank of thread and plane perpendicular to
helix
degree
π Constant
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T3 THE EFFECT OF THE GASKET ON THE LOAD CARRIED
The load on the bolt depends on the initial load (Pi) and the external load (Pext).
The load on the bolt also depends on the relative elastic yielding (springiness) of the bolt
and the connected members as follows:
(a) If the connected members are very yielding compared with the bolt the resultant load
on the bolt (Pres) will closely approximate the sum of the initial tension (Pi) and the
external load (Pext),
(b) If the bolt is very yielding compared with the connected members the resultant load
will be either the initial tension or the external load, whichever is the greater.
To estimate the resultant load on the bolt the following formula can be used:
Pres = b
i ext
b j+
kP P
k k
+
. . . T3
For flanged joints with a flexible gasket, the value in brackets approaches unity, for a solid
gasket, such as metallic ring jointed gasket, the bracketed value is small and the resultant
load is due mainly to the initial tension Pi (or to Pext if it is greater than Pi).
T4 STRENGTH CAPACITY OF A BOLT
It is relatively easy to calculate the static tensile strength of a bolt.
The load may be assumed to be uniformly distributed across the root section of the bolt and
stress concentration can be neglected.
The stress area of the bolt can be obtained from the dimensions of the standard to which the
bolt is manufactured and used together with the yield strength (y
S ) of the bolt material to
determine the load carrying capacity P of the bolt as follows:
P = AbSy . . . T4
T5 INITIAL LOAD AND PRELOAD
The initial load in a joint for a leak tight joint is highly indeterminate.
Residual bolt tension or preload provides the necessary clamping force on the joint. In the
case of a flexible joint the preload provides the force to compress the gasket, maintain a
tight joint and carry the externally applied loads from internal fluid pressure, etc. Applying
an external load to a flexible joint, after preloading the joint, reduces the clamping force but
increases the bolt tension.
In the case of a rigid joint, applying an external tensile load less than the preload tension
will not affect the magnitude of the bolt tension. Where the external tensile load is greater
than the preload, the bolt tension will increase to the value of the applied tensile load and
the clamping load will decrease. The clamping load will be reduced once the initial preload
had been exceeded.
The minimum preload in the flanged joint bolts can be determined. Consideration will
include at least the following:
(a) Preload to seat the gasket and prevent gasket leakage:
P1 = πbGy (For self-energizing gaskets P1 = 0) . . . T5(1)
(b) Preload to provide additional compression force to ensure a tight joint:
P2 = 2bπGmp (For self-energizing gaskets P2 = 0) . . .T5(2)
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(c) Preload to carry the load from the internal pressure inside the pipe:
P3 = 2
4G p
π
. . .T5(3)
(d) Preload to account for the expected loss of preload due to plastic deformation in the
bolted joint.
(e) Preload to carry any additional operating loads from the connected piping.
The total preload is the algebraic sum of Items (a) through (e) above.
The preload loss can vary between about 2% and 10% of the actual preload level in the bolt.
If a joint is configured such that its stiffness is primarily dependent upon non-metallic
materials or, if it does not have metal-to-metal contact throughout, the preload loss can be
determined from a specific application test.
The values of the effective gasket seating width b, the gasket or joint contact surface
seating stress y and the gasket factor m will need to be obtained from a suitable standard,
such as AS 1210.
It has been reported that under repeated operational bending strains and internal pressure,
flanged joints will leak before failure and also that gasket leakage has not been experienced
when flange bolts have been pre-tightened to a bolt stress level of 276 MPa (40 ksi),
although leakage has been observed when bolts were only tightened to 138 MPa (20 ksi).
It is possible to relate the tightening load to the dimensions of the bolt screw thread and the
value of the applied torque. In practice there can be considerable error in the calculation of
the torque required, because of the wide variation of the effect of surface finish and
lubrication of the sliding components on the torque that is required to overcome the
frictional resistance.
T6 RELATIONSHIP BETWEEN APPLIED TORQUE AND TENSION
The torque required to turn the nut can be related to the axial load in the bolt by the
following formula:
T = QdpFac/2 . . .T6(1)
The factor Fac is a function of the lead angle of the helix λ , the angle between the flank of
the thread and a plane perpendicular to the helix of the thread α , the coefficient of friction
µt and dc the mean radius of the nut face as follows:
Fac = ( ) ( )( )t t c c pcos tan / cos tan /d dα λ µ α µ λ µ + − + . . .T6(2)
where
tanλ = p
/L dπ . . .T6(3)
Alternatively, the torque may be calculated using the simplified screw jack formula of A.P.
Farr, rewritten using the notation of these guidelines, as follows:
T = ( )t p c c/ 2 2cos / 2
Q
L d dπ µ α µ + +
. . .T6(4)
Coefficients of friction can vary between 0.06 and 0.40. These are practically independent
of load and vary only slightly with different combinations of materials and rubbing speed.
Due to the wide variance of coefficient of friction the correlation between applied torque
and load will contain a degree of uncertainty.
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T7 LOADS IMPOSED ON A BOLT
Loads may be separated into two categories loads imposed during installation and
externally applied loads after installation.
The following is a list of the loads imposed on the bolts of a flanged joint during
installation:
(a) Load on a bolt imposed by the connected piping from misalignment (note this load
should be either eliminated or minimised by careful construction),
(b) Load on a bolt from the preload.
The following is a list of the loads imposed on the bolts from operating conditions:
(i) Static load from internal pressure.
(ii) Dynamic load from internal pressure.
(iii) Loads applied externally from connecting piping.
T8 COMBINED STRESSES
T8.1 Stresses during installation
During installation the minor diameter cross-section of the portion of the screw thread of
the bolt between the nut and the flange will be subjected to a biaxial stress condition. This
stress condition is comprised of a tensile stress due to the axial force and a shear stress due
to the applied bolting torque.
The stress S1 in the bolt from the tensile load is as follows:
S1 = Q/Ab . . .T8(1)
The predicted bolt extension under the tensile load is as follows:
e = U s
b
L LQ
E A A
+
. . .T8(2)
The stress S2 in the bolt from the applied torque is as follows:
S2 = Ttc/J . . .T8(3)
The polar moment of inertia J is based on the minor diameter.
The torque on the threads (Tt) is:
Tt = ( ) ( )p t tcos tan / cos tan / 2Qd α λ µ α µ λ + − . . .T8(4)
The maximum shear stress (SS) is:
SS =
2
21
22
SS
+
. . .T8(5)
The shear stress level in the bolt will cause the bolt to yield when the maximum shear stress
Ss is equal to the shear yield strength of the material, which is equal to half of the yield
strength in simple tension Sy /2.
The maximum principal tensile stress during torque up is:
Spr = ( )1 S/ 2S S+ . . .T8(6)
The bolts should have sufficient strength to withstand the required applied torque during
installation.
After torque up has been completed the shear stress from the torque will cease to exist. Lice
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AS 2885.1—2007 238
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T8.2 Stresses during operation
The design of the bolts should also have adequate strength to withstand the applied loads
during operation.
The stress in a bolt Sg to keep the gasket in compression may be calculated from the
minimum recommended bolt preload as follows:
Sg = Pm/Ab . . .T8(7)
The static operational stress (Sp) in the bolt from internal fluid pressure p is given as
follows:
Sp = Ps/Ab . . .T8(8)
where
Ps = pAg and Ag = πG2/4 . . .T8(9)
The dynamic stress in the bolt from fluid pressure (Sd) is determined as follows:
Sd = Pd/Ab . . .T8(10)
where
Pd = pdAg . . .T8(11)
The loads from the connected piping will be determined from analysis and the stress in the
bolt (Sc) will be determined from these loads.
The total stress St in the bolt from the operational loads will vary depending upon the type
of gasket being used in the bolted joint.
For flexible gaskets the total bolt stress in operation will be the sum of the individual
stresses as follows:
St = Sg + Sp + Sd + Sc . . .T8(12)
For rigid gaskets the total stress will be either:
St = Sg . . .T8(13)
or
St = Sp + Sd + Sc . . .T8(14)
whichever is the greater.
The required load capability of the bolt can then be back calculated from the greater of Sg
and St above for a rigid gasket.
T8.3 Stresses during the hydrostatic pressure test
The design of the bolts should also have adequate strength to withstand the applied loads
during the hydrostatic pressure test.
The hydrostatic test pressure produces the following flange load:
Pp =
2
24 / 4
p G
p G
π
π
. . .T8(15)
and the stress in a single bolt is:
Sp = ( )
p
b /
P
A N . . .T8(16)
For flexible gaskets the total stress will be the sum of the individual stresses as follows:
St = Sg + Sp . . .T8(17)
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For rigid gaskets the total stress will be either:
St = Sg . . .T8(18)
or
St = Sp . . .T8(19)
whichever is the greater.
T9 FATIGUE FROM OPERATING LOADS
It can be shown from the Soderberg triangle that the following is true:
Fs = ( )( )
y
av y e f r/
S
S S S K S+
. . .T9(1)
where
Sr = ( )max min/ 2S S− . . .T9(2)
Sav = ( )max min/ 2S S+ . . .T9(3)
Stress
Range = Smax − Smin . . .T9(4)
The equation above can be adapted to calculate the total stress range due to the cyclic load.
The total fatigue stress is given by:
Stf = ( )av y e f r/S S S K S+ . . .T9(5)
Values of the endurance limit Se lie within the range 0.45 to 0.6 Su, with an upper limit of
about 690 MPa, a value 0.5 Su is commonly used in design.
T10 THE EFFECTS OF PIPING LOADS ON FLANGED JOINTS
For routine design on the effects of loading on flanged joints other than internal pressure,
i.e. loads from the connected piping, the method of M.W. Kellogg is provided.
M.W. Kellogg found that, with a properly pretightened flange, the bolt load changes very
little when a moment is applied to it.
Further, Kellogg found from experience that it is satisfactory to first calculate the maximum
load per millimetre of gasket circumference due to the applied longitudinal bending
moment and force. Then the internal pressure equivalent to this loading is determined. The
formula proposed by Kellogg is as follows:
Pe = 3 2
16 4M F
G Gπ π
+
. . .T10(1)
The equivalent force in each bolt Fe = PeAg/N, and the stress in the bolt may be calculated as
for other pressure load calculation i.e.:
Sc = Fe/Ab . . .T10(2)
Regarding torsion, if the frictional resistance of the gasket is ignored and all of the bolts are
put in shear it can be shown that the shear stress in the bolts is conservatively:
Ss = ( )2
p8 /T BCDd Nπ . . .T10(3)
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AS 2885.1—2007 240
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Stresses can then be combined in accordance with the theory given in Paragraph T8.1.1.
Note that this torsional shear stress is an applied stress during operation. It is not the
torsional shear stress arising from the torque up of the joint.
T11 COEFFICIENT OF FRICTION
There is a wide variance in the values of coefficient of friction for the calculation of applied
torque. These variations are caused by a number of factors such as the condition of the
threads, the condition of the flange to the nut bearing surface and the type of lubricant used.
