Download - As 2885 1 Pipeline

COMMITTEE ME-038

DR 04561

(Project ID: 2425)

Draft for Public Comment Australian Standard LIABLE TO ALTERATION—DO NOT USE AS A STANDARD

BEGINNING DATE FOR COMMENT:

17 December 2004

CLOSING DATE FOR COMMENT:

18 February 2005

Pipelines—Gas and liquid petroleum Part 1: Design and construction

COPYRIGHT

Draft for Public Comment Australian Standard

The committee responsible for the issue of this draft comprised representatives of organizations interested in the subject matter of the proposed Standard. These organizations are listed on the inside back cover.

Comments are invited on the technical content, wording and general arrangement of the draft.

The preferred method for submission of comment is to download the MS Word comment form found at http://www.standards.com.au/Catalogue/misc/Public%20Comment%20Form.doc. This form also includes instructions and examples of comment submission.

When completing the comment form ensure that the number of this draft, your name and organization (if applicable) is recorded. Please place relevant clause numbers beside each comment.

Editorial matters (i.e. spelling, punctuation, grammar etc.) will be corrected before final publication.

The coordination of the requirements of this draft with those of any related Standards is of particular importance and you are invited to point out any areas where this may be necessary.

Please provide supporting reasons and suggested wording for each comment. Where you consider that specific content is too simplistic, too complex or too detailed please provide an alternative.

If the draft is acceptable without change, an acknowledgment to this effect would be appreciated.

When completed, this form should be returned to the Projects Manager, Kris Longmore via email to [email protected].

Normally no acknowledgment of comment is sent. All comments received electronically by the due date will be put before the relevant drafting committee. Because Standards committees operate electronically we cannot guarantee that comments submitted in hard copy will be considered along with those submitted electronically. Where appropriate, changes will be incorporated before the Standard is formally approved.

If you know of other persons or organizations that may wish to comment on this draft Standard, could you please advise them of its availability. Further copies of the draft are available from the Customer Service Centre listed below and from our website at http://www.standards.com.au/.

STANDARDS AUSTRALIA Customer Service Centre Telephone: 1300 65 46 46

Facsimile: 1300 65 49 49

e-mail: mailto:[email protected]

Internet: http://www.standards.com.au/

mailto:[email protected]

http://www.standards.com.au/

Draft for Public Comment

STANDARDS AUSTRALIA

Committee ME-038—Petroleum Pipelines

Subcommittee ME-038-01 — Design and Construction

DRAFT

Australian Standard

Pipelines—Gas and liquid petroleum

Part 1: Design and construction

(To be AS 2885.1)

This Standard specifies requirements for the design and construction of carbon and carbon manganese steel pipelines and associated piping and components that are used to transmit single and multiphase hydrocarbon fluids. Major changes proposed in this draft relate to a structural basis for increasing the maximum allowable operating pressure of a qualifying existing pipeline. These benefits are supported by robust requirements for safety, structural design, construction, testing and record keeping.

Comment on the draft is invited from people and organizations concerned with this subject. It would be appreciated if those submitting comment would follow the guidelines given on the inside front cover.

This document is a draft Australian Standard only and is liable to alteration in the light of comment received. It is not to be regarded as an Australian Standard until finally issued as such by Standards Australia.

DRAFT ONLY 2 DRAFT ONLY

DR04561.doc

PREFACE This Standard was prepared by the Joint Standards Australia/Standards New Zealand Committee ME-038 on Petroleum Pipelines, to supersede AS 28851997, Pipeline—Gas and liquid petroleum. AS 1697, Gas transmission and distribution systems is currently undergoing revision and will be published as a distribution pipeline standard, and has been deleted as a reference standard.

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 requirements for the design and construction of steel pipelines and associated piping and components that are used to transmit single phase and multiphase hydrocarbon fluids.

This standard provides guidelines for use of pipe manufactured from certain non steel or corrosion resistant materials.

This Standard is one of the following series, which refers to high pressure petroleum pipelines:

AS 2885 PipelinesGas and liquid petroleum 2885.0 Part 0: General Requirements 2885.1 Part 1: Design and construction (this Standard) 2885.2 Part 2: Welding 2885.3 Part 3: Operation and Maintenance 2885.4 Part 4: Submarine pipelines 2885.5 Part 5 Field Pressure Testing

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

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

This comprehensive revision is the result of extensive work by subcommittee ME-038-1 in response to a request from the industry that it consider increasing the design factor from 0.72 to 0.80. This request prompted a detailed review of each section and each clause of the Standard, resulting in the preparation of some 70 Issue Papers that considered the underlying technical issues (in relation to an increased design factor) and recommended changes to the Standard. These issue papers were debated within the subcommittee and published on the Industry web site to allow consideration by the Industry. The results of these deliberations form the basis of this revision. The revision also reflects the results of a significant and ongoing industry funded research program undertaken by the Australian Pipeline Industry Association and its research contractors, and through its association with the Pipeline Research Council International and the European Pipeline Research Group.

This revision provides a basis for Industry to benefit through the application of an increased factor for pressure design (for new pipelines) and a structured basis for increasing the MAOP of a qualifying existing pipeline. These benefits are supported by robust requirements for safety, structural design, construction, testing and record keeping.

Significant changes in this Revision include:

1) A restructure of the sections of the document to separate Pipeline General, Pipeline, Stations, and Instrumentation and Control.


DR04561.doc

2) The separation of information common to Parts 1, 2 3 and 5 of the Standard to a new part (Part 0), including the requirements for a holistic approach to pipeline and environmental safety, and including definitions that apply to the Standard.

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

4) Section 2 (Safety) is re-written, reflecting experience gained in the seven years since it was revised to provide a mandatory requirement for risk assessment. This revision (2005) provides more explicit guidance on obligation to undertake safety assessments with the integrity required for compliance with this Standard.

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

6) Section 4 (Pipeline General) contains most of the material in the Pipeline General section of the 1997 revision. The Section has been expanded to include:

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

ii. A revision of the requirements for effective pipeline marking including a change to require the marker sign to comply with a Danger sign in accordance with AS 1319.

iii. A Plan for Isolation of a Pipeline.

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

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

vi. The hydrostatic strength test pressure is re-defined to address the situation where the pipe wall thickness exceeds the pressure design thickness, including corrosion allowance).

vii. Provisions for low temperature excursions.

viii. Calculation methods for critical defect length, energy release rate and radiation contour

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

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

i. The pipe wall thickness is now required to be the greater of the pressure design thickness, and the thickness required for each other identified load condition.

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


DR04561.doc

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

iv. A mandatory calculation method for determining resistance to penetration by excavator is provided.

v. Requirements for Stress and Strain are completely re-written to clarify the requirements. The limits for each stress condition are tabulated and normative and informative appendices are provided incorporating the relevant equations.

vi. The requirements for a prequalified design are included in a new clause. This is permitted to be used for short pipelines DN200 and smaller with a MAOP of 10.2 MPa or less.

vii. The provisions for reduced cover for a pipeline constructed through rock are revised.

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

10) Section 7 (Instrumentation and Control) incorporates these requirements that were included in Section 4.2 of the 1997 revision. The requirements for pipeline operation under transient conditions and a tolerance specification for pressure controls on pipelines intended to be operated at MAOP are addressed.

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

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

13) Section 10 (Construction). This section incorporates Section 6 of the 1997 standard. The requirements for construction survey are clarified, and a minimum accuracy for as-constructed survey are incorporated. Since padding and backfilling are two activities that impact on the pipeline integrity, the 2005 revision incorporates additional requirements for these activities reflecting outcomes from APIA research on backfilling.

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

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

16) Appendices Each appendix in the 1997 revision of the standard has been critically reviewed and revised as appropriate. New appendices are provided


DR04561.doc

reflecting the findings of APIA research, clarification of concepts in the Standard, and providing detailed calculation methods.

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


DR04561.doc

CONTENTS

Page

SECTION 1 SCOPE AND GENERAL 1.1 SCOPE......................................................................................................................... 9 1.2 REFERENCE DOCUMENTS ..................................................................................... 9 1.3 DEFINITIONS............................................................................................................. 9 1.4 SYMBOLS AND UNITS........................................................................................... 15 1.5 ABBREVIATIONS ................................................................................................... 16

SECTION 2 SAFETY 2.1 BASIS OF SECTION ................................................................................................ 18 2.2 ADMINISTRATIVE REQUIREMENTS................................................................... 19 2.3 OVERVIEW OF PROCESS ...................................................................................... 21 2.4 PIPELINE RISK MANAGEMENT ........................................................................... 24 2.5 STATIONS, PIPELINES FACILITIES AND PIPELINE CONTROL SYSTEMS .... 31 2.6 ENVIRONMENTAL RISK MANAGEMENT .......................................................... 31 2.7 ELECTRICAL ........................................................................................................... 34 2.8 CONSTRUCTION & COMMISSIONING ................................................................ 34

SECTION 3 MATERIALS AND COMPONENTS 3.1 BASIS OF SECTION ................................................................................................ 36 3.2 QUALIFICATION OF MATERIALS AND COMPONENTS................................... 36 3.3 REQUIREMENTS FOR COMPONENTS TO BE WELDED.................................... 39 3.4 ADDITIONAL MECHANICAL PROPERTY REQUIREMENTS ............................ 39 3.5 REQUIREMENTS FOR TEMPERATURE AFFECTED ITEMS.............................. 40 3.6 MATERIALS TRACEABILITY AND RECORDS ................................................... 40 3.7 RECORDS................................................................................................................. 41

SECTION 4 PIPELINE GENERAL 4.1 BASIS OF SECTION ................................................................................................ 42 4.2 ROUTE...................................................................................................................... 45 4.3 PIPELINE MARKING .............................................................................................. 46 4.4 CLASSIFICATION OF LOCATIONS ...................................................................... 48 4.5 SYSTEM DESIGN .................................................................................................... 51 4.6 ISOLATION .............................................................................................................. 53 4.7 SPECIAL PROVISIONS FOR HIGH CONSEQUENCE AREAS............................. 55 4.8 FRACTURE CONTROL ........................................................................................... 57 4.9 LOW TEMPERATURE EXCURSIONS ................................................................... 63 4.10 ENERGY DISCHARGE RATE............................................................................... 64 4.11 RESISTANCE TO PENETRATION ......................................................................... 64

SECTION 5 PIPELINE DESIGN 5.1 BASIS OF SECTION ................................................................................................ 67 5.2 DESIGN PRESSURE ................................................................................................ 67 5.3 DESIGN TEMPERATURES ..................................................................................... 68 5.4 WALL THICKNESS ................................................................................................. 68 5.5 EXTERNAL INTERFERENCE PROTECTION........................................................ 70 5.6 PRE-QUALIFIED PIPELINE SAFETY DESIGN .................................................... 77 5.7 STRESS AND STRAIN............................................................................................. 79 5.8 SPECIAL CONSTRUCTION ................................................................................... 85 5.9 PIPELINES ASSEMBLIES ..................................................................................... 118


DR04561.doc

5.10 JOINTING ............................................................................................................... 120 5.11 SUPPORTS AND ANCHORS................................................................................. 121

SECTION 6 STATION DESIGN 6.1 BASIS OF SECTION .............................................................................................. 124 6.2 DESIGN .................................................................................................................. 124

SECTION 7 INSTRUMENTATION AND CONTROL DESIGN 7.1 BASIS OF SECTION ............................................................................................. 133 7.2 CONTROL AND MANAGEMENT OF PIPELINE SYSTEM ................................ 133 7.3 FLUID QUALITY ASSURANCE ........................................................................... 135 7.4 SCADA.................................................................................................................... 135 7.5 COMMUNICATION............................................................................................... 136 7.6 CONTROL FACILITIES......................................................................................... 136 7.7 CRITICAL EQUIPMENT AND REDUNDANCY/BACKUP ................................. 136

