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AS 2885.3—2012

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AS 2885.3—2012

Australian Standard®

Pipelines—Gas and liquid petroleum

Part 3: Operation and maintenance

This Australian Standard® was prepared by Committee ME-038, Petroleum Pipelines. It was approved on behalf of the Council of Standards Australia on 6 March 2012. This Standard was published on 20 September 2012.

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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 Petroleum Production and Exploration Association Australian Pipeline Industry Association Bureau of Steel Manufacturers of Australia Department for Manufacturing, Innovation, Trade, Resources and Energy (SA) Department of Labour New Zealand Department of Mines and Petroleum (WA) Department of Natural Resources and Mines (Qld) Department of Resources (NT) Energy Networks Association Energy Safe Victoria Gas Association of New Zealand New Zealand Institution of Gas Engineers NSW Department of Trade and Investment, Regional Infrastructure and Services Petroleum Exploration and Production Association New Zealand Welding Technology Institute of Australia

Additional Interests: •

Independent Chairperson

This Standard was issued in draft form for comment as DR AS 2885.3. Standards Australia wishes to acknowledge the participation of the expert individuals that contributed to the development of this Standard through their representation on the Committee and through the public comment period.

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 Standards may also be withdrawn.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

AS 2885.3—2012

Australian Standard®

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Pipelines—Gas and liquid petroleum Part 3: Operation and maintenance

Originated in part as AS CB28—1972. Revised and redesignated AS 2885.3—1997. Third edition 2012.

COPYRIGHT © Standards Australia Limited All rights are reserved. No part of this work may be reproduced or copied in any form or by any means, electronic or mechanical, including photocopying, without the written permission of the publisher, unless otherwise permitted under the Copyright Act 1968. Published by SAI Global Limited under licence from Standards Australia Limited, GPO Box 476, Sydney, NSW 2001, Australia ISBN 978 1 74342 214 4

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PREFACE This Standard was prepared by the joint Standards Australia/Standards New Zealand Committee ME-038, Petroleum Pipelines, to supersede AS 2885.3—2001. This Standard is the result of a consensus among Australian and New Zealand representatives on the Joint Committee to produce it as an Australian Standard. The objective of this Standard is to provide important principles, practices and guidelines for use by competent persons and organizations involved in the operation and maintenance of high-pressure petroleum pipelines. Significant changes in this revision

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This Standard is a result of a comprehensive revision of AS 2885.3—2001. It reflects significant changes that have taken place in the industry and within the regulatory environment since the original publication. It has been revised to reflect these changes and is based on a management system philosophy. The changes to the Standard enable it to be viewed as a stand-alone document whilst retaining and strengthening the references to AS 2885.1, Pipelines—Gas and liquid petroleum, Part 1: Design and construction and AS 2885.2, Pipelines—Gas and liquid petroleum, Part 2: Welding. The readability of the document has been improved by drawing together like requirements into common sections and basing the structure on the pipeline lifecycle. It also incorporates changes— (a)

to harmonize it with AS 2885.0, Pipelines—Gas and liquid petroleum Part 0: General requirements, AS 2885.1, Pipelines—Gas and liquid petroleum, Part 1: Design and construction and AS 2885.5, Pipelines—Gas and liquid petroleum, Part 5: Field pressure testing (Section 2), to eliminate inconsistencies between the parts; and

(b)

to recognize agreement by Committee ME-038 to adopt a change to the use of ‘Approval’ as defined in AS 2885.0.

The most important changes include the following: (i)

The inclusion of a new section ‘Pipeline management system’ (Section 2) incorporating management system elements and a governance approach. NOTES: 1 This has required the removal of the term ‘safety and operating plan’ to allow for the many document naming conventions around Australia and within the industry. 2 This revision has been reviewed and updated to correlate with the requirements of ‘safety case’ regimes.

(ii)

The inclusion of a new section ‘Anomaly assessment and defect repair’ (Section 9); ‘anomaly assessment and repair’ identified as a weakness in the previous version. This Section provides a level assessment approach to anomaly assessment and includes greater guidance on assessing a broader range of pipe wall anomalies. MOP is introduced to provide an operational parameter that can be adjusted within the limitations of MAOP and provide a basis for safe operation of a pipeline during anomaly assessment and defect repair. A table for glass-reinforced epoxy pipeline defect assessment has also been included for guidance.

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AS 2885.3—2012

(iii) An update to pipeline integrity management. A new requirement has been introduced to develop a pipeline integrity management plan (PIMP) to provide a greater focus on the technical aspects of integrity management. (iv)

The inclusion of a station integrity section, to group all station operation and maintenance issues together and acknowledge that stations needed a greater level of guidance as they are becoming more complex and integrated into pipeline infrastructure.

(v)

An update to the ‘Change of operating conditions and remaining life review’ (Section 10) to include remaining life review. ‘Review of design life’ has been changed to ‘Remaining life review’ so that the focus is on how long the asset will be fit for purpose and to integrate with an integrity management approach for the life of the asset.

(vi)

The incorporation of an appendix to indicate how the pipeline management system approach aligns to safety case regimes.

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(vii) A revision of the ‘Pipeline structural integrity’ (Section 6) relating to coating systems and cathodic protection. (viii) The modification and update environmental management’ such as job hazard analysis industry has adopted these industry.

of safety and environment issues into a ‘Site safety and (Section 4). Inclusion of common industry procedures and permit to work to acknowledge that the pipeline practices and adapted them for specific use in this

(ix)

An update to the ‘External interference management’ (Section 7). Revision of this Section included classification of external interference controls into detection and control and addition of guidance on vehicle load limits.

(x)

Minor updates to other section (e.g. Record management), where required.

(xi)

An update of a ‘Site safety and environmental management (Section 4)’ section to cover specific issues relating to pipeline operation and maintenance activities.

The terms ‘normative’ and ‘informative’ are used in this Standard to define the application of the appendix to which they apply. A ‘normative’ appendix is an integral part of a Standard, whereas an ‘informative’ appendix is only for information and guidance.

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CONTENTS Page SECTION 1 SCOPE AND GENERAL 1.1 SCOPE ......................................................................................................................... 7 1.2 APPROVAL ................................................................................................................ 7 1.3 APPLICATION ........................................................................................................... 7 1.4 RETROSPECTIVE APPLICATION ........................................................................... 7 1.5 NORMATIVE REFERENCES .................................................................................... 8 1.6 DEFINITIONS............................................................................................................. 8 1.7 ABBREVIATIONS ................................................................................................... 13

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SECTION 2 PIPELINE MANAGEMENT SYSTEM 2.1 BASIS OF SECTION ................................................................................................ 15 2.2 PIPELINE MANAGEMENT SYSTEM ELEMENTS ............................................... 15 SECTION 3 PREPARATION FOR OPERATION 3.1 BASIS OF SECTION ................................................................................................ 21 3.2 PREREQUISTES ....................................................................................................... 21 3.3 READINESS FOR OPERATION .............................................................................. 21 3.4 HANDOVER TO OPERATIONS .............................................................................. 22 3.5 DELAYED COMMENCEMENT OF OPERATION ................................................. 22 SECTION 4 SITE SAFETY AND ENVIRONMENTAL MANAGEMENT 4.1 BASIS OF SECTION ................................................................................................ 24 4.2 WORK HOURS AND FATIGUE .............................................................................. 24 4.3 REMOTE TRAVEL................................................................................................... 24 4.4 FIRST AID REQUIREMENTS ................................................................................. 24 4.5 JOB HAZARD ANALYSIS (JHA) ............................................................................ 25 4.6 PERMIT TO WORK (PTW) SYSTEM ..................................................................... 26 4.7 ENVIRONMENTAL MANAGEMENT .................................................................... 27 4.8 FLUID HAZARDS .................................................................................................... 29 4.9 VENTING AND PURGING PIPELINES .................................................................. 29 4.10 WORKING ON LIVE PIPELINES—SPECIFIC REQUIREMENTS AND GUIDANCE .............................................................................................................. 31 SECTION 5 PIPELINE INTEGRITY MANAGEMENT 5.1 BASIS OF SECTION ................................................................................................ 34 5.2 PIPELINE INTEGRITY MANAGEMENT PROCESS ............................................. 34 5.3 REVIEW OF PIPELINE INTEGRITY MANAGEMENT PLAN (PIMP).................. 35 SECTION 6 PIPELINE STRUCTURAL INTEGRITY 6.1 BASIS OF SECTION ................................................................................................ 36 6.2 STRUCTURAL INTEGRITY MANAGEMENT OVERVIEW ................................. 36 6.3 PIPELINE OPERATION AND CONTROL .............................................................. 37 6.4 PIPELINE CORROSION PROTECTION ................................................................. 37 6.5 PIPE WALL INTEGRITY ......................................................................................... 40 6.6 INSPECTION ACTIVITIES ...................................................................................... 40 6.7 MAINTENANCE PLAN—PIPELINE ...................................................................... 42

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SECTION 7 EXTERNAL INTERFERENCE MANAGEMENT 7.1 BASIS OF SECTION ................................................................................................ 43 7.2 EXTERNAL INTERFERENCE ................................................................................. 43 7.3 THIRD-PARTY PIPELINE AWARENESS .............................................................. 43 7.4 EXTERNAL INTERFERENCE DETECTION .......................................................... 44 7.5 EXTERNAL INTERFERENCE CONTROL ............................................................. 46 SECTION 8 STATIONS OPERATIONS AND MAINTENANCE 8.1 BASIS OF SECTION ................................................................................................ 50 8.2 SAFETY OF CRITICAL EQUIPMENT .................................................................... 50 8.3 PRESSURE VESSELS .............................................................................................. 50 8.4 STATION OPERATIONAL CHECKS ...................................................................... 51 8.5 STATION STRUCTURAL INTEGRITY .................................................................. 51 8.6 COMPRESSOR AND PUMP STATIONS ................................................................ 52 8.7 MAINTENANCE PLAN ........................................................................................... 52 8.8 STATION LOCAL CONTROL SYSTEMS............................................................... 53 8.9 SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA) ..................... 53 8.10 SITE SECURITY....................................................................................................... 53 8.11 STATION EQUIPMENT AND COMPONENTS ...................................................... 54 SECTION 9 ANOMALY ASSESSMENT AND DEFECT REPAIR 9.1 BASIS OF SECTION ................................................................................................ 56 9.2 DIRECT ASSESSMENT ........................................................................................... 56 9.3 INITIAL ASSESSMENT AND REMEDIAL ACTION ............................................. 57 9.4 PIPE WALL ANOMALY ASSESSMENT ................................................................ 58 9.5 FITNESS FOR PURPOSE (FFP) LEVEL ASSESSMENT ........................................ 62 9.6 ASSESSMENT OF ILI RESULTS ............................................................................ 67 9.7 INSPECTION TOLERANCES .................................................................................. 68 9.8 MAXIMUM OPERATING PRESSURE (MOP) RESTRICTION ............................. 68 9.9 PIPELINE REPAIRS ................................................................................................. 68 9.10 REPAIR METHODS ................................................................................................. 72 SECTION 10 CHANGE OF OPERATING CONDITIONS AND REMAINING LIFE REVIEW 10.1 BASIS OF SECTION ................................................................................................ 76 10.2 CHANGE OF OPERATING CONDITIONS ............................................................. 76 10.3 REMAINING LIFE REVIEW ................................................................................... 79 10.4 REFURBISHMENT .................................................................................................. 80 10.5 PIPELINE FAILURE ................................................................................................ 81 10.6 ABANDONING A PIPELINE ................................................................................... 81 SECTION 11 EMERGENCY RESPONSE 11.1 BASIS OF SECTION ................................................................................................ 84 11.2 EMERGENCY RESPONSE PLAN (ERP) ................................................................ 84 SECTION 12 RECORDS MANAGEMENT 12.1 BASIS OF SECTION ................................................................................................ 86 12.2 DESIGN, CONSTRUCTION AND COMMISSIONING RECORDS ........................ 86 12.3 OPERATION AND MAINTENANCE RECORDS ................................................... 87 12.4 ABANDONMENT RECORDS.................................................................................. 88

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Page APPENDICES A NORMATIVE REFERENCES .................................................................................. 89 B PIPELINE MANAGEMENT SYSTEM ..................................................................... 90 C ASSESSMENT AND REPAIRS OF PIPELINE ANOMALIES ................................ 91 D APPROVAL REQUIREMENTS ............................................................................... 93 E PIPELINE MANAGEMENT SYSTEM AND SAFETY CASE ................................. 95

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BIBLIOGRAPHY ..................................................................................................................... 97

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STANDARDS AUSTRALIA Australian Standard Pipelines—Gas and liquid petroleum Part 3: Operation and maintenance

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 the minimum requirements for the operation and maintenance of pipelines complying with AS 2885.0. NOTE: Other fluids may be transported in accordance with AS 2885.0.

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The fundamental principles on which this Standard is based are the following: (a)

Important matters relating to safety, engineering design, materials, testing, inspection and operation are required to be reviewed and approved by the Licensee.

(b)

A documented pipeline management system is required to be implemented to provide for continued integrity, monitoring and safe operation of the pipeline.

(c)

Where the Standard does not provide detailed requirements appropriate to a specific item, the principles and guidelines set out in the Standard are the basis on which an engineering assessment is made by competent persons. Specific requirements of the Standard do not replace the need for appropriate experience and engineering judgement.

1.2 APPROVAL Each document prepared for a pipeline in accordance with this Standard shall be approved as required by AS 2885.0. Documents nominated in this Standard as requiring approval shall be approved by the Licensee and not be delegated. All other documents shall be approved by the person, position or organization nominated in the Licensee’s approval matrix, in accordance with the approval requirements specified in Appendix D. 1.3 APPLICATION This Standard applies to the operation and maintenance of pipelines designed in accordance with AS 2885.1. Operation and maintenance procedures and practices for pipelines shall comply with the most recent edition of this Standard. Licensees who operate and maintain pipelines that are not designed and constructed in accordance with AS 2885.1, and where it is not feasible to physically modify the pipeline, may apply this Standard, provided the areas of non-compliance with AS 2885.1 are documented and are subject to a safety management study. Any actions required to control threats shall be approved in the pipeline management system. 1.4 RETROSPECTIVE APPLICATION Retrospective application of this Standard is governed by AS 2885.0. www.standards.org.au

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1.5 NORMATIVE REFERENCES The normative documents referenced in this Standard are listed in Appendix A. NOTE: Documents referenced for informative purposes are listed in the Bibliography. For dated references only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies.

1.6 DEFINITIONS For the purpose of this Standard, the definitions given in AS 2885.1, AS 2885.2, AS 1929, AS 2812, AS/NZS 2832.1 and those below apply. 1.6.1 Anomaly A discontinuity or imperfection of the pipe wall. 1.6.2 Approved and approval Approved by the Licensee or the Licensee’s delegate, and includes obtaining the approval of the relevant regulatory authority where this is legally required. Approval requires a conscious act and is given in writing.

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1.6.3 As low as reasonably practicable (ALARP) ALARP means the cost of further risk reduction measures is grossly disproportionate to the benefit gained from the reduced risk that would result. NOTE: Guidance on demonstration of ALARP and ‘grossly disproportionate’ is given in AS 2885.1.

1.6.4 Buckle An irregularity in the surface of a pipe caused by a compressive stress. 1.6.5 Casing A conduit through which a pipeline passes, to protect the pipeline from excessive external loads or to facilitate the installation or removal of that section of the pipeline. 1.6.6 Collapse A permanent cross-sectional change to the shape of a pipe (normally caused by instability, resulting from combinations of bending, axial loads and external pressure). 1.6.7 Commissioning The process of verifying the operational and safety functions of a pipeline and the introduction of the process fluid prior to handover for operation. 1.6.8 Competent person A person who has acquired through training, qualification, and experience, or a combination of these, the knowledge and skills that enable the person to safely and effectively perform the task required. 1.6.9 Component Any part of a pipeline other than the pipe. 1.6.10 Construction Activities required to fabricate, construct and test a pipeline, and to restore the right of way of a pipeline. 1.6.11 Critical safety system Systems that maintain the pipeline’s operation within the process or design basis limits.

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1.6.12 Damage 1

An anomaly deemed as not affecting MAOP after engineering assessment, which does not require repair on the basis of the requirements of this Standard.

2

A detrimental impact on the environment.

1.6.13 Decommissioning The action undertaken to prepare the pipeline and peripheral facilities for pending suspension or abandonment. 1.6.14 Defect An anomaly deemed unacceptable after engineering assessment. 1.6.15 Dent A depression in the surface of the pipe, caused by mechanical damage, that produces a visible irregularity in the curvature of the pipe wall without reducing the wall thickness (as opposed to a scratch or gouge, which reduces the pipe wall thickness). 1.6.16 ‘Dial Before You Dig (DBYD)’ or ‘One Call’ services

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A referral service to assist with public and industrial enquiries related to ground excavation and/or construction adjacent to the underground utilities. 1.6.17 Emergency shutdown (ESD) An emergency system response to deactivate and isolate a system or components to a safe state. 1.6.18 Environmentally assisted cracking A form of cracking resulting from the combination of a susceptible pipeline steel under tensile stress (residual or applied) exposed to a specific corrosive environment. 1.6.19 Failure The occurrence of one or more of the following conditions: (a)

Any loss of containment.

(b)

Supply is restricted (with effects that are other than purely commercial).

(c)

MAOP is reduced.