It is not possible to accurately determine a value of the coefficient of friction existing at
site, some conservatism is therefore recommended in the selection of the value used in the
calculations unless the conditions have been well established.
Typical coefficients of friction need to be selected for the type of bolt to joint interfaces to
be used for the specific application. The following list of parameters will need to be
considered in selecting appropriate values of coefficient of friction for the threads and for
the nut/bolt head face contacts:
(a) Material, i.e. carbon steel, chrome molybdenum, stainless steel, etc.
(b) Condition of components, material grades and workmanship.
(c) Coatings, i.e. no coating, plated etc.
(d) Lubrication, degreased, dry, average lube, low friction lube.
(e) Surface film, oxidised, no oxidation.
(f) Hardness of the materials.
(g) Surface finish, abrasive cleaned, machined, ground, etc.
T12 COMPONENTS OF THE FLANGE ASSEMBLY
All of the components of the flange assembly should be designed to carry the required load
capacity of the bolts.
The other components of the assembly to be considered in the design of the flanged joint
are as follows:
(a) The nut threads.
(b) The bolt threads.
(c) The gaskets.
(d) The flanges.
If the flange is purchased as an assembly in accordance with a recommended Standard, at
the appropriate design pressure and temperature, then it may be assumed that the strength of
the flange components will match the strength of the bolts. Whilst these guidelines provide
a basis to review the strength of the bolts of the flanged joints, they do not provide any
basis for reviewing the strength of the flange, the nuts or the gaskets.
T13 DERATING OF ALLOWABLE STRESS AT ELEVATED TEMPERATURE
The upper limit of temperature for the standard is 200°C fluid temperature. These
guidelines only apply to steel bolts to ASTM standards up to 200°C.
For bolt temperatures up to 120o
C no de-rating of allowable bolt stress level is required. For
temperatures between 120o
C and 200o
C the permitted allowable bolt stress level shall be
de-rated in accordance with an approved standard.
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241 AS 2885.1—2007
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T14 ALLOWABLE STRESS LIMITS
The evaluation of the loading of the bolts of flanged joints is treated in these guidelines as
being similar to the evaluation of the loads in the pipe. The allowable stress limits in the
bolts for steel materials given in Clause 5.7.8 of the Standard have been tabulated and
included in these guidelines as follows:
Load Case Load Type Stress Type Stress limit
Installation Torque + Axial Shear 45% Yield
(90% Shear Stress)
Installation Torque + Axial Tension 90% Yield
Installation Residual (Preload) Axial 2/3rd Yield
Hydrostatic pressure test
Sustained Axial <100% Yield
Operation Sustained Axial 54% Yield
Operation Cyclic stress range Axial 72% Yield
Operation Occasional Axial 80% Yield
T15 WORKED EXAMPLE
T15.1 Details for the worked example
It is required to install an ASME B16.5 flange assembly using a 600 mm NPS Class 150
flange with raised face flanges. The bolt material is ASTM A 193-B7 material requiring 20
number 32 mm bolts. The minimum yield strength of the bolts is 724 MPa and the ultimate
tensile strength of the bolts is 862 MPa. The reaction load diameter (G) of the gasket has
been calculated to be 666.76 mm per AS 1210.
The screw threads of the bolt have been stated to be 8UN with an external diameter of
32 mm, a pitch diameter of 29.69 mm, a minor diameter of 27.85 mm, a stress area of
644.19 mm2 (AS 1210) and a dimension h = 0.866025 p. The vee formation of the screw
thread is 60° and the relationship between the lead angle to the pitch diameter dp and the
lead L is tan p
/ dL πλ = . The bolts are single screw thread (L = 1/p) with 8 TPI. The width
across the flats of the nut face is 48 mm.
It is assumed that the coefficient of friction is 0.15 for the threads and 0.15 for the nut face.
It is also assumed that the resultant load on the bolt is the sum of gasket compression load
and the externally applied load.
The maximum internal operating pressure is 1.5 MPag, the allowance for liquid surge is
10% of the operating pressure. The flange is subject to a sustained bending moment of
25 000 N.m, a thermal bending moment of 120 000 N.m and a thermal axial tensile load of
0.97 × 106 N from the connected piping. The thermal moment and force are cyclic in nature.
The hydrostatic test pressure is 1.5 times the maximum internal operating pressure.
T15.2 Gasket compression and test pressure
The minimum calculated load Pi for a tight seal for the hydrostatic pressure test case is as
follows:
Gasket width N = 28.55, Type II spiral wound gasket, m = 3, y = 69 MPa and for a serrated
flange per AS 1210 and using the formula for bo from AS 1210:
(a) b0 3 3 28.55
10.69 mm8 8
N ×
= = =
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b 0
2.52 2.52 10.69 8.24 mmb= = =
(b) P1 = π b G y (Gasket seating)
P1 = π × 8.24 ×666.76 × 69
P1 = 1.19 × 106 N
(c) P2 = 2 b π G m p (For a tight joint)
P2 = 2 × 8.24 × π × 666.76 × 3 × 1.5
P2 = 0.155 × 106 N
(d) P3 = 2
4G p
π
(Hydrostatic test pressure)
P3 = (π/4) × 666.762 × 1.5 × 1.5
P3 = 0.786 × 106 N
The total preload on the joint Pi = 2.13 × 106 N
The total preload on each bolt = 2.13 × 106/20 = 106500 N
The corresponding stress level in the bolt = 106500/644.19 = 165 MPa (24 ksi).
T15.3 Operating loads
The operating loads need to be added to the loads given in Paragraph T15.1.2 above to
ensure that the joint will not leak during operation. An allowance of 5% has been included
to cover any loss in preload.
The additional operating loads are:
(a) Load from the operating thermal moment.
em 3 3
16 16(25 000 120 000)10002.5MPa
666.76
MP
Gπ π
+
= = =
2 2 6
4 em666.76 2.5 0.87 10
4 4P G P N
π π
= = × = ×
(b) Load from the applied thermal force.
P5 = 0.97 × 106 N
The total load on the joint for a tight seal including the operating loads and preload
allowance loss, less the margin of the test pressure over the operating pressure, is:
( ) 6 6
i2.13 1/3 0.786 0.87 0.97 10 1.05 3.89 10P N = − × + + × = ×
The total preload on each bolt = 3.89 × 106/20 = 194500 N.
The corresponding stress level in the bolt = 194 500 / 644.19 = 301.93 MPa (44 ksi).
The static stress level in the bolt adopted for the preload Sb = 310 MPa (45 ksi).
T15.4 The applied load (Q)
The applied load (Q) is:
Q = SbAb = 310π 27.852/4
Q = 189 000N
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243 AS 2885.1—2007
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T15.5 The applied torque (T)
The constants tanλ and cosα are:
( ) ( )ptan / 1/8 / 29.69 / 25.4 0.034L dλ π π= = =
( )cos cos 60 / 2 0.866α = =
Taking the mean radius of the nut face equal to the mean of the bolt diameter and width
across the flats of the nut then:
( )c
48 32 / 2 40 mmd = + =
The applied torque (T) is:
( ) ( )( )p t t c c pcos tan / cos tan / / 2T Qd d dα λ µ α µ λ µ = + − +
( ) ( )( )189 000 29.69 0.8660 0.034 0.15 / 0.866 0.15 0.034 0.15 40 / 29.69 / 2 /1000T = × × + − × + ×
1151T Nm=
Alternatively, as the tangential force acts at the pitch radius, using the Farr formula:
( ) ( )t p c c/ 2 / 2cos / 2T Q L d dπ µ α µ = + +
( ) ( )189 000 1/8/ 2 25.4 0.15 29.69 / 2cos30 0.15 40 / 2 /1000T π = + × + ×
1149 .T N m=
T15.6 Combined stress level in the bolts during installation
During tightening the maximum combined shear stress level can be obtained as follows:
S1 = 310 MPa (45 ksi)
J = 4 4 4/ 32 27.85 /32 59 061mm
bdπ π= =
Tt = ( ) ( )189 000 29.69 0.866 0.034 0.15 / 0.866 0.15 0.034 / 2 /1000 × × + − ×
Tt = 584.82 N.m
S2 = ( )/ 584.82 1000 27.85/ 2 /59 061 137.89 MPaTc J = × =
Ss = ( ) ( ) ( ) ( )0.5 0.5
2 2 2 2
1 2/ 2 310 / 2 137.89S S + = +
Ss = 207.46 MPa
Sy/2 = 724/2
Sy/2 = 362 MPa
Ss = 57.31% of yield in shear during tightening, and reduces to 310 MPa or 42.82% yield in
tension after tightening.
The maximum principal stress (Spr) is:
Spr = ( )310 / 2 207.46 362.46 MPa+ =
Spr = 50.06% of yield in tension during torque up
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AS 2885.1—2007 244
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T15.7 Stress level in the bolts during the hydrostatic pressure test
As the gasket is a flexible gasket the stress in the bolts Sg from the preload will add to the
hydrostatic pressure test load. It is assumed that the piping is well supported during testing
and that there are no additional imposed piping loads.
Pp = 1.5 × 1.5π 666.762/4 = 785 618 N
pS = ( ) ( )p b/ / 785 618/ 644.19 / 20 60.98MPaP A N = =
tS = 310 + 60.98 MPa
tS = 370.98 MPa
or 51.24% yield in tension.
T15.8 Sustained stress level in the bolts during operation
As the gasket is a flexible gasket the stress in the bolts Sg from the preload will add to the
operating loads. During operation, the operating stresses are Sp + Sd + Sc. Note that the
dynamic load from surge (10%) has been conservatively included in this sustained load
case. Thermal loads have not been included.
Sg = 310 MPa
Pp = 21.5 666.76 / 4 523 745 Nπ =
Sp = ( )p b/ 523 745/ 644.19 / 20 40.65MPaP A = =
Sd = 0.1 × 40.65 = 4.07 MPa
The pressure equivalent to the sustained bending moment is:
Pe = ( )3 316 / 16 25 000 1000 / 666.76M Gπ π= × ×
Pe = 0.43 MPa
The applied load from the bending moment in each bolt is:
F = ( )20.43 666.76 / 4 20π ×
F = 7 498 N
The stress in each bolt from the moment is:
Sc = ( )7 498/ 644.19 11.64 MPa=
The total stress is:
St = 310 + 40.65 + 4.07 + 11.64
St = 366.36 MPa
or 50.6% of yield in tension.
Sa = 0.54 × 724 = 390.96 MPa
T15.9 Fatigue stress level during operation
As the gasket is a flexible gasket, the stress in the bolts (Sg) from the preload will add to the
operating loads. During operation the operating stresses are Sp + Sd + Sc with Sc comprising
the static component and the cyclic component of stress. The stress intensification factor of
the vee thread is taken to be 2.5.
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245 AS 2885.1—2007
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The pressure equivalent to the bending moment is:
Pe = ( )3 316 / 16 120 000 1000 / 666.76M Gπ π= × ×
Pe = 2.06 MPa
The applied load from the bending moment in each bolt is:
F = 2.06 × π666.762/(4 × 20)
F = 35 995 N
The stress in each bolt from the moment is:
Sc1 = ( )35 995/ 644.19 55.88MPa=
The stress level in each bolt from the applied force is:
Sc2 = ( )
60.97 10
75.29 MPa20 644.19
×
=
The stress due to the cyclic load Sr is equal to the total of the Sc components.