SECTION 8 MITIGATION OF CORROSION 8.1 BASIS OF SECTION .............................................................................................. 137 8.2 PERSONNEL .......................................................................................................... 137 8.3 RATE OF DEGRADATION ................................................................................... 137 8.4 CORROSION MITIGATION .................................................................................. 138 8.5 CORROSION MONITORING ................................................................................ 139 8.6 INTERNAL CORROSION MITIGATION METHODS .......................................... 139 8.7 EXTERNAL CORROSION MITIGATION METHODS......................................... 140 8.8 EXTERNAL ANTI-CORROSION COATING........................................................ 143 8.9 INTERNAL LINING ............................................................................................... 144

SECTION 9 UPGRADE OF MAOP 9.1 BASIS OF SECTION .............................................................................................. 146 9.2 MAOP UPGRADE PROCESS ................................................................................ 146

SECTION 10 CONSTRUCTION 10.1 BASIS OF SECTION .............................................................................................. 150 10.2 SURVEY ................................................................................................................. 150 10.3 HANDLING OF COMPONENTS ........................................................................... 150 10.4 INSPECTION OF PIPE AND COMPONENTS....................................................... 151 10.5 CHANGES IN DIRECTION ................................................................................... 152 10.6 COLD-FIELD BENDS ............................................................................................ 153 10.7 FLANGED JOINTS................................................................................................. 154 10.8 COVERING SLABS, BOX CULVERTS, CASINGS AND TUNNELS.................. 154 10.9 SYSTEM CONTROLS............................................................................................ 154 10.10 ATTACHMENT OF ELECTRICAL CONDUCTORS ............................................ 155 10.11 LOCATION............................................................................................................. 156 10.12 CLEARING AND GRADING................................................................................. 156 10.13 TRENCH CONSTRUCTION .................................................................................. 156 10.14 INSTALLATION OF A PIPE IN A TRENCH ........................................................ 157 10.15 PLOUGHING-IN AND DIRECTIONALLY DRILLED PIPELINES...................... 158 10.16 SUBMERGED CROSSINGS .................................................................................. 159 10.17 REINSTATEMENT................................................................................................. 159 10.18 CLEANING AND GAUGING PIPELINES ............................................................ 159

SECTION 11 INSPECTIONS AND TESTING 11.1 GENERAL............................................................................................................... 160 11.2 INSPECTION AND TEST PLAN AND PROCEDURES........................................ 160 11.3 PERSONNEL .......................................................................................................... 160


DR04561.doc

11.4 PRESSURE TESTING ............................................................................................ 160 11.5 COMMENCEMENT OF PATROLLING ................................................................ 163

SECTION 12 DOCUMENTATION 12.1 RECORDS .............................................................................................................. 164 12.2 RETENTION OF RECORDS ................................................................................. 165

APPENDICES A REFERENCED DOCUMENTS............................................................................... 166 B DESIGN CONSIDERATIONS FOR EXTERNAL INTERFERENCE

PROTECTION......................................................................................................... 171 C INTEGRITY ASSESSMENT OF PIPELINE RISK ASSESSMENTS

CONDUCTED IN ACCORDANCE WITH AS 2885 .............................................. 174 D EFFECTIVENESS OF PROCEDURAL MEASURES FOR THE PREVENTION

OF EXTERNAL INTERFERENCE DAMAGE TO PIPELINES............................. 184 E PREFERRED METHOD FOR TENSILE TESTING OF WELDED LINE PIPE

DURING MANUFACTURE ................................................................................... 191 F FRACTURE TOUGHNESS TEST METHODS ...................................................... 192 G FRACTURE CONTROL PLAN FOR STEEL PIPELINES ..................................... 194 H STATION PIPING STANDARDS AND DESIGN FACTORS .............................. 198 I ....................................................................................................................................... J FATIGUE ................................................................................................................ 200 K MAOP UPGRADE .................................................................................................. 203 L SUITABILITY OF ASSOCIATED STATION EQUIPMENT................................. 204 M FACTORS AFFECTING CORROSION.................................................................. 205 N ENVIRONMENT RELATED CRACKING ............................................................ 208 O INFORMATION FOR CATHODIC PROTECTION............................................... 215 P MITIGATION OF A.C. EFFECTS FROM HIGH VOLTAGE ELECTRICAL

POWERLINES ....................................................................................................... 217 Q CHANGE IN INTEGRITY (DUE TO DEFECTS IN SERVICE) KNOWN

CORROSION DEFECTS PAPER 5.13 ........................................................ 225 R PROCEDURE QUALIFICATION FOR COLD FIELD BENDS............................. 226 S GUIDELINES FOR THE TENSIONING OF BOLTS IN THE FLANGED

JOINTS OF PIPING SYSTEMS.............................................................................. 231 T STRATEGIC SPARES PAPER 5.21 ....................................................................... 245 U RECORD KEEPING PAPER 5.2 ............................................................................ 246 V STRESS TYPES & DEFINITIONS......................................................................... 247 W EXTERNAL LOADS .............................................................................................. 254 X COMBINED EQUIVALENT STRESS.................................................................... 258 Y PIPE STRESS ANALYSIS...................................................................................... 269


DR04561.doc

STANDARDS AUSTRALIA

Australian Standard Pipelines—Gas and liquid petroleum

Part 1: Design and construction

S E C T I O N 1 S C O P E A N D G E N E R A L

1.1 SCOPE

This Standard specifies requirements for the design and construction of carbon and carbon-manganese steel pipelines falling within the scope of AS2885 Part 0 and associated piping and components that are used to transmit single phase and multiphase hydrocarbon fluids, such as natural and manufactured gas, liquefied petroleum gas, natural gasoline, crude oil, natural gas liquids and liquid petroleum products. AS 2885 Part 0 defines the principles for design, construction, operation and abandonment of petroleum pipelines that form the basis for Design and construction, Welding, Operation and maintenance and Field hydrostatic testing in accordance with AS2885 Parts 1, 2, 3, and 5.

The principles are expressed in practical rules and guidelines for use by competent persons.

The fundamental principles and the practical rules and guidelines set out in AS2885 Parts 1, 2, 3, and 5 are the basis on which an engineering assessment is to be made where these Standards do not provide detailed requirements appropriate to a specific item.

NOTE: AS 2885.4 for offshore pipelines is a standalone document.

Where approved, this Standard may also be used for design and construction of pipelines made with corrosion resistant alloy steels or fibreglass. Where this Standard is used for pipelines fabricated from these materials appropriate requirements shall be established to replace the provisions of this standard in relation to nominated standards for Materials (Section 3), Fracture Control (Section 4.8), Stress and Strain (Section 5.7) and Corrosion (Section 8) and the provisions of AS 2885.2 in relation to Welding and Non Destructive Examination. For fibreglass appropriate requirements shall be established to replace the hydrostatic strength test endpoint provisions of AS2885.5.

This standard is complementary to AS2885.0 but the requirements of this standard take precedence over any corresponding requirements in AS2885.0.

1.2 REFERENCE DOCUMENTS

The documents referred to in this Standard are listed in Appendix A.

1.3 DEFINITIONS

For the purpose of this standard the definitions in AS2885.0 shall apply.

Where this standard imposes requirements, which add to or override the requirements of a permitted Standard or Code, the additional requirements are explicitly stated in this standard and shall be met.

For the purpose of the Standard, the definitions given in AS 1929, AS 2812, AS 2832.1 and those below, apply.


DR04561.doc

1.3.1 Accessory

A component of a pipeline other than a pipe, valve or fitting, but including a relief device, pressure-containing item, hanger, support and every other item necessary to make the pipeline operable, whether or not such items are specified by the Standard.

1.3.2 Approved and approval

Approved by the Licensee, and includes obtaining the approval of the relevant regulatory authority where this is legally required.

Approval requires a conscious act and is given in writing.

1.3.3 As Low as Reasonably Practicable

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 the demonstration of ALARP and grossly disproportionate is given Appendix ALARP

1.3.4 Buckle

An unacceptable irregularity in the surface of a pipe caused by a compressive stress.

1.3.5 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.

1.3.6 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).

1.3.7 Competent person

A person who has acquired through training, qualification, or experience, or a combination of these, the knowledge and skills enabling the person to perform the task required.

1.3.8 Common threats

Threats which occur at similar locations along the pipeline and which can therefore be treated by a standard design solution for that location type (e.g. road crossings).

1.3.9 Component

Any part of a pipeline other than the pipe.

1.3.10 Construction

Activities required to fabricate, construct and test a pipeline, and to restore the right of way of a pipeline.

1.3.11 Control piping

Ancillary piping used to interconnect control or instrument devices or testing or proving equipment.

1.3.12 Controlled threat

A threat is considered to be controlled when the application of multiple independent protective measures (physical and procedural for external interference and design and/or procedures for other threats) in accordance with this Standard means that for all practical purposes failure as a result of that threat has been removed at that location.


DR04561.doc

1.3.13 Critical Defect Length

The length of a through wall axial flaw that if exceeded, will grow by plastic failure and result in pipeline rupture. When the defect is smaller than this length, the pipeline will leak.

A critical defect length also exists for part through wall flaws.

1.3.14 Defect

A discontinuity or imperfection of sufficient magnitude to warrant rejection on the basis of the requirements of this Standard.

1.3.15 Dent

A depression in the external 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).

1.3.16 Diameter

The outside diameter nominated in the material order.

1.3.17 Failure Analysis

Threats which have not been reduced to accepted risk by external interference protection design or other design measures are then assessed to determine whether or not they will cause failure of the pipeline at the location of the threat. This combination of the characteristics of the threat and the characteristics of the pipeline is called failure analysis. Failure analysis determines the outcome from the identified threat.

1.3.18 Failure

For the purpose of safety assessment, failure within the Pipeline System has occurred if one or more of the of the following conditions apply:

(a) Any loss of containment

(b) Supply is restricted

(c) MAOP is reduced

(d) Immediate repair is required NOTE: It is emphasised that failure is not restricted to loss of containment.

1.3.19 Failure Event

An event that has not been reduced to an accepted risk by external interference protection or design processes, and which involves failure. Failure events are subject to risk evaluation and risk management. Threats that are not reduced to accepted risk become failure events, where their effect on a pipeline results in failure.

1.3.20 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.

1.3.21 Fluid

Any liquid, vapour, gas or mixture of any of these.

1.3.22 Gas

Any hydrocarbon gas or mixture of gases, possibly in combination with liquid petroleum condensates or water.


DR04561.doc

1.3.23 Heat

Material produced from a single batch of steel processed in the final steel making furnace at the steel plant.

1.3.24 High Consequence Areas

Locations where pipeline failure can be expected to result in multiple fatalities or major environmental damage.

1.3.25 High Consequence Events

Failure events in high consequence areas.

1.3.26 High vapour pressure liquid (HVPL)

A liquid or dense phase fluid which releases significant quantities of vapour when its pressure is reduced from pipeline pressure to atmospheric, e.g. LP gas.

1.3.27 Hoop stress

Circumferential stress in a cylindrical pressure containing component arising from internal pressure.

1.3.28 Hot tap

A connection made to an operating pipeline containing hydrocarbon fluid.

1.3.29 Imperfection

A material discontinuity or irregularity that is detectable by inspection in accordance with this Standard.

1.3.30 Inert gas

A non-reactive and non-toxic gas such as argon, helium and nitrogen.

1.3.31 Inspector

A person appointed by the licensee to carry out inspections required by this Standard.

1.3.32 Leak test

A pressure test that determines whether a pipeline is free from leaks.

1.3.33 Location class

An area classified according to its general geographic and demographic characteristics.

1.3.34 Mainline pipework

Those parts of a pipeline between stations, including fabricated assemblies (see AS 2885.1)

1.3.35 Maximum allowable operating pressure (MAOP)

The maximum pressure at which a pipeline or section of a pipeline may be operated.