(d)

Immediate repair is required in order to maintain safe operation.

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

1.6.20 Fitting A component, including the associated flanges, bolts and gaskets used to join pipes, to change the direction or diameter of a pipeline, to provide a branch, or to terminate a pipeline. 1.6.21 Fluid Any liquid, vapour, gas, or mixture of any of these. 1.6.22 Gas Any hydrocarbon gas or mixture of gases, possibly in combination with liquid petroleum condensates or water. 1.6.23 Gouge Surface anomaly caused by mechanical removal or displacement of metal, which reduces the wall thickness of a pipe or component.

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1.6.24 Heat Material produced from a single batch of steel processed in the final steel-making furnace at the steel plant. 1.6.25 Heat-affected zone (HAZ) The portion of parent metal that has not been fused but has nevertheless been metallurgically affected by the heat of welding, brazing or cutting. 1.6.26 High vapour pressure liquid (HVPL) A liquid or dense phase fluid that releases significant quantities of vapour when its pressure is reduced from pipeline pressure to atmospheric (e.g. LP gas). 1.6.27 Hoop stress Circumferential stress in a pipe or cylindrical pressure-containing component, arising from internal pressure. 1.6.28 Hot tap A connection made to an operating pipeline.

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1.6.29 Hydrogen-induced cracking (HIC) A form of environmentally assisted cracking characterized by laminar (in-plane) cracking with some associated through-thickness crack linkage; also known as stepwise cracking or blistering. NOTE: See AS 2885.1.

1.6.30 Hydrogen-assisted cold cracking (HACC) A form of brittle cracking that occurs at near-ambient temperature in the weld or heat-affected zone (HAZ) or ferritic steel weldments, due to the combined effects of hydrogen arising from welding, together with tensile stress and a susceptible microstructure. NOTE: The time delay after welding at which HACC occurs depends upon the particular circumstances, especially the hydrogen concentration. With low levels of hydrogen it may be 24 h or more (see AS 2885.2).

1.6.31 Inert gas A non-reactive and non-toxic gas such as argon, helium or nitrogen. 1.6.32 Inspector A person appointed by the Licensee to carry out inspections required by this Standard. 1.6.33 Job hazard analysis (JHA) A process to identify, mitigate and communicate activity and specific hazards, which is carried out prior to commencement of work. 1.6.34 Leak test A pressure test that determines whether a pipeline is free from leaks. 1.6.35 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.

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1.6.36 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. NOTE: For additional information, see AS 2885.1.

1.6.37 Manufacturer’s data report (MDR) A document that consolidates all materials, testing, fabrication and installation data to comply with the traceability requirements of AS 2885.1. 1.6.38 Maximum allowable operating pressure (MAOP) See pressure, maximum allowable operating. 1.6.39 Maximum operating pressure (MOP) See pressure, maximum operating. 1.6.40 May Indicates the existence of an option.

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1.6.41 Non-destructive testing (NDT) Test methods used to examine pipes, components, materials or systems without impairing the fitness for purpose or usable life of the pipes and components. 1.6.42 Petroleum Any hydrocarbon or mixture of hydrocarbons in a gaseous or liquid state, which may contain hydrogen sulfide, nitrogen, helium, carbon dioxide, water and trace quantities of other materials. 1.6.43 Pig (pipeline inspection gauge) A device inserted in a pipeline for operation or inspection, and transported through it by the flow of the product in the pipeline. 1.6.44 Pig trap (scraper trap) A pipeline assembly to enable a pig to be inserted into or removed from an operating pipeline. 1.6.45 Piping An assembly of pipes, valves and fittings associated with a pipeline. 1.6.46 Pipework, mainline Those parts of a pipeline between stations, including pipeline assemblies. 1.6.47 Pipework, station Those parts of a pipeline within a station that begin and end where the pipe material specification changes to or from the mainline pipework. 1.6.48 Pressure, maximum allowable operating (MAOP) The maximum pressure at which a pipeline or section of a pipeline may be operated, following hydrostatic testing or after an MAOP review performed in accordance with this Standard. 1.6.49 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.

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1.6.50 Pretest (also known as ‘pretested’) A pressure test of pipe, pipeline assembly or a component that is undertaken separately from the pipeline and is not retested after installation (e.g. spare pipe, isolation valve, assemblies). 1.6.51 Protection measures, procedural Measures for protection of a pipeline that minimize the likelihood of human activities with potential to damage the pipeline. 1.6.52 Protection measures, physical Measures for protection of a pipeline that prevent external interference from causing failure, either by physically preventing contact with the pipe or by providing adequate resistance to penetration in the pipe itself. 1.6.53 Regulatory authority An authority with legislative powers relating to pipelines covered by the scope of this Standard. 1.6.54 Rupture

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Failure of the pipe such that the cylinder has opened to a size equivalent to its diameter. 1.6.55 Risk assessment A systematic (quantitative or qualitative) assessment of the likelihood and consequence of a failure to determine the level of risk in accordance with the methodology described in AS/NZS ISO 31000. NOTE: Guidance on pipeline risk assessment processes is given in AS 2885.1.

1.6.56 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. NOTE: The safety management study is performed in accordance with AS 2885.1.

1.6.57 Shall Indicates that a statement is mandatory. 1.6.58 Should Indicates a recommendation. 1.6.59 Specified minimum yield stress (SMYS) The minimum yield stress for a pipe material that is specified in the manufacturing Standard with which the pipe or fittings used in the pipeline complies. 1.6.60 Sulfide stress corrosion cracking (SSCC) Brittle fracture by cracking under the combined action of tensile stress and corrosion in the presence of water and hydrogen sulfide. 1.6.61 Strength test That part of the pressure test procedure that establishes the pressure strength of the test section. 1.6.62 Stress corrosion cracking (SCC) A form of environmentally assisted cracking.

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1.6.63 Telescoped pipeline A pipeline that is made up of more than one diameter or MAOP, tested as a single unit. 1.6.64 Threat Any activity or condition that can adversely affect the pipeline if not adequately controlled.

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1.7 ABBREVIATIONS ALARP

As low as reasonably practicable

APIA

Australian Pipeline Industry Association

CIPS

Close interval potential survey

CP

Cathodic protection

DBYD

Dial Before You Dig

DCVG

Direct current voltage gradient

EMP

Environmental management plan

ERP

Emergency response plan

ETA

Expected time of arrival

ESD

Emergency shutdown

FEA

Finite element analysis

FFP

Fitness for purpose

GIS

Geographical information system

HACC

Hydrogen-assisted cold cracking

HAZ

Heat-affected zone

HAZOP

Hazard and operability study

HIC

Hydrogen-induced cracking

HVPL

High vapour pressure liquid

ILI

In-line inspection

JHA

Job hazard analysis

MAE

Major accident event

MAOP

Maximum allowable operating pressure

MDR

Manufacturer’s data report

MIC

Microbiologically influenced corrosion

MOP

Maximum operating pressure

MSDS

Material Safety Data Sheet

NDT

Non-destructive testing

PIMP

Pipeline integrity management plan

PTW

Permit to work

SCADA

Supervisory control and data acquisition

SCC

Stress corrosion cracking

SIL

Safety integrity level

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Safety management study

SMYS

Specified minimum yield stress

SWP

Safe working pressure

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SMS

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S E C T I O N

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AS 2885.3—2012

P I P E L I N E M A N A G E M E N T SYSTE M

2.1 BASIS OF SECTION This Section sets requirements for the management system. A pipeline shall have a documented and approved pipeline management system. The pipeline management system shall be in place before commissioning and operation to ensure that the pipeline remains fit for operation.

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The pipeline management system shall address the Licensee’s approach to the following elements: (a)

Management.

(b)

Planning.

(c)

Implementation.

(d)

Measurement and evaluation.

(e)

Consultation, communication and reporting.

The pipeline management system shall include a description of the pipeline(s) including suitable maps (alignment sheets and/or GIS) showing the route of the pipeline, the location of associated facilities such as compressor and pump stations, transfer points, SCADA control centres, transmission towers, cathodic protection systems, valve stations, metering stations, and launching and receiving stations. NOTES: 1 A schematic representation of the pipeline management system is depicted in Appendix B. 2 Guidance on safety case regimes is provided in Appendix E. 3 Existing documents including safety and operating plan (SAOP) may continue to be used as part of the pipeline management systems subject to review for adequacy. 4 For pipelines that are owned or operated by organisations that have an appropriate management system (such as an EH&S, HSE, OH&S or SMS), the pipeline management system may be developed as a sub-set of that management system to address specific aspects that are particular to a pipeline complying with relevant parts of AS 2885.

2.2 PIPELINE MANAGEMENT SYSTEM ELEMENTS 2.2.1 General The structure of the pipeline management system is flexible; however, as a minimum, it shall address the criteria specified in Clauses 2.2.2 to 2.2.6. All elements of the pipeline management system support each other (Clauses 2.2.2 to 2.2.6). The pipeline management system shall comply with the requirements set out in Clauses 2.2.2 to 2.2.6. 2.2.2 Management 2.2.2.1 Policy and commitment The Licensee shall define its policy towards the various aspects of operating the pipeline. Policies shall address at least— (a)

pipeline integrity management;

(b)

environmental management; and

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occupational health and safety management.

NOTE: A clear commitment by the Licensee towards specific outcomes forms the basis of the pipeline management system.

2.2.2.2 Management structure A defined management structure for the pipeline shall be established to identify key positions and or personnel. A management structure appropriate to the size and complexity of the pipeline shall be maintained. 2.2.2.3 Responsibilities, accountabilities and authorities

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The responsibilities, accountabilities and authority levels of personnel and or contractors with respect to the various aspects of the operation and maintenance of the pipeline shall be detailed in the pipeline management system. In particular, personnel shall be identified and documented with the responsibility and authority to— (a)

initiate action to prevent a loss of pipeline integrity, damage to the environment, impact to public, or to correct an occupational health and safety issue;

(b)

identify and report on any existing or potential deficiencies within the pipeline management system or the pipeline’s operation and maintenance;

(c)

initiate, recommend and approve corrective and preventive actions in relation to identified existing or potential deficiencies within the pipeline management system or the pipeline’s operation and maintenance;

(d)

evaluate and verify the effectiveness of any corrective or preventive action implemented; and

(e)

satisfy the mandatory approval requirements of this Standard.

NOTE: AS 2885.0 requires the development of an approval matrix to document the delegations of the Licensee.

2.2.2.4 Training and competency Personnel shall be competent to perform the specific tasks and functions for which they are responsible. The Licensee shall establish and maintain procedures for identifying and providing the training needs of all personnel performing functions covered by the pipeline management system. As a minimum and as applicable to each position, personnel responsible for the operation and maintenance of the pipeline shall be— (a)

adequately trained and experienced in all aspects of the equipment in their control;

(b)

adequately trained in the obligations of the pipeline management system and briefed in the requirements of the controls and actions identified during the safety management study;

(c)

aware of properties of the fluid, including its hazards (see Note 1); and

(d)

adequately knowledgeable in the design, construction, welding, hydrostatic testing, cathodic protection and coating of pipelines as required by AS 2885, the relevant pipeline coating and cathodic protection standard and other technical documents and Standards relevant to the pipeline’s integrity (see Note 2 and Note 3).

NOTES: 1 For more information on fluid properties see AS 4343. 2 Detail on the framework for National Competencies for Transmission Pipeline Operators can be found at www.ee-oz.com.au. 3 Detail on the engineering competencies can be found at the APIA website www.apia.net.au © Standards Australia

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2.2.2.5 Resourcing The Licensee shall identify the resourcing, equipment and material requirements for the pipeline’s operation and maintenance, including the resources required to ensure the appropriate development, implementation and review of the pipeline management system. NOTE: Where the pipeline is in continuous operation, sufficient personnel should be available for undertaking planned and unplanned operations and maintenance, taking into account the requirements for leave and training.

2.2.2.6 Change management The Licensee shall establish procedures for managing changes to the pipeline management system, procedures, pipeline design or operation so that they are conducted in a controlled manner, and reviewed and approved.

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Any change to the pipeline or its operating context shall be reviewed and approved. Change shall be considered to have taken place if the engineering design has been upgraded or modified (see Section 10), or if any event or newly identified threat initiates an operational, technical or procedural change in the measures in place to— (a)

protect the pipeline and associated components;

(b)

promote public awareness of the pipeline;

(c)

operate and maintain the pipeline safely;

(d)

respond to emergencies;

(e)

prevent and minimize loss of containment;

(f)

carry out inspections in accordance with Clauses 6.4, 6.5, 6.6 and Clause 6.7; and

(g)

ensure that the plans and procedures continue to comply with the engineering design.

The change management procedures shall address implementation of management system changes, including notification and training of change, and the allocation of responsibilities for any identified management procedures shall also include communication of stakeholders.

any resulting pipeline staff impacted by the actions. The change changes to relevant

2.2.2.7 Management review The Licensee shall establish procedures for regular management review of the effectiveness and appropriateness of the pipeline management system. NOTE: The management review should include review by the Licensee for those elements of the pipeline management system considered high risk, and take into account the outcomes from the various procedures covering the measurement and evaluation of elements of the pipeline management system (see Clause 2.2.5).

The pipeline management system shall be reviewed and, if necessary, updated, at least every 2 years or in the event of any change to the pipeline management system elements (as detailed in Clause 2.2.2 to 2.2.6). NOTE: For example, updating of the pipeline management system may be necessary when there are changes to legislative requirements, Licensee, or organization structure.

2.2.3 Planning 2.2.3.1 General The Licensee shall have appropriate planning processes and procedures for the pipeline for any situations that may result from normal and abnormal operations including emergencies.

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2.2.3.2 Planning for normal operation When developing the policies and procedures of the pipeline management system, the Licensee shall utilize the various safety management studies undertaken under the requirements of AS 2885.1 and this Standard. Control measures required to eliminate threats or reduce them to an acceptable level, including threats to the environment as a result of pipeline operation activities, shall be incorporated into the appropriate procedures. The Licensee shall also establish a process for the identification of occupational health and safety and environment hazards and mitigation of occupational health and safety and environment risks as described in Section 4, prior to the commencement of any activity. 2.2.3.3 Planning and preparation for abnormal operations

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The Licensee shall plan and prepare for operation of the pipeline in circumstances that are different from those initially considered during the design of the pipeline or during significant disruption to normal operations. These circumstances may include the following: (a)

Operating under emergency power supplies.

(b)

Operating without key assets such as compressors.

(c)

Operating at low flow, pressure or linepack levels.

(d)

Operating under communication outages.

(e)

Operating under changed conditions to maintain safety of a damaged pipeline.

2.2.3.4 Emergency planning and preparation The Licensee shall plan and prepare for emergency events resulting from the pipeline’s operation and maintenance and from external events that may affect the safe and reliable operation of the pipeline (see Section 11). In the event of an emergency, the Licensee shall ensure that any response is performed in a safe manner. NOTE: Liaison with emergency services and stakeholders may assist the Licensee to be adequately prepared for an emergency event.

2.2.4 Implementation The Licensee shall implement the plans and procedures of the pipeline management system covering at least the following: (a)

Preparation for operation (Section 3).

(b)

Site safety and environmental management (Section 4).

(c)

Pipeline integrity management (Section 5) incorporating— (i)

pipeline structural integrity (Section 6);

(ii)

external interference management (Section 7);

(iii) anomaly assessment and defect repair (Section 9); and. (iv)

change of operating conditions and remaining life review (Section 10).

(d)

Stations operations and maintenance (Section 8).

(e)

Emergency response (Section 11).

(f)

Records management (Section 12).

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2.2.5 Measurement and evaluation 2.2.5.1 General The pipeline management system shall incorporate procedures for the appropriate measurement and evaluation of the performance of the pipeline management system elements. NOTE: The results of audit, review and monitoring processes should be utilized for the purpose of management review of the pipeline management system.

2.2.5.2 Data acquisition and analysis The Licensee shall establish procedures for identifying, collecting and analysing the pipeline’s operational, maintenance and reliability data to identify trends in the pipeline’s operation and performance. NOTE: Analysis of this data should enable operation of the pipeline to continue as planned. It should also identify any negative trend that may result in an event adversely impacting the safe and reliable operation of the pipeline.

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2.2.5.3 Accident/incident investigation and reporting The Licensee shall establish procedures for identifying, notifying, recording, investigating and reporting accidents or incidents resulting from the operation and maintenance of the pipeline. This shall cover any event associated with the pipeline that either causes or has the potential to cause— (a)

injury or death to pipeline personnel or the public;

(b)

significant damage to the environment; and/or

(c)

significant impact on the pipeline’s operation or integrity.

Reporting shall include notification of relevant regulatory authorities as required by legislation. NOTE: Apart from incident reporting to the regulatory authority where required by legislation, the circumstances of any incident, as defined in the Australian Pipeline Industry Association (APIA) Pipeline Incident Database, should be reported to APIA to enable statistics of pipeline incidents to be gathered.

2.2.5.4 System audits The Licensee shall establish procedures for planning and implementing audits of the pipeline management system to determine compliance with and effectiveness of the plans and procedures. System audits should also assess compliance with legal and regulatory requirements and ensure the pipeline management system adequately addresses these issues. The Licensee shall consider the threats identified and risks evaluated in the safety management study to ensure that audits evaluate— (a)

the effectiveness of the pipeline management system in controlling the risks identified; and

(b)

the effectiveness of the monitoring procedures in place to identify new or changed threats and risks.