The steady stress is the same as that in Paragraph T15.8 above.
The maximum stress is:
Smax = 366.36 + 55.88 + 75.29 = 497.53 MPa
The minimum stress is:
Smin = 366.36 − 55.88 − 75.29 = 235.19 MPa
The average stress is:
Sav = ( )497.53 235.19 / 2 366.36 MPa+ =
The total fatigue stress is:
Stf = ( )av y e f r/S S S K S+
Stf = ( )( ) ( )366.36 724 / 0.5 862 2.5 55.88 75.29+ × × × +
Stf = 917.21 MPa
or 126.69% yield in tension.
The stress range from the alternating stress SE = Smax − Smin or = 2Sr
SE = ( )2 55.88 75.29× +
SE = 262.34 MPa
The allowable stress range is:
Sall = 0.72 × 724 = 521.28 MPa
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AS 2885.1—2007 246
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Table T15.1.9(A) summarizes these results.
TABLE T15.9(A)
SUMMARY of STRESS LEVELS
Case Type Total value
of stress
MPa
Total %SMYS Total stress
excluding
residual
MPa
%SMYS
Installation Torque 208 — — —
Installation Torque 363 — — —
Installation Residual—
Pre-tension
310 43 310 43
Hydro Sustained 371 51 61 8
Operation Sustained 366 51 56 8
It can be seen from the Table 15.1(A) in this example that the bolt pre-tension comprises
the majority of the sustained stress in the flanged joint.
For stress compliance, Table 15.9(B) summarizes the calculated and allowable values.
TABLE T15.9(B)
SUMMARY of STRESS COMPLIANCE
Case Type Value of
stress
MPa
Stress limit
MPa
Allowable
stress
MPa
%Allowable
Installation Torque 208 90% shear 323 64
Installation Torque 363 90% yield 652 56
Installation Residual—
Pre-tension
310 2/3rd yield 483 64
Hydro Sustained 371 100% yield 724 51
Operation Sustained 366 54% yield 391 94
Operation Stress range 262 72% yield 521 50
T16 VALIDATION OF THE TORQUE WRENCH TIGHTENING PROCEDURE
The following procedure may be used to establish the method for the tensioning of the bolts
of flanged joints, for installation at site:
1 Establish the residual bolt preload for leak tightness including any operating forces
using this Appendix.
2 Calculate the bolt torque necessary to achieve the required residual load in 1 above
using this Appendix.
3 Estimate the coefficient of friction of the nut/flange face and the threads individually.
4 Calculate the combined stress level to ensure that the bolts will not be over stressed
during tightening. If the calculated stress value indicates that the bolts would be
overstressed, then the application shall be amended until the calculated stress value
shows that the bolts will not be overstressed. If the value of residual bolt tension is
reduced it shall not be less than that established for the leak tightness of the joint.
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247 AS 2885.1—2007
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5 Validate the estimated value of coefficient of friction by measuring the torque and the
axial deformation (extension) of at least one bolt at site during the tightening of the
bolt of the first joint. A ‘G’ frame with feeler gauges, a caliper or a dial gauge can be
used to measure the change in bolt length at the observed value of torque. The value
of torque measured should be the static value of torque not the running value of
torque.
6 Adjust the calculated value of coefficient of friction to match the measured value of
torque and confirm the bolt stress level from the extension of the bolt (use the
measured extension to calculate the axial load in the bolt and the bolt stress level).
Where different values of friction are estimated for nut/flange face and bolt threads
the new values may be individually amended in their prior proportion to achieve the
adjusted values.
7 Recalculate the value of torque to meet the required bolt pre-load/stress level using
the confirmed value of coefficient of friction.
8 Recheck the combined stress level using the confirmed value(s) of coefficient of
friction and torque and reassess the application if necessary.
9 Tighten all bolts to the confirmed torque value for the flange used for validation
purposes if required, and all other identical flanges for a duration, which does not
exceed the day of the validation of the value of the coefficient of friction.
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AS 2885.1—2007 248
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APPENDIX U
STRESS TYPES AND DEFINITIONS
(Normative)
U1 GENERAL
There are fundamental differences between the calculation of stresses of restrained
pipelines and unrestrained pipelines. This Appendix provides the formulae to enable
calculation of stresses in accordance with the requirements of this code and defines the
stress terminology and units for both of these types of pipeline restraint condition.
The intent of this Appendix is to cover the ‘operating’ design stresses and not
‘construction’ design stresses. For the calculation of stresses during hydrostatic pressure
testing of a new pipeline, the wall thickness to be used shall be the wall thickness defined
below except that the wall thickness allowances for corrosion and erosion may be added to
the specified thickness.
The equations and components of stress in this Appendix are as accurate and
comprehensive as is reasonable for inclusion in a document of this nature. Unusual or
complex circumstances may arise in which there are additional stress components. The
general principles expressed here shall continue to be applied. The omission of a stress
component from the following discussion does not justify its omission from the calculated
stress state if it is relevant.
In many piping configurations it is not possible to calculate the stresses from simple
formulae such as provided here and the stress state can be predicted only through finite
element analysis (i.e. pipe stress analysis software). For example, it is very common in
buried pipelines that the longitudinal expansion stress (σEA Paragraph U2.3) does not reach
the theoretical value given by Equation U2(4) as a result of slight relaxation of the pipe at
end points or changes of direction, although the longitudinal stress may still be high. As
another example, the bending stresses due to thermal expansion at changes in direction of a
buried pipeline may be very high if the temperature differential is high (e.g. Compressor
station discharge) but cannot be expressed by any formula. The general principles expressed
here shall continue to be applied, regardless of whether the stresses are calculated by simple
formulae or sophisticated numerical methods.
U2 STRESSES IN RESTRAINED PIPELINES
This Paragraph provides the definition of stress terms, formulae and units for the evaluation
of stresses in pipelines fully restrained in an axial direction, denoting +ve as being tensile.
U2.1 Hoop or circumferential pressure stress (σH)
The Barlow formula for thin wall cylinders
Hσ =
d
2W
P D
t . . . U2(1)
where
Pd = design pressure, in MPag
D = nominal external diameter, in mm
tW = required wall thickness, in mm
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U2.2 Longitudinal pressure stress (σL)
The longitudinal stress from the Poisson effect of hoop stress
σL = Hνσ . . . U2(2)
σL = d
2W
P D
tν . . . U2(3)
where
ν = Poisson’s ratio
PD = design pressure, in MPag
D = nominal external diameter, in mm
tW = required wall thickness, mm
U2.3 Longitudinal thermal expansion stress EA
σ
The fully constrained axial thermal expansion stress in straight pipe is
σEA = ( )c
E T Tα − . . . U2(4)
where
Tc = closing temperature, in °C
T = design temperature, in °C
E = Young’s modulus, in MPa
α = coefficient of thermal expansion of steel
Consider two values of T.
T1 at the upper design temperature and T2 at the lower design temperature, i.e. both
compressive and tensile stress types.
NOTE: That σEA may not achieve the value given by Equation U2(4) where the pipe is not
perfectly restrained. In particular, in analysis of pipe restrained by anchors it is necessary to
include in σEA the effects of anchor displacement under thermal expansion load.
In addition, substantial bending stresses can arise due to thermal expansion at changes in
direction, particularly in buried pipe where the lateral restraint of the soil gives rise to
complex deformation and stress patterns. Generally this stress can be calculated only by
finite element methods (i.e. pipe stress analysis software). Where such stresses exist they
shall be included in the longitudinal thermal expansion stress.
Bending stress due to thermal expansion = σEB
The longitudinal thermal expansion stress
σER = σEA + σEB . . . U2(5)
U2.4 Bending stress σW
Bending stresses may be due to gravity from unsupported spans. Note that axial
compressive stress increases beam bending stresses in these unsupported spans.
Unsupported span (beam bending, buckling) = σw
Consider both tensile and compressive stress types. From beam theory one side will be in
tension and the other in compression. σw may be calculated from conventional beam theory.
The section modulus Z to be used to calculate the bending stresses shall be based on the
wall thickness tW in Paragraph U2.1 above.
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U2.5 Direct axial stresses σF and σother
U2.5.1 Direct stress from externally applied forces/displacements/pressure
σF = F
S
P
A . . . U2(6)
Consider both tensile and compressive stress type.
where
PF = direct axial force, in N
As = ( )2 2
i
4
D Dπ −
, in mm2
D = nominal external diameter, in mm
Di = internal diameter ( )2W
D t− , in mm
tW = required wall thickness, mm
U2.5.2 Stress from other imposed force (σother)
U2.6 Sustained stress (σsus)
σsus = σL + σW + σF + σother . . . U2(7)
Evaluate the maximum value of stress considering both tensile and compressive stress type
combinations.
Note that for calculation of sustained stress the components σF and σother should not include
displacement of anchors under thermal expansion load; this effect should be included in the
longitudinal thermal expansion stress (σEA).
U2.7 Total longitudinal stress (σT)
σT = σsus + σER
. . . U2(8)
Evaluate both tensile and compressive stress types.
U2.8 Total shear stress (τ )
Shear stresses may not be large in buried fully restrained pipelines; however, they may be
caused by lateral loads due to unsupported valves, and also from torsion from various
sources.
The shear stress due to torsion:
τt = t
2
M
Z . . . U2(9)
where
Mt = torsion moment, in Nm
Z = section modulus based on tW in Paragraph U2.1 above
In addition, if direct (plane) shear stress is significant it shall be included in the calculation
of total shear stress.
The shear stress due to direct shear:
τd = T
ST
S
A . . . U2(10)
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251 AS 2885.1—2007
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where
ST = total design shear force, in N
AST = total area resisting shear, in mm2
Total shear stress τ = τt + τd . . . U2(11)
U2.9 Combined equivalent stress (σc)
Use either the Tresca Maximum Shear Theory for biaxial stress without shear—
σC = σH − σT, when σT <0 . . . U2(12)
NOTE: That this is equivalent to adding the absolute values of the hoop and longitudinal stresses,
i.e. when the longitudinal stress σT <0 it is negative, then according to the Maximum Shear theory
this negative stress adds directly to the hoop stress to increase the onset of yielding.
Where the longitudinal stress σT is tensile the combined equivalent stress (σC) shall be
taken as the greater of σT or σH,
σC = ( )H T,Max σ σ , when
T0σ > . . . U2(13)
or alternatively use the von Mises Maximum Distortion Energy theory for biaxial stress
with shear:
σC = 2 2 2
H H T T3σ σ σ σ τ− + + . . . U2(14)
Which when the shear stress is zero reduces to:
σC = 2 2
H H T Tσ σ σ σ− + . . . U2(15)
Evaluate both tensile and compressive stress types.
U3 STRESSES IN UNRESTRAINED PIPELINES
This Clause provides the definition of stress terms, formulae and units for the evaluation of
stresses in unrestrained pipelines, denoting +ve as being tensile.