1.3.36 May

Indicates the existence of an option.

1.3.37 Mechanical interference-fit joint

A joint for pipe, involving a controlled plastic deformation and subsequent or concurrent mating or pipe ends.

1.3.38 Non-credible threat

A threat for which the frequency of occurrence is so low that it does not exist for any practical purpose at that location.


DR04561.doc

1.3.39 Non-location specific threat

Threats which can occur anywhere along the pipeline (e.g. corrosion).

1.3.40 Pipeline Licensee

The organization responsible for the design, construction, testing, inspection, operation and maintenance of pipelines and facilities within the scope of this Standard.

1.3.41 Petroleum

Any naturally occurring hydrocarbon or mixture of hydrocarbons in a gaseous or liquid state and which may contain hydrogen sulfide, nitrogen, helium and carbon dioxide.

1.3.42 Pig

A device that is propelled inside a pipeline by applied pressure.

1.3.43 Pig trap (scraper trap)

A fabricated component to enable a pig to be inserted into or removed from an operating pipeline.

1.3.44 Piping

An assembly of pipes, valves and fittings connecting auxiliary and ancillary components associated with a pipeline.

1.3.45 Pre-tested

The condition of a pipe or a pressure-containing component that has been subjected to a pressure test in accordance with this Standard before being installed in a pipeline.

1.3.46 Pressure strength

The maximum pressure measured at the point of highest elevation in a test section. NOTE: Pressure strength for a pipeline or a section of a pipeline is the minimum of the strength test pressures of the test sections comprising the pipeline or the section of the pipeline.

1.3.47 Proprietary item

An item made or marketed by a company having the legal right to manufacture and sell it.

1.3.48 Protection measures–Procedural

Measures for protection on a pipeline which minimize the occurrence of activities by third parties, which could cause failure.

1.3.49 Protection measures–Physical

Measures for protection of a pipeline which prevent external interference from causing failure.

1.3.50 Regulatory authority

An authority with legislative powers relating to petroleum pipelines.

1.3.51 Riser

The connection between a submarine pipeline and a fixed structure, such as processing a platform, jetty or pier.

1.3.52 Risk

The combination of the frequency, or probability, of occurrence and the consequence of a specified failure event (Note: The concept of risk always has two elements: the frequency or probability of which a failure event occurs and the consequences of the failure event).


DR04561.doc

1.3.53 Rupture

Rupture occurs when a defect size exceeds a critical value, dependent on the applied stress followed by rapid growth until the pipe cylinder has opened to a size equivalent to the diameter of the pipeline. Rupture may initiate propagation of the defect by brittle or tearing fracture until it is arrested.

1.3.54 Shall

Indicates that a statement is mandatory.

1.3.55 Should

Indicates a recommendation.

1.3.56 Sour service

Piping conveying crude oil or natural gas containing hydrogen sulfide together with an aqueous liquid phase in a concentration that may affect materials.

1.3.57 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.

1.3.58 Station pipework

Those parts of a pipeline within a station (e.g. pump station, compressor station, metering station) that begin and end where the pipe material specification changes to that for the mainline pipework.

1.3.59 Strength test

A pressure test that confirms that the pipeline has sufficient strength to allow it to be operated at maximum allowable operating pressure.

1.3.60 Telescoped pipeline

A pipeline that is made up of more than one diameter of MAOP, tested as a single unit.

1.3.61 Threat

A threat is any activity or condition that can adversely affect the pipeline if not adequately controlled.

NOTE: Additional information on what constitutes a threat is provided in Appendix ZZZ / HB105

1.3.62 Wall thickness, nominal

The thickness of the wall of a pipe that is nominated for its manufacture, ignoring the manufacturing tolerance provided in the nominated Standard to which the pipe is manufactured. Quantity symbol δN.

1.3.63 Nominated Standard

1.3.64 Loss of integrity

Loss of integrity has occurred if one or more of the following conditions apply:

(a) MAOP is reduced.

(b) Supply is restricted.

(c) Immediate repair is required.

It will generally occur as a result of significant metal damage to the pipeline.


DR04561.doc

1.3.65 Loss of integrity event

An event that has not been reduced to an accepted risk by external interference protection or design processes, and which involves loss of integrity. Loss of integrity events are subject to risk evaluation and risk management. Threats that are not reduced to accepted risk become loss of integrity events, where their effect on a pipeline results in loss of integrity.

1.3.66 Threat

An activity or condition with the potential to damage the pipeline, cause interruption to service or cause release of fluid from the pipeline.

1.3.67 Risk

Combination of the frequency, or probability, of occurrence and the consequence of a specified loss of integrity event.

NOTE: The concept of risk always has two elements: the frequency or probability of which a loss of integrity event occurs and the consequences of the loss of integrity event.

1.3.68 Pipeline risk assessment

The process comprising Risk Identification, Risk Evaluation and Risk Management set out in Section 2 of this Standard, used to ensure that risks imposed by a pipeline are reduced to ALARP / accepted levels.

1.4 SYMBOLS AND UNITS NOTE: Unless otherwise noted, pressure and calculations involving pressure are based on gauge pressures

Symbol Description Unit

HS∆ Stress for longitudinal welds (consistent with API 1102) MPa

LS∆ Stress for girth welds (consistent with API 1102) MPa

σ Stress MPa

Eσ Expansion stress range MPa

flowσ Flow stress (=SMYS + 68.95 MPa) MPa

Hσ Hoop stress MPa

Lσ Longitudinal stress MPa

Oσ Occasional stress MPa

SUSσ Sustained stress MPa

Uσ Ultimate tensile strength MPa

Yσ Yield strength MPa µ Poissons ratio (stress and strain) AC Fracture area of the Charpy V Notch specimen mm2 CDL Critical defect length mm CV Upper shelf CharpyVe Notch energy J Ca10 Full size specimen (10 x 10 mm) Charpy energy arrest value J c Half of the length of an axial through wall flaw mm D Nominal outside diameter = Pipe diameter = Pipeline diameter mm Dm Average diameter mm


DR04561.doc

Dmax Greatest diameter Mm Dmin Smallest diameter mm d Branch diameter mm dW Depth of part through wall flaw mm E Youngs modulus MPa FD Design factor for Pressure Containment FBucket Force exerted at a bucket, correlated against excavator mass kN FMAX Maximum force exerted at bucket (most severe geometry) kN FTP Test Pressure factor FTPE Equivalent test pressure factor fo Ovality factor G Sum of allowances mm L Length of tooth at tip mm Kc In plane stress intensification factor (fracture initiation toughness) MPa/mm0.5

MT Folias factor PC Collapse pressure MPa PD Design pressure MPa PEXT External pressure MPa PL Pressure limit MPa PM Measured pressure from hydrostatic test MPa PMIN Minimum strength test pressure MPa Rp Puncture resistance N RLi Number of runs of np pipe, each run having a length i SDEV Standard deviation of toughness in all heat population Seff Effective stress (consistent with API 1102) MPa SF Statistical Factor used to calculate minimum toughness for any heat SFG Stress limit for girth weld fatigue (consistent with API 1102) MPa SFL Stress limit for longitudinal weld fatigue (consistent with API 1102) MPa t Wall thickness mm tDP Wall thickness for internal pressure design mm tN Nominal wall thickness mm tW Required wall thickness mm W Width of tooth at tip mm WOP Operating weight tonne

1.5 ABBREVIATIONS

Abbreviations Meaning Unit

ALARP As low as reasonably practicable

AS Australian standard

CDL Critical defect length

CHAZOP Control hazard and operability

CRA Corrosion resistant alloy


DR04561.doc

CW Continuously welded

DN Nominal diameter

DWTT Drop weight tear test

EIP External interference protection

EIS Environmental impact statement

EPRG European Pipeline Research Group

ERW Electric resistance welded

FRP Fibre reinforced plastic

GIS Geographic information system

HAZ Heat affected zone

HAZAN Hazard analysis study

HAZOP Hazard and operability study

HAZID Hazard identification study

HVPL High vapour pressure liquid

JSA Job safety analysis

LPG Liquefied petroleum gas

MAOP Maximum allowable operating pressure MPa

MLV Main line valve

MOP Maximum operating pressure MPa

O&M Operation and maintenance

P&ID Piping and instrumentation diagram

PDR Public draft

PRCI Pipeline research council international

QC Quality control

SAOP Safety and operating plan

SAW Submerged arc welded

SCADA Supervisory control and data acquisition

SCC Stress corrosion cracking

SIL Safety integrity level

SLV Station limit valve

SMYS Specified minimum yield stress MPa

XS Extra strong


DR04561.doc

S E C T I O N 2 S A F E T Y

2.1 BASIS OF SECTION

2.1.1 General

This Section provides guidance on techniques which, when implemented rigorously, are sufficient for the review of all activities associated with the pipeline life-cycle to ensure that risks associated with the pipeline are As Low As Reasonably Practical (ALARP).

Risks to public safety, supply and the environment arise from threats to the pipeline which have the potential to result in pipeline failure.

Risks to public safety, supply and the environment also arise from as a result of construction, operations and maintenance activities.

Pipeline risk management is an ongoing process over the life of the pipeline.

The pipeline risk management process is designed to ensure that each threat to a pipeline and each risk from immediate or delayed pipeline failure is systematically identified and evaluated, and action to mitigate threats and risks from failure is implemented.

The pipeline risk management process is a structured, qualitative process which requires the application of multiple independent measures to protect the pipeline from each identified threat:

(a) Route selection shall be the primary control for avoiding or minimising threats to the pipeline and consequences to the public and environment.

(b) Physical and procedural and/or design methods are applied to all threats with the objective of controlling them.

(c) Those threats not controlled by the above are subject to risk evaluation and risk treatment.

Application of Physical and Procedural protection measures to control external interference threats to the pipeline is mandatory, because these threats are known to be the most frequent events that have the potential to create a risk. Furthermore, mandatory requirements are specified in high consequence areas for:

(a) Control of rupture, and

(b) Maximum energy release rate.

Where land use changes from a low consequence area to a high consequence area this Standard applies mandatory requirements for maintaining the risk at ALARP.

The safety of stations, pipeline facilities and pipeline control systems are determined by the application of one or more of a number of recognised safety study methodologies. HAZOP studies of the process design for pipeline facilities is mandatory.

The basis for the control of all threats and acceptance of all risks shall be documented and approved.

The principles established for risk management for pipeline failure are used to provide guidance on environmental risk management. It is intended that this process be applied when assessing alternative methodologies to mitigate environmental risk through pipeline planning, design, construction and operating phases of its life, irrespective of the existence of other environmental assessment methodologies.

Guidance on electrical and construction safety is provided.


DR04561.doc

The Licensee shall ensure that the pipeline risk management process is carried out by suitably qualified, trained and experienced personnel, and shall demonstrate that the integrity of the assessment process is in accordance with the requirements of Appendix C.

Where necessary, other processes, including numerical methods, may be used to assist to determine that an ALARP condition is achieved and to compare and rank the effectiveness of the threat mitigation measures. However, these processes shall complement but not replace the methodology set out in this Standard.

Threats controlled in accordance with the provisions of this Standard are considered an accepted risk subject to the continuous application of effective operations and maintenance procedures to monitor and correct any deviations from the design conditions.

2.2 ADMINISTRATIVE REQUIREMENTS

2.2.1 Approval

The risk management study and its components shall be approved.

2.2.2 Documentation

2.2.2.1 General

All aspects of the risk management process shall be documented with sufficient detail for independent or future users of the risk management study to make an informed assessment of the integrity of the process and its outcomes, including the reasoning behind the assessment of the effectiveness of the mitigation measures applied.

NOTE: The risk management study results in a risk management documentation which includes risk management actions which form the basis of the risk management plan.