Audits shall be performed by competent personnel who are independent of the section of the pipeline management system being audited. The audit procedures shall cover the timing of audits, including the conduct of external independent audits where chosen to be undertaken or where required by regulatory authorities. Audit procedures shall cover arrangements for verifying the implementation and effectiveness of corrective and preventive actions designed to address any non-conformances identified during the audit.

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The outcomes of audits shall be subject to management review. NOTE: Guidance on auditing is given in AS/NZS ISO 9001.

2.2.5.5 Corrective and preventive action The Licensee shall develop and implement procedures for determining, approving and implementing corrective and preventive actions. NOTE: Corrective actions are taken to deal with an existing issue while preventive actions address potential issues.

The proposed actions shall, as far as reasonably practicable, eliminate or mitigate the issue and shall be appropriate and commensurate to the risk encountered. The proposed actions shall be recorded and their effectiveness determined by audit. The basis for any action shall be documented and the outcomes of actions taken, along with their effectiveness, shall be subject to management review. 2.2.6 Consultation, communication and reporting

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The Licensee shall identify external people and organizations with a legitimate interest in the safety and environmental aspects of the pipeline’s operation and maintenance. These may include landowners, contractors, utilities, local and emergency authorities, regulatory authorities and government agencies. The Licensee shall establish procedures for regular consultation with, and communication and reporting to, these identified stakeholders. These procedures should include statutory reporting requirements. NOTE: Clause 7.3.1 provides details of stakeholders and community awareness processes as they relate to external interference protection.

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S E C T I O N

3

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AS 2885.3—2012

F O R

O P E R A T I O N

3.1 BASIS OF SECTION This Section sets out the requirements that have to be in place prior to commissioning or recommissioning a pipeline. Pipeline operation follows commissioning and requires adequate preparation involving a number of stakeholders including, for example, construction, commissioning and operations personnel, landholders and regulators. These stakeholders need to work together to take the pipeline through a controlled process from construction through to a fully commissioned and operating pipeline. This requires coordination and appropriate resources and communication at each stage. With the preparation completed and following approval to commence operation, the filling of the pipeline in accordance with AS 2885.1 can occur and the pipeline can then be put into operation.

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3.2 PREREQUISTES Preparations for operation shall only be deemed complete when the plans and procedures set out in this Section have been implemented. The Licensee shall ensure that the pipeline management system specified in Section 2 is fully designed and, as a minimum, the key features implemented. Deficiencies shall be considered and appropriate mitigation implemented prior to commissioning commencing. Additional specific planning for safety or environmental issues that would occur during commissioning shall be prepared, appropriate mitigation implemented and staff inducted accordingly. A detailed handover process shall be developed, which includes the involvement of key operating personnel. 3.3 READINESS FOR OPERATION Pipelines shall not be considered ready to commence or recommence operation unless, as a minimum, the following checklist has been completed: (a)

The safety management study has been reviewed, including operations personnel as ready for operation NOTE: This is important for the operations personnel to understand the threats and control measures specific to this pipeline.

(b)

The pipeline complies with the requirements of all relevant parts of AS 2885 series.

(c)

The hydrostatic strength and leak test requirements have been achieved and documented.

(d)

The MAOP has been established.

(e)

The welds of tie-ins to existing facilities, which have not been subjected to testing in accordance with Item (c), have been inspected by an approved non-destructive examination method, and comply with AS 2885.2.

(f)

Components have been tested for satisfactory operation. Where impracticable, other appropriate inspections have been carried out.

(g)

Sufficient operating, maintenance and emergency personnel have been trained.

(h)

The pipeline is cathodically protected as required by AS 2885.1.

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Threat mitigation measures have been implemented in accordance with Section 7. NOTES: 1 Additional site-specific aspects may need to be evaluated prior to commencement of operation. 2 Initial operations may be approved before completion of the field work, provided the incomplete work does not directly affect the safety of the pipeline, the public, or the operating personnel, or provided alternate temporary provisions have been made.

3.4 HANDOVER TO OPERATIONS Handover of a commissioned pipeline system occurs at the completion of the commissioning phase. At the completion of commissioning, the Licensee shall approve completion of commissioning and pass control of the system to operations. NOTE: Operation of the pipeline post-commissioning may involve multiple groups of construction and commissioning personnel working to resolve any outstanding issues from construction and commissioning. This phase of operations contains additional risks, as new systems and management personnel may be introduced and the number of work sites and scopes may be unusually high.

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The handover process shall transfer the management and control of the pipeline system at a defined point. Preparation for the transfer to operations shall include compiling critical documentation including, where appropriate, the following items: (a)

Update and delivery of as-built design records and documents.

(b)

Review of a complete as-built construction MDR.

(c)

Transfer of a construction punch list.

(d)

Inventory of pipeline tools, spare parts location and documentation.

(e)

Register of landholder and third-party records and liaison documentation.

(f)

Specialist vendor training for operations personnel.

(g)

Updated details incorporated by the Licensee in the pipeline management system.

(h)

Updated EMP.

(i)

Records management plan.

(j)

Transfer of electronic files, software and licences such as SCADA and logic controller programs.

(k)

Training or briefing of operational personnel on commissioning issues.

(l)

Liaison with regulatory authorities.

3.5 DELAYED COMMENCEMENT OF OPERATION Where a pipeline is commissioned but not placed in operation immediately, it shall meet the requirements of Clause 3.2. If the hydrostatic test fluid is allowed to remain in the pipeline, the test fluid shall be dosed with a corrosion inhibitor or the pipeline shall be filled with a fluid that inhibits corrosion, unless it can be demonstrated that such measures are not warranted. Where the test fluid is removed, the pipeline shall be dried or purged, or both, with inert gas to produce a moisture level that will not promote corrosion during the delay period.

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Where the pipeline is left filled with a fluid, precautions shall be taken to ensure that no damage is caused by overpressure (e.g. thermal expansion effects). During the period between the hydrostatic test and the initial operation, the pipeline integrity shall be maintained in accordance with this Standard.

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Should an inspection reveal that unacceptable corrosion is occurring, corrective action shall be taken and consideration shall be given to further hydrostatic testing.

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S E C T I O N 4 S I T E S A F E T Y A N D E N V I R O N M E NT A L M A N A G E M E N T 4.1 BASIS OF SECTION The safety of the public and pipeline personnel, the impact on the environment and the integrity of the pipeline and its equipment shall not be compromised by pipeline operations and maintenance activities. The Licensee shall consider the work environment in which pipeline personnel are required to work when planning operations and maintenance activities and take into account the impact of operations and maintenance activities on the pipeline personnel, public and the environment. 4.2 WORK HOURS AND FATIGUE

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When planning field works, the Licensee shall consider the duty cycle of personnel to ensure that they are not required to work or drive excessive hours without suitable rest periods. Should emergency work demands create situations where personnel are likely to exceed normal work cycle maximums, this shall be considered, documented and mitigated, as necessary, in the site JHA and noted in the permit records. 4.3 REMOTE TRAVEL Where pipeline operations involve travel to remote areas, the Licensee shall consider the need to have a documented procedure for tracking and following up crews that fail to arrive by the expected time of arrival (ETA). NOTE: As a minimum, the Licensee should ensure records of the departure of the crew, their destination and ETA. The Licensee should evaluate the duration for retention of these records.

4.4 FIRST AID REQUIREMENTS 4.4.1 Assessment The Licensee shall assess the first aid requirements in accordance with local jurisdictional requirements (as appropriate). NOTE: The assessment should consider the following: (a) The types of incidents that may occur. (b) The site locations. (c) The necessary competence and number of trained first aid personnel. (d) The inventory levels of first aid equipment and the location of facilities. (e) The arrangements for continuous first aid cover throughout extended work programs. (f) The arrangements for transporting injured persons.

4.4.2 Procedures The Licensee shall ensure that arrangements are in place for the following: (a)

The treatment of minor injuries.

(b)

The treatment and/or emergency transportation of personnel requiring off-site medical attention.

(c)

The security of medications.

(d)

The maintenance of the first aid inventory.

(e)

The availability of additional medical advice.

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4.5 JOB HAZARD ANALYSIS (JHA) 4.5.1 General A JHA shall be undertaken prior to work being performed on a pipeline or its facilities with the objective of providing a safe system of work, and shall be used to identify, assess and control safety and environmental hazards. A JHA process involves four steps, involving as many of the work party as practicable to ensure a wide knowledge base is used, as follows: (a)

Hazard identification Consideration of all potential hazards associated with a particular work scope, including giving consideration to each step of the work procedure or instruction.

(b)

Mitigation Consideration of necessary actions to remove or reduce the hazard. A hierarchy of mitigation applies to both safety and environmental hazards. NOTE: Where practicable, mitigation actions designed from higher up the hierarchy to remove the hazard should be used in preference to those from lower down, which only apply controls.

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The hierarchy of mitigation controls is as follows: (i)

Elimination.

(ii)

Substitution.

(iii) Isolation. (iv)

Engineering controls.

(v)

Procedural controls.

(vi)

Protective equipment (including personal protective equipment).

(c)

Implementation The determined mitigation action is implemented. Should the determined mitigation prove impracticable, the JHA shall reassess the need and design of that mitigation.

(d)

Review Assessment by the JHA of the risks associated with any significant hazards remaining after the application of mitigation measures. NOTE: Work should not proceed unless the risk is reduced to an acceptable level.

4.5.2 Preliminary JHAs For routine repetitive activities, preliminary JHA assessments may be prepared off-site in advance of the works. Preliminary assessments enable standard mitigation measures to be developed and integrated into the work procedures to ensure that work teams are suitably skilled and equipped prior to attending the site. NOTE: For more complex or non-standard work, a preliminary JHA should also be conducted involving specialized expertise, as necessary, to ensure all potential hazards are considered and mitigation designed.

The preliminary JHA shall be reviewed on-site and any additional on-site hazards shall be addressed. 4.5.3 On-site JHAs Work procedures (see Clause 4.5.2) and JHAs shall be used for all activities on a site. This may involve multiple JHAs at a single location. On arrival at a work site, an on-site JHA shall be completed. Where preliminary JHAs have been previously completed, the suitability of any determined actions shall be verified and incorporated into the on-site JHA. In all cases, identification of further actions necessary to maintain high levels of occupational health and safety and environment at the specific site shall be identified. www.standards.org.au

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NOTE: In particular, the on-site JHA should consider the work procedures and the preliminary JHA (if applicable) in light of any other on-site hazards such as weather conditions, fluid escapes, local site arrangements, interaction with third parties, equipment or communication failures and fatigue.

All determined actions shall be implemented where practicable, and suitable checks put in place to confirm their adequacy throughout the works. All members of the work party shall be briefed and shall confirm their understanding by signing the JHA document. Additional members subsequently arriving on-site shall also be inducted with the contents of the JHA and confirm their understanding by signing the JHA document. Should site circumstances change or a mitigation method fail, the JHA shall be reviewed. Related work activities shall be suspended until satisfactory measures are in place and the documented JHA updated. 4.6 PERMIT TO WORK (PTW) SYSTEM

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4.6.1 General A permit to work process shall be required for site works involving high levels of risk when working with any pipeline or its facilities, to ensure that high levels of occupational health and safety and environment are maintained. As a key requirement of the system, a job hazard analysis (JHA) shall be carried out to ensure that all on-site occupational health and safety and environment hazards are identified and addressed prior to commencement of work. The Licensee shall determine the type of work that requires a permit to work. A permit to work system shall coordinate site works to ensure that activities are suitably managed and do not conflict. 4.6.2 Control processes The Licensee shall have a range of permit classes covering at least the following: (a)

Cold work.

(b)

Hot work.

(c)

Entry to confined spaces.

(d)

Excavation alongside live pipelines.

The Licensee shall ensure that suitable occupational health and safety and environment procedures are in place for each of the permit classes. NOTE: All permits should be numbered, dated and timed and the names of the key officers recorded.

As a minimum, the Licensee shall consider the following prior to issuing the permits: (i)

A list of personnel on-site is maintained.

(ii)

Site personnel have the necessary skills.

(iii) The scope of works and the likely duration is defined. (iv)

A JHA for the work has been performed, and all necessary mitigation actions have been implemented.

(v)

Interaction between multiple work sites is managed.

NOTE: Permits may be withdrawn at any time and work immediately suspended.

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4.6.3 Communication and control Wherever practicable, a reliable communication system and procedure shall be established with the work site. Where effective communications are not practicable, this shall be considered during the JHA and suitable arrangements implemented. 4.7 ENVIRONMENTAL MANAGEMENT 4.7.1 General Environmental planning is necessary to ensure that all field practices and procedures minimize impact on the environment.

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The Licensee shall consider environmental aspects of its pipeline operations and associated facilities and document them in an environmental management plan (EMP). Any threats to the environment shall be assessed and appropriate controls implemented as part of the pipeline management system. NOTES: 1 Pipeline corridor maintenance programs can be very visible to the community and regular routine operations should manage the maintenance works to ensure minimal impact to the public and on the environment. 2 An environmental management plan may be part of the pipeline management system. 3 The Australian Pipeline Industry Association’s Code of Environmental Practice—Onshore Pipelines provides guidance regarding an environmental management system. The Code outlines the minimum measures to be taken, which would be deemed to constitute an effective environmental management system.

4.7.2 Pipeline corridor management Pipeline corridor management (right of way) involves— (a)

vegetation management;

(b)

maintaining easement and access track condition, particularly after heavy rain;

(c)

maintaining signage; and

(d)

monitoring third-party activities.

Consideration shall be given to avoiding the spread of disease and weed infestations between properties by vehicle, machinery and shoe transfer. NOTE: Liaison with landowners and other stakeholders should include environmental matters.

4.7.3 Noise emissions A certain level of noise is inherent in high-pressure operation and maintenance activities. The best practicable methods shall be employed to meet statutory requirements for the protection of site personnel and the public. Special consideration shall be given to the following: (a)

Provision of suitable ear protection to site personnel.

(b)

The use of acoustically treated power tools, compressors, generators, air coolers, vents and pipework.

(c)

The timing of all operation and maintenance activities, to take into account the impact on the environment and the community.

(d)

Reducing inventory levels in advance of venting to reduce the impact and period.

(e)

Blow-down silencers can significantly reduce the noise levels emitted but do impose other impacts such as depressurization rate and safety.

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NOTES: 1 Noisy processes in the vicinity of the public can be distressing; therefore, communication with the local residents prior to commencement is recommended to enable their input and remove unnecessary concerns. 2 Unless a silencer is installed permanently at each location, because of its size, it is unlikely that it could be utilized in situations where there is limited time for mobilization.

4.7.4 Heritage sites Heritage sites are protected by law. They shall be identified prior to site work. Licensees shall identify locations that may be impacted by the activities and shall ensure that they are protected, and the relevant permissions are obtained prior to working in those locations. 4.7.5 Water management Management of surface water flows and streams are major issues that can lead to washaways and integrity threats. Care shall be taken when designing work impacting on river banks to avoid changing their shape, as this could lead to erosion of downstream banks.

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Earthworks close to waterways shall include consideration of the specific hazards, and the relevant legislation shall be complied with. These environmental hazards include silting of the waterway, destruction of native vegetation and affects on local fauna. Routine surveillance shall (particularly after heavy downpours) monitor the condition of the pipeline easement and the access tracks. NOTE: JHA processes involving excavation work should pay particular attention to possible water runoff from sudden rain.

4.7.6 Waste management Waste materials from pipeline operations and maintenance may be hazardous and their handling, disposal, transport and storage require consideration to ensure that the associated hazards are appropriately mitigated. Preliminary and on-site JHAs shall consider all materials that may be encountered during site works with reference to their Material Safety Data Sheets (MSDSs) and relevant legislation. As a minimum, waste management procedures shall cover the following: (a)

Internal waste Pipelines can produce varying degrees of internal waste matter, depending upon their operational circumstances, which may be received in filters and during pigging operations. This waste may include iron-based compounds, which could spontaneously combust when exposed to oxygen and other residues, having potential impact on the environment.

(b)

External waste External waste may involve a variety of materials from hazardous substances, such as asbestos in pipeline coatings, through to recyclable packaging from pipeline supplies. Some items may be recycled or disposed of with domestic waste, whilst others may require specific licensing and special disposal arrangements.

4.7.7 Spill prevention and response Pipelines containing oils, fuels and hazardous liquids require specific planning to minimize the environmental impact should controls fail. In addition, hazardous materials may be present at work sites, storage areas and in vehicles and other equipment. Spill prevention considerations shall be built into the operating procedures and specific response planning shall be developed to enable any spills to be contained rapidly. Where necessary, specific spill response training shall be conducted, taking into consideration regulatory requirements.

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4.8 FLUID HAZARDS Employees, contractors, emergency services and (where appropriate) neighbours of the pipeline shall be informed of the characteristics and hazards of the fluid conveyed, whether it be natural gas, HVPL, hydrocarbon liquid, CO 2 or other fluid. Such characteristics may include flammability, toxicity and behaviour on release (e.g. HVPLs and CO 2 will usually spread at ground level). 4.9 VENTING AND PURGING PIPELINES 4.9.1 General Hydrocarbon fluids shall only be released from a pipeline when operating procedures dictate the need. NOTE: The Licensee should ensure that inventory in the pipeline is minimized prior to commencement. Methane is a greenhouse gas and the release of any emissions should be minimized.