U3.1 Hoop or circumferential pressure stress (σH)
The Barlow formula for thin wall cylinders:
σH = D
2W
P D
t . . . U3(1)
where
PD = design pressure, in MPag
D = nominal external diameter, in mm
tW = required wall thickness, in mm
U3.2 Longitudinal pressure stress (σL)
The longitudinal stress from the capped end pressure effect
Lσ = H
0.5σ . . . U3(2)
Lσ =
D
W4
P D
t . . . U3(3)
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AS 2885.1—2007 252
Standards Australia www.standards.org.au
where
PD = design pressure, in MPag
D = nominal external diameter, in mm
tW = required wall thickness, in mm
U3.3 Thermal expansion stress (σE)
The unrestrained thermal expansion stress in isolation from other stress types, uniaxial with
shear, from the maximum shear stress theory:
σE = 2 2
b4σ τ+ . . . U3(4)
or alternatively, using the maximum distortion energy theory
σE = 2 2
b3σ τ+ . . . U3(5)
where
σb = the longitudinal bending stress, in MPa
τ = the resultant torsional shear stress, in MPa
Either the maximum shear stress theory or the maximum distortion energy theory may be
used, but shall be used consistently:
σb = ( ) ( )2 2
i it o oti M i M
Z
+
. . . U3(6)
τ = 2
M
Z . . . U3(7)
ii = stress intensification factor in plane
io = stress intensification factor out of plane
Mit = thermal bending moment in plane, in Nm
Mot = thermal bending moment out of plane, in Nm
M = torsional shear moment, in Nm
The section modulus (Z) to be used to calculate the bending and torsional stresses shall be
based on the wall thickness (tW) in Paragraph U3.1 above.
Evaluate two values of dT, from the installed temperature
Expansion (T1 − T) at the upper design temperature and
Contraction (T − T2) at the lower design temperature
U3.4 Bending stress (σw)
Bending stresses may be due to gravity from unsupported spans.
σw = ( ) ( )2 2
i ig o ogi M i M
Z
+
. . . U3(8)
ii = stress intensification factor in plane
io = stress intensification factor out of plane
Mig = gravity bending moment in plane, in Nm
Mog = gravity bending moment out of plane, in Nm
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253 AS 2885.1—2007
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The section modulus (Z) to be used to calculate the bending stress shall be based on the
wall thickness tW in Paragraph U3.1 above.
U3.5 Direct axial stresses σF and σother
U3.5.1 Direct stress from externally applied forces/displacements/pressure
σF = F
S
P
A . . . U3(9)
Consider both tensile and compressive stress type.
where
PF = direct axial force, in N
AS = ( )2 2
i
4
D Dπ −
, in mm2
D = nominal external diameter, in mm
Di = internal diameter (D − 2tW), in mm
tW = required wall thickness, mm
U3.5.2 Stress from other imposed force (σother)
Stress from forces other than those in Paragraph U3.5.1 are termed other stresses (σ other)
U3.6 Sustained stress (σsus)
σsus = σL + σW + σF + σother . . . U3(10)
Evaluate the maximum value of stress considering both tensile and compressive stress type
combinations.
U3.7 Total shear stress (τ )
The shear stress from sustained loads due to torsion
τt = t
2Z
M . . . U3(11)
where
Mt = torsion moment, in Nm
Z = section modulus based on tW in Paragraph U3.1 above
In addition, if direct (plane) shear stress is significant it shall be included in the calculation
of total shear stress.
Shear stress due to direct shear = τd
Total shear stress τ = τt + τd . . . U3(12)
U4 STRESSES IN ALL PIPELINE APPLICATIONS
U4.1 Occasional stress (σo)
σo = σsus + σocc . . . U4(1)
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AS 2885.1—2007 254
Standards Australia www.standards.org.au
where occ
σ is the stress from the occasional load.
σocc = ( ) ( )2 2
i io o oo
od
i M i M
Zσ
+
+ . . . U4(2)
ii = stress intensification factor in plane
io = stress intensification factor out of plane
Mio = occasional bending moment in plane, in Nm
Moo = occasional bending moment out of plane, in Nm
σod = direct longitudinal stress due to the occasional load, in MPa
Evaluate the maximum value. The section modulus (Z) to be used to calculate the
occasional stress shall be based on the wall thickness (tW) in Paragraph U3.1 above.
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255 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX V
EXTERNAL LOADS
(Informative)
V1 GENERAL
Clause 5.7.3(c) addresses the stresses due to transverse external loads and specifies that
stresses in pipelines crossing roads and railways are to be calculated by the methods defined
in API RP 1102; however, external loads can arise from a variety of situations not covered
by API RP 1102. This Appendix provides guidelines on methods and criteria for assessing
the acceptability of external loadings in general, with emphasis on those outside the scope
of API RP 1102.
The purpose of the information in this Appendix is to provide broad guidance and to
identify the key issues that need to be addressed when considering these other types of
external loadings. This Appendix is not intended to be a comprehensive design manual.
Users will need to obtain and use the referenced documents in order to acquire an
understanding of the methods discussed herein.
V2 API RPI 1102
API RP 1102 (1993) is based on research carried out by Gas Research Institute (GRI) from
1989-1991, and reported in the following documents:
GRI-91/0283: Guidelines For Pipelines Crossings Railroads
GRI-91/0284 : Guidelines For Pipelines Crossings Highways
GRI-91/0285 : Technical Summary and Database for Guidelines for Pipelines Crossings
Railroads and Highways.
The research involved a combination of analytical methods, finite element modelling and
experimental measurements. The latter consisted of strain gauging, which was used to
validate and calibrate the analytical and numerical modelling.
This broad foundation provides a high level of confidence in the results produced by the
API RP 1102 calculation procedures. For this reason API RP 1102 is the preferred approach
for the range of loads and depths of cover that are within its scope.
V3 LOAD SITUATIONS
Load situations, together with the recommended engineering methods, can be classified as
follows:
(a) Within the scope of API RP 1102
(Including all normal road and railway
crossing)
Use API RP 1102 (mandatory under this
Standard)
(b) Capable of conversion to an equivalent
API RP 1102 situation (e.g. some
loadings due to aircraft, heavy cranes,
etc.)
Convert to equivalent loading and use
API RP 1102
(c) All other load types Use another approved method
Situations (a), (b) and (c) above are discussed in the following Paragraphs of this Appendix.
All methods require interpretation of the loading to translate it into a form that is suitable
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AS 2885.1—2007 256
Standards Australia www.standards.org.au
V4 VEHICLE LOADS
API RP 1102 recommends vehicle loads be based on practice in the USA. Australian design
loads may be higher and should be used in preference to the API RP 1102
recommendations. Guidelines on Australian vehicle loads are as follows:
(a) State regulations on vehicle loads. These represent the legally permitted loads and
should be adopted as a lower bound for all cases
(b) The SM1600 suite of loads in AS 5100.2, Bridge design—Design loads, may be
adopted as a conservative upper bound and should be considered as a starting point
for most calculations. AS 5100.2 also provides information on dynamic load
allowance.
NOTE: SM1600 loads defined in AS 5100.2, Bridge design—Design loads, represent the
maximum load permitted for bridge design to this Standard, and includes allowance for
dynamic effects. Because most road infrastructure was designed to Standards current at the
time of their construction, State regulations on maximum vehicle loads are less than those
nominated in AS 5100.2. It is expected that as old infrastructure is replaced or upgraded, road
authority limits will be raised.
(c) Site-specific data for non-standard heavy haul roads (e.g. mine roads), if applicable,
should be used in preference to other load data.
Loads less than those specified in AS 5100.2 (but not less than the legally permitted loads)
may be used provided they are justified for the specific road crossing, including
consideration of the risk of overloaded vehicles and possible future increase in legal load
limits.
Relevant load cases from the AS 5100.2 are as follows:
(i) W80 wheel loading and A160 axle loading, comprising a single wheel and two-
wheeled axle respectively, with wheel load of 80 kN on a tyre footprint
400 × 250 mm, giving an applied surface pressure of 800 kPa.
(ii) M1600 moving traffic loading, a complex load footprint which for the purpose of
pipeline design consists of a series of axles each bearing 120 kN at spacings as close
as 1.25 m. Tyre footprint is 400 × 200 mm, giving an applied surface pressure of
750 kPa.
AS 5100.2 also nominates a dynamic load allowance (DLA) to account for the dynamic
effects of vehicles moving over typical road profile irregularities. The DLA at the surface
varies from 0 to 0.4 depending on the loading (W80, M1600, etc.) and decreases linearly
with depth. The design load is increased by factor of (1+DLA), which is equivalent to the
impact factor in API RP 1102. For the purposes of this Standard either the AS 5100.2 DLA
method or the API RP 1102 impact factor method may be used, although using the latter
with AS 5100.2 loading may be very conservative.
API RP 1102 distinguishes between single-axle and tandem-axle vehicle configurations and
provides guidance on which is the more critical; however, that guidance is applicable to the
API RP 1102 recommended loads. For Australian vehicle loads it is expected that the
tandem-axle configuration will always be more severe, and hence the tandem-axle values
for R and L should be selected from API RP 1102 Table 2.
V5 EQUIVALENT API RP 1102 LOADS
Because the results of an API RP 1102 analysis are considered to have a markedly higher
credibility than those from any other currently available method, it is reasonable to expect
that the best results for non-standard loadings will be achieved if the bearing pressure on
the ground can be converted to a form that is compatible with the assumptions of
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257 AS 2885.1—2007
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Suggested below are some conditions under which an equivalent-loads approach may be
valid. Care and judgement is required, and the greater the deviation from these conditions
the greater the care that has to be taken in interpreting the suitability of the application of
the method. Particular caution is necessary if cover is low; a load applied to the ground
surface in a discrete or irregular pattern will lead to soil stresses that are more uniform at
greater depth, but at shallow depth the pattern of soil stresses may remain irregular and may
not be a good approximation to the distributions of soil stresses on which API RP 1102 is
based.
For railway loads API RP 1102 considers the load from the rail vehicle to be applied to the
ground over an area 6.1 × 2.4 m (20 × 8 ft) to which a uniform pressure is applied. Other
loads that are widely spread may, with care, be converted to an equivalent load and used in
the API RP 1102 calculation. For example, the load due to a large tracked vehicle
(bulldozer or excavator) may be suitable for this approach.
For road vehicles API RP 1102 considers both single-axle and tandem-axle load patterns,
represented by two or four concentrated load application areas each of 0.093 m2 (144 in
2). It
may be possible to approximate other relatively concentrated loads by equivalent vehicle
loadings. Examples may include a crane outrigger placed temporarily over the pipe, an
aircraft loading (depending on the distribution of the load in both examples) or construction
vehicles.
This equivalent-load approach may be recommended only when—
(a) the area over which the load is applied is similar to the load footprint assumed by
API RP 1102;
(b) the load is evenly distributed over the load application areas;
(c) the magnitude of the load does not deviate greatly from the range of loadings covered
by API RP 1102; and
(d) the depth of cover is 0.9 m or more (if the API RP 1102 road crossing method is used)
or 1.8 m or more (if the API RP 1102 railway crossing method is used).