For new pipelines, or modifications to existing pipelines, the detailed design and the risk management study are undertaken as integrated iterative processes. The output of this process is a design (generally shown on alignment sheets), and a risk management study document (generally recorded on a database).

2.2.2.2 Safety and Operating Plan

Where threat mitigation and management requires actions by the pipeline Licensee (e.g. procedural protective measures) the obligations of the Licensee shall be documented in the Safety and Operating Plan (SAOP). The SAOP shall identify that these actions arose from the risk management study and are an integral part of pipeline risk management.

NOTES: 1 Because of the SAOP is prepared after the design phase risk management study, the risk

management documentation should clearly summarise the obligations of the pipeline operator that arise in order to facilitate transfer of these requirements to the SAOP.

2 The detailed requirements for the incorporation of the risk management study are provided in Part 3.

2.2.3 Implementation

All actions arising from the risk management study shall be implemented and the implementation documented.

Risk management documentation shall be transferred from the design and construct phase of the project to the operating phase of the project in a form that enables risk management to be undertaken from the time that operation commences.

For new pipelines, all actions which are considered necessary for the safe pressurisation of the pipeline shall be completed prior to the commencement of commissioning.

For new pipelines, all actions which are considered necessary for the safe operation of the pipeline shall be completed prior to the commencement of operation.


DR04561.doc

For existing pipelines the period for the implementation of each action shall be identified as part of the risk management documentation. The schedule for implementation shall be approved.

Where ongoing action is required, a reporting mechanism to demonstrate action shall be established and audited.

2.2.4 Pre-requisites for Risk Management Studies

2.2.4.1 Pre-requisites for an initial risk management study

An initial risk management study shall be undertaken to provide for regulatory approvals. It shall consider at least:

(a) Location and zoning information / Location class / Environmental sensitivity assessments / leading to definition of High Consequence Areas.

(b) Typical threats in typical locations

(c) Location specific threats, particularly in High Consequence Areas

(d) Basic pipeline design parameters

(e) The energy release rate and the contour radius for a radiation intensity of 12.6 and 4.7 kW/m2 in the event of a full bore rupture.

NOTE: A thermal radiation level of 4.7 kW/m2 will cause injury, at least second degree burns, after 30 seconds exposure. A thermal radiation level of 12.6 kW/m2 represents the threshold of fatality, for normally clothed people, resulting in third degree burns after 30 seconds exposure. The energy release is calculated in accordance with Section 4.10. Guidance is provided in HB 105 and API 521, API 581.

2.2.4.2 Detailed Risk Management Study

A robust risk management study requires detailed preparatory information & analysis to ensure a consistency of approach across the pipeline and to provide all of the tools necessary to correctly identify ALL threats and facilitate their assessment and control.

The risk management study shall be undertaken by personnel with expertise in each component of the design, construction and operation of the pipeline, including, or with the support of, personnel closely familiar with the land uses and environments along the entire route.

The following information shall be generated and used for the detailed risk management study:

(a) Design basis and description including:

(i) Basic pipeline properties.

(ii) Engineering design guidelines for non-standard construction (crossings, facilities etc).

(b) Design calculations (e.g. thickness).

(c) Initial pipeline alignment.

(d) Typical design drawings (crossings, facilities etc).

(e) Risk management study of common threats to typical designs

(f) Documented investigations of external threats including information from land owner/holder, public / planning authority, construction contractor

(g) Documented investigations of external threats from existing and planned buried and above ground infrastructure crossing and parallel to the pipeline


DR04561.doc

(h) An assessment of current land uses, and plans for future land use (based on information from landowners and land planning authorities).

(i) Construction line list (list of construction and landowner constraints)

(j) Environmental line list (list of environmental constraints)

(k) Preliminary Safety and Operating Plan (which provides first drafts of standard procedural measures, such as patrolling, land access procedures etc).

(l) Isolation Plan

(m) HAZOP and other design review studies applied to stations, pipeline facilities and pipeline control systems.

(n) Fracture Control Plan

(o) Critical defect length / rupture case / resistance to penetration.

(p) Consequence modelling. Consequence modelling shall include the energy release rate and the contour radius for a radiation intensity of 12.6 and 4.7 kW/m2 in the event of a full bore rupture. Consequence modelling shall include an assessment of the impacts of a fluid release on people, property and the environment, and shall take into account factors such as the nature of the fluid released, topography and prevailing weather conditions.

(q) Environmental studies and information developed specifically for the pipeline project or as otherwise may be available for the route traversed by the pipeline.

NOTE: Electronic Tools (eg. Risk database, GIS) can greatly assist both in process of risk assessment and in documenting its deliberations and outcomes, and allowing decisions to be made transparently.

For in-service pipelines, in addition to the foregoing, the information shall also include:

(a) Land use changes

(b) Changes in population density

(c) As-built drawings

(d) Maintenance history

(e) Previous risk assessment studies

If any of the above items are considered to be not applicable the reason for exclusion from the risk management study shall be documented and approved.

2.2.5 Risk Management Study Validation

Each detailed risk management study shall be validated by a properly constituted workshop(s) which shall review the risk management study in detail and either approve or recommend actions necessary to control the risk from each identified threat to ALARP.

The information requirements listed in Section 2.4.2 are essential for the detailed risk assessment validation workshop, and shall be considered in the workshop.

NOTE: Guidance on risk management study validation is provided in Appendix C.

2.3 OVERVIEW OF PROCESS

2.3.1 Whole of Life Pipeline Risk Management

Pipeline Risk assessment to this Standard is an integral component of the planning, design, construction, operation and abandonment of the pipeline. Figure 2.3.1 illustrates the components of the process and their interrelationship.


DR04561.doc

WHOLE OF LIFE PIPELINE RISK MANAGEMENTP

RE

LIM

INA

RY

D

ES

IGN

AN

D

AP

PR

OV

AL

DE

TA

ILE

D

DE

SIG

NA

BA

ND

ON

OP

ER

AT

E,

MA

INT

AIN

, M

OD

IFY

CO

NS

TR

UC

T

AN

D

CO

MM

ISS

ION

Preliminary Design

Route SelectionEnvironmental Impact Assessment

System Design Feasibility Study

Initial Pipeline Risk Risk Assessment

Pipeline Licence Approval

AS

288

5 S

EC

TIO

N 2

Review and Validate

System Design

Commercial Design a Delivery PointsHydraulic Design a Compressor stations

SAOP a Scraper StationsIsolation Plan a MLVs and SLVs

Pipeline Risk Assessment

Avoid by route selectionApply Physical & Procedural Measures

Apply DesignDamage AnalysisRisk Evaluation

Risk Management

Pipeline Design

Process Design

PIDs, Equipment, Layout

Process Safety a HAZOPControl System Safety a CHAZOPElectronic Systems Safety a SIL

Societal Safety a HAZAN

Construction Safety

Construction Safety Plan, Environmental Management Plan, Risk Assessment of Plans / JSA

Approval to Construct

Commissioning Safety

Commissioning Plan, Safety and Operating Plan, As constructed Risk Assessment / Review

Approval to Commission

Operations Safety

Safety and Operating Plan, Environment Plan, Training, Audits, Integrity Inspections, Risk Assessment Review

Abandon Pipeline

Abandonment Plan, Environment Plan, Maintenance Plan, Risk Assessment

16 O

ctob

er 2

004

vers

ion

FIGURE 2.3.1 WHOLE OF PIPELINE RISK MANAGEMENT


DR04561.doc

2.3.2 Project Phases

2.3.2.1 General

The risk management process involves periodic re-assessment of threats and the implementation of measures to mitigate them which evolves as knowledge of the threats is gained over time.

The risk management study shall be reviewed at intervals during the pipeline design, construction and operational cycles. As a minimum, reviews shall be conducted at the following phases.

2.3.2.2 Initial Design Phases

The initial design is typically developed as part of a feasibility study undertaken early in the life of the project. It is also generally used as the basis to obtain regulatory approvals for the project. The initial design shall include an initial assessment of risks to the community and the environment.

The initial risk management study shall identify high consequence events that impose major risks to the project, community and environment, and their mitigation. The initial design shall generate sufficient information to allow this study to be carried out effectively.

The initial risk management study will deliver sufficient information to allow stakeholders involved in the regulatory approvals process to make informed decisions about the risks associated with the project

The initial risk management study must recognise that detailed design will identify detailed threats and develop specific procedures for their mitigation.

NOTE: The study should be consistent with the requirements of the relevant licensing authority. These may vary from jurisdiction to jurisdiction and should be clarified at the earliest opportunity.

2.3.2.3 Detailed Design Phase

A risk management study which complies with this Standard shall be undertaken in parallel with the design.

NOTE: The application of the risk management process is an integral part of pipeline system design, and cannot be performed independently from the design process. This allows the pipeline design to be continually refined on the basis of pipeline risk management information.

2.3.2.4 Pre-Construction Review

The review shall determine that the design complies with this Standard prior to construction.

Each corrective action that relates to the physical pipeline shall be implemented prior to or during the construction of the affected part of the pipeline.

2.3.2.5 Pre-Commissioning Review

The review shall confirm that the constructed pipeline complies with the requirements of this Standard prior to commissioning.

Where the pipeline route or its design has been changed during construction, the compliance of each change with the requirements of this Standard shall be established.

The review shall confirm that the requirements of the risk management study have been incorporated into the Safety and Operating Plan.

2.3.2.6 Operational Review

A risk management study shall be conducted as a result of any of the following triggers:

(a) At intervals not exceeding five years


DR04561.doc

(b) At any review for changed use

(c) At any review for extension of design life

(d) At any review to increase MAOP

(e) As may be required by AS 2885.3

(f) At any other time that new or changed threats occur

Where a trigger point relates to a part of the pipeline (for example a change at a specific location), the risk management study may be restricted to only that part which is changed.

An assessment of the implementation and effectiveness of the controls required by the design and risk management study shall be made at each Operational Review.

2.4 PIPELINE RISK MANAGEMENT

2.4.1 General

The pipeline risk management process consists of four stages:

(a) Threat Identification

(b) Initial Threat Control

(c) Risk Evaluation of failure threats

(d) Risk Treatment

Figure 2.4.1 illustrates the Pipeline Risk Management Process. This section describes the detail and application of risk management process.


DR04561.doc

Description of design and operation

Location analysis

Threat analysis / specificationNon location related

threats

Apply Design & Procedures & HAZOP (where applicable)

Apply External Interference Protection (where applicable)

Is threat credible?

Threat controlled?

Failure analysis

Failure?

Failure Event

THREAT IDENTIFICATION /

LOCATION ANALYSIS

RISK RANKING

Consequence analysis

Frequency analysis

RISK TREATMENT

ACCEPTED RISK

Assess

Re-Assess

Re-evaluate

Reduce to ALARP Management Plan

Reduce

RISK EVALUATION

INTERMEDIATE

HIGH

HIGH

LOW / NEGLIGIBLE

LOW

NO

YES

YES

YES

NO

NO

THREAT CONTROL

Common Threats / Common Threat Locations /

Standard Design

5 Oct 2004 version

STILL INTERMEDIATENOTE: All stages of the process must be

documented.

FIGURE “PIPELINE RISK MANAGEMENT PROCESS”

FIGURE 2.4.1 PIPELINE RISK MANAGEMENT PROCESS


DR04561.doc

2.4.2 Threats

2.4.2.1 General

The underlying principle of threat identification is that a threat exists at a location. Threats exist at either specific locations (e.g. excavation threat at a particular road crossing), specific sections of a pipeline (e.g. farming; forestry; fault currents for sections with parallel power lines), or over the entire length of the pipeline (e.g. corrosion).

NOTE: Threats which apply to the entire pipeline are considered non-location-specific, and are often qualitatively different to location-specific threats (eg. Corrosion, versus external interference threats at a road crossing). The same risk assessment process applies to both location-specific and non-location-specific threats.