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Any purging of pipelines shall be in accordance with a procedure, and a JHA shall be developed to ensure that all hazards are suitably mitigated. Consideration shall be given to any noise implications, temperature variations and the hazards associated with gaseous clouds. When a pipeline is being purged of gas by the use of air after venting, consideration shall be given to the safety and operational consequences of the formation of an explosive mixture at the gas/air interface. For safety and environmental reasons, where practicable, depleting linepack by consumer use and flaring is preferable to venting. 4.9.2 Working on purged pipelines Where a pipeline, which has been filled with air, is connected to a source of hydrocarbon fluid that cannot be completely isolated, welding, thermal cutting or repair operations shall not be permitted unless— (a)

the flow of hydrocarbon fluid toward the work site is prevented; and

(b)

the pipeline contents at the work site are tested continuously to ensure that an unsafe concentration of hydrocarbon fluid does not occur.

This may require— (i)

the generation of airflow away from the work within the pipeline, by the operation of air movers at suitable locations; or

(ii)

the installation of pipeline stop devices (e.g. stopples, pigged stopping plugs or spheres with bleed vents on each side of the work site), taking care that this does not prevent adequate airflow that may be required for Item (a) above.

4.9.3 Purging an HVPL 4.9.3.1 General Where an HVPL is to be purged from a pipeline, the pressure in the pipeline shall be maintained at a value greater than the bubble point, at all points in the pipeline, until the purging is complete. 4.9.3.2 Hydrocarbon liquid phase purging operations Where a pipeline is to be purged of hydrocarbon liquid, the purging fluid shall be water, air or a non-flammable gas. NOTES: 1 Where the hydrocarbon has a flashpoint equal to or less than 61°C and is being purged with air, a batching sphere, a batching pig or slug of water between two spheres should be introduced between the air and the hydrocarbon liquid. www.standards.org.au

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Where the hydrocarbon has a flashpoint greater than 61°C and is being purged with air, a batching sphere or a batching pig should be introduced between the air and the hydrocarbon liquid. Where the hydrocarbon is being purged with water, an assessment should be made of the need to separate water from the hydrocarbon liquid with batching spheres or batching pigs.

Gas phase purging shall be used only where the pressure in the pipeline has accidentally fallen to less than the bubble point or where the HVPL is deemed to be a single hydrocarbon. 4.9.3.3 Gas phase purging operation

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When a pipeline is being purged of gas by the use of air after venting, consideration shall be given to the safety and operational consequences of the formation of an explosive mixture at the gas/air interface. NOTES: 1 During purging, air should be released into one end of the pipeline in a controlled and continuous flow at an appropriate rate for the pipeline being purged. A slug of inert gas of sufficient length to separate the gas from the air to control the formation of an explosive mixture may be released into the pipeline before the air. 2 Pigs or spheres may be used in some cases to reduce mixing at the interface and, therefore, reduce the volume of explosive mixture or reduce the inert gas required. 3 Where air movers are used to purge the pipeline, or section of the pipeline, of gas, sizing of components should be carefully considered to ensure a continuous and adequate flow. 4 Additional earth strapping should be used at the air mover location to discharge any build-up of static electricity.

Where the above conditions cannot be met or controlled for the duration of the purge, the Licensee shall ensure that the procedure is suitable for the task. The above procedure shall ensure that the pipeline is purged in a safe manner. Under certain conditions, a direct purge with air may be used, provided the procedure meets the conditions and requirements of AGA XK0101. Dual-phase conditions shall be avoided. Where dual-phase conditions are expected, the conditions under which dual-phase conditions occur and are handled shall be analysed and a specific purging procedure developed prior to commencement of purging. 4.9.4 Trapped hydrocarbon Where a pipeline or auxiliary equipment that has been in service is to be filled with air and there is a reasonable possibility that— (a)

the inside surfaces are wetted with a volatile combustible liquid;

(b)

a volatile combustible liquid may have accumulated in low places; or

(c)

gas may have accumulated,

a procedure designed to purge such liquids or gas shall be used. NOTES: 1 Filter vessels can accumulate combustible material, which may spontaneously ignite when exposed to air. 2 Transmission pressure may be trapped in valve body cavities and other blind off-takes.

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4.10 WORKING GUIDANCE

ON

LIVE

PIPELINES—SPECIFIC

AS 2885.3—2012

REQUIREMENTS

AND

4.10.1 Site set-up and control Parking areas shall be clearly identified at sites and, where sites are located in public areas, provide a secure location to store mobile phones and other possible sources of ignition that are not being operated under a hot work permit. The hazards shall be documented in the JHA and shall include the following aspects: (a)

Confirmation of correctly calibrated and tested flammable gas detectors prior to and during the work.

(b)

Safe work procedures.

(c)

Physical barriers to delineate the work site in public areas.

(d)

The perimeter of hazardous areas to be determined and delineated.

NOTE: When any work is to be carried out on a pipeline, the formation of mixtures of flammable vapour or gas and air should be avoided wherever possible.

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Unless specifically authorized by a hot work permit, the following shall be prohibited in hazardous areas: (i)

Smoking.

(ii)

The presence of matches, lighters and naked flame.

(iii) Electrical equipment, including radios, flashlights and hand lanterns, unless safe for use in Zone 1 hazardous locations as defined by AS 2430.1. (iv)

Any sources of ignition to the work area (e.g. spark-ignition engines, motor vehicles and mobile phones).

NOTE: Where there is a likelihood of a gas or vapour leak, the area should be monitored continuously by a competent person using appropriate gas detection equipment to ensure that personnel on-site are fully aware of the situation and the level of hazard.

4.10.2 Tunnels, shafts and casing The Licensee shall ensure that the atmosphere in a tunnel, shaft or casing, including any opening that is too small for human access, is made safe before any work is carried out on the pipeline within that tunnel, shaft or casing. Specific requirements for the entry shall be considered in the JHA. 4.10.3 Electrical safety To prevent an accidental ignition of possible hazardous concentrations of flammable vapour or gas inside a pipeline due to electrical hazards, appropriate precautions shall be taken and, where relevant, the following requirements shall apply: (a)

Adequate training and instruction shall be given to operating and maintenance personnel regarding the possibility of electric surges (sparks) occurring across insulated joints.

(b)

Static electricity shall be safely discharged in accordance with AS/NZS 1020.

(c)

Where two joining flanges are to be separated or a pipeline cut, an electrical connection shall be installed across the proposed separation.

Where a coated pipeline is exposed to threats from induced a.c. voltage (low frequency induction), earth potential rise effects, direct lightning strikes or d.c. voltage conduction (interference bonds to d.c. traction systems), a preliminary JHA shall be completed prior to any site works.

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Procedures shall be developed in accordance with AS/NZS 4853 to ensure that the mitigation equipment installed as part of the design is maintained and, if necessary, improved, to protect personnel from excessive touch voltages. 4.10.4 Welding onto an in-service pipeline 4.10.4.1 Welding Welding onto an in-service pipeline is a special process that requires highly trained and competent personnel to mitigate risks. Such welding shall be in accordance with the relevant requirements of AS 2885.2. 4.10.4.2 Monitoring of operating conditions The Licensee shall ensure that the welding procedures used are appropriate for the task and that the required operating conditions and controls are implemented. Training of welding operators, supervisors and inspectors shall be carried out prior to in-service welding by simulated weld trials, and the frequency shall be determined in accordance with AS 2885.2. Whilst any welding is in progress, the requirements of the welding procedure shall be adequately monitored. Welding shall be discontinued at any time when the pressure, flow rate or heat sink capacity measurement is outside the specified limits.

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4.10.4.3 Resumption of normal operation Following a repair, the pressure in a pipeline shall not be increased outside the specified limits until the repair has been visually inspected and subjected to NDT in accordance with this Standard and AS 2885.2 and after the inspection has confirmed that it is safe for normal operation to be resumed. 4.10.5 Working on pipelines where fluid is escaping Welding or cutting on pipelines that contain flammable and/or pressurized substances, involves high risk and requires highly trained and competent personnel to mitigate risks. Welding shall be carried out in accordance with AS 2885.2. A JHA shall be conducted to determine the most appropriate action for the specific circumstance and to determine any necessary mitigation to ensure the safety of operatives, third parties and the surrounding area. Any cutting of pipelines that contain or have contained liquid petroleum or HVPL that has not been purged shall only be carried out following a risk assessment, which shall specify a safe work method for removing or repairing the leak, and that any heat generated shall be controlled below the product flashpoint. 4.10.6 Hot-tapping operations The Licensee shall ensure that any hot-tapping operation is carried out in accordance with a preliminary JHA and a hot-tapping procedure. The procedure shall be based on training, shop tests, experience, practice runs and other relevant information and shall be documented and followed throughout the operation. The procedure shall address the following: (a)

Safety of personnel, public and the environment.

(b)

Product containment.

(c)

Site control.

(d)

Specific welding and NDT requirements, as specified in AS 2885.2.

(e)

Testing requirements.

(f)

Coating and backfill.

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(g)

Emergency procedures.

(h)

Testing and operation of hot tapping tool and fittings.

(i)

Traceability of materials.

AS 2885.3—2012

NOTE: See WTIA Technical Note 20 and AS 2885.2.

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On-site operating personnel shall be competent to undertake the procedure and participate in the on-site JHA before the hot-tap operation is commenced.

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S E C T I O N

5

P I P E L I N E I N T E G R I T Y M A N A G E M E N T

5.1 BASIS OF SECTION Pipeline integrity shall be achieved by implementing a systematic approach to the utilization of resources on pipeline system design, construction, operation and maintenance activities, in conjunction with the application of sound engineering principles with due regard to safety and the environment. The Licensee shall ensure continued pipeline integrity during the life of the pipeline. As part of the pipeline management system, the Licensee shall prepare and implement a pipeline integrity management plan (PIMP) for the operation and maintenance of the pipeline. The adequacy of the PIMP shall be reviewed at least every 5 years and immediately following a pipeline failure event.

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5.2 PIPELINE INTEGRITY MANAGEMENT PROCESS Monitoring, inspection and mitigation of the identified integrity threats shall be appropriate for the threats and controls identified in the safety management study prepared in accordance with AS 2885.1. Pipeline integrity management procedures shall be developed for each monitoring, inspection or mitigation action, to ensure the controls identified during the safety management study remain effective. The pipeline management system shall include the identification and capture of relevant data necessary to enable an assessment, at approved intervals, of the pipeline condition and the physical and procedural control measures in place. A PIMP shall cover the following: (a)

Pipeline structural integrity, including the technical aspects of maintaining pipelines as detailed in Section 6.

(b)

Anomaly assessment and defect repair, as detailed in Section 9.

(c)

External interference threats to the pipeline, as detailed in Section 7.

(d)

Operating condition changes and remaining life review, as detailed in Section 10.

(e)

Stations operations and maintenance, as detailed in Section 8.

Pipeline integrity management shall be carried out by competent personnel so that the responsibilities for approvals can be adequately implemented and demonstrated as sufficient for independent review. The diagram shown in Figure 5.1 describes the pipeline integrity management process, which incorporates the safety management study and an ongoing process of monitoring and review. This process is designed to ensure adequate integrity information is available when making the assessments required in Sections 6, 7, 8, 9 and 10.

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AS 2885.3—2012

I d e ntif y in g a n d c o ll e c ti n g r e l eva nt data

Pe r i o di c o r o n g o i n g s a fe t y m a n a g e m e n t s tu d y

Pip e li n e i nte g r i t y management r ev i ew

M o ni to r i n g of p ip e li n e i n te g r i t y m a n a g e m e nt ac tiviti e s a n d th re ats

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No

Pip e li n e i n te g r i t y i s s u e s i d e ntif i e d

Ye s

Revision and adjustment of pipeline management system and pipeline inte grit y management plan

FIGURE 5.1 PIPELINE INTEGRITY MANAGEMENT PROCESS

5.3 REVIEW OF PIPELINE INTEGRITY MANAGEMENT PLAN (PIMP) The PIMP of each pipeline shall be reviewed at approved intervals not exceeding 5 years and, if necessary, amended whenever— (a)

there are changes (including corrosion or damage, see Section 9); or

(b)

where there are new failure mechanisms identified as relevant to the pipeline that could adversely affect the safety of the public, the operating personnel or the integrity of the pipeline.

Investigations and calculations shall be reviewed to confirm that— (i)

the PIMP is consistent with the current structural condition of and the failure mechanisms identified in the pipeline; and

(ii)

any existing basis used to determine the remaining life calculated in accordance with Section 10 is valid.

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S E C T I O N

6

P I P E L I N E S T R U C T U R A L I N T E G R I T Y

6.1 BASIS OF SECTION Pipeline structural integrity is achieved when the pipeline is leak-tight, operating within the design parameters and able to safely withstand all identifiable forces to which it may be subjected during operation, including the MAOP. Effective management of structural integrity is a key component of successful pipeline integrity management (see Section 5). The objective of maintaining structural integrity of a pipeline is to ensure that the operation and maintenance of the pipeline will not cause injury to the public, pipeline personnel, damage to the environment, or disruption of service. The Licensee shall establish systems and processes based on the safety management study to ensure pipeline structural integrity for the design life of the pipeline. The Licensee shall describe these systems and processes in the pipeline management system and be able to demonstrate that appropriate systems are established, implemented and maintained.

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NOTE: For more information on how a pipeline management system relates to safety case, see Appendix E.

The continued structural integrity of pipelines relies on elements of pipeline design, construction and operation, and maintenance. Procedures shall be developed to ensure structural integrity of the pipeline infrastructure, including compressor and pump stations, regulator stations and metering facilities (see Section 8) are maintained during operation and maintenance activities. 6.2 STRUCTURAL INTEGRITY MANAGEMENT OVERVIEW To maintain the structural integrity of the pipeline, the Licensee shall review both time-dependent and time-independent factors that have a bearing on the pipeline, including the following: (a)

Pipeline operation and control.

(b)

Corrosion protection systems, including— (i)

protective coatings systems;

(ii)

cathodic protection systems; and

(iii) inhibition/internal corrosion control. (c)

(d)

Pipe wall integrity, including— (i)

anomaly assessment and defect repair (Section 9); and

(ii)

joints.

Station integrity (see Section 8).

The measures to address structural integrity shall be described in the PIMP (see Section 5). NOTE: The data and information identified and collected during these activities, assessments and reviews should form the basis for ongoing assessment of the risk and integrity of the pipeline. The findings of such a program will determine what responses are necessary to ensure continuous safe and reliable operation of the pipeline.

Structural integrity activity records shall be identified, collected and retained to enable new and emerging threats to be identified and managed through the safety management study’s process and to determine effectiveness of controls (see Section 12).

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AS 2885.3—2012

6.3 PIPELINE OPERATION AND CONTROL 6.3.1 General Pipeline operation and control shall be continually monitored while the pipeline is in operation to ensure that pipeline structural integrity is maintained. The pipeline shall be operated in accordance with the following: (a)

Operate a pipeline only when it conveys the fluid or fluids under the conditions (including subsequent changes) for which it was designed, constructed, tested, and approved.

(b)

Ensure that during normal operation, the overpressure control system is in place to ensure the operating pressure, at any point in the pipeline, does not exceed the MAOP, in accordance with AS 2885.1, and that transient pressure does not exceed 110% of the MAOP.

(c)

Ensure that the operating temperature is such that the coating temperature rating and the thermal stress limits used in the pipeline design are not exceeded.

(d)

Ensure that operating conditions are assessed and mitigate the likelihood of stress corrosion cracking initiation or growth.

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6.3.2 Operating parameters Operating parameters shall be established and communicated to enable pipeline control personnel to operate within desired limits, and the pipeline shall be operated within these limits. Operating parameters and alarm limits established for SCADA systems shall have appropriate change control measures in place. The Licensee shall regularly review the adequacy of operating and maintenance procedures as referenced in the pipeline management system. 6.4 PIPELINE CORROSION PROTECTION 6.4.1 General Pipeline corrosion protection systems provide protection of the pipe wall against corrosion. Adequate monitoring and maintenance shall be carried out to ensure that corrosion protection systems perform as required. The pipeline shall be operated with the required thickness for pressure containment. Metal loss from corrosion shall be investigated and mitigated by a documented corrosion monitoring strategy to maintain pipeline integrity. The Licensee shall have the processes and procedures defined in the PIMP. The processes and procedures shall ensure that the coating system and cathodic protection system are maintained and perform the required function of protecting the pipeline from threats, such as corrosion and physical damage, to ensure the pipeline remains fit for purpose during the operating life. 6.4.2 Corrosion mitigation strategy A corrosion mitigation strategy, consistent with the corrosion protection design and control equipment, shall be developed and implemented for the life of the pipeline. The external and internal corrosion mitigation strategy shall be developed based on the monitoring and control mechanisms identified in the safety management study and the pipeline design. The corrosion mitigation strategy shall include protection criteria, applicable principles, and procedures. www.standards.org.au

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The corrosion mitigation strategy shall cover maintaining coating condition, cathodic protection levels and inspection surveys. The corrosion mitigation strategy shall be detailed in the PIMP. NOTE: The monitoring and control of the following items should be considered part of the internal corrosion mitigation strategy: (a) Pipeline pigging. (b) Trash and water sampling, to determine iron counts or bacteria populations. (c) Inhibitor rate monitoring and residual sampling. (d) Biocide rate monitoring and residual sampling. (e) Fluid (composition) change. (f) Internal corrosion coupon assessment. (g) Pipeline inlet quality monitoring—abnormal operation assessment—off-specification gas or liquids entry. (h) Internal corrosion defect assessment by NDT methods. (i) Internal liner condition assessment (where used).