V6 OTHER DESIGN METHODS
Prior to the GRI research leading to API RP 1102, the standard method for analysis of
external loads on pipes was due to Spangler M.G. and Handy R.L. Soil Engineering, Harper
& Row, New York, 1982*. The GRI work cast various doubts on the validity of the
Spangler method for high pressure steel pipelines. GRI note that ‘At low internal pressures
the Spangler equations predict circumferential stresses much greater than those based on the
Cornell/GRI methodology. At high internal pressures, the two design methods are in
reasonable agreement …’, although the reason for the agreement is considered by the
researchers to be due to the counterbalancing of two spurious but opposing effects (pressure
re-rounding and springline soil support) rather than accurate representation of real
behaviour (GRI 91/0285, Executive Summary).
The Spangler method may be used, with appropriate caution, in situations where
API RP 1102 cannot be applied either directly or indirectly.
It is not appropriate here to present a full description of the Spangler methods; reference
documents should be consulted. Because this approach has been superseded (for most
purposes) since about 1990 the best reference material has become dated and may be hard
to obtain.
* Currently out of print, but may be available in libraries.
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AS 2885.1—2007 258
Standards Australia www.standards.org.au
Another reference is Guidelines for the Design of Buried Steel Pipe, American Lifelines
Alliance (ASCE/FEMA), July 2001 (PDF file available to download from
www.americanlifelinesalliance.org).
Other sources may also provide useful information.
There are two parts to the calculation of pipe stress due to external load:
(a) Determination of the loading applied to the top of the pipe, which is a relatively
straightforward problem in soil mechanics, and most soil mechanics texts will provide
a range of suitable methods.
(b) Calculation of the pipe stresses in response to the applied loading, which is where the
GRI researchers disagreed with the Spangler approach.
Designers using the Spangler approach should be familiar with the background to the
method, and its limitations, and interpret the results accordingly.
Consideration should also be given to the diametral deflection of the pipe, particularly
under condition of zero internal pressure. Out-of-roundness may interfere with the passage
of pigging devices during commissioning and operation.
Where circumferential stress, under zero or low internal pressure, is expected to be
significant under soil load or soil reaction, the pipe should be checked to ensure that
buckling or denting is avoided.
The guideline usually adopted is that the deflection should not exceed 5% of the pipe
diameter.
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259 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX W
COMBINED EQUIVALENT STRESS
(Informative)
W1 INTRODUCTION
This Standard (AS 2885.1) has limits for hoop stress, total longitudinal stress and combined
equivalent stress. These are provided in Clause 5.7. The stress types and their definitions
are given in Appendix U.
In this Standard combined equivalent stress limits are applicable only to that part of the
pipeline with full axial restraint. Combined equivalent stress means the stress calculated
from the combination of the three principal stresses using either the Tresca theory or the
von Mises theory of failure.
Where the total longitudinal stress is compressive, any increase in the design factor for
hoop stress from internal pressure will result in a corresponding reduction in the
permissible longitudinal stress because there has been no increase in the allowable value for
combined equivalent stress. There will also be a reduction in the thermal expansion (and/or
bending and axial) compressive stress components of the total longitudinal compressive
stress. In addition there will be a reduction in the permissible longitudinal tensile stress and
a reduction in the thermal (and/or bending and axial) tensile components of the total
longitudinal tensile stress.
This Appendix sets out a basis for evaluating the longitudinal thermal stresses and
corresponding permitted temperature differentials for the buried and fully restrained
pipeline. This Appendix assumes that there are not any bending or applied axial stress
components (which is typical of the restrained and fully supported pipeline) in the
calculation of longitudinal stresses. The methodology provided however could be extended
to include these effects where present by modifying the longitudinal stresses accordingly.
W2 DESIGN LIMITS
This Standard has a design factor related to internal pressure (circumferential hoop) stress
design. The upper limit of design factor is currently 0.80 for all location classes; however,
the hoop stress may be less than 80% SMYS where wall thickness is greater than that
required for pressure containment alone, such as resistance to penetration, prevention of
rupture and the like.
The limit for total longitudinal stress in this Standard is set at 72% SMYS. Where hoop
stresses are towards or at the upper limit allowed by the pressure design factor, permissible
longitudinal compressive stresses will be significantly lower than this limit because this
Standard requires combined equivalent stresses to be assessed and limited. This does not
apply to longitudinal tensile stresses, however, which may be the same as, but not greater
than, the limit allowed by the total longitudinal stress.
This Standard requires combined equivalent stresses to be assessed where longitudinal
stresses are combined with the internal circumferential pressure stress. The total
longitudinal stresses may be tensile or compressive or both. Similarly, the combination of
stresses applies to the less common torsional stresses. For the fully restrained pipeline,
however, there will not be any torsional stress and therefore torsional stress is not
considered further in this Appendix.
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AS 2885.1—2007 260
Standards Australia www.standards.org.au
This Appendix considers triaxial stresses without shear and the three directly applied
stresses have been taken to be the three principal stresses. Further, the radial pressure stress
has been taken to be zero because it is usually small compared to the other stresses in the
pipeline. Whilst the radial pressure stress has been taken to be zero, a triaxial stress state
still exists in the pipeline. Note that this is not the same as considering only a biaxially
stressed system.
The limits in this Standard for combined stresses are set at 90% SMYS for long-term
stresses. It also permits stresses to be combined using either the maximum shear stress
(Tresca) theory or the maximum distortion energy theory (von Mises).
W3 DISCUSSION OF DESIGN FACTOR, STRESS AND TEMPERATURE
The effect of a higher pressure-design factor (new design) or increased MAOP (upgrade)
will be to narrow the allowable longitudinal compressive (or torsional) stress limit. Using
the full internal pressure design factor of 0.72 for an existing pipeline, an increase to 0.80
will result in a reduction of the allowable longitudinal compressive stress from 50.50%
SMYS to 41.45% SMYS using the von Mises theory of failure (and from 39.6% SMYS to
34% SMYS using the Tresca theory of failure). Note that the von Mises theory permits
significantly higher longitudinal stresses than the Tresca theory for both compressive and
tensile stress.
If all of the total longitudinal stress less the longitudinal pressure component of stress is
attributed to thermal stress then for a change in design factor from 0.72 to 0.8 there will
also be a reduction in the maximum permitted upper temperature differential from 115°C to
95°C for Grade X80 material and from 50°C to 41°C for Grade B material using the von
Mises theory (Refer to Paragraph W5. of this Appendix for the derivation). For a tie in
temperature of 20°C the lowest value of maximum operating temperature is 61°C for Grade
B material. This is not considered to be a significant limitation to the use of a design factor
of 0.80 because temperatures are usually limited to 60°C for the majority of buried
pipelines. Buried pipelines with design temperatures above 60°C may require special
consideration anyway.
For longitudinal tensile stress there will also be a decrease in the net longitudinal stress and
a corresponding decrease in temperature differential. As longitudinal tension permits much
higher temperature design differentials than compression it is considered that the higher
design factor of 0.8 imposes no additional constraint on combined equivalent stress design
for design temperatures less than the closing temperature.
For those parts of the buried pipeline containing significant bending or applied axial loads
the thermal stresses and temperature differentials would be reduced below those values
stated above.
W4 DESIGN ENVELOPES
Values of combined equivalent stress from the von Mises and Tresca formulae given above
have been plotted against longitudinal thermal stress and the equivalent temperature
differential in the graphs for temperature and pressure provided at the end of this Appendix
as Figures W1 to W8 inclusive. These are the upper design bounds of the graphs for
temperature and pressure only.
Also plotted on the graphs are the plots of longitudinal thermal stress and the equivalent
temperature differential but for temperature only, excluding pressure. These are the lower
design bounds of the graphs. Together with the combined equivalent stress limit of 90%
SMYS these lines together then all form the design envelopes for the two theoretical bases
with separate design envelopes for design factors of 0.72 and 0.8.
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261 AS 2885.1—2007
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From the graphs it is possible to see the differences in the design envelopes over any
pressure/temperature combination or at the upper and lower limits of pressure and
temperature. One significant feature of these envelopes is that the combined equivalent
stresses resulting from the design values of temperature and pressure in combination cannot
lie outside them. In addition it should be noted that the vertical dotted lines represent the
design longitudinal thermal stress and temperature limits for full internal pressure and that
greater temperatures beyond these dotted lines are only compliant with AS 2885.1 at a
reduced value of pressure. For these greater temperatures the points considered still need to
lie within the boundaries of the envelopes.
It should be emphasised that these graphs apply only to positive internal pressure
differential and not to a negative internal pressure differential (external pressure). The latter
is subject to a different theoretical basis and constraints.
It should also be emphasised that apart from longitudinal pressure stress these graphs only
include longitudinal thermal stress and exclude any stresses from bending or from applied
loads.
The methodology provided in this Appendix could be adapted to consider additional
longitudinal stresses with or without thermal stress to consider the necessary compliance
with the limits of combined equivalent stresses required by this Standard.
It is the responsibility of the designer to ensure that all worst case analyses for appropriate
combinations of all of the necessary load cases are covered in the evaluation of the
combined equivalent stresses for compliance with this Standard.
W5 DERIVATION OF STRESS AND TEMPERATURE VALUES
Derivation of the allowable longitudinal compressive stress and tensile stress factors (of
yield) and temperature differentials for design factors of 0.72 and 0.8 for pipelines with full
axial restraint are provided in this section.
The following derives stress factors, longitudinal stresses and temperature differentials for
both the von Mises and Tresca theories of failure for the case of triaxial stress without
shear. Also provided are the calculated values of these parameters for design factors of 0.72
and 0.8 for Grade B and Grade X80 materials to demonstrate the differences between them
resulting from the different design factors and also from the different material strengths.
W5.1 The von Mises formula
f combined equivalent = ( ) ( ) ( )( )2 22
1 2 2 3 3 10.5 f f f f f f− + − + − . . . W5(1)
and where there is no shear stress:
1 Hf f= . . . W5(2)
2 H thermalf f fν= ± . . . W5(3)
3 Rf f= . . . W5(4)
where ƒ1, ƒ2 and ƒ3 are the three principal stresses, ƒH is the circumferential hoop stress and
ƒR is the radial pressure stress.
W5.1.1 For Fd = 0.72
Fd = 0.72
Putting the limit of combined stress at 0.9ƒy, ƒH = 0.72ƒy and taking ƒR = 0 then:
0.9fy = ( ) ( )2
2y L y L0.72 0.72f f f f+ − . . . W5(5)
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AS 2885.1—2007 262
Standards Australia www.standards.org.au
from which ƒL = -0.2890ƒy and +1.0090ƒy, where ƒy is the material yield strength.
However ƒL is not the longitudinal thermal compressive stress component (ƒcomp), it is the
net longitudinal stress. To derive the longitudinal thermal compressive stress component the
calculation has to consider the longitudinal tensile pressure stress (which is always present
in the buried pipeline as longitudinal stress together with the hoop pressure stress).