2.4.2.2 Location analysis

The pipeline route should be analysed to divide it into risk assessment sections, for each of which the land use and population density is consistent. A risk assessment section shall not contain more than one location class.

NOTES: 1 Use of risk assessment sections facilitates the threat analysis for threats that apply over whole

sections of the route (eg. Farming, forestry, urban development, etc). 2 It is recommended that data sources to be used to conduct the location analysis include:

alignment survey data to determine basic geographical information; land user surveys in which land liaison officers gather information from land users on the specific activities carried out on the land, and obtain any other local knowledge; third-party spatial information (GIS type data) on earthquakes, drainage, water tables, soil stability, near-surface geology, environmental constraints etc; land planning information.

2.4.2.3 Threat identification

Threat identification shall be conducted for the full length of the pipeline, including stations and pipeline facilities. The threats to be considered shall include external interference, corrosion, natural events, electrical effects, operations and maintenance activities, construction defects, design defects, material defects, intentional damage and other threats such as seismic and blasting. The threat identification shall consider all threats with the potential to damage the pipeline, cause interruption to service, cause release of fluid from the pipeline, or cause harm to pipeline operators, the public or the environment.

The threats identification must generate sufficient information about each threat to allow external interference protection and engineering design to take place. For each identified threat, the following minimum information shall be recorded:

(a) What is the threat to the pipeline?

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

(c) Who (or what) is responsible for the activity?

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

(e) When is it done? (Frequency of the activity, time of the year)

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

The description shall be sufficiently detailed for independent or future reviewers of the risk management study to make an informed assessment of the identified threat and its potential consequence.

2.4.2.4 Common Threats to Typical Designs

The pipeline design process involves the development and application of typical designs to locations where there is a common range of design conditions and identified threats. Where


DR04561.doc

the pipeline design uses typical designs the threats common to that design shall be documented. Each typical design shall be subjected to the risk management process in accordance with this Standard to demonstrate that the threats are mitigated by that design.

2.4.2.5 Other Threats at Typical Design Locations

Each location at which a typical design is applied shall be assessed to determine whether threats other than the approved threats common to that design exist at that location. Where identified, effective threat mitigation measures shall be applied to each of these location specific threats and the effectiveness of the additional mitigation measures shall be assessed.

2.4.2.6 Non-credible threats

Each non-credible threat and the reason for it being declared non-credible shall be documented. Non-credible threats are considered accepted risk. The correctness of this decision shall be considered at each review of the risk assessment.

2.4.3 Threat Control by External Interference Protection or Design

2.4.3.1 General

Each credible threat shall be subject to a systematic process to control the threat.

For external interference threats, external interference protection measures shall be applied.

For those threats for which external interference protection is either not effective or not applicable, design and/or procedure shall be applied.

Threats that are not controlled by this process shall be subject to failure analysis.

2.4.3.2 Threat control by external interference protection

The whole of the pipeline shall be protected from external interference by a combination of physical and procedural measures applied to mitigate the identified threats at each location. The minimum number of physical and procedural measures that must be applied at a location are varied by the location class.

Physical external interference protection for the full length of the pipeline shall be designed in accordance with Section 5.5. The physical measures applied shall be demonstrated to protect the pipeline from the specified threat.

NOTE: Guidance on resistance to penetration calculations is provided in Section 4.11.

Procedural external interference protection for the full length of the pipeline shall be designed in accordance with Section 5.5. The procedural measures shall be demonstrated to be effective in contributing to reducing the frequency of the occurrence of that threat.

NOTE: Guidance on the effectiveness of procedural measures is provided in Appendix D.

External interference threats that are not controlled by external interference protection shall be considered for control by development of additional specific design and/or procedures.

NOTE: Re-routing is a design change decision that may be taken here if EIP is not sufficient, prior to undertaking risk evaluation.

Threats controlled by effective physical measures and with the required procedural protection are considered accepted risk.

2.4.3.3 Control of other threats by design and/or procedures

For threats for which external interference protection is not applicable, specific design and/or procedures shall be applied.

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

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


DR04561.doc

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

Operational controls for the full length of the pipeline shall be designed in accordance with Section 7.

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

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

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

Other threats requiring specific control by design and/or procedures include:

(a) Operational releases

(b) Loss of communication leading to loss of control

(c) Temperature outside design range

(d) Natural events (landslip, seismic activity, flotation and erosion).

(e) Threats arising through operating and maintenance activities

(f) Fluid composition

Threats controlled by effective design and/or procedures are considered accepted risk.

2.4.4 Failure Analysis

2.4.4.1 General

Each threat that is not controlled by external interference protection or design and/or procedures shall be analysed to determine the damage that the threat may cause to the pipeline.

The analysis shall determine whether the damage resulting from a threat results in a failure. Where the outcome is failure the analysis shall determine the mode of failure (significant metal damage, leak or rupture) and the energy release rate at the point of failure (if applicable) as inputs to the consequence analysis.

Each failure event shall be subjected to risk evaluation and risk control.

The analysis may conclude there is no immediate or delayed failure, in which case the threat is reduced to accepted risk. Appropriate management action shall be identified.

Guidance on failure analysis is provided in Appendix Z.


DR04561.doc

FAILURE TREE EXAMPLEEXTERNAL

INTERFERENCE THREAT OCCURS

HIT?NO

YES

FAILURE

• MAOP reduced

• Supply restr icted

• Immediate repair

Note 1: Procedural errors such as fai lure to correctly fol low venting procedures result in uncontrol led gas release and injury/fatal i ty.

Note 2: Loss of containment result ing in energy release rates of 1 GJ/s (T2) and 10 GJ/s (T1) are prohibited.

PIPELINE DAMAGE

• MAOP not reduced

• Maintenance repair

NEAR MISS

COATING DAMAGE

SUPERFICIAL METAL DAMAGE

SIGNIFICANT METAL DAMAGE

LOSS OF CONTAINMENT

FIRE / EXPLOSION

ENVIRONMENTAL DAMAGE

INJURY / FATALITY

MAOP REDUCTION

Figure 2.4.4.1


DR04561.doc

2.4.4.2

2.4.4.3 Documentation

The failure analysis for the specific threat shall document (as applicable):

(a) The pipeline design features.

(b) The threat.

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

(d) The physical dimensions of the failure.

(e) Location of the failure.

(f) Nature of the escaping fluid.

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

(h) Environmental effects at the location (eg. wind)

(i) For fluids with potential to cause environmental damage, the volume release and other factors related to the spread of the fluid in the environment (eg. oil and drainage systems).

NOTE: Some of this information can be addressed in a generic manner for a given set of pipeline parameters, and does not necessarily have to be documented against every threat analysed.

2.4.5 Risk Evaluation

2.4.5.1 General

Consequence analysis and frequency analysis shall be conducted for each failure event. The risk shall be evaluated for each failure event.

Where a failure event may have several outcomes, each outcome shall be considered. Full evaluation of every outcome may not be necessary, but sufficient outcomes shall be evaluated to identify the outcome with the highest risk ranking.

NOTE: The highest energy release rate may not give rise to the highest consequence or the highest risk (eg. A small LPG leak which is initially unignited may well have a higher consequence or higher risk ranking than a large immediately ignited release).

2.4.5.2 Consequence Analysis

The severity of the consequences of each failure event shall be assessed. Consequences to be assessed shall include the potential for

(a) Human injury or fatality;

(b) Interruption to continuity of supply with economic impact; and

(c) Environmental damage. NOTES: 1 Other factors such as property damage and loss of reputation may also be considered. 2 Gas pipelines and some liquid petroleum pipelines may be identified as essential

infrastructure where the consequence of a loss of supply is significant. This may be in terms of the potential for economic impact, and in some cases significant fatalities may result from the cascading consequence of loss of the energy supply.

The consequence analysis for each failure event shall derive the extent of effect of the consequences at that location and shall include assessment of location specific environmental parameters.


DR04561.doc

The description of the severity classes based on Table risk matrix shall be established for the pipeline under study and used in the risk matrix which determines the risk rank.

In establishing pipeline-specific severity classes description, the severity classification shall be maintained, but the description of the consequences associated with each classification shall be reviewed and approved.

The reasons for any changes to the severity class description shall be documented and approved.

2.4.5.3 Frequency analysis

A frequency of occurrence of each failure event shall be assigned for each location where risk estimation is required. The frequency of occurrence shall be selected from Table 2.4.5. The contribution of operations and maintenance practices and procedures to the occurrence of or prevention of failure events may be considered in assigning the frequency of occurrence to each failure event at each location.

2.4.5.4 Risk Ranking

Table risk matrix shall be used to combine the results of frequency analysis and consequence analysis.

Risks determined to be low, negligible or demonstrated to be ALARP are accepted risks.

TABLE 2.4.5 RISK MATRIX

TYPICAL SEVERITY CLASSES

CATASTROPHIC

MAJOR SEVERE MINOR NEGLIGIBLE

People Multiple fatalities result.

Few fatalities, or several people with life-threatening injuries

Injury or illness requiring hospital treatment

Injuries requiring first aid treatment

Minimal impact on health & safety

Supply Long term interruption of supply

Prolonged interruption or long-term restriction of supply

Short term interruption prolonged restriction of supply

Short term interruption or restriction of supply but shortfall met from other sources

No impact; no restriction of pipeline supply

CO

NSE

QU

EN

CE

S

Environment

NOTE: Significant environmental consequences may occur in locations which are relatively small and isolated

Effects widespread; viability of ecosystems or species affected; permanent major changes

Major off-site impact or long-term severe effects or rectification difficult

Localised (<1 ha) & short-term (< 2 yr) effects, easily rectified

Effect very localised (< 0.1 ha) and very short term (weeks), minimal rectification

No effect, or minor on-site effects rectified immediately with negligible residual effect

Frequent Expected to occur once per year or more

Extreme Extreme High Intermediate Low

FRE

QU

EN

CY

Occasional May occur occasionally in the life of the pipeline

Extreme High Intermediate Low Low


DR04561.doc

Unlikely Unlikely to occur within the life of the pipeline, but possible

High High Intermediate Low Neglible

Remote Not anticipated for this pipeline at this location

High Intermediate Low Neglible Neglible

Hypothetical Theoretically possible but has never occurred on a similar pipeline

Intermediate Low Neglible Neglible Neglible

Risk Management Actions:

Extreme: Modify the threat, the frequency or the consequences to ensure that the risk class is reduced to Intermediate or lower. For an in-service pipeline the risk must be reduced immediately.

High: Modify the threat, the frequency or the consequences to ensure that the risk class is reduced to Intermediate or lower. For an in-service pipeline the risk must be reduced as soon as possible, typically within a timescale of not more than a few weeks

Intermediate: Repeat threat identification and risk evaluation processes to verify and, where possible, quantify the risk estimation; determine the accuracy and uncertainty of the estimation. Where the risk class is confirmed to be Intermediate, modify the threat, the frequency or the consequence to ensure the risk class is reduced to Low or Negligible. Where the risk class cannot be reduced to Low or Negligible action shall be taken to remove threats, or reduce frequencies or reduce severity of consequences so as to reduce the risk to ALARP. For an in-service pipeline the reduction to Low, Negligible or ALARP must be completed as soon as practicable, typically within a timescale of not more than a few months

Low: Determine the management plan for the threat to prevent occurrence and to monitor changes which could affect the classification.

Negligible: Review at the next review interval

2.4.5.5 Numerical Methods

It is recognised that there are circumstances where risk estimation using numerical methods is required to enable comparison of alternative mitigation measures as a basis for demonstration of ALARP, and in some jurisdictions, to satisfy planning criteria.

2.4.6 Risk Treatment

2.4.6.1 General

Action shall be taken to reduce the risk in accordance with Table 2.4.5.