A pipeline provided with a corrosion allowance shall incorporate monitoring of the consumption of the allowance (see AS 2885.1).

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6.4.3 Pipeline coating systems 6.4.3.1 General Licensee shall assess, monitor and maintain any pipeline coating system in accordance with the PIMP. 6.4.3.2 Above-ground pipework Above-ground pipework is likely to be subject to atmospheric corrosion where poor coating condition allows water and/or moisture to come into contact with the steel surface. The applied pipe coating shall be maintained in a condition that prevents water reaching and collecting next to the pipe surface. Coating inspection of ground entry locations, especially at fluctuating immersion zones, shall be specifically addressed. The pipe coating shall be inspected, assessed and monitored at crevice areas such as pipe supports, interface of above and below ground pipe sections, and on the underside of the pipework. NOTE: The pipe wall should also be inspected for corrosion at areas of blistered or disbonded coating.

Records of the coating condition inspections shall be kept. 6.4.3.3 Below-ground pipework The assessment of the coating condition of below-ground pipework shall be achieved by evaluation of some or all of the following: (a)

Cathodic protection data.

(b)

Coating defect surveys (e.g. Pearson or DC-pulsed method surveys). NOTE: For information on coating defect surveys, see AS 4827.1.

(c)

Visual inspection at selected locations in bell-hole excavations and where the pipeline is exposed for any reason.

The coating and/or the cathodic protection system shall be maintained to a standard such that— (i)

the integrity of the pipe wall is maintained in accordance with the PIMP;

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(ii)

AS 2885.3—2012

the cathodic protection system effectively maintains protection at all coating defects in accordance with AS 2832.1; and

(iii) coating disbondment is minimized. Records of coating condition inspections shall be kept. 6.4.3.4 Coating maintenance strategy Where, after inspection, the pipe coating integrity is identified to be affected, the Licensee shall undertake an assessment to determine if remedial action is required. The corrective action may include coating repair or renewal. Where a repair is made to a pipeline coating, the material used for repair 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 repair shall be developed so that the desired physical and chemical qualities are obtained. Thereafter, the application shall be in strict accordance with the procedures. Surface preparation, application and testing of the coating shall be subject to a quality control program.

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6.4.4 Pipeline cathodic protection system Operation, maintenance and monitoring of cathodic protection systems shall be carried out in accordance with the requirements of AS 2832.1. NOTE: AS 2832.1 covers the following areas: (a) Criteria for cathodic protection. (b) Measuring techniques and equipment. (c) Operation of cathodic protection systems.

Where any inspection indicates that satisfactory protection is not fully achieved on the pipeline, timely and appropriate action shall be taken to restore full protection or to instigate other measures that monitor corrosion. The following specify personnel, instrument, test and record requirements: (i)

Personnel, experience, qualification and required training The parties responsible for the monitoring, survey, inspection, testing and maintenance of the cathodic protection system shall be competent in cathodic protection as approved by the delegate of the Licensee.

(ii)

Instrument and equipment Only approved measuring equipment and techniques in accordance with the requirements of AS 2832.1 shall be used.

(iii) Interference testing Interference testing shall be conducted in accordance with AS 2832.1. (iv)

Records Records complying with the requirements of AS 2832.1 shall be retained for the life of the pipeline.

6.4.5 Other corrosion mitigation measures Where the design of the pipeline in accordance with AS 2885.1 includes the use of inhibitors and biocides as the method of corrosion mitigation, the Licensee shall confirm that corrosion is adequately controlled and shall validate corrosion mitigation measures through the integrity management process. Where the mitigation method is found to be unsatisfactory, the method shall be revised to achieve the required level of corrosion control in accordance with AS 2885.1.

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6.4.6 Corrosion monitoring and remediation The internal/external surfaces of the pipeline shall be monitored for corrosion in accordance with the pipeline integrity management plan. Where corrosion is confirmed, it shall be assessed in accordance with Section 9. Where a pipe section is removed from the pipeline, the internal surface of the removed pipe section shall be inspected to assess the effectiveness of the internal corrosion control program. Whenever any part of a buried or submerged anti-corrosion-coated pipeline is exposed, it shall be inspected for corrosion and evidence of damage to, or deterioration of, any anti-corrosion coatings. If corrosion is found, it shall be evaluated to determine if the corrosion is systemic in the rest of the pipeline. A repair procedure shall be established and implemented to rectify the corroded pipe sections, where applicable. The corrosion mitigation measures in the PIMP shall be reviewed to determine if additional requirements and/or measures will be necessary for controlling the identified corrosion in the pipeline. This review shall consider the cause and rate of corrosion and recommend suitable actions, which may include a reduction of the design life.

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6.5 PIPE WALL INTEGRITY The Licensee shall implement processes and procedures to monitor and assess pipe wall integrity to maintain the required wall thickness. To maintain pipe wall integrity, the Licensee shall ensure the following requirements are met: (a)

Sufficient wall thickness shall be maintained at all locations, to contain fluid at the system MAOP. The minimum allowable wall thickness shall be assessed as follows: (i)

For a new pipeline, and for an in-service pipeline containing no corrosion anomalies or uniform general wall thickness loss, the minimum wall thickness shall be calculated in accordance with AS 2885.1.

(ii)

For a pipeline with anomalies, the minimum wall thickness shall be assessed in accordance with Section 9.

(b)

Sufficient structural integrity shall be maintained at joints to prevent leakage at the MAOP.

(c)

Where the safety management study identifies environment-related cracking, HIC or corrosion fatigue, the pipelines shall be inspected for evidence of both longitudinal and circumferential cracks in accordance with the PIMP.

(d)

The pipeline shall be inspected for evidence of material and construction anomalies in accordance with the PIMP.

(e)

The results of inspections shall be analysed and the outcomes incorporated in the PIMP.

(f)

Corroded pipelines shall be inspected for the extent of internal and external corrosion in accordance with the PIMP and the rate of corrosion shall be determined.

6.6 INSPECTION ACTIVITIES 6.6.1 General As specified in the PIMP, periodic inspections shall be carried out to identify actual or potential factors that could affect the integrity of the pipeline.

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AS 2885.3—2012

The Licensee shall consider the use of an inline inspection tool capable of detecting the flaws that may exist in the pipeline. Any decision not to use an inline inspection tool shall be consistent with the safety management study and PIMP, and shall be documented. Where a pipeline (or section of a pipeline) is not capable of being inspected by an inline tool, the Licensee shall consider whether the pipeline needs to be modified to permit inspection by an inline inspection tool. Any decision not to undertake modifications for this purpose shall be consistent with the safety management study and PIMP, and shall be documented. Where during inspection the integrity of the pipeline is threatened, the Licensee shall take immediate action, including actions required by Clause 9.3. NOTE: The following references provide guidance on the use of inline inspection tools: (a) API Std 1163 ‘In-line Inspection Systems Qualification Standard’ (adopts: NACE RP0102 In-Line Inspection of Pipelines’). (b) ASNT ILI-PQ ‘In-Line Inspection Personnel Qualification and Certification’. (c) Pipeline Operators Forum ‘Specifications and requirements for intelligent pig inspection of pipeline’, Version 2009.

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6.6.2 Frequency of inspection assessment The frequency of inspection and assessment shall be documented in the PIMP, based on past reliability of the pipeline, historical records, current knowledge of its condition, the rate of deterioration (both internal and external corrosion, and coating degradation), and statutory requirements. 6.6.3 Leak detection The PIMP shall nominate the methods used for leakage detection, and the minimum frequency of inspection by each method. The selected types of surveys or system shall be effective for determining whether a potentially hazardous leakage exists. The extent and frequency of the leakage surveys shall be based on operating pressure, piping age, class location, and whether the pipeline transports un-odourized gas. NOTE: Leakage surveys are only effective when the fluid is detectable by the instrument used for the survey. Tracer gas will be required for inert gas (CO 2) or low vapour point liquid (stabilized crude oil) pipelines. There is normally no need to use tracer gas for hydrocarbon gas or HVPL pipelines.

Location of any leaks should be determined by reviewing pipeline operating data, undertaking field leak detection in any suspected pipeline section, and/or mainline valve facilities. Where delay to make good of the fluid leak occurs, an assessment shall be undertaken to evaluate the impact on public and environment. When a significant fluid leak occurs in sensitive areas, an emergency response shall be in place to eliminate gas ignition by isolating or eliminating all ignition sources.

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6.7 MAINTENANCE PLAN—PIPELINE A pipeline maintenance plan shall be prepared, and shall include, as a minimum, the following: (a)

Maintenance measures identified during the relevant safety management study as necessary to eliminate threats, or to reduce threats to an acceptable level.

(b)

Where maintenance is to be carried out according to the plan.

(c)

A description of the maintenance tasks to be performed at each site.

(d)

A schedule for when each task is to be performed.

(e)

Records of results of the maintenance tasks that are to be kept.

The maintenance plan shall be a standalone document or be incorporated into the pipeline management system.

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NOTE: Associated maintenance procedures may be included by reference.

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S E C T I O N

7

AS 2885.3—2012

E X T E R N A L I N T E R F E R E N C E M A N A G E M E N T

7.1 BASIS OF SECTION External interference threats can arise from third party, contractor and pipeline operator activities. This Section sets out the approach to prevent, detect and control external interference threats to the pipeline. The Licensee shall establish and implement pipeline integrity management procedures to ensure that all external interference threats to the pipeline identified in the safety management study are controlled effectively. 7.2 EXTERNAL INTERFERENCE

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The safety management study, carried out in accordance with the requirements of AS 2885.1, requires that the Licensee identify and assess the risks associated with threats to the pipeline and instigate appropriate measures to manage those threats. The Licensee shall establish and implement procedures to monitor the effectiveness of the threat mitigation controls, and to identify any new external interference threats and document any such threat in the PIMP. 7.3 THIRD-PARTY PIPELINE AWARENESS 7.3.1 Community and stakeholder awareness Regular communication with the community and stakeholders and the relevant authorities is required to raise and reinforce awareness of the presence of a pipeline and the constraints with respect to the use of the land on and near the pipeline. Awareness programs enhance the effectiveness of other procedural controls such as pipeline markers, buried marker tape and call services. The Licensee shall establish a liaison program to communicate to the community and stakeholders the presence of the pipeline and the importance of the integrity of the pipeline for the safety of the public and the environment. When communicating with the relevant parties, the Licensee shall advise of any constraints that apply to the pipeline easement. 7.3.2 Land use planning 7.3.2.1 General The Licensee shall identify groups such as land use planners, developers, property and service designers, owners and operators, construction organizations, excavators, drillers, blasting companies and borers, and the general public on the basis of the requirements identified in the safety management study. The objective of liaising with these groups is to identify as early as possible any changes in planning, development or other activities that pose a threat to the pipeline.

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7.3.2.2 Landowner and occupier liaison Landowners and other occupiers of land through which the pipeline passes shall be visited, at approved intervals, to provide the landowners or occupiers with information regarding the asset and the requirements to obtain permission before carrying out certain works to ensure that their activities do not endanger the pipeline and its appurtenances. NOTE: Where it is not possible to personally contact the identified parties, consideration should be given to providing a package of information and contact details to the parties. Advice should include the dangers of interference with the pipeline and its appurtenances.

7.3.2.3 Emergency services liaison The Licensee shall take all reasonably practicable steps to inform people and organizations, such as emergency services, environmental agencies, landowners and occupiers, of the following: (a)

The hazardous properties of the fluid and the effects of any accidentally discharged fluid on the safety of the public and the environment so that, in the event of an emergency, prompt joint cooperative action can be taken.

(b)

The methods of recognizing threats to the pipeline and emergency situations.

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The Licensee shall provide 24 h contact telephone numbers of the appropriate responsible persons or organizations to be notified in the case of an emergency. 7.3.3 Pipeline marking Signs shall be maintained so they are legible and visible along the route of the pipeline to ensure the pipeline can be located and identified from the air, ground, or both, as appropriate to each particular situation, and as identified in the safety management study and AS 2885.1. 7.4 EXTERNAL INTERFERENCE DETECTION 7.4.1 Pipeline patrolling Pipeline patrols shall be undertaken at a frequency that will enable the Licensee to be assured that external interference threats are identified and managed. The patrol method and frequency shall be appropriate to the pipeline environment and location class and to the assessed likelihood of external interference and documented in the PIMP. The patrol method and frequency shall be varied as required by changes in threat, threat likelihood and consequence throughout the pipeline life. The boundaries and responsibilities for patrolling shall be clearly understood and defined in the pipeline management system to eliminate any gaps in coverage. Where a pipeline is decommissioned or its operational arrangements change, the frequency and type of patrolling shall be reviewed in the pipeline management system. Factors to be considered when developing a patrolling program at a minimum include the following: (a)

Operation of a ‘one-call system’.

(b)

Whether the pipeline is above- or below-ground.

(c)

Other forms of protection against interference.

(d)

Third-party activities that could affect the pipeline.

(e)

Location in a built-up area.

(f)

Locations close to environmentally sensitive areas.

(g)

Provision of a leak-detection system.

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(h)

Regularity of use.

(i)

Nature of the fluid carried.

(j)

Design and operating pressure and temperature.

(k)

Specific requirements such as at bridge crossings

AS 2885.3—2012

The Licensee shall ensure pipeline patrolling is conducted in accordance with the PIMP. 7.4.2 Patrol of pipeline During a patrol, attention shall be given to excavation, directional drilling, blasting operations, boring activities, including the use of an auger, and drains or ditches that are maintained and cleaned by an independent party. Natural events such as flood, earthquake and ground slips have the potential to affect the pipe’s integrity. Uncontrolled ground movements can impact and/or displace the pipe resulting in higher pipe stress and/or coating damage.

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The following shall be identified during the patrol of a pipeline: (a)

Variations to surface conditions such as erosion or earth movement or seismic activity.

(b)

Changes to watercourse, steep terrain and crossings.

(c)

Indications of leaks such as dead vegetation or evidence of liquid.

(d)

Construction activity or evidence of construction activity on or near the pipeline.

(e)

Impediments to access to valve stations, pressure regulator stations, compressor stations, pump stations, cathodic protection sites and communication installations for authorized personnel.

(f)

Deteriorating condition, visibility, adequacy and correctness of route markers and signs installed in accordance with the relevant requirements of Clause 7.3.3.

(g)

Security of sites and evidence of unauthorized entry.

(h)

Any relevant action identified in the safety management study.

(i)

Any other factors affecting the safety and operation of the pipeline.

(j)

Any factors likely to initiate a review of the safety management study such as urban encroachment and new developments.

(k)

Encroachment of vegetation limiting visibility of signs, access or potential of threat to pipeline coating from tree roots.

The person conducting the patrol shall— (i)

be issued with written patrolling procedures;

(ii)

be appropriately trained and competent in the procedures;

(iii) know the extent of the pipeline easement and the location of the pipeline; (iv)

be in radio/telephone communication with the control centre; and

(v)

maintain a patrol log.

All patrol records shall be retained for a minimum period of 10 years and maintained as specified in the record management plan. Patrol records shall be available to determine procedural measure effectiveness during future safety management studies.

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7.4.3 ‘Dial Before You Dig’ or ‘One Call’ services Licensees shall register and maintain the information about their assets with ‘Dial Before You Dig’ or ‘One Call’ services, where available, to provide third parties that are intending to work near the pipeline the location of pipeline assets, prior to the work activity. NOTE: Third parties excavating in areas for which ‘Dial Before You Dig’ or ‘One Call’ services are available should be encouraged to seek from that service information about pipeline assets, at least 48 h prior to excavating.

7.5 EXTERNAL INTERFERENCE CONTROL 7.5.1 Controlling activities near pipelines

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The Licensee shall bring to the attention of relevant parties the following in relation to activities near pipelines: (a)

The minimum notice of intended activities near a pipeline to be given to the Licensee or operators so that arrangements can be made to have a Licensee’s representative on-site during the work. Typically this is not less than 48 h.

(b)

Where third-party works are to be conducted in the proximity of a pipeline and the integrity of the pipeline is potentially under threat, the need for the site to be inspected and, where determined necessary, a work plan specified.

(c)

The need for a representative of the Licensee to be present during excavation near a pipeline, to minimize the risk of pipeline damage.

(d)

No mechanical equipment to be used for excavation within 1 m of the pipeline in any radial direction, even after the pipeline location has been proven, except when approved by, and under explicit ‘on-site’ direction from, the Licensee’s inspector. Under no circumstances is mechanical equipment other than hand-held and operated equipment to be used closer than 0.3 m to the pipeline. Exposure of the pipeline to be performed by hand digging, to minimize the risk of pipeline or coating damage.

(e)

The minimum clearance from a pipeline for any buried structure to be 0.3 m. The minimum clearance for parallel installation to be such that future maintenance can be conducted, but not be less than 0.5 m.

(f)

The minimum cover and maximum vehicle load limits for the protection of the pipeline.

(g)

Backfill requirements around the pipeline (typically no less than 150 mm and in accordance with AS 2885.1).

(h)

The notification requirements in relation to any damage to the pipeline and its coating and equipment.

All reasonable steps shall be taken by the Licensee to enforce the abovementioned criteria. NOTE: Apart from incident reporting to the regulatory authority where required by legislation, the circumstances of any incident, as defined in the Australian Pipeline Industry Association (APIA) Pipeline Operators Database, should be reported to APIA to enable statistics of pipeline incidents to be gathered.