Hence—
fL = νfH − fcomp . . . W5(6)
= ( )y comp0.3 0.72 f f−
and as
fL = −0.2890fy
= ( )y comp y0.3 0.72 0.2890f f f− = −
From which f comp = 0.5050fy,
And f comp = −279 MPa for Gr X80 and –122 MPa for Gr B material.
Given that the preceding only applies to fully axially restrained pipe, the maximum upper
temperature differential that is permitted, assuming that there are no other longitudinal
stresses, can be established as follows:
fcomp = Eα∆T
∆T = 0.5050fy/Eα
= 0.2085fy (for E = 207 000 MPa and α = 11.7 × 10−6
per °C)
For Grade X80 pipe with ƒy = 552 MPa the allowable ∆T is 115°C.
For Grade B with ƒy = 241 MPa the allowable ∆T is 50°C.
For the tensile case:
fL = νfH + ftens . . . W5(7)
= ( )y tens0.3 0.72 f f+
And as yL ff 0090.1=
tens0.3(0.72 ) 1.0090
y yf f f+ =
from which, ƒtens = 0.793ƒy, where ƒtens is the longitudinal thermal tensile stress component,
and ƒtens = 438 MPa for Gr X80 and 191 MPa for Gr B material.
The corresponding ∆T’s are −180oC and −79
oC for Gr X80 and Gr B respectively.
W5.1.2 For Fd = 0.80
Putting the limits of combined stress at 0.9ƒy and ƒH = 0.80ƒy then:
0.9fy = ( ) ( )
22
y L y L0.80 0.80f f f f+ − . . . W5(8)
from which fL = −0.1745fy and + 0.9745fy
Hence
fL = νfH − fcomp
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263 AS 2885.1—2007
www.standards.org.au Standards Australia
= ( ) comp0.3 0.80
yf f−
And as
fL = − 0.1745fy
( ) comp0.3 0.80 0.1745
y yf f f− = −
from which fcomp = 0.4145fy,
and fcomp = −229 Mpa for GrX80 and −100 MPa for Gr B material.
Using the same logic as above, ∆T = 0.1711fy and:
For Grade X80 pipe with fy = 552 MPa the allowable ∆T is 95°C.
For Grade B with fy = 241 MPa the allowable ∆T is 41°C.
For the tensile case:
fL = νfH + ftens
= 0.3(0.80fy) + ftens
and as
fL = 0.9745fy
0.3(0.80fy) − fcomp = 0.9745fy
from which
ftens = 0.7345fy
and
ftens = 405 MPa for Gr X80 and 177 MPa for Gr B material.
The corresponding ∆T’s are −167°C and −73°C for Gr X80 and Gr B respectively.
W5.2 Tresca formulae
fcombined equivalent1 = f1 − f2 . . . W5(9)
fcombined equivalent2 = f2 − f3 . . . W5(10)
fcombined equivalent3 = f3 − f1 . . . W5(11)
and for triaxial stress without shear
f1 = fH, f2 = νfH ± fthermal, f3 = fR
then
fcel = fH − (νfH ± fthermal) . . . W5(12)
fce2 = (νfH ± fthermal) − fR . . . W5(13)
fce3 = fR − fH . . . W5(14)
For the upper bounds of pressure and temperature the maximum combined equivalent stress
and the corresponding maximum longitudinal thermal stress and temperature differential are
as follows:
For thermal compression fce1 governs until fcomp = νfH
For thermal tension fce2 governs until ftens = fH − νfH
Between these two points fce3 governs, and taking fR = 0 the factors are as follows
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AS 2885.1—2007 264
Standards Australia www.standards.org.au
W5.2.1 For Fd = 0.72
For compression:
0.9fy = 0.72(1 − 0.3) fy + fcomp
and fcomp = 0.3960fy
The corresponding stress and ∆t values are:
−219 MPa and 90°C in compression for Gr X80 material,
and
−95 MPa and 39°C in compression for Gr B material.
For tension:
0.9fy = ( ) y tens0.72 0.3 f f +
and ftens = 0.684fy
The corresponding stress and ∆T values are:
378 MPa and −156°C in tension for Gr X80 material,
and
165 MPa and −68°C in tension for Gr B material.
W5.2.2 For Fd = 0.80
For compression:
0.9fy = ( ) y comp0.80 1 0.3 f f− +
and fcomp = 0.340fy
The corresponding stress and ∆T values are:
−188 MPa and 78°C in compression for Gr X80 material,
and
−82 MPa and 34°C in compression for Gr B material.
For tension:
0.9fy = ( ) y tens0.80(0.3) f f+
and ftens = 0.660fy
The corresponding stress and ∆T values are:
364 MPa and −150°C in tension for Gr X80 material,
and
159 MPa and −66°C in tension for Gr B material.
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265 AS 2885.1—2007
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40
5
49
7
0 .00
100.00
200.00
300.00
400.00
500.00
600.00
600 400 200 0 200 400 600
LONGITUDINAL THERMAL STRESS, MPa(COMPRESSIVE OR TENSILE)
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
49
7
22
9
No
te
mp
Fd = 0.8
90% SMYS
SMYS = 552
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W1 VON MISES—COMBINED STRESS ENVELOPES GR X80
94
20
5
0 .00
100.00
200.00
300.00
400.00
500.00
600.00
300 200 100 0 100 200 300
TEMPERATURE DIFFERENTIAL, °C
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
20
5
16
7
No
te
mp
Fd = 0.80
90% SMYS
SMYS = 552
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W2 VON MISES—COMBINED STRESS ENVELOPES GR X80
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AS 2885.1—2007 266
Standards Australia www.standards.org.au
17
7
0 .00
50.00
100.00
150.00
200.00
250.00
300.00
300 400 100 0 100 200 300
LONGITUDINAL THERMAL STRESS, MPa(COMPRESSIVE OR TENSILE)
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
21
7
10
0
21
7
No
te
mp
Fd = 0.80
90% SMYS
SMYS = 241
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W3 VON MISES—COMBINED STRESS ENVELOPES GR B
0.00
50.00
100.00
150.00
200.00
250.00
300.00
150 100 50 0 50 100 150
TEMPERATURE DIFFERENTIAL, °C
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
41
90
90
73
Fd = 0.80
No
te
mp
90% SMYS
SMYS = 241
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W4 VON MISES—COMBINED STRESS ENVELOPES GR B
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267 AS 2885.1—2007
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36
4
49
7
0 .00
100.00
200.00
300.00
400.00
500.00
600.00
600 400 200 0 200 400 600
LONGITUDINAL THERMAL STRESS, MPa(COMPRESSIVE OR TENSILE)
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
49
7
18
8
No
te
mp
90% SMYS
SMYS = 552
Fd = 0.8
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W5 TRESCA—COMBINED STRESS ENVELOPE GR X80
77
20
5
0 .00
100.00
200.00
300.00
400.00
500.00
600.00
300 200 100 0 100 200 300
TEMPERATURE DIFFERENTIAL, °C
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
20
5
15
0
No
te
mp
90% SMYS
SMYS = 552
Fd = 0.8
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W6 TRESCA—COMBINED STRESS ENVELOPES GR X80
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AS 2885.1—2007 268
Standards Australia www.standards.org.au
15
9
21
7
0 .00
50.00
100.00
150.00
200.00
250.00
300.00
300 200 100 0 100 200 300
LONGITUDINAL THERMAL STRESS, MPa(COMPRESSIVE OR TENSILE)
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
82
21
7
No
te
mp
90% SMYS
SMYS = 241
Fd = 0.8
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W7 TRESCA—COMBINED STRESS ENVELOPES GR B
34
90
0 .00
50.00
100.00
150.00
200.00
250.00
300.00
150 100 50 0 50 100 150
TEMPERATURE DIFFERENTIAL, °C
CO
MB
INE
D E
QU
IVA
LE
NT
ST
RE
SS
, M
Pa
66
90
No
te
mp
90% SMYS
SMYS = 241
Fd = 0.8
NOTE: The total longitudinal stress will govern the permitted negative temperature difference in
design and not the combined equivalent stress.
FIGURE W8 TRESCA—COMBINED STRESS ENVELOPES GR B
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269 AS 2885.1—2007
www.standards.org.au Standards Australia
APPENDIX X
PIPE STRESS ANALYSIS
(Informative)
X1 GENERAL
This Appendix provides some commentary to aid in understanding the criteria for
longitudinal and combined equivalent stresses in Clause 5.7. Not addressed here are
limitations on hoop stress (no commentary required), and stresses due to transverse external
loads (discussed in Appendix V).
X2 FAILURE MODES AND CRITERIA
The stress criteria used in this Standard are based on limiting the allowable working stress
in the pipe.
For restrained pipe, the limitation on longitudinal stress (regardless of hoop stress) is
consistent with the margin of safety applied to hoop stress. It protects against local buckling
(wrinkling) if the load is compressive, and against failure at girth weld defects if the load is
tensile.
The limitation on the combined equivalent stress for restrained lines ensures that the biaxial
stress state resulting from combined axial and hoop stress does not approach the yield
condition. If the combined stress were to result in yielding the plastic deformation would be
in both the hoop and axial directions (the exact direction depending in a non-linear way on
the magnitude of each stress component). Compliance with this criterion prevents both
longitudinal and circumferential deformation.
For unrestrained pipe the limitation on longitudinal stress due to sustained loads provides a
large margin of safety against uncontrolled collapse due to loads, which continue to act as
the pipe deforms, (typically weight and internal pressure). Stresses due to temperature
changes are not included in the calculation as they are self-limiting and cannot contribute to
uncontrolled collapse.
The limitation on expansion stress ensures that the variation in stress through each thermal
cycle remains fully within the elastic range, i.e. no approach to yield. If yield was repeated
on every thermal cycle the variation in stress may rapidly lead to failure due to work
hardening; however, it is possible that yielding may occur the first time the pipe
experiences the full range of temperature. Calculation of the combined stress from sustained
and thermal expansion loads using the Tresca or Von Mises formula for an unrestrained
pipe (not required to be calculated by this Standard) can produce values above 100% SMYS
despite having individually acceptable values for longitudinal stress and expansion stress.
Such a calculation may indicate that yielding is likely. Such yielding is acceptable provided
it is not repeated. The limitation on expansion stress ensures that yielding does not recur.
There are no other failure modes associated with longitudinal or combined stresses for
normal pipelines. Hence the four criteria defined in the code as discussed above are
sufficient to provide a high degree of protection against failure. In unusual circumstances it
may be necessary to consider additional failure modes, such as buckling of laterally free but
axially restrained pipes.
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AS 2885.1—2007 270
Standards Australia www.standards.org.au
X3 RESTRAINED AND UNRESTRAINED PIPE
As noted above, the distinction between restrained and unrestrained pipe has implications
for the failure mode and hence the stress criteria. The distinction between them is not
always clear. An alternative terminology that is closely equivalent (and which assists
insight) is the distinction between displacement-controlled and load-controlled loading
conditions, such as used in DNV OS-F101 (AS 2885.4).