The action(s) taken and their effect on the risk assessment shall be documented and approved.

2.4.6.2 Design stage

Risk treatment actions at design stage may include the following:

(a) Relocation of the pipeline route.

(b) Modification of the design for any one or more of the following:

(i) Pipeline isolation.

(ii) External interference protection.

(iii) Corrosion prevention.


DR04561.doc

(iv) Operational controls.

(c) Establishment of specific procedural measures for prevention of external interference.

(d) Establishment of specific operations measures.

2.4.6.3 Operating pipelines

Risk treatment actions at operating pipeline stage may include one or more of the following:

(a) Installation of modified physical external interference protection measures.

(b) Modification of procedural external interference protection measures in operation.

(c) Specific actions in relation to identified activities; e.g. presence of operating personnel during activities on the easement.

(d) Modification to pipeline marking.

(e) Changes to the Isolation plan.

(f) Changes to the design or operation to satisfy the requirements of this Standard when there is a change to the location class of the pipeline.

(g) Specific operational or maintenance procedures.

Risk treatment for operating pipelines shall consider interim risk reduction measures (e.g. reduction in operating pressure, access restrictions) to allow time for the implementation of permanent risk reduction measures (e.g. repair).

2.5 STATIONS, PIPELINES FACILITIES AND PIPELINE CONTROL SYSTEMS

2.5.1 General

Stations and pipeline facilities involve processes that control or change the properties and / or the operating conditions of the fluid being transported and they are normally facilities above ground and contain operable components.

Consequently, the threats and failure outcomes are normally different than those for a transmission pipeline.

2.5.2 Safety Assessments

The safety of these facilities shall be assessed by the application of one or more of a number of recognised safety study methodologies. A study shall be made to determine the most appropriate methodologies for each facility.

As a minimum:

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

(b) Non-process threats shall be reviewed in accordance with the risk management process in this Standard.

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

2.6 ENVIRONMENTAL RISK MANAGEMENT

2.6.1 General

Pipeline construction, operation and maintenance has the potential to impact on the environment. This Standard requires the risk to the environment of each part of the life cycle of the pipeline to be assessed using the methodology of this Section so that the risks associated with each identified threat are reduced to ALARP.


DR04561.doc

NOTE: Environmental impact assessment is not simply a vehicle to obtain regulatory approval. It is a critical element of the planning for design and construction of the pipeline. Experience shows that many construction and rehabilitation problems can be avoided where appropriate attention is paid to developing detailed environmental information and ensuring that this information is integrated into design and construction planning. It is important that personnel experienced in construction are involved at this early stage. The greatest environmental impacts occur during the construction phase, and construction personnel are in the best position to advise on this.

This environmental risk assessment shall not remove the obligation of compliance with statutory and project specific requirements to manage environmental risk. Rather it shall provide a base for determining the appropriateness of a mitigation approach, particularly to a construction activity, where the consequence and the frequency (or duration of the consequence) is a direct result of the approach taken to control the risk.

Effective environmental impact assessment requires gathering basic environmental data and shall include consultation with key stakeholders (prior to any statutory consultation requirements). Stakeholder consultation at an early stage is critical to the process of gathering all relevant information required for all subsequent planning.

An analysis of the impacts of construction techniques and design at sensitive locations shall be included in the environmental risk assessment.

An environmental impact assessment shall include an environmental risk assessment in accordance with this Standard along the length of the pipeline route.

An environmental impact assessment report shall form the basis of the environmental management plan.

During the operation of the pipeline, the risk of damage to the environment from operational and maintenance activities must also be assessed and measures developed to reduce those risks to ALARP.

The environmental management plan shall include approved procedures for protecting the environment form operation and maintenance activities.

2.6.2 Environment Risk Management Process

An objective of the pipeline development process, including pipeline route selection, is that the environmental risk is managed through careful investigation, assessment and selection of the pipeline route such that, to the greatest extent possible, environmental risk is minimised by avoidance (route selection), and where necessary specific construction techniques, together with appropriate environmental management procedures.

The environmental risk assessment must be based on data which is sufficient for informed decisions about the impacts of the pipeline project and the efficacy of the environmental controls. Data which must be obtained prior to conducting the environmental risk assessment shall include:

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

(b) Stakeholder survey information

(c) Constructability / safety constraints

(d) Emergency response capabilities

(e) Legislative requirements

Sources of data may include:

(a) Field survey information

(b) Landholder survey information

(c) Stakeholder survey information


DR04561.doc

(d) Experienced pipeline construction personnel

(e) Externally sourced data resident in the project environmental impact assessment

(f) Other publicly available information including papers, studies, reports, assessments and data libraries on flora, fauna and eco-systems in the pipeline route or ecologically similar environments.

The environmental severity classes that apply to the pipeline project shall be defined and approved.

The process for managing environmental risk using the AS 2885 principles are outlined below:

(a) Divide the route into sections with similar environments and threats, such as level cropping land, undulating grazing land, steeply dissected bushland, etc, and then identify specific locations where adverse environmental consequences may occur, such as creek crossings, paddocks (e.g. weed impacts), bushland (e.g. vegetation clearance), etc.

(b) Specify each activity (e.g. right-of-way clearance) that has the potential to create a threat to the environment. Specification of the activity shall, as far as possible, be expressed in quantified terms (e.g. width of clearance; period of disturbance).

(c) Specify the potential impacts of each activity on each component of the environment (fauna, flora, soil, ground water, surface water, drainage, landholders and land use, emissions (air and noise), cultural heritage, public safety and visual amenity. Specification of impacts shall, as far as practicable, be expressed in quantified terms.

(d) Identify and apply the mitigation measures for each threat (including rehabilitation), and assess whether the measures will meet the environmental objectives (i.e. can reduce the threat to a level of acceptable risk).

(e) For threats requiring further assessment, at each location, identify the consequence of the threat to each component of the environment. As a general guide, the consequence must be considered with an understanding that the duration of the threat in both construction and operational phases of the project is short, and the land affected is relatively small. However, the analysis must also recognise that some consequences (e.g. weed infestation) have the potential to create an impact whose duration is significantly greater than the duration of the activity, and the consequence may propagate well beyond the easement.

(f) For threats requiring further assessment, determine the frequency of each adverse consequence of the threat (taking into account the duration of the activity at the specified location and the robustness of the specified controls).

(g) Evaluate the risk using the risk matrix in Table 2.4.5, and apply further risk treatment as required by Table 2.4.5.

The following are important:

(a) The environmental risk management must take a holistic view of the environment and the activities that may impact on the environment (e.g. construction). The net effect of the mitigation measures (taking into account the environmental impact of the mitigation measures) must be considered concentration on a specific issue may create greater environmental impact while minimising risk of a particular threat.

(b) The environmental objectives set at the approvals stage must be achievable within practical construction processes.

(c) The environmental objectives must be established sufficiently early in the process for the bulk of the objectives to be satisfied by route selection.


DR04561.doc

(d) Occasional impacts (eg sedimentation at stream crossings) may be an acceptable outcome if the duration of the release is small. The impact must be considered in the context of other land uses in the immediate vicinity of the project.

(e) Environmental risk that is ongoing through the operational phase need to be addressed during the approvals and design process

2.6.3 Implementation

The outcomes of the environmental risk assessment shall be incorporated into environmental management procedures for both the construction, operational and abandonment phases of the pipeline life cycle.

The environmental management procedures shall also address emergency situations. NOTE: The APIA Code of Environmental Practice provides industry accepted guidance on management of the Environment through the Design, construction and Operational phases of a project.

2.7 ELECTRICAL

A pipeline can be subject to significant voltages that can be hazardous to the pipeline itself, or to personnel who may come in contact with it.

High voltages can arise due to a variety of causes, such as earth potential rise in the vicinity of electrical earthing under fault conditions or due to voltages induced on the pipeline when faults occur on nearby parallel powerlines.

A pipeline in the vicinity of electricity supply powerlines or facilities shall be subject to analysis to determine if procedures and/or installations to provide electrical safety are required.

General guidance on electrical safety is given in Appendix Q.

2.8 CONSTRUCTION & COMMISSIONING

2.8.1 Construction Safety

Construction of pipelines shall be carried out in a safe manner.

The safety of the public, construction personnel, adjacent property, equipment and the pipeline shall be maintained and not compromised.

A construction safety plan shall be prepared, reviewed by appropriate personnel, and approved. This review shall take the form of a construction safety plan workshop.

NOTES: 1 Review by appropriate personnel should include designers, construction personnel, OH&S

personnel, environmentalists and/or the approval authority. 2 The construction safety plan detail should be consistent with the nature of the work being

undertaken. It may be a component of an enterprise construction safety system, a construction safety case (where the regulatory jurisdiction require this), or a project or activity specific safety plan

At least the following items shall be addressed:

(a) Approved fire protection shall be provided and local bushfire and other fire regulations shall be observed.

(b) Where the public could be exposed to danger or where construction operations are such that there is the possibility that the pipeline could be damaged by vehicles or other mobile equipment, suitable warnings shall be given.

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


DR04561.doc

(d) Where a pipeline is in close proximity to a power line, potential threats from induced voltage and induced or fault currents to personnel safety shall be assessed and appropriate measures taken to mitigate risk to personnel and equipment. Appendix Q provides guidance on measures that might be implemented.

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

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

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

(h) Provision of adequate measures to prevent public from hazards caused by welding.

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

(j) Procedure for safe use and handling of chemicals and solvents.

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

(l) Accident reporting and investigation procedure.

(m) Appointment of safety supervisor and duties if applicable.

(n) Travel associated with attending the worksite

(o) Statutory obligations. NOTES: 1 Specific construction safety requirements exist in each regulatory jurisdiction. The more

stringent of the regulatory requirements and the requirements of this Section shall apply. 2 APIA Safety Committee is developing a Code of Pipeline Construction Safety to provide

appropriate guidance for the Australian Pipeline Industry.

2.8.2 Testing Safety

The construction safety plan shall address safety through all phases of testing of the pipeline during construction.

2.8.3 Commissioning Safety

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

Commissioning safety requirements include complying with AS 2885.3 Section 2.


DR04561.doc

S E C T I O N 3 M A T E R I A L S A N D C O M P O N E N T S


Materials and components shall be suitable and safe for the conditions under which they are used, including construction. They shall have the pressure strength, temperature rating, and design life specified by the engineering design.

The engineering design shall take into account the effect of all of the manufacturing and construction processes and service conditions on the properties of the materials.

3.2 QUALIFICATION OF MATERIALS AND COMPONENTS

3.2.1 General

Materials and components shall comply with one or more of the relevant requirements of this Clause. They shall be supplied with test certificates containing sufficient data to demonstrate compliance with the nominated standards and any supplementary specifications.

Where materials and components do not comply with nominated standards and have been qualified in accordance with this Clause, documentary evidence of that qualification shall be provided.

3.2.2 Materials and components complying with nominated Standards

Materials and components complying with the following nominated Standards may be used for appropriate applications as specified and as limited by this Standard without further qualification. Except as provided in Clause 3.4.3, they shall be used in accordance with the pressure/temperature rating contained in those Standards:

(a) Pipe-Carbon/Carbon manganese steel pipe. API Spec 5L, ISO 3183, ASTM A 53, ASTM A 106 and ASTM A 524. Minimum additional requirements for pipes complying with any of these Standards consist of the following:

(i) Furnace welded (CW) pipe shall not be used for pressure containment.

(ii) The integrity of any seam weld shall be demonstrated by non-destructive examination of the full length of the seam weld.

(iii) The integrity of each pipe length shall be demonstrated by hydrostatic testing as part of the manufacturing process.

(iv) Where the design factor exceeds 0.72 the minimum weight tolerance in API 5L shall be adhered to, irrespective of the Standard to which the pipe is purchased.