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The Licensee shall consider the following when determining appropriate separation distances of pipeline to other buried structures: (i)

Corrosion protection interference.

(ii)

Penetration resistance.

(iii) Rupture or explosion interaction. (iv)

Access for maintenance and emergency repair.

(v)

Additional third-party activity.

NOTES: 1 Separation distances from the metallic structure forming part of electrical power generation, transmission and distribution systems should be determined on an individual basis as large currents can be discharged into the ground under fault conditions. Radiated heat may also impact pipeline coating systems. 2 Where boring or directional drilling is to take place under or over a pipeline, approved measures should be employed to ensure that the pipeline or its coating will not be damaged and a separation of at least 0.3 m between the pipe and bore is maintained.

Whenever the pipeline is exposed, a record should be kept of location, coating condition and any other pertinent information that can be used for integrity assessments. Accessed by APT Management Services Pty Limited on 21 May 2015 (Document currency not guaranteed when printed)

7.5.2 Placement of material on or near the pipeline The Licensee shall take all reasonable steps to ensure material is not placed on or near the pipeline without approval. Inappropriate placement of material on or near the pipeline can result in unacceptable soil loading, restricted access to the pipeline, changes in the pipe environment (corrosion) and increase to the risk of cave-in during subsequent excavation. NOTES: 1 Any landscaping material should be level within the easement or a minimum of 3 m (but preferably 6 m) to each side of the pipeline, to permit excavating equipment to operate without having to destroy the adjacent landscaping. 2 The addition of material on or near the pipeline should only be clean (preferably the same as the natural soil in that area) and should not contain ash, salt or chemicals.

7.5.3 Power and telephone poles, fencing, seismic and land disturbance activities The Licensee should ensure adequate liaison so that parties undertaking such works adjacent to the pipeline advise the Licensee not less than 48 h prior to commencement. This allows marking out the prohibited area and enables the Licensee to supervise, where appropriate, to prevent damage to the pipeline. The Licensee shall take all reasonable steps to ensure that the following activities are appropriately controlled: (a)

The placement of a new or replacement of power and communications services poles and fencing across or along the easement or pipeline route. NOTE: Holes should only to be drilled and poles or posts placed after the Licensee has marked the exact pipeline location and has decided if supervision of the activity is required.

(b)

Land disturbance activities deeper than 300 mm, such as deep ripping, and the installation of drainage systems on the pipeline easement, or where no easement exists, a minimum of 3 m (but preferably 6 m) each side of the pipeline.

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Any seismic surveys and associated blasting near the pipeline, or crossing activities need to be designed to ensure that these activities do not affect the pipeline.

NOTES: 1 The Licensee should advise seismic contractors of restrictions on working near the pipeline including maximum particle velocity level and the advance notice required to enable calculations and designs to be produced for actions to protect the pipeline during seismic work. 2 The Licensee should ensure that it is able to respond within a reasonable time to requests for seismic crossings.

7.5.4 Vegetation on and near the pipeline Unless approved by the Licensee or delegate, vegetation shall be managed to allow free passage along the pipeline route. NOTE: Vegetation, whose roots may damage the anti-corrosion coating of the pipeline, should not be permitted in the vicinity of the pipeline.

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7.5.5 Encroachment/location class Any change of land use near the pipeline requires the Licensee to review the pipeline’s safety management study to assess the impact and advise the developer of the impact identified as a result of the change in land use. Additional mitigation measures may be required to meet the requirements of AS 2885.1, particularly where land use changes become high consequence areas and more stringent control requirements arise. The Licensee shall establish the necessary management procedures for all known and proposed land use changes around the pipeline and be ready to implement changes for future planned land use. When a known proposed development is identified, the Licensee shall undertake a safety management study and confirm the pipeline integrity, both its structural strength and coating condition, to ensure continuous safe and reliable pipeline operation for the proposed new operating environment. 7.5.6 Vehicle load limits Loads imposed by vehicles on the pipeline shall be assessed and managed if they are considered to exceed the design conditions of the pipeline at any specific location. The induced pipe stress shall be confirmed to comply with the total pipeline stress and strain limits, as specified in AS 2885.1. Where the pipeline stress due to external loads is assessed to exceed the specified limits, appropriate load restrictions and/or stress limitation measures shall be provided to ensure the pipeline’s safe and reliable operation. 7.5.7 Access to the pipeline easement The requirement for access to the pipeline easement by a third party shall be assessed. Where access is determined necessary, the easement shall be maintained to allow appropriate access by pipeline personnel and authorized contractors. 7.5.8 Explosives The Licensee shall ensure adequate liaison with any person intending to use explosives near the pipeline. Any use of explosives in the vicinity of the pipeline shall be fully evaluated prior to granting approval.

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7.5.9 Licensee’s activities In addition to the external interference controls identified in the safety management study the controls associated with the following Licensee’s activities, shall be included in the PIMP: Coating assessment and repairs.

(b)

Pipe wall assessment and repairs.

(c)

Joint assessment and repair.

(d)

Loss of cover repair.

(e)

Incident response, review and prevention.

(f)

In-service modifications.

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(a)

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8

S T A T I O N S O P E R AT I O N S M A I N T E N A N C E

A N D

8.1 BASIS OF SECTION Stations shall be operated within the limits of their process design. Maintenance of stations shall ensure that— (a)

all devices and systems required to ensure the station operates within these limits are operable; and

(b)

the structural and pressure integrity of stations is not compromised over time.

Operations and maintenance activities of stations shall be documented and the effectiveness of these activities shall be monitored. 8.2 SAFETY OF CRITICAL EQUIPMENT

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Equipment, devices or systems that maintain station operations within the constraints of their process design shall be maintained and tested to ensure their operation is reliable. Such systems include, but are not limited, to the following: (a)

Regulators.

(b)

Pressure-control valves.

(c)

Pressure- and temperature-sensing and control circuits.

(d)

Safety or relief valves.

(e)

Slam-shut or emergency shut-off valves.

(f)

Pressure and temperature switches.

(g)

Emergency shutdown systems.

Such systems shall be identified and maintained in accordance with the maintenance plan as specified in Clause 8.7. Records of the maintenance and testing of these systems shall be kept. The maintenance of these systems shall ensure the systems are— (i)

in good electrical, mechanical or hydraulic condition;

(ii)

set to function at the correct level;

(iii) properly installed and protected from foreign material or other conditions that might prevent proper operation; (iv)

installed in a manner so as to prevent unauthorized operation or alteration;

(v)

operating correctly; and

(vi)

adequate from the standpoint of capacity and reliability of operation.

Safety valves shall be maintained and tested in accordance with AS 3788. 8.3 PRESSURE VESSELS Pressure vessels within stations shall be operated within the limits of their design parameters. Maintenance of pressure vessels shall ensure the pressure rating of the vessel is not degraded over time. Internal and external inspections shall be performed at regular intervals to ensure corrosion or other degradation is detected before it threatens pressure containment capability. Pressure vessel inspections shall be in accordance with AS 3788. © Standards Australia

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Pressure vessels shall be identified and maintained in accordance with the maintenance plan. Records of the maintenance and inspection of pressure vessels shall be kept. 8.4 STATION OPERATIONAL CHECKS Operational checks shall be performed at regular intervals to ensure stations are functioning correctly and are operating safely. The frequency and scope of these checks shall be established as part of the pipeline management system, and shall be based on the safety management study. Where a pipeline isolation or emergency response plan (ERP) requires that systems to control or isolate the pipeline are operable, these shall be maintained as part of station maintenance. Where a change to a maintenance frequency or scope is proposed, this change shall be approved by the Licensee or delegate of the Licensee. The change to maintenance frequency and scope may require reference to, or review of the safety management study.

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Station operational checks shall include the following items, where relevant to each site: (a)

Remote and/or local actuation of main line valves.

(b)

Detection and repair of leaks of process or ancillary fluids.

(c)

Examination of the condition of safety critical equipment.

(d)

Inspection for coating conditions and corrosion.

(e)

Inspection of cathodic protection systems.

(f)

Checking of filter vessels and pig traps.

(g)

Checking of station ancillary systems.

(h)

Recording key operating data and status.

(i)

Reviewing local alarm indications or control panels.

(j)

Checking communications systems.

(k)

Checking huts, compound gates, fencing and vegetation growth.

8.5 STATION STRUCTURAL INTEGRITY Stations are subjected to threats to structural integrity. Stations shall be inspected at regular intervals. Threats to stations include the following: (a)

Corrosion at pipe supports or braces.

(b)

Fatigue, corrosion, fretting or cracking induced by vibration.

(c)

Erosion of pipework caused by gas flow.

(d)

Corrosion at flange bolts and other threaded fittings.

(e)

Corrosion where pipe enters the ground.

(f)

The effects of thermal and pressure cycling.

(g)

Corrosion in low lying or zero flow piping.

(h)

Accumulation of liquids in piping.

(i)

Effects of lightning strikes.

(j)

Incorrect maintenance or operation.

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Threats to station structural integrity shall be defined in the safety management study conducted in accordance with AS 2885.1. The management of credible threats shall be identified and inspection intervals and procedures defined and documented in the maintenance plan. NOTE: A HAZOP and/or the safety management study prepared during pipeline/station design or construction may provide source of information on possible threats and mitigation actions.

8.6 COMPRESSOR AND PUMP STATIONS Compressor and pump stations shall be operated and controlled within the limits of their process design. Process design limits are established in design calculations and are documented in the pipeline management system. Safety critical equipment shall be maintained in accordance with Clause 8.2 and pressure vessels in accordance with Clause 8.3. In addition, other pressure and temperature-containing, relieving or controlling devices shall be operated, maintained and tested to ensure reliable and safe operation. Compressor and pump stations generally contain more complex equipment than other pipeline stations. Compressors, pumps and their drivers generally have vendor documentation describing maintenance requirements.

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NOTE: Compressor and pump stations should have a design basis manual, compiled during design, which describes the process design and safety of critical systems.

Compressor and pump station safety critical equipment shall be identified and inspection and testing procedures documented. Particular attention shall be given to validating systems where control circuits form the first layer of safety critical systems, and to multiple layer systems normally found at compressor and pump discharges. The following apply to stations for pumps, compressors, meters, mainline valves, pressure regulators, odourizers, and similar devices: (a)

The area around stations shall be maintained in a clean and safe condition.

(b)

Entries, exits, and escape routes shall be kept free from obstruction at all times.

(c)

Fences and gates shall be maintained to prevent unauthorized access to the station area.

(d)

Start-up, operating, and shutdown procedures for all equipment shall be established and followed. The procedures shall include details of the measures required to ensure that all equipment, including any shutdown control or alarm circuits, functions correctly.

(e)

Warning signs shall be maintained to ensure their accuracy, legibility and adequacy.

(f)

When deviations from the normal operating conditions that affect the safety of the pipeline occur, corrective action shall be initiated immediately.

(g)

Where determined necessary, firefighting equipment shall be kept on-site and maintained in good condition.

NOTE: When the site is attended, sufficient personnel, trained in the use of the firefighting equipment, should also be in attendance.

8.7 MAINTENANCE PLAN A maintenance plan shall be prepared for station maintenance. The maintenance plan for stations shall include, as a minimum, the following: (a)

Safety critical system testing.

(b)

Piping inspections.

(c)

Pressure vessel inspections and maintenance.

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Station maintenance shall be conducted in accordance with the maintenance plan. 8.8 STATION LOCAL CONTROL SYSTEMS Most stations are remote from their point of operation and are generally designed for unattended operation. Each station with a local control system to manage the safe operation of the station shall be operated and maintained to ensure the station operates within the limits of its process design. The local control system shall— (a)

either continue to operate safely in the event of a communications failure or fail in a safe manner;

(b)

where electrically powered, in conjunction with an uninterruptible power supply, maintain the design capacity to ensure continuous operation throughout a reasonable power outage;

(c)

use reliable technology;

(d)

be maintained to fail in a safe manner; and

(e)

be maintained with appropriate security.

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Each facility may also be configured to enable remote monitoring or control of the facility. Where remote monitoring or control of a facility is possible, the system shall be resistant to external electronic interference or monitoring by unauthorized third parties. In certain installations, local control systems form part of layers of process control, or safety critical systems. Changes to the local control system design, set points, or logic shall be subjected to management of change processes. This may include revalidation of system operation, such as factory acceptance testing, and field function testing. 8.9 SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA) Where a pipeline is provided with a SCADA system, it shall be operated and maintained to enable the safe operation of the pipeline. The following features, incorporated in the design, shall be maintained during the operational life of the pipeline: (a)

Security and reliability.

(b)

Supervision of the operation of the pipeline system.

(c)

The capability of issuing operating and control commands.

(d)

The capability of collecting, storing and displaying data, facility alarms and status.

(e)

Ensuring safe operation of control systems at remote facilities, irrespective of the condition of the SCADA system.

Changes to the SCADA design shall be undertaken and approved in accordance with the requirements of AS 2885.1. 8.10 SITE SECURITY The security of a station against unauthorized interference shall be addressed by the safety management study. Security provisions that are incorporated in station design shall be maintained. Consideration shall be given to securing key items, such as valves, huts and control cabinets, against unauthorized interference, particularly where such interference may produce fluid releases, interruption to fluid flows or hazards within the site. NOTE: Changes in local land use, population density, construction or improvement of nearby roads, urban encroachment, or other similar factors may increase the security risk to a station and result in the revision of the safety management study, requiring changes to site security. www.standards.org.au

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8.11 STATION EQUIPMENT AND COMPONENTS 8.11.1 General In addition to the pipeline itself, station equipment and components shall be maintained in accordance with the maintenance plan. 8.11.2 Above-ground valves Above-ground valves and actuators shall be inspected and maintained to ensure that— (a)

each valve is properly supported and that corrosion problems at support points are not occurring;

(b)

valves are secured to prevent unauthorized access and usage;

(c)

corrosion on fittings is not occurring;

(d)

valves are not leaking; and

(e)

valves and actuators are fully operable.

Valves, including mainline valves and the emergency hand-operated equipment of remotely controlled valves, shall be tested or operated at intervals to confirm operability.

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8.11.3 Pipe supports All pipe supports for above-ground portions of lines shall be inspected to establish the physical condition of each support, and to verify that they are supporting the pipe at that point. Where applicable, the interface between the carrier pipe and the pipe support shall be inspected for corrosion. 8.11.4 Ground entry locations Locations where pipelines enter and leave the ground shall be inspected for coating deterioration and associated corrosion, in accordance with the maintenance plan. NOTE: The inspection intervals are dependent on the coating type applied to the pipeline.

8.11.5 Pig trap inspection and maintenance Inspection and maintenance of pig traps, including end closure seals, bleed locks, electrical bonds, locking rings, pig signallers and fasteners, shall be undertaken in accordance with the maintenance plan. In addition, temporary or removable pig traps shall be inspected before use for mechanical damage (due to handling) and for evidence of corrosion. Quick-opening closures shall be operated and maintained strictly in accordance with the manufacturer’s instructions, particularly with regard to the yoke adjustments and pressurewarning devices. 8.11.6 Tunnels and valve pits Where practicable, inspection and maintenance of tunnels and valve pits shall be specified in the maintenance plan to confirm— (a)

the structural integrity of the tunnel or pit;

(b)

the structural integrity of any pressure-containing equipment;

(c)

the absence of leaks in the pipeline; and

(d)

valve pits are free of all matter that could interfere with the operation of the valve.

Corrective action shall be initiated as warranted. Where a tunnel, shaft or valve pit is determined to be a confined space, entry shall be controlled by confined space entry procedure and permit in accordance with Section 4. NOTE: For a definition of confined spaces, see AS 2865. © Standards Australia

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8.11.7 Structures housing equipment Structures that are housing equipment containing hydrocarbons, such as compressors, pumps, valve/regulator/meter pits or buildings, instrument rooms and laboratories, shall be inspected and maintained in a safe condition in accordance with the maintenance plan. Intervals for inspection shall be determined from the safety management study carried out in accordance with AS 2885.1 and experience with the equipment involved. The inspection shall include, as minimum, the following: Testing of the atmosphere in the structure for toxic or combustible atmosphere.

(b)

Proving the operation of ventilating equipment.

(c)

Proving the operation of any fire or gas detection systems.

(d)

Structural integrity of pit covers.

(e)

Testing of any alarms.

(f)

Testing of any emergency exits.

(g)

Inspection of gas bottles housed within structures.

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S E C T I O N

9

A N O M A L Y A S S E S S M E N T DEFE CT RE PAIR

A N D

9.1 BASIS OF SECTION The objective of establishing anomaly assessment and repair procedures for the pipeline is to ensure that the continued operation of the pipeline will not cause injury to the public, operating personnel, damage to the environment and infrastructure, and/or disruption of service. This Section— (a)

outlines the direct assessment process;

(b)

stipulates an anomaly assessment process:

(c)

describes acceptable repair strategies/considerations; and

(d)

suggests recommended repair methods.

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NOTE: In the event of a loss of containment or imminent threat to the integrity of the pipeline due to damage or corrosion, for initial response see Clause 9.9.2.1.

The Licensee shall establish procedures to assess anomalies and repair defects. The Licensee shall describe these procedures in the PIMP. 9.2 DIRECT ASSESSMENT 9.2.1 General Direct assessment has a four-element approach, as follows: (a)

Pre-assessment Pre-assessment is the first element within the overall direct assessment process. This requires the compilation of past and present pipeline data. This data may include pipeline physical characteristics as well as operational history.