Fully restrained conditions normally occur only in long buried pipelines constrained by soil
friction, or in pipe controlled by anchors that are much stiffer than the pipe (difficult to
achieve in practice), and only when the pipe is more or less straight. Few other situations
offer sufficient resistance to the very high axial force that may occur in a fully restrained
pipe. Conditions approximating full restraint are common, and the stress criteria for fully
restrained pipe should be applied.
In a fully restrained pipe, temperature changes result in the development of axial stress with
zero change in pipe length, and imposed axial displacements are absorbed entirely by axial
strain of the pipe. It is therefore straightforward to calculate the theoretical maximum axial
force and stress due to temperature change in a fully restrained straight pipe length.
Unrestrained pipe occurs where the restrictions on pipe movement are relatively minor,
such as piping at scraper stations and the like. Buried pipe bends of large angle, and
particularly of small radius (e.g., 90° induction bends), are also effectively unrestrained
because the resistance offered by the soil is small relative to the forces in the pipe.
In practice, pipes are frequently partly restrained in that they are not completely free of
axial restraint but the restraint is not sufficient to develop the very high axial force that
develops in a fully restrained pipe.
In cases where the restraint status is unclear it is suggested that consideration also be given
to the following:
(a) The magnitude of the axial force in the pipe relative to the theoretical maximum force
required to fully restrain the pipe.
(b) The loading condition (displacement-controlled or load-controlled).
(c) The possible failure modes.
If the pipe is not vulnerable to collapse due to the action of sustained loads then it is likely
that it should be considered as restrained. If the pipe is subject to bending moments and the
expansion stress is significant then it may be prudent to apply the criteria for unrestrained
pipe.
If doubt still remains regarding the type of restraint condition to be considered then the
stress criteria for both restrained and unrestrained situations should be checked.
X4 SUSTAINED AND SELF-LIMITING LOADS
Sustained loads (i.e. those that continue to act undiminished as the pipe deforms) consist
mainly of those due to internal pressure and weight. Certain other loads such as those due to
wind, water and earthquake may also be considered as sustained but are rarely encountered
as pipe loads. Stresses due to sustained loads are also known as primary stresses.
Self-limiting loads (i.e. those that are relieved as the pipe deforms) consist of those due to
thermal expansion/contraction and displacements imposed by the movement of anchors,
pipe supports or the surrounding ground. Stresses due to such loads are also known as
secondary stresses.
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271 AS 2885.1—2007
www.standards.org.au Standards Australia
X5 THEORIES OF FAILURE (TRESCA AND VON MISES)
There are a number of theories of failure, of which the two most commonly used are known
as the Maximum Shear Stress theory due to Tresca and the Maximum Distortion Energy
theory due to von Mises. These two theories are the most appropriate for ductile materials
such as steel linepipe. Each theory predicts that yielding will commence when the combined
equivalent stress (calculated from the appropriate formula) exceeds the uniaxial yield stress
of the material in simple tension. Figure X1 shows the yield locus for each of the two
theories. Stress combinations that fall on the locus are at the point of yielding while those
inside are still in the elastic range.
It is clear from the figure that the von Mises theory predicts somewhat greater stresses in
certain regions (up to about 15% higher) than the Tresca theory. The Tresca criterion is
more conservative, and because it is simpler to calculate it is a useful basis for quick
assessment of cases where there is no incentive to maximise the predicted combined
equivalent stresses in the pipe. This Standard permits either theory of failure to be used, but
once one theory is adopted it should be used throughout unless the most conservative
combinations of the two theories are used. Calculations carried out to API RP 1102 need
not be included in this consideration.
0.5
0.5
1
0.5 0 0.5 1
Axial stresscompression
Hoop stresscompression
Hoop stresstension
Axial stresstension
LEGEND:
= Tresca = von Mises
1.5
1.5
1
11.5 1.5
NOTES:
1 Only the right hand half of the diagram is relevant to pipelines with positive internal pressure and therefore
tensile hoop stress.
2 f1 and f2 are the principal stresses:
f1 = hoop stress
f2 = axial stress
FIGURE X5 TRESCA AND VON MISES YIELD LOCI
(FOR A TWO-DIMENSIONAL STRESS SYSTEM WITHOUT SHEAR)
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AS 2885.1—2007 272
Standards Australia www.standards.org.au
X6 YIELDING
The term yielding of the pipe is used in the Standard and may have different values for the
same pipe depending on the way in which it is derived and the context in which it is used.
Some of the meanings relating to yielding are as follows:
(a) The result from a sample specimen tested in simple tension to determine the yield
point of the material under test
(b) The result from a sample specimen tested using the ring expansion test to determine
the yield point of the material under test
(c) The prediction of the onset of yield in a tubular cylinder from internal pressure using
the Barlow formula and the SMYS of the material being considered
(d) The prediction of the onset of yield using an equivalent stress theory such as the
Tresca or von Mises formula
(e) The end point in a volume-strain controlled hydrostatic pressure test equal to 0.4%
offset volume strain.
Each of these references will have a different numerical value for a particular application.
The terms yield, yielding, and yield pressure should be qualified by the basis to which they
are being referred.
The references in Items (a) and (b) above relate to the establishment of the yield point (or
SMYS) using a specimen flattened from a circular test piece and a tubular specimen
expanded in a ring test respectively. The yield stress for a pipe is determined in accordance
with API 5L, which defines it as the stress corresponding to 0.5% total strain. In normal
linepipe steel this yield stress is at a point on the stress-strain curve where there has already
been a small amount of plastic strain.
Before and during the hydrostatic pressure test the onset of yield may be predicted from
Item (c) above for monitoring the expected deviation from the slope of the P-V plot during
pressurization.
The theories of failure in Item (d) above relate to the evaluation of the equivalent stresses
and comparison to the value of yield in simple tension. These references are appropriate to
the design evaluation of the stress conditions from the applied loads. These theories are also
used in comparing the strength of the pipe steel in the mill pressure test to the in ground
strength of the pipeline. For more discussion of this aspect of yield refer to AS 2885.5.
X7 COMPUTATION OF STRESSES
It is normal to use proprietary pipe stress analysis software to calculate stresses and
compare them with the allowable criteria, although there is no reason why calculations
should not be done by hand, spreadsheet, or general purpose, finite element software. A
major advantage of using proprietary pipe stress analysis software is that it can greatly
simplify the comparison of calculated stresses with the specified code criteria. Users of this
Standard may wish to note that the stress criteria adopted in this Standard are functionally
identical with those of ANSI/ASME B31.4, and ANSI/ASME B31.4 code calculations in
standard software may be used without modification; however, the allowable stress limits
in: ANSI/ASME B31.4 may need to be amended to comply with this Standard.
Expansion stresses shall be evaluated from installation temperature to upper operating
temperature and installation temperature to lower operating temperature, as required by this
Standard. There is no requirement in this Standard to evaluate the stress range of upper
operating temperature to lower operating temperature for thermal expansion as required by
ANSI/ASME B31.4.
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273 AS 2885.1—2007
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The appropriate design factor and other factors relating to allowable stress criteria of this
Standard will need to be considered. For example the default design factor to
ANSI/ASME B31.4 may be 0.72 and may need to be overridden in the input file where the
design factor has some other value to this Standard. The occasional load factor may also
need to be overridden to conform to the requirements of this Standard. The longitudinal
joint factor for pipes manufactured in accordance with this Standard will be unity. The
correct insertion of these factors will need to be confirmed by the users of the software.
Where factors are overridden in proprietary software, the software may not issue a
compliance statement to ANSI/ASME B31.4. This is acceptable provided the allowable
limits of this Standard are not exceeded.
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AS 2885.1—2007 274
Standards Australia www.standards.org.au
APPENDIX Y
RADIATION CONTOUR
(Informative)
Y1 GENERAL
This Standard requires consideration of the consequence distance considered in terms of
radiation intensities of 4.7 kW/m2 and 12.6 kW/m
2.
The Standard provides guidance on the method of calculating the energy release rate, and
the radius of the radiation contour for gas pipelines.
This Appendix presents the radiation contour radius for pipeline 30 seconds after rupture
for typical pipelines with maximum allowable operating pressure of 15.3 MPa, 10.2 MPa
and 5.1 MPa.
The energy release rate was computed using the transient program FLOWTRAN for the
following conditions:
1 Pipeline length 50 km
2 Assumed rupture point Midpoint
3 Initial conditions Pipeline at MAOP
4 Pipeline inlet connection Constant pressure
5 Gas specific energy 39.5 MJ/scm
6 Pipeline temperature 20°C
7 Pipeline roughness 18 micron
8 Pipeline thickness Typical for MAOP
The radiation contour is calculated using Equation 20 from API RP 521:
D = 4
FQ
K
τ
π
where
D = minimum distance from the midpoint of the flame to the object being
considered, (m)
τ = fraction of heat intensity transmitted (1.0)
F = fraction of heat radiated (assumed 0.25)
Q = heat release (lower heating value) in kW)
K = allowable radiation, (kW/m2)
NOTE: The value of F varies with the size of the release, and the composition of the gas. F = 0.25
is a little conservative, reflecting values typical of a DN 400 pipe and a ‘typical’ rich
transmission pipeline gas. Less conservative values may be justified for specific designs.
The calculation results are presented in the following figures:
1 Figure Y1 Radiation contour radius—15.3 MPa
2 Figure Y2 Radiation contour radius—10.2 MPa
3 Figure Y3 Radiation contour radius—5.1 MPa
4 Figure Y4 Energy release rate (GJ/s)
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275 AS 2885.1—2007
www.standards.org.au Standards Australia
The information presented in these figures have to be considered as ‘typical’.
The energy release rate is pipeline dependent. Designers should consider differences
between the pipeline used to compute the radiation contours presented in this Appendix and
the pipeline being designed and assessed, and appropriate allowance (or pipeline specific
calculations) made. Factors that affect the calculation output include:
1 The gas higher heating value
2 Significant differences in the pipeline length
3 The pipeline hydraulic roughness (very smooth – internally lined pipe, or poorly
maintained, rough pipe)
4 Changes in the gas quality which affect the flame emissivity
0
200
400
600
800
1000
1200
0 100 200 300 400 500 600 700 800
NOMINAL PIPE DIAMETER
RA
DIA
TIO
N C
ON
TO
UR
RA
DIU
S,
m
LEGEND: = 4.7 kW/m2
= 12.6 kW/m2
FIGURE Y1 RADIATION CONTOUR RADIUS—RUPTURE—15.3 MPa
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AS 2885.1—2007 276
Standards Australia www.standards.org.au
0
100
200
300
400
500
600
700
800
900
0 100 200 300 400 500 600 700 800
NOMINAL PIPE DIAMETER
RA
DIA
TIO
N C
ON
TO
UR
RA
DIU
S,
m LEGEND: = 4.7 kW/m2
= 12.6 kW/m2
FIGURE Y2 RADIATION CONTOUR RADIUS—RUPTURE—10.2 MPa
0
100
200
300
400
500
600
700
0 100 200 300 400 500 600 700 800
NOMINAL PIPE DIAMETER
RA
DIA
TIO
N C
ON
TO
UR
RA
DIU
S,
m
LEGEND: = 4.7 kW/m2
= 12.6 kW/m2
FIGURE Y3 RADIATION CONTOUR RADIUS—RUPTURE—5.1 MPa
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277 AS 2885.1—2007
www.standards.org.au Standards Australia
0
50
100
150
200
250
300
0 100 200 300 400 500 600 700 800
NOMINAL PIPE DIAMETER
EN
ER
GY
RE
LE
AS
E R
AT
E,
GJ/
s
LEGEND: = 15.3 MPa = 10.2 MPa = 5.1 MPa
FIGURE Y4 ENERGY RELEASE RATE—RUPTURE
Y2 LIQUID HYDROCARBON PIPELINES
The energy release rate from liquid hydrocarbon pipelines is not addressed in this
Appendix.