(v) Where the design factor exceeds 0.72 the level of eccentricity permitted in seamless pipe shall be established. The resulting minimum allowable wall thickness shall be adopted in design calculations (see Clause 5.4.4).

(b) Corrosion Resistant alloys - API Spec 5L C

(c) Fibreglass pipe API 15LR, API 15HR or ISO 14692 Parts 1 and 2 Note: Where this standard is used for pipelines constructed with Corrosion Resistant Alloy or fibreglass pipe, attention is drawn to the requirements of Clause 3.1.

(d) Fittings, and Components ASME B16.9, ASME VIII, BS5500, AS1200 ASME B16.11, ASME B16.25, ASME B16.28, ASTM A 105, ASTM A 234, ASTM A 420, BS 1640.3, BS 1640.4, BS 3799 and MSS SP-75.


DR04561.doc

(e) Pipeline Assemblies - elements of a pipeline assembled from pipe complying with a nominated Standard and pressure rated components complying with a nominated Standard or of an established design and used within the manufacturer's pressure temperature rating.

(f) Piping AS4041 and B31.3.

(g) Induction Bends ISO 15590-1 ASME B16.49.

(h) ValvesASME B16.34, API Spec 6D, API Std 600, API Std 602, API Std 603, ASTM A 350, BS 5351, MSS SP-25 and MSS SP-67.

(i) FlangesASME B16.5, ASME B16.21, MSS SP-6 and MSS SP-44.

(j) GasketsASME B16.21 and BS 3381.

(k) BoltingAS 2528, ANSI B18.2.1, ASME B16.5, ASTM A 193, ASTM A 194, ASTM A 307, ASTM A 320, ASTM A 325, ASTM A 354 and ASTM A 449.

(l) Pressure gaugesAS 1349.

(m) Welding consumablesAS 2885.2.

(n) Anti-corrosion coatingsAS 3862, AS 1518, CAN/CSAZ245.21 System B Tri-laminate

(o) Galvanic anodes AS 2239.

3.2.3 Materials and components complying with Standards not nominated in this Standard

Materials and components complying with Standards that are not nominated in Clause 3.2.2 may be qualified by one of the following means:

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

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

(i) Proof tests as described in AS 1210.

(ii) Experimental stress analysis.

(iii) Theoretical calculations.

(iv) Function testing (supplementary).

The results of tests and findings of investigations shall be recorded and approved.

3.2.4 Components, other than pipe, for which no Standard exists

Components, other than pipe, for which no Standards exist may be qualified by investigation, tests or both, to demonstrate that the component is suitable and safe for the


DR04561.doc

proposed service, provided that the component is recommended for that service from the standpoint of safety by the manufacturer.

3.2.5 Reclaimed pipe

Reclaimed pipe may be used, provided that

(a) The pipe was manufactured to a nominated Standard;

(b) The history of the pipe is known;

(c) The pipe is suitable for the proposed service in light of its history;

(d) An inspection is carried out to reveal any defects that could impair its strength or pressure tightness; and

(e) A review and, where necessary, an inspection is carried out to determine that all welds comply with the requirements of this Standard.

(f) Defects shall be repaired or removed in accordance with this Standard.

Provided that full consideration is given in the design to the effects of any adverse conditions under which the pipe had previously been used, the reclaimed pipe may be treated as new pipe to the same Standard only after it has passed a hydrostatic test (see Clauses 3.2.10 and 11.4.1).

3.2.6 Reclaimed accessories, valves and fittings

Reclaimed accessories, valves and fittings may be used, provided that

(a) The component was manufactured to a nominated Standard;

(b) The history of the component is known;

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

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

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

Components shall be cleaned, examined and where required reconditioned and tested, to ensure that they comply with this Standard.

Provided that any adverse conditions under which the component had been used will not affect the performance of the component under the operating conditions that are to be expected in the pipeline, the component may be treated as a new component to the same Standard, but shall be hydrostatically tested (see Clauses 3.2.10 and 11.4.1).

3.2.7 Material and components not fully identified

Where an identity with a nominated Standard is in doubt, any material or component may be used, provided that it is approved and has the chemical composition and mechanical properties and integrity tests specified in the nominated Standard.

3.2.8 Identification of components

Components that comply with nominated Standards that are produced in quantity, carried in stock and wholly formed by casting, forging, rolling or die-forming, (e.g. fittings, flanges, bolting) are not required to be fully identified or to have test certificates unless otherwise specified. However, each such component shall be marked with the name or mark of the manufacturer and the markings specified in the Standard to which the component was manufactured. Components having such marks shall be considered to comply with the Standard indicated.


DR04561.doc

3.2.9 Unidentified materials and components

Materials, pipes and components that cannot be identified with a nominated Standard or a manufacturer's test certificate may be used for parts not subject to stress due to pressure (e.g. supporting lugs), provided that the item is suitable for the purpose.

3.2.10 Hydrostatic test

Reclaimed pipe and components, the strength of which may have been reduced by corrosion or other form of deterioration, or pipe or components manufactured to a Standard which does not specify the manufacturer's test, shall be tested hydrostatically either individually in a test similar to a manufacturer's test or as part of the pipeline to the test pressure specified for the pipeline.

3.3 REQUIREMENTS FOR COMPONENTS TO BE WELDED

3.3.1 Welding of Pre-Qualified materials

Except where otherwise indicated herein, where welding is specified by Standards nominated in this section, that welding shall be acceptable without further qualification.

NOTE: AS 2885.2 states that that Standard is not intended to be applied to welds made by the manufacturer during fabrication of a component.

3.3.2 Materials specifications

AS2885.2 provides information on factors that affect weldability and should be considered when specifying components.

3.4 ADDITIONAL MECHANICAL PROPERTY REQUIREMENTS

3.4.1 Yield strength

The yield strength (σY) to be used in equations in this Standard shall be the SMYS specified in the Standard with which the pipe complies.

The preferred method for determining the tensile properties of line pipe complying with API 5L is given in Appendix E.

3.4.2 Pipe Yield to Tensile Ratio

For cold expanded pipe the API 5L yield to tensile strength ratio requirement of 0.93 maximum shall be met using either the ring expansion test or the round bar test. Subject to the approval of the Pipeline Licensee this requirement may be demonstrated by correlation between one of those tests and the results of flattened bar tests. This correlation shall be established using the actual material concerned.

3.4.3 Strength De-rating

Carbon steel and carbon manganese steel flanges and valves complying with nominated Standards may be used without derating at design temperatures not exceeding 120°C.

Where the pipeline design temperature is above 65°C the yield strength of the pipe steel shall be derated. The reduction in yield strength shall be 0.07% per degree C by which the design temperature exceeds 23°C.

NOTE: The use of 65°C as a boundary below which no de-rating needs to be applied covers common gas pipeline compressor discharge temperatures. This exemption results in a step change in de-rating above 65°C.

3.4.4 Fracture toughness

The fracture toughness of line pipe shall comply with the requirements identified in the fracture control plan determined in accordance with Clause 4.8.2. Test methods for fracture toughness shall be in accordance with Appendix F.


DR04561.doc

3.5 REQUIREMENTS FOR TEMPERATURE AFFECTED ITEMS

3.5.1 General

Properties of materials may be altered by exposure to non-ambient temperatures during manufacture and construction by processes such as hot bend manufacture, application of corrosion prevention coatings including joint coating, pre-weld and post weld heat treatment, and where pipe is exposed to cryogenic temperatures. Exposure to above ambient temperatures during operation such as downstream of compressor stations or in hot oil, or gas gathering service may also affect material properties.

The effect of these processes on the integrity of the pipeline shall be considered.

3.5.2 Items heated subsequent to manufacture

Where pipe or components are heated as part of processes subsequent to manufacture, the effect of the heating on yield strength and fracture properties shall be established.

Materials and components which are heated or hot-worked at temperatures above 280°C after completion of the manufacturing and testing processes, shall not be used without approval. In order for such approval to be obtained it shall be demonstrated that the materials and components satisfy the minimum strength and fracture toughness requirements for the pipeline design after the heat treatment or hot-work is performed.

Where carbon manganese steel components are subject to temperatures above 100oC during coating, field weld heat treatment or similar processes, strain ageing effects shall be considered. The effect of material processing on strength, ductility and fracture properties shall be determined by representative tests on samples subjected to simulated or actual heat treatment cycles and taken into consideration in the design, including the fracture control plan. Flattened strap test pieces shall not be used for yield strength determination.

NOTE: The effect of heating required for coating application on yield to tensile ratio is a subject of current APIA research. The outcome of this research will be addressed by way of amendment to this standard should it be required.

3.5.3 Pipe operated at elevated temperatures

Where pipe is operated at elevated temperatures, the yield stress shall be determined in accordance with clause 3.4.3. The effect of exposure to the design maximum temperature on the competing processes of increased strength due to strain ageing and loss of strength due to the elevated temperature shall be considered. Other mechanical properties including toughness need not be considered.

3.5.4 Pipe exposed to cryogenic temperatures

Exposure of carbon manganese steel to cryogenic temperatures is deemed not to alter subsequent properties. The effect of cryogenic temperatures on pipeline coating shall be considered.

3.6 MATERIALS TRACEABILITY AND RECORDS

All pressure containing materials installed on a pipeline system shall be traceable to the purchase documentation, the manufacturing standard, the testing standard, and to inspection and accepting documents. The pipeline licensee shall maintain the records until the pipeline is abandoned or removed.

Special traceability procedures shall be applied to materials whose markings are destroyed in processes following their manufacture (eg coated pipe).

Consideration shall be given to the need in subsequent operation, maintenance and development of the pipeline for the materials to be identified spatially, by item (eg identification of each pipe by coordinate, and each component by mark to the as constructed


DR04561.doc

drawing). Where such identification is applied, the requirement shall be documented and the quality procedure implemented shall be sufficient to ensure the accuracy of the data.

Electronic records that can be accessed by common text, database or spreadsheet programs are preferred. Where documents are only available on paper, they should be scanned into an appropriate format.

3.7 RECORDS

The identity of all materials shall be recorded and this identity shall include reference to the test certificates and/or inspection reports.


DR04561.doc

S E C T I O N 4 P I P E L I N E G E N E R A L


Every pipeline shall be leak tight and have the necessary capability to safely withstand all reasonably predictable influences to which it may be exposed during the whole of its design life.

A structured design process, appropriate to the requirements of the specific pipeline, shall be carried out to ensure that all safety, performance and operational requirements are met during the design life of the pipeline. Where required by this Standard, the design shall be approved.

NOTE: An example of the design process structure is illustrated in Figure 4.1.


DR04561.doc

SAFETY4.2.4ROUTE SERVICE CONDITIONS

Construction safetyElectr ical safety

Risk identi f icat ionRisk evaluationManagement of r isks Occ. health and safety

DESIGN PRINCIPLES 4.1

INSPECTION

Inspections and test planPressure test ing

5.3.2,

5.3.45.3.3,

CoatingsEnvironmental

5.7

CORROSION

InternalExternal

5.55.6

MAINLINE PIPEWORK

External interference protectionFabricated assemblies

Pressure design

Stress and strainFracture controlSpecial construction

4.3.2, 4.3.4

4.3.74.3.64.3.9

4.3.8

4.2.5

Location class 4.2.4.4

OPERATION AND MAINTENANCE

CHOSEN DESIGN

7.47.2

protection proceduresExternal interferenceEmergency plan

4.2.5

AS 2885.3

Pressure, temperature, f lowand surge design condit ions

STATIONS

Design standards

Pipework

StructureEquipment

Design considerations

Pipel ine controls

Safety

4.2.6

2.82.7

2.4

2.62.5

2.3 MAOP

4.4.1

4.4.34.4.44.4.54.4.6

4.4.2

4.3.2,

4.2.3

4.3.3

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

(a) Safety of pipeline and public is paramount.