(b)

Indirect inspection This element incorporates the equipment and practices utilized to take measurements above ground or near a pipeline to locate and characterize anomalies. An indirect inspection survey could typically include coating and cathodic protection surveys and acoustic emission monitoring.

(c)

Direct examination This process is based on the equipment and the practices used to take measurements on or at the pipeline to locate and characterize anomalies. A direct examination may be done with direct methods such as ILI, measured corrosion protection data, non-destructive examination on the pipeline (including excavations of representative sample locations), strain measurements, deposits and coating damage.

(d)

Post-assessment After the first three elements are confirmed, a fourth element, namely post-assessment, is required. The output of the post assessment is based on the data collected from the three previous elements and is utilized to— (i)

support engineering assessments of the pipeline; and

(ii)

determine the need for any review of inspection intervals.

The Licensee shall confirm/verify that the intent of each element is met taking into account historical data. These elements need not be conducted sequentially. NOTES: 1 A depiction of the direct assessment process is shown in Figure 9.1. 2 NACE RP0502 and NACE SP0206 provide additional guidance on direct assessment methodologies. These Standards do not incorporate methodology associated with stress corrosion cracking (SCC). For guidance on SCC, see NACE SP0204. © Standards Australia

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Steps

e.g. Historic data, legacy

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AS 2885.3—2012

1. Pre-assessment

Output

Compiled understanding

e.g. DCVG, CP audits, CIPS, acoustic emission

2. Indirect inspection

Results and defect characterization

e.g. ILI, NDT, deposit analysis, strain measurements

3. Direct examination

Results and defect characterization

Steps, 1, 2 and 3

4. Post assessment

Engineering assessment to review effectiveness and reassessment inter val

FIGURE 9.1 DIRECT ASSESSMENT PROCESS

9.2.2 Personnel Persons responsible for undertaking direct and indirect monitoring, inspection and assessment activities shall be competent to undertake these activities. The parties responsible for the Levels 1, 2 and 3 engineering assessments (see Clause 9.5) of anomalies and determination of repair methods for defects shall be competent to conduct engineering assessments. 9.3 INITIAL ASSESSMENT AND REMEDIAL ACTION Where the integrity of a pipeline, or a section of a pipeline, is assessed as being compromised, the operator shall immediately take steps to prevent loss of containment of the pipeline until the integrity of the pipeline is restored. Interim measures shall be taken to mitigate the risk of a failure. This may include pipeline pressure reduction, bypassing, or carrying out temporary repairs and appropriately adjusted surveillance intervals and methods. An MOP shall be established immediately to stabilize any anomaly potentially impacting on pressure containment. The MOP so established shall be documented. NOTE: The minimum pressure reduction should be at least 10%, but preferably 20%, of the operating pressure at time of identification.

An engineering assessment should be completed as soon as practicable to confirm the MOP, which may result in a raised or further lowered MOP. If an engineering assessment is carried out, it shall be documented.

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The operating pressure should not be permitted to be raised above the established MOP until the anomaly has been inspected and assessed. A permanent repair shall be planned, documented and implemented following the temporary repair. The repair shall reinstate the integrity of the pipeline for the MAOP. Prior to the commencement of any repair work, a risk assessment shall be undertaken to examine all of the potential threats to the public, operating personnel, and the continuity of supply that will arise as a result of the repair, and a risk management plan shall be developed. The repair shall take into consideration the requirements of Clause 9.10.

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NOTES: 1 Revision of corrosion mitigation strategy (see Clause 6.4.2) should be considered. 2 Due consideration should be made for circumferential orientated anomalies or penetration anomalies when planning initial assessment and remedial action. For circumferential orientated anomalies, inspection via excavation should be designed to minimize axial load and to be scheduled, if possible, when ground temperature is not at a minimum. For penetration anomalies (in addition to the requirements for circumferential orientated anomalies), the operating pressure should be reduced to as low as possible to minimize release rates. Environmental considerations take precedence in this respect; however, this Standard does not include requirements for, or information on, environmental considerations.

9.4 PIPE WALL ANOMALY ASSESSMENT 9.4.1 General The objective of anomaly assessment is to determine whether a pipeline has sufficient structural integrity to withstand all forces to which it may be subjected to during operations (within prescribed safety margins). Where a pipeline anomaly is detected, it shall be investigated to determine its nature, extent, depth and cause. The anomaly shall be evaluated to confirm acceptability and the current MAOP shall be confirmed. In the event that the MAOP is determined to have been compromised, a safe operating pressure shall be determined by assessment in accordance with Clause 9.6 and, if necessary, either a new MAOP shall be established or the affected portion of the pipeline shall be repaired or replaced. Upon completion of engineering assessments (see Clause 9.6) carried out on a pipeline anomaly, the Licensee may decide to deem such anomaly as acceptable (damage not requiring repair). For all anomaly types, including all known applicable stresses and bending moments the anomaly area may be subjected to, shall be considered in the assessment. If deemed as a defect, repair or remediation shall be carried out in accordance with Clause 9.10. Recommendations from pipe wall anomaly assessments and remaining life assessments (anomaly degradation rates) shall be incorporated into the PIMP. NOTE: Requirements for detailed assessment of pipeline anomalies are given in Clause 9.6.

9.4.2 Anomaly types 9.4.2.1 Corrosion anomalies Corrosion anomalies on pipelines are generally of the following types: (a)

Localized corrosion such as pits.

(b)

General corrosion, either axial or circumferential.

(c)

Axial groove or slotting corrosion.

(d)

Circumferential groove or slotting corrosion.

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AS 2885.3—2012

Hybrid corrosion (e.g. pits within general corrosion areas).

NOTE: For dents containing corroded areas, see Clause 9.4.2.4.

9.4.2.2 Interaction of corrosion anomalies Adjacent corrosion anomalies may interact to produce a failure pressure that is lower than the individual failure pressures of the isolated anomalies treated as single anomalies. If two or more anomalies are close to one another, they can be combined into a single equivalent anomaly for the purpose of analysis. If the separation distance is sufficient to avoid interaction, then the anomalies may be analysed separately. Combined pipe wall anomalies shall be subjected to detailed assessment. NOTE: Rules for combining interacting anomalies into a single equivalent anomaly are detailed in various documents and recommended practices including API RP 579, AGA PR3-805 (RSTRENG) and DNV RP F101.

The Licensee shall ensure that due consideration is given for the interaction of anomalies in corrosion anomaly engineering assessments.

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Areas that have coincident internal and external corrosion anomalies shall be acceptable, regardless of the length of the corroded area, provided the sum of the maximum internal anomaly depth and the maximum external anomaly depth is 10% or less of the nominal wall thickness of the pipe. NOTE: Suggested corrosion anomaly interaction rules are given in Appendix C.

9.4.2.3 Gouges, grooves and notches Abrasion and light mechanical damage shall be assessed to the criteria specified in this Clause. Anomalies such as gouges, grooves and notches less than 0.25 mm in depth are not considered defects, unless otherwise determined by the Licensee. Gouges, grooves and notches deeper than 0.25 mm depth are considered defects and shall be removed, replaced or otherwise repaired. Gouges, grooves and notches above 0.25 mm and up to 10% of wall thickness may be removed by grinding without further wall thickness assessment, provided they are not associated with dents or micro-cracking. The requirements for non-destructive testing (NDT) for dents and micro-cracking associated with gouges, grooves and notches shall be assessed by the Licensee. Wall thickness loss due to grinding shall be assessed in the same manner as for corroded pipe wall. Detailed engineering assessment shall be carried out to confirm the acceptability of gouges, grooves and notches outside of the criteria specified in this Section. NOTE: Detailed assessment of pipeline anomalies is given in Clause 9.6.

Gouges, grooves and notches are considered severe anomaly types as it is difficult to establish the pipe’s strength and ductility at the location of maximum deformation. In the absence of adequate understanding of material condition data, the requirements set out in this Clause shall apply. 9.4.2.4 Dents and buckles Dents in pipelines are generally of the following types: (a)

Plain dents.

(b)

Rock dents (including restrained).

(c)

Dents with associated gouge.

(d)

Dents with associated corrosion.

(e)

Dents containing a long seam weld.

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(f)

Dents associated with a girth weld.

(g)

Dents subject to cyclic loadings (fatigue) particularly liquids pipelines that are not operated continuously, where stress cycles may be equal to MAOP.

A separate assessment shall be required for each of the above dent types. Dents with gauges shall be removed or stabilized by a sleeve. Workmanship standards set out by AS 2885.1 and assessment techniques set out in Table 9.2 shall be taken into consideration when assessing dents. Anomalies such as dents and buckles shall be inspected using visual and/or mechanical measurement methods capable of determining the depth and shape of the anomaly, the location of the anomaly with respect to seam welds and the presence of gouges, grooves or other anomalies within or in close proximity to the dents/buckles. Where considered necessary, non-destructive methods capable of sizing dents and buckles shall be utilized. Dents containing corroded areas deeper than 10% or up to 40% of nominal wall thickness are considered defects unless engineering assessment determines otherwise. Corroded areas greater than 40% of nominal wall thickness within dents are considered defects and shall be removed, replaced or otherwise repaired.

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9.4.2.5 Pipe body surface cracks Crack-like anomalies found on pipe body surface are considered defects unless fracture mechanics analysis, including fatigue cracking assessment (see Note), indicates that such anomalies are acceptable. NOTE: For information on fracture mechanics analysis, see Table 9.2.

The engineering assessment shall include consideration of service history and loading, anticipated service conditions (including the effects of corrosive and chemical attack), the mechanism of crack formation, crack dimensions, crack growth mechanisms, failure modes, and material properties (including fracture toughness properties). Crack-like defects shall be removed, replaced or otherwise repaired. Crack-like defects may be removed by grinding provided appropriate, as per industry practice and repair plan (see Clause 9.10), measures are put in place and metal loss due to grinding complies with acceptable limits of anomaly assessment codes. The requirements for detailed non-destructive testing (NDT) for cracks shall be assessed by the Licensee. Wall thickness loss due to grinding may be assessed in the same manner as for corroded pipework. 9.4.2.6 Environmentally assisted cracking Stress corrosion cracking (SCC), hydrogen-induced cracking (HIC), sulfide stress corrosion cracking and hydrogen-assisted cold cracking (HACC) are environmentally assisted forms of cracking that shall be assessed as crack-like anomalies in accordance with Clause 9.4.2.5. NOTE: Environmental cracks typically occur in multiples and may be branched. The assessment procedures in Appendix C should be applied to such cracks provided a predominant crack, whose behaviour largely controls the structural response of the material, can be identified. The predominant crack in the presence of multiple or branched cracks may be defined through characterization rules that allow multiple crack geometry to be modelled to a simpler one in order to make the actual crack geometry more manageable to fracture mechanics analysis. These characterization rules account for anomalies of shape, orientation and interaction. The rules used to characterize crack-like anomalies are necessarily conservative and intended to lead to idealized crack geometries that are more severe than the actual crack geometry they represent.

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For further guidance on interaction rules in environmentally assisted cracking, see API RP 579 and Stress Corrosion Cracking (Dec 2007) – Canadian Energy Pipeline Association (CEPA). When a predominant crack cannot be defined even after re-characterization, more advanced assessment techniques, such as damage mechanics, may be used. Multiple crack-like anomalies do not have to be combined into an equivalent anomaly for evaluation if a stress intensity factor and limit load solution can be obtained for the interacting anomaly geometries.

9.4.2.7 Anomalies on field welds and seam welds Anomalies found on field and seam welds, HAZ or areas near welds shall undergo NDT to determine the extent and origin of the anomaly. The extent of NDT shall be assessed to ensure the chosen inspection method (or combination of methods) is capable of detecting cracks. Such anomalies shall be accepted, provided they comply with the workmanship criteria set out in AS 2885.2, or based on engineering assessment involving consideration of service history and loading, anticipated service conditions (including the effects of corrosive and chemical attack), anomaly dimensions, and weld properties (including fracture toughness properties).

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Engineering assessments of these anomalies shall be carried out in accordance with suitable anomaly assessment methods. NOTE: Suggested anomaly assessment methods are given in Table 9.2.

Pipe containing weld anomalies that are unacceptable shall be removed, replaced or otherwise repaired as specified in this Standard, AS 2885.1 and AS 2885.2. NOTE: Seam welds include longitudinal and spiral seam welds.

9.4.2.8 Anomalies on fibreglass pipelines Anomalies detected on the surface of fibreglass (glass reinforced) material pipelines shall be inspected using visual and mechanical measurement methods capable of determining the depth and shape of the anomaly. NOTE: For guidance on assessment of anomalies commonly found in this type of material, see Table 9.1.

In the absence of adequate understanding of material condition data, the requirements set out in this Section shall apply.

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TABLE 9.1 ANOMALY ASSESSMENT GUIDELINES FOR FIBREGLASS PIPELINES Anomaly type

Description

Shallow scratches

Depth < 0.1 mm

Light surface abrasion

No exposed fibres

‘Coin’ marking

Resin surface intact

Deep scratches

0.1 mm < depth < 0.5 mm

Assessment

Acceptable

Deemed as defect—surface requires repair. Hot patch repair may be used

Surface abrasion

Fibreglass decolouration (i.e. whitening)

Acceptable

Light mechanical damage Resin surface damage visible (i.e. gouges, grooves, notches)

Acceptable

Gouge, grooves, notches

Deemed as defect—section requires replacement

Dent

Depth >0.5 mm Fibreglass exposed Laminate strength compromised

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NOTE: Detailed analysis of anomalies in fibreglass pipelines may be undertaken using CSA-Z662 Oil and Gas Pipeline Systems. ISO 14692-4 and Shell DEP 31.40.10.19-Gen., provide additional guidance in regards to operation of fibreglass (glass reinforced) pipelines.

9.5 FITNESS FOR PURPOSE (FFP) LEVEL ASSESSMENT 9.5.1 General This Standard provides various methods for the assessment of pipeline anomalies in a framework of levels—Level 1, 2 and 3. NOTE: An assessment flow chart is shown in Figure 9.2.

Level 1 being most conservative, empirical and having the least data requirements; Level 2 having intermediate data requirements; and Level 3 being detailed, reliability based and having the most data requirements. The level assessment methodology shall be documented and shall be applied to both parent metal/mother pipe and weld anomaly assessments. NOTE: Examples of methods of assessment are given in Appendix C.

The Licensee may undertake anomaly assessments using other approved/industry accepted methods. Regardless of method chosen, the MOP (see Clause 9.8) of the pipeline shall always be less than or equal to the safe working pressure (SWP) ascertained for the detected anomaly(ies), as follows: SWP = Pf × SF where Pf

= failure pressure of anomaly (dependent on anomaly orientation)

SF

= safety factor

The safety factor (SF) may vary as determined by engineering assessment and shall be approved. For long-term integrity of the pipeline, the Licensee shall comply with the MAOP requirements of Clause 9.8.

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Where design factors described by the level assessment methods (see Clauses 9.5.4 to 9.5.6) are more conservative than AS 2885.1, the stipulated design factors for the assessment methods prevail over AS 2885.1, as these methods have been empirically and physically qualified for a given design factor(s). Where design factors described by the level assessment methods (see Clauses 9.5.4 to 9.5.6) are less conservative than AS 2885.1, the Licensee or delegate shall approve the application of these methods by demonstrating due diligence and sound engineering judgment. Due consideration (sound engineering and documented process) shall also be given to anomaly degradation rates when using the level assessment framework in determining remaining life. 9.5.2 Anomaly degradation rates

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Internal degradation rate considerations typically include, but are not be limited to— (a)

theoretical and actual flow conditions;

(b)

product content including CO2, H2S and water content;

(c)

bathymetry and temperature profile that will facilitate water pooling;

(d)

pressure cycling;

(e)

presence of microbiologically induced corrosion (e.g. sulfate-reducing bacteria);

(f)

predicted and confirmed (through successive anomaly-matched inspections) anomaly degradation rates; and

(g)

erosion.

External degradation rate considerations typically include, but are not limited to— (i)

hydrogen evolution rates through CP;

(ii)

stress cycling due to external influences;

(iii) coating integrity—degradation rates and shielding. (iv)

soil types; and

(v)

CP levels.