For these pipelines, the consequence distance is pipeline specific, and requires
consideration of a range of pipeline and fluid characteristics as follows:
(a) The hydrocarbon volume released until the failure is detected and the failed section is
isolated.
(b) The fluid characteristics (e.g. HVPL, gasoline, stable oil etc.)
(c) The topography.
NOTE: The release rate in a hydrocarbon liquid line may exceed the pump rate depending on the
elevation change in the section.
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AS 2885.1—2007 278
Standards Australia www.standards.org.au
APPENDIX Z
REINFORCEMENT OF WELDED BRANCH CONNECTIONS
(Normative)
Z1 SCOPE
This Appendix defines the requirements for reinforcement of fabricated branch connections.
It applies to branch connections other than those consisting solely of pipe and pressure
rated components (forged tees, extruded outlets, integrally reinforced fittings, proprietary
split tees).
Z2 REINFORCEMENT OF SINGLE WELDED BRANCH CONNECTIONS
A single welded branch connection shall be reinforced in accordance with the following:
(a) The reinforcement required in the crotch of a welded branch connection shall be
determined by the requirement that the area of metal available for reinforcement shall
be not less than the required cross-sectional area defined in Figure Z2(A).
(b) The area that can be counted for reinforcement must lie within the Boundary of
Reinforcement (see Figure Z2(A)).
(c) The material of any added reinforcement shall have strength equal to that of the
header wall, but, where material of lower strength is used, the area shall be increased
in direct ratio to the specified strengths for header and reinforcement material
respectively.
(d) The material used for ring or saddle reinforcement may be to a specification differing
from that of the pipe, provided the cross-sectional area is made in correct proportions
to the relative strength of the pipe and reinforcing materials at the operating
temperatures and provided it has welding qualities compatible with those of the pipe.
No allowance shall be made for the additional strength of material having a higher
strength than that of the part to be reinforced.
(e) Where rings or saddles are used and these cover the weld between branch and header,
a vent hole shall be provided in the ring or saddle to reveal leakage in the weld
between branch and header and to provide venting during welding and heat treatment.
NOTE: Vent holes should be plugged during service to prevent crevice corrosion between the
pipe and the reinforcing member, but the plugging material should not be capable of retaining
pressure within the crevice.
(f) The use of ribs or gussets should not be considered as contributing to reinforcement
of the branch connection. Ribs or gussets may be used for purposes other than
reinforcement, such as stiffening.
(g) The branch shall be attached by a weld for the full thickness of the branch or header
wall plus a fillet weld (W1) as shown in Figure Z2(C). Concave fillet welds should be
used to minimize corner stress concentration. Pad or saddle reinforcement shall be
attached as shown in Figure Z2(D).
NOTE: Where a full fillet weld is not used, it is recommended that the edge of the
reinforcement be relieved or chamfered at approximately 45 and meld with the edge of the
fillet.
(h) Reinforcement rings and saddles shall be fitted accurately to the parts to which they
are attached. Figure Z2(B) and Figure Z2(D) illustrate some forms of reinforcement.
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279 AS 2885.1—2007
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(i) Unwelded sections of saddles or rings (such as are illustrated as ‘optional weld’ in
Figure Z2(B) shall be sealed at the edges with a suitable compound to prevent the
entry of corrosive matter.
(j) Where the reinforcing member is attached to the header by a fillet weld, the weld
shall be continuous and the edges of the reinforcing member shall be tapered to a
thickness not greater than twice the thickness of the header.
(k) The inside edge of the finished opening, wherever possible, shall be rounded to 3 mm
radius.
Z3 Reinforcement of multiple openings
Z3.1 Overlapping of effective reinforcement areas
Where two or more adjacent branches are spaced at a distance less than 2 times their
average diameter (so that their effective areas of reinforcement overlap), the group of
openings shall be reinforced in accordance with Paragraph Z2. The reinforcing metal shall
be added as a combined reinforcement, the strength of which shall equal the combined
strengths of the reinforcements that would be required for the separate openings. A portion
of a cross-section shall not be applied to more than one opening or be evaluated more than
once in a combined area.
Z3.2 Minimum distance between adjacent openings
Where more than two adjacent openings are to be provided with a combined reinforcement,
the area of reinforcement between them shall be not less than half of the total required for
these two openings on the cross-section being considered.
NOTE: The minimum distance between centres of any two of these openings should preferably be
not less than the product of 1.5 and the average diameter of both openings.
Where the distance between centres of two adjacent openings is less than the product of
1.33 and their average diameter, no allowance shall be made for the reinforcement metal
between these two openings.
Z3.3 Closely spaced openings
Any number of closely spaced adjacent openings, in any arrangement, may be reinforced
provided the group is treated as one opening which has a diameter that would enclose all
the closely spaced openings.
Z4 EXTRUDED OUTLET
An extruded outlet may be used if it is determined by investigation and, if needed, tests that
such an outlet is suitable and safe for the proposed service and MAOP.
One method of a design for an extruded outlet is given in ASME B31.8. Other methods
shall be approved.
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AS 2885.1—2007 280
Standards Australia www.standards.org.au
LEGEND:l = greater of l1 and l2l1 = internal d iameter of branchl2 = length of f in ished opening in the headerl3 = l 0.5 l2lA = smal ler of 2.5 t WH and ( tR 2.5 t WB)
A1 = l3 ( t WH tPH)A2 = lA ( t WB tPB)A3 = area of added reinforcement inc luding weld area
tPB = pressure wal l th ickness of a branch (see Clause 5.4.3 )tPH = pressure wal l th ickness of a header (see Clause 5.4.3 )tR = actual (determined by measurement) or nominal th ickness of the added reinforcementt WB = required wal l th ickness of the branch (= t N G , see Clause 5.4.1)t WH = required wal l th ickness of the header
REQUIREMENTS:Reinforcement area required, (AR) = l2 tPHReinforcement area, A = 2 (A1 A2 A3)Reinforcement design is sat isf ied when A AR
l3
l
A3
A2
AR
tPHt WH
A1
l1
Boundary ofreinforcement
lA
tPB
t WB
tR
l2
FIGURE Z2(A) AREA OF REINFORCEMENT OF A BRANCH CONNECTION
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281 AS 2885.1—2007
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(a) Tee type (b) Sleeve type
Opt ionalweld Opt ional
weld
These longi tudinalwelds may belocated anywherearoundcircumference
(c ) Saddle and s leeve type (d) Saddle type
Opt ionalweld Opt ional
weld
Opt ionalweld Opt ional
weld
FIGURE Z2(B) WELDING DETAILS FOR BRANCH CONNECTIONS WITH COMPLETE
ENCIRCLEMENT TYPES OF REINFORCEMENTS
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AS 2885.1—2007 282
Standards Australia www.standards.org.au
W
N
45° min.
(a) Set- in branch
t WB
t WH
(b) Si t-on branch
t WB
t WH
W1
N 45° min.
LEGEND:N = 1.5 mm minimum, 3 mm maximum (unless welded from both s ides or a backing str ip is used)t WB = required wal l th ickness of a branch (see Note)t WH = required wal l th ickness of a header (see Note)W1 = 0.375 t WB but not less than 6 mm
NOTE: A welding pad, saddle or encircling reinforcement, when used, shall be inserted over these types of
connections see Figure Z2(D).
FIGURE Z2(C) WELDING DETAILS FOR THE BRANCH CONNECTIONS WITHOUT
REINFORCEMENT OTHER THAN THAT IN THE
WALLS OF THE PIPE, HEADER OR BRANCH
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283 AS 2885.1—2007
www.standards.org.au Standards Australia
(a) Pad type reinforcement
W1
W2
W1
W2
W1
W2
W1
W2
(b) Saddle type reinforcement
W4
W3 W3
W4
W3 W3
LEGEND:W1 (minimum) = 0.375 t WB but not less than 6 mmW2 (minimum) = 0.5 tR but not less than 6 mmW3 (minimum) = tR but not less than t WHW4 (minimum) = tR but not less than t WHwheret WB = required wal l th ickness of a brancht WH = required wal l th ickness of a header tR = actual (by measurement) or nominal th ickness of the added reinforcement
N
NOTES:
1 All welds shall have equal leg dimensions and the minimum size of the throat to be 0.7 × leg dimension.
2 If tR is thicker than tWH the reinforcing member shall be tapered to the wall thickness header.
FIGURE Z2(D) WELDING DETAILS FOR BRANCH CONNECTIONS WITH LOCALIZED
TYPE REINFORCEMENT
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AS 2885.1—2007 284
NOTES
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Standards AustraStandards AustraStandards AustraStandards Australialialialia Standards Australia develops Australian Standards® and other documents of public benefit and national interest. These Standards are developed through an open process of consultation and consensus, in which all interested parties are invited to participate. Through a Memorandum of Understanding with the Commonwealth Government, Standards Australia is recognized as Australia’s peak non-government national standards body. Standards Australia also supports excellence in design and innovation through the Australian Design Awards. For further information visit www.standards.org.auwww.standards.org.auwww.standards.org.auwww.standards.org.au Australian StandardsAustralian StandardsAustralian StandardsAustralian Standards®®®® Committees of experts from industry, governments, consumers and other relevant sectors prepare Australian Standards. The requirements or recommendations contained in published Standards are a consensus of the views of representative interests and also take account of comments received from other sources. They reflect the latest scientific and industry experience. Australian Standards are kept under continuous review after publication and are updated regularly to take account of changing technology. International InvolvementInternational InvolvementInternational InvolvementInternational Involvement Standards Australia is responsible for ensuring the Australian viewpoint is considered in the formulation of International Standards and that the latest international experience is incorporated in national Standards. This role is vital in assisting local industry to compete in international markets. Standards Australia represents Australia at both the International Organization for Standardization (ISO) and the International Electrotechnical Commission (IEC). Sales and DistributionSales and DistributionSales and DistributionSales and Distribution Australian Standards®, Handbooks and other documents developed by Standards Australia are printed and distributed under license by SAI Global Limited.
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For information regarding the development of Standards contact: Standards Australia Limited GPO Box 476 Sydney NSW 2001 Phone: 02 8206 6000 Fax: 02 8206 6001 Email: [email protected] Internet: www.standards.org.au For information regarding the sale and distribution of Standards contact: SAI Global Limited Phone: 13 12 42 Fax: 1300 65 49 49 Email: [email protected]
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