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Inspection data

Pre-level assessment (workmanship standards) No

Fail Yes

Pipeline data

Inspection tolerances

Pipeline loading and environmental data

Anomaly degradation rates

Level 1 assessment

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No

Fail Pass

Yes

Cost -benefit analysis

Level 2 assessment No

Fail

Pass

Yes Level 3 assessment

Yes

Repair, rerate, or remediate

Fail

No

Fit for service

FIGURE 9.2 ASSESSMENT FLOW CHART

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TABLE 9.2 TYPICAL ASSESSMENT METHODS Method/RP/Standard vs failure mechanism

General/Local Gouges/Dents metal loss

Out of roundness/ ovality/weld misalignment

Fatigue

API RP 579 Level 1 Level 2 Level 3

  Guidance (1)

  Guidance (1)

  Guidance (1)

ASME B31G Level 1



N/A

N/A

N/A

 (5)  (5)  (5)



BS 7910 Level 1 Level 2 Level 3

DNV RP F109 Level 1 Level 2 Level 3 DNV RP F101 (revised versions) ASA (Level 2) PSF (Level 3)

FEA Level 3

Brittle fracture

    Guidance (2) Guidance (3)

Freespans Stability Buckling

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

  

N/A

N/A

N/A

N/A

N/A







N/A



N/A

Guidance

Guidance



N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

  

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

  N/A

  N/A

N/A

N/A

N/A N/A

N/A

  







N/A   Guidance





N/A (6)



N/A

N/A (6)

N/A (continued)

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DNV RP F105 Level 1 Level 2 Level 3

N/A

  Guidance (1)

Crack-like flaws

65

DNV OS F101 Workmanship standards Level 3

N/A



(4)

Complex defects/ Interaction

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Method/RP/Standard vs failure mechanism NG-18 Level 1

General/Local Gouges/Dents metal loss

Out of roundness/ ovality/weld misalignment

Fatigue

Complex defects/ Interaction

Crack-like flaws

Brittle fracture

Freespans Stability Buckling

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A



N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A



N/A

N/A

N/A



N/A

N/A

N/A

N/A

N/A

Shell 92 Level 2



N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Fatigue analyses Level 3

















N/A

N/A

RSTRENG (AGA PRE-805) (Simplified) Level 1 RSTRENG AGA PRE-805 (Detailed/effective area) Level 2

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TABLE 9.2 (continued)

NOTES: 1

This method provides guidance on the Level 3 assessment but does not provide detailed assessment guidelines/equations for this failure mechanism.

2

The guidance provided for crack-like flaw analyses is extensive, especially with regards to methods Level 3 (B) and (D).

3

Level 3 brittle fracture assessments may include API RP 579, or detailed FEA of stress state or more detailed determinations of flaw size and material toughness.

4

API RP 579 provides guidance for fatigue assessments of all the failure mechanisms detailed in the RP.

5

BS 7910 provides specific guidelines if weld misalignment is present. Not used in assessment methods for general ovality/out of roundness.

6

Whilst FEA does not specifically address susceptibility to brittle fracture or instability, FEA can help provide a better understanding of the stress state (Level 3 Brittle fracture) and thermal state of a pipeline.

7

In this document, fatigue as a failure mode is different from fatigue as an analysis method.

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9.5.3 Pre-level assessment For certain anomaly types (e.g. out-of-roundness, ovality, weld anomalies), the Licensee shall ascertain whether detected anomalies are fabrication or installation anomalies that have satisfied workmanship standards, as set out in AS 2885.1 and AS 2885.2. If the detected anomaly is ascertained to be an anomaly that satisfies workmanship standards for the pipeline, no further assessment or remediation is required. 9.5.4 Level 1 assessment Level 1 anomaly FFP assessment shall be carried out by or under the direction of qualified engineers. Level 1 anomaly FFP assessment is characterized by the pipeline and anomaly information requirements being limited and generally involving the following: (a)

Basic pipeline design and operational data including MAOP, wall thickness, outside diameter (OD), material grade and temperature.

(b)

Coarse/gross inspection data normally consisting of axial/longitudinal dimensions and minimum wall thickness data (in the case of metal loss) for the anomaly in question.

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NOTE: These methods are usually based upon empirical validation methods and the methodologies/equations are deterministic in nature.

9.5.5 Level 2 assessment Level 2 anomaly FFP assessment has the following characteristics: (a)

Specialist engineering knowledge is required to ascertain the correct inputs to these assessment methods.

(b)

A greater level of line pipe material mechanical property data (e.g. Charpy V-notch data for crack-like flaw analyses) and inspection data (e.g. a longitudinal profile of the anomaly in question to a specified increment) is required.

(c)

Interaction of anomalies is normally checked in this level of assessment.

9.5.6 Level 3 assessment Level 3 anomaly FFP assessment has the following characteristics: (a)

Specialist engineering knowledge is required to ascertain the correct inputs and methods to be used in the assessment.

(b)

In-depth knowledge of and/or access to materials information (e.g. mill certificates).

(c)

A thorough understanding of environmental, operational and upset conditions (including cyclic operations).

(d)

FEA methods to determine detailed stress states in the vicinity of an anomaly or failure mechanism.

(e)

Elements of probability (e.g. Monte Carlo simulation) or partial safety factors that statistically account for variables such as material strength and inspection tool accuracies.

(f)

Fatigue analyses normally play a role in this level of assessment.

(g)

Interaction of anomalies is normally checked in this level of assessment.

9.6 ASSESSMENT OF ILI RESULTS The Licensee shall identify anomaly indications with reported characteristics and dimensions that might indicate the presence of defects, taking into account allowances for errors in the reported anomaly dimensions. www.standards.org.au

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The Licensee shall assess the severity of reported anomalies and perform excavations and additional verification inspections until there is confidence that any remaining anomalies do not pose a threat to pipeline integrity. NOTE: An anomaly growth assessment should be undertaken and a pipeline reinspection interval determined and the integrity management plan revised. Additional repairs that are required, based on anomaly growth assessment, should be identified to ensure all indications posing a threat to pipeline integrity over the re-inspection interval are addressed.

9.7 INSPECTION TOLERANCES The Licensee shall take into account the allowances for errors in the chosen NDT verification inspection technique. Where assessment of ILI results is undertaken, the Licensee shall consider the inspection tool tolerances. Pipelines with indications of anomalies shall be subject to detailed inspection, if required, to verify the nature and dimensions of the anomalies.

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If verification of anomaly dimensions via NDT inspections is not possible, the Licensee shall undertake the anomaly assessment using the criteria given in Table 9.2 to the worst case anomaly dimensions detected during ILI. 9.8 MAXIMUM OPERATING PRESSURE (MOP) RESTRICTION When an inspection identifies that the pipeline integrity may be affected, the Licensee shall determine if MOP restriction needs to be applied until corrective actions are undertaken. The MOP restriction shall remain until such time that repairs, follow-up inspections, or further anomaly assessment can be completed. The MOP restriction shall be documented, and communicated to all relevant operating personnel. Following remediation of the pipeline anomaly, reinstatement of the pipeline MOP shall be subject to a safety management study, to ensure continuous safe operation. Where an MOP restriction may be required for an extended period (e.g. 12 months or longer), a safety management study shall be undertaken to assess the integrity of the pipeline and its reliable operation, prior to lifting the MOP restriction. Where an anomaly is determined to affect the pipeline’s long-term integrity, the pipeline MAOP shall be reduced. MAOP reduction shall be approved and documented. NOTE: The purpose of a MOP restriction is to provide a margin of safety to the pipeline at the time of the damage identification. Pressure reduction is usually temporary during repairs or until remediation is completed. Typically the pressure is reduced to 80% of the peak pressure at that location within the previous 6 months for gas pipelines and 2 months for liquid pipelines (subject to risk assessment and/or anomaly assessment). Consideration should be given to typical operating conditions, including surge and transient conditions.

9.9 PIPELINE REPAIRS 9.9.1 General Anomalies that are assessed as defects in pipelines shall be repaired. The objective of repair is to ensure that the repaired pipe is fit for service over the remaining pipeline life, having sufficient structural integrity to withstand all the identifiable forces to which it may be subjected during operations, including the MAOP and cyclic pressure fluctuations, with an acceptable safety margin. Repairs are undertaken for— (a)

pressure containment;

(b)

strengthening; or;

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AS 2885.3—2012

a combination of the two.

NOTE: Table C1 of Appendix C provides general guidance on applicable type of repair methods for typical pipeline defects (see API 1160).

Repair procedures shall be formally documented and reviewed. The repair methods, equipment and all repair materials shall be recorded along with NDT records verifying that the repair is effective. As a minimum, the following parameters shall be considered in repair selection: (i)

Pipe material.

(ii)

Pipeline operating characteristics.

(iii) Pipeline configuration and stress state. (iv)

Pipeline location.

(v)

Nature and extent of anomaly.

(vi)

MOP restriction as per Clause 9.8.

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For all types of defects, replacement of a defective section may be considered as an acceptable repair method. NOTE: Additional information on repair methods and their applicable limits can be found in the following publications: (a) PRCI Pipeline Repair Manual. (b) CSA Z662—Oil and Gas Pipeline Systems. (c) UK HSE—Temporary/permanent pipe repair—Guidelines. (d) WTIA Technical Note 20.

9.9.2 Repair strategy 9.9.2.1 Initial response When a leak or loss of containment is detected, corrective action shall be initiated immediately and damage shall be evaluated promptly. Where the situation is uncontrolled, consideration shall be given to immediate pressure reductions, to minimize loss of inventory and to reduce the likelihood of the situation escalating. The emergency response, as specified in Section 11, shall be activated and, in association with emergency services where possible, the site shall be controlled to minimize risks to personnel and property. Where a pipeline is damaged or corroded to the extent that continued operation would be unsafe, the Licensee shall ensure that the pipeline is shut down or the operating pressure is reduced to a safe level (see Clause 9.3) until necessary repairs have been completed, inspected and tested and it is safe to resume safe normal operation. Only when immediate shutdown is not practicable, temporary repairs may be made, provided they will be made permanent as soon as possible. Temporary repairs shall be approved and shall not extend over a period of 12 months, except if continued pipeline integrity can be proven. Pipeline FFP shall be monitored during the period of temporary repair.

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9.9.2.2 Repair strategy considerations The Licensee shall plan a repair strategy as part of their operating/management documentation taking into account (but not limited to) the following: (a)

Considerations when placing out of/returning to service (e.g. isolation or shutdown).

(b)

Type of repair, replacement or remediation.

(c)

Lead time for repair capability.

(d)

Risk assessments for various elements of the repair strategy.

(e)

Stakeholder management.

(f)

Regulatory approvals/management (as required).

(g)

Temporary repairs (if required).

(h)

Contractor/resourcing strategy.

(i)

Inventory (e.g. line pipe and clamps).

All reasonable care and precaution (including appropriate planning and risk assessments) shall be taken when work is carried out on a portion of a pipeline (see Section 4).

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The pipeline operating pressure shall either— (i)

not exceed the pressure at which the anomaly was subjected to at the time of identification; or

(ii)

be reduced to a safe level as determined by engineering assessment.

NOTE: For pressure reduction, see Clauses 9.3 and 9.8.

The ‘derated/reduced pressure’ assessed for particular anomalies should not be exceeded until such time as the anomalous area has been cleaned and inspected, the extent and depth of anomaly has been confirmed via verification activities (e.g. dig-ups) and an assessment has been made using the verified anomaly dimensions. Prior to the commencement of any activity, a repair plan (on a case by case basis) shall be prepared. Where the contents of the pipeline are liquid and locked in between valves, consideration shall be given to any increase in pressure that may be caused by changes in temperature. NOTE: A repair strategy is given in flow chart shown in Figure 9.3.

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S t a tu s

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Pip e li n e a n o m a l y( i e s) d ete c te d o r p ip e li n e i n c i d e nt

Decision

Ac tivit y

Initial response R e du c e l e a k R e du c e s tr e s s vi a p r e s s u r e r e du c ti o n / M O P Repair

I d e ntif y t y p e of a n o m a l y Measure Assess

I n i t i a te p l a n s fo r p e r m a n e nt r e p a i r

Ye s

Is c o ntinu e d o p e r a ti o n p o s s ib l e?

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C o ntinu e d o p e r a ti o n s (r e s tr i c te d?)

No

Is pipeline ready for normal o p e r a ti o n?

Ye s

No

Ye s

S hu t d own pipeline

Is te m p o r a r y repair p o s s ib l e?

No

I n i t i a te p l a n s fo r p e r m a n e nt r e p a i r Ye s Is i n te g r i t y of p ip e li n e ok?

M a ke te m p o r a r y repair

No Is f u r th e r te m p o r a r y repair p o s s i b l e?

Ye s

No

In s t a ll by p a s s

Ye s

M a ke p e r m a n e nt repair

Is by p a s s p o s s ib l e?

No

N o r m a l o p e r a ti o n s

FIGURE 9.3 REPAIR STRATEGY FLOW CHART

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9.9.3 Permanent repairs

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Permanent repairs shall be made to a pipeline, subject to the following conditions: (a)

On a liquids pipeline, the defect has been sealed or suitably vented to prevent leakage during repair.

(b)

The internal pressure is at a low enough level to ensure safety during the repair operation.

(c)

Grinding in the area containing the defect complies with Clauses 9.10.3.

(d)

Safety precautions comply with Section 4 and AS 2885.1.

(e)

Cutting and welding comply with AS 2885.2, and welding procedures that ensure pipe walls are not reduced in thickness or weakened.

(f)

Where a section of pipe or weld reinforcement containing a defect is replaced, the replacement pipe is pretested and its properties verified such that the integrity of the pipe is not less than that of the section to be replaced, and the repaired section does not impede pigging operations (if applicable).

(g)

Pressure-containing repairs have design pressures determined in accordance with AS 2885.1, subject to the MAOP of the pipeline not being reduced.

(h)

The use of mechanical devices other than full-encirclement welded sleeves to repair pipeline defects have the type, installation and pressure rating documented. Operators installing such devices have been trained and competent to conduct such work. NOTE: The use of reinforcement sleeves or mechanical devices for permanent repair of pipeline internal corrosion defects is not recommended as— (a) the passivation of the internal corrosion cannot be guaranteed; and (b) establishing the internal corrosion mechanism is required (typically by hot tapping). A fully welded encirclement sleeve is the recommended method of repair.

(i)

The carbon equivalent of materials that are to be welded into the pipeline conforms to that specified in the certified weld procedure in accordance with AS 2885.2.

9.10 REPAIR METHODS 9.10.1 General Repair methods, procedures, materials or components shall be subject to design qualification. Repair methods shall be documented. Repair methods or techniques shall be fit for purpose for the conditions under which they are used. They shall have the pressure strength, temperature rating and design life specified by the engineering design. Engineering design of a repair shall take into consideration the damage mechanism and environment, service conditions and properties of existing materials. The typical repair methods are set out in Clauses 9.10.2 to 9.10.6. 9.10.2 Replacement The replacement pipe shall be pre-tested and welds subject to inspection in accordance with AS 2885.2 or the replacement section hydro-tested post replacement in accordance with AS 2885.5. Where a section of pipe is identified with multiple defects in close proximity, the replacement of those defective sections of pipe may be desirable. The pipe used for replacement should be the same grade, wall thickness and diameter as the defective section. Where differences from the original are proposed, consideration should be made of future maintenance and operability of the repaired section. © Standards Australia

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Pipe replacement methods include— (a)

pipe section depressurization;

(b)

hot tapping and stoppling; and

(c)

localized isolation using other techniques.

NOTES: 1 A risk assessment of pipeline replacement methods should be undertaken as part of repair procedure development to examine all of the potential threats to public, operating personnel and the continuity of supply. 2 Hot taps allowing coupon assessment may be recommended where the internal corrosion mechanism is required to be established.

Pipeline blow-down, purging and filling shall be in accordance with Section 3. 9.10.3 Grinding

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Grinding repairs shall be carried out to the criteria set out in AS 2885.2 or, if on parent metal, shall ensure continued safe operation of the pipeline. Grinding may be used to repair a defect or damage in a pipeline, including elimination of stress concentrators and microstructurally damaged material, provided the amount of material removed is determined to be acceptable. Where the extent of metal removal is determined to be unacceptable, grinding repairs may be supplemented by repair sleeves complying with Clause 9.10.4. Where grinding is used, inspection of the repair area (including surface preparation of adjacent areas) shall be undertaken. The grinding procedure shall minimize heat input and limit introduction of surface grooving and shall not exceed size limitations as set out in this Standard (see Clause 9.4.2.3). Caution shall be taken when grinding repairs are to be undertaken pre 1970 ERW pipe which may be subject to low toughness seam weld. All areas repaired by grinding shall be rechecked using either magnetic particle testing or dye-penetrant testing in accordance with AS 2885.2. Caution shall be exercised when conducting weld repairs on hydrogen-charged steel to prevent crack growth and/or subsequent re-cracking. A hydrogen bake-out shall be considered prior to welding or grinding. The application of a suitable coating after blend grinding or weld repairs shall be considered. 9.10.4 Weld deposition repair Approved repair may be carried out by weld metal deposition to rebuild pipe wall metal loss due to the corrosion or defect removal by grinding. Weld repair is limited by the remaining minimum wall thickness to prevent burn-through. Weld deposition as a repair method requires specialist welding knowledge and repair procedure development. Consideration of HAZ hardness and susceptibility to hydrogen cracking is required. 9.10.5 Repair sleeves Full encirclement repair sleeves are used to repair a wide range of pipeline defects, including supplementing reinforcement of defect removed by grinding and pressure containment of leaks. Consideration shall be given to the response of repair sleeves to repeated pressure cycling to ensure fitness for service over the expected repair life. Defects should be removed by grinding in accordance with Clause 9.10.3 and verified prior to sleeve application.

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There are four generic types of repair sleeve: (a)

Steel-reinforcing sleeve—consists of two half circular shells placed over the carrier pipe and joined by welding the longitudinal seam. The sleeve is installed on the pipeline without welding to the carrier pipe; the sleeve provides reinforcement to the defect but is not pressure containing. These sleeves are generally installed at a reduced operating pressure.

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NOTE: It is recommended that a hardenable filler material be used to ensure a tight fit between sleeve and carrier pipe to restrain bulging in the vicinity of a defect.

(b)

Composite reinforcing sleeve—typically consists of composites of fibreglass or carbon fibre. The sleeve is applied to non-leaking defects