(b) Design is specific to the nominated fluid(s).

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

(d) The fitness for purpose of pipeline and other associated equipment.

(e) Engineering calculations for known load cases and probable conditions.

(f) Stresses, strains, displacements and deflections have nominated limits

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


DR04561.doc

(h) Fracture control plan to limit fast fracture is required.

(i) Pressure positively controlled and limited.

(j) Pipeline integrity is established before service by hydrostatic testing.

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

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

(i) External interference protection;

(ii) corrosion mitigation;

(iii) integrity monitoring capability where applicable; and

(iv) operation and maintenance in accordance with defined plans.

(m) Changes in the original design criteria which prompt a design review.

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

The design process shall include an assessment of risks to the pipeline and the community and shall reflect the obligation of the designer to provide reasonable protection for the pipeline and the community against the consequences of the hazards identified during assessment of risks.

Figure 4.1(A) describes the separation of a pipeline system into Pipeline and Stations.

The limit between Pipeline and Station shall be defined for each Station. The limit should preferably be at or adjacent to the first valve off the pipeline on the side of the valve remote from the pipeline. Other suitable locations may be a flange, a weld or a point defined by dimensions.

Scraper launcher

1

Supply stat ion

2

Inl ine scraper faci l i ty

Booster stat ion

TYPICAL PIPELINE

Main l ine valve

1 1

2

Branch connection

Scraper receiver

Offtake stat ion

2

1

Receipt stat ion

2

Scope of stat ion design to Section 4.4

Scope of pipel ine design to Section 4.3

2

1

LEGEND:

FIGURE 4.1(A) PIPELINE SYSTEM SCHEMATIC

The requirements of Section 5 shall apply to the pipeline and to piping associated with pipeline assemblies and shall be met notwithstanding the use of any other Standard for design of elements of the pipeline.

The requirements of this Section (Section 4) shall apply, except where an element of a pipeline has been designated as a station in accordance with Figure 4.1(A).

The requirements of Section 6 shall apply where an element of the pipeline has been designated as a Station.


DR04561.doc

4.2 ROUTE

4.2.1 General

The route of a pipeline shall be selected having regard to public safety, pipeline integrity, environmental impact, and the consequences of escape of fluid.

A new pipeline shall be designed in accordance with the requirements of this Standard:

(a) For the land use existing at the time of design and;

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

The land use for which the pipeline is designed shall be documented and approved.

For an existing pipeline, changes in land use from those for which the pipeline was designed introduce an obligation for a safety assessment of the pipeline and where required, the implementation of design and /or operational changes to comply with the safety obligations of the Standard

4.2.2Investigations

A detailed investigation of the route and the environment in which the pipeline is to be constructed shall be made. The appropriate authorities shall be contacted to obtain details of any known or expected development or encroachment along the route, the location of underground obstructions, pipelines, services and structures and all other pertinent data.

4.2.3 Route selection

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

(a) Pipeline integrity.

(b) Fluid properties, particularly if HVPL.

(c) The consequences of escape of fluid.

(d) Public safety.

(e) Proximity to populated areas.

(f) Easement width.

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

(h) Special concerns associated with the use of common infrastructure corridors

(i) Proximity of existing cathodic protection groundbeds.

(j) Proximity of sources of stray d.c. currents.

(k) Proximity of other underground services.

(l) Proximity of high voltage transmission lines.

(m) Environmental impact.

(n) Present land use and any expected change to land use.

(o) Prevailing winds.

(p) Topography.

(q) Geology.

(r) Possible inundation.

(s) Constructability


DR04561.doc

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

4.2.4 Route identification

The pipeline route and the location of the pipeline in the route shall be identified and documented. The requirements for each pipeline shall be approved. The following shall be considered in developing an appropriate marking strategy for the pipeline:

(a) Identification for public information.

(b) Identification for services information.

(c) Identification for emergency services.

(d) Identification on maps.

(e) Identification on land titles.

(f) Identification using visible markers generally complying with the marker illustrated in Figure 4.4.1, as aid to protection from external interference damage.

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

4.3 PIPELINE MARKING

4.3.1 General

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

Signs should be located so that from any location along the pipe centreline, a sign is visible in either direction from the observer.

Table 4.4.1 provides guidance on sign spacing in each Location Classification.

4.3.2 Sign Location

Signs shall be placed at the following locations:

(a) Both sides of public roads

(b) Both sides of railways

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

(d) Both sides of rivers

(e) Vehicle tracks

(f) Each change of direction

(g) Utility crossings (buried or aboveground)

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

(i) At all above-ground facilities

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

Where strict adherence to the requirements of this clause is shown to provide no increase in safety, alternative spacing may be developed.

A single sign is sufficient at sites where a number of the above locations coincide (eg. utilities alongside a road, vehicle tracks).

At ephemeral streams signs should be placed where required to locate the pipeline.


DR04561.doc

Where signs are used to provide procedural protection, the spacing to provide effective protection shall be established in the external interference protection design in accordance with Section 5.5.

4.3.3 Sign Design

Except as noted herein, marker signs shall comply with the requirements of a DANGER sign generally in accordance with AS 1319. Figure 4.3.1 illustrates a typical marker sign for cross country pipeline. The sign dimensions and shape may be modified to suit the constraints of the location.

Marker signs shall:

(a) Indicate the approximate position of the pipeline, its description, the name of the operator, and a telephone number for contact for assistance and in emergencies.

(b) Indicate that excavating near the pipeline is hazardous.

(c) Contain a direction to contact the pipeline operator before beginning excavation near the pipeline.

NOTE:Appendix D provides guidance on the effectiveness of procedural measures, including signs, in contributing to pipeline awareness.

TABLE 4.3.1

SIGN SPACING

Location class / sub class Recommended Maximum sign spacing, m.

R1 500 (Note 1)

R2 250 (Note 1)

T1 100

T2 50

Sensitive 50

CIC Note 2

I, HI 100

NOTES:

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

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

3 In locations T1, T2, S, CIC, I and HI signs should be intervisible


DR04561.doc

350-450

150

350-450

FIGURE 4.2.4.5 TYPICAL PIPELINE MARKERS

4.4 CLASSIFICATION OF LOCATIONS

4.4.1 General

Locations for pipelines shall be classified for possible risks to the integrity of the pipelines, the public, property and the environment. The classification shall include a primary location class reflecting population density, and where appropriate shall include one or more secondary location classes reflecting special land uses.

Location class analysis for a new pipeline shall take full account of known planning for land use along the pipeline route including all published land planning instruments.

Location class analysis of an existing pipeline shall take full account of current land use and authorized developments along the pipeline route, but need not take full account of land use which is planned, but not implemented.

NOTE: Consideration of population density shall include both residents and others who spend prolonged periods in the vicinity of the pipeline as a result of their employment, recreation or any other reason.

4.4.2 Measurement Length

The measurement length the radius of the 4.7 kW/m2 radiation contour for a full bore rupture, calculated in accordance with Clause 4.10.


DR04561.doc

4.4.3 Location Classification

It is the intent of this Standard that the Location Class is selected from an analysis of the predominant land use in the broad area traversed by the pipeline. The following requirements shall be followed in determining the Location Class:

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

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

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

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

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

4.4.4 Primary location class

The pipeline route shall be classified into one of the Primary Location Classes R1, R2, T1 and T2 as defined below.

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

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

(b) Rural Residential (R2) Land which is occupied by single residence blocks typically in the range 1 ha to 5 ha or is defined in a local land planning instrument as rural residential or its equivalent. Land used for other purposes but with similar population density shall be assigned Rural Residential location class. NOTE: In Rural Residential societal risk (the risk of multiple fatalities from a hole) is not a dominant design consideration.

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

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


DR04561.doc

4.4.5 Secondary location class

Location classes S, CIC, I, HI and W are sub-classes that may occur in any primary location class. The affected length is generally less than the length of the primary location class.

Where the land use through which the pipeline route passes is identified as S, CIC, I or W the requirements of the primary location class (R1, R2, T1, T2) shall be applied together with additional consideration and additional requirements established for the S, CIC, I or W Location Class.

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

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

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

(c) Heavy Industrial (HI) Sites developed or zoned for use by Heavy Industry or for Toxic industrial use locations shall be considered classified as Heavy Industrial. They shall be assessed individually to assess whether the industry or the surroundings include features that:

(i) Contain unusual threats to the pipeline

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

Depending on the assessed severity the design requirements of R2, T1 or T2 shall be applied. NOTE: In Heavy Industrial use areas the dominant consideration may be the threats associated with the land use or a range of location specific risks associated with the loss of containment

(d) Common Infractructure Corridor (CIC) Land which is either defined as a Common Infrastructure Corridor, or which by dint of its function results in multiple (more than one) infrastructure development within a common easement or reserve, or in easements which abut, and which may or may not use common land for access or maintenance is classified as a Common Infrastructure Corridor location class. Within a this location classification external interference protection should require a minimum of one physical measure and three procedural measure, one of which should be a formal agreement between the corridor users on the rights and obligations of each to operate, maintain and develop their asset within the corridor.


DR04561.doc

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

4.5 SYSTEM DESIGN

4.5.1 Design basis

The basis for design of the pipeline, for each station, and for each modification to the pipeline or station shall be documented in the Design Basis.

The purpose of the Design Basis is to document both principles and philosophies that will be applied during the development of the detailed design, and specific design criteria that will be applied throughout the design.

The Design Basis is usually an output of the Planning and Preliminary design phase of a project, and it usually describes the project for which the budget is set.

The Design Basis shall be revised during the development of the project to record changes required to the design basis as a result of additional knowledge of the project requirements as the detailed design is developed.

The Design Basis shall be revised at the completion of the project to reflect the as-built design. The final document shall be transferred to Operations as a record of the design.

The Design Basis shall record at least:

(a) A description of the project covered by the design basis

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

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

(ii) Design life of pipeline system and design lives of sub-systems as applicable.

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

(iv) Design temperature(s).

(v) Corrosion allowance, internal and external.

(vi) Fluids to be carried.

(vii) Minimum design and installation criteria

(c) Specific process and maintenance criteria to be used in the design including at least:

(i) Operating and maintenance philosophy.

(ii) The basis for fracture control design, including gas composition

(iii) Performance requirements for pipeline depressurisation, repressurisation, and isolation valve bypass.

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


DR04561.doc

(v) Isolation principles.

(vi) Limiting conditions.

(vii) Corrosion mitigation strategy

(d) Design principles established as the basis of detailed design.

(e) Design philosophies established to guide development of the detailed design.

4.5.2 Maximum velocity

Transmission pipelines (and the associated station facilities) usually transport clean fluids which can be transported at any practical velocity without causing any reduction of wall thickness as a result of wear.

The design shall establish the presence in the fluid of any contaminants that could reduce the pipe wall thickness during the pipeline design life through erosion or a synergistic erosion-corrosion mechanism. Where erosion or erosion-corrosion mechanisms exist and where these mechanisms can be controlled by limiting the maximum velocity in the pipeline, the maximum velocity in the transmission pipeline and in the station piping shall be determined and documented in the Design Basis.

NOTES: 1 API RP 14E is one experience based method of determining limiting velocity for control of erosion in

piping systems containing solids and liquids. 2 Where synergistic erosion-corrosion mechanisms exist, specific designs should be developed.

4.5.3 Design life

The design life for a pipeline, and where relevant, its components shall be determined and documented. Design lives include:

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

(b) Engineering Design Lives For each metallic, non-metallic, electrical and electronic components (or sub-systems) that may be expected to have a service life that is different from the System Design Life, an Engineering Design Life shall be nominated, and applied when specifying each sub-system or component. The individual engineering design lives shall be considered when preparing operating and maintenance plans and risk assessments. Where a component supplier is unable to meet the engineering design life, the change shall be nominated in the project records, and the plans and procedures dependent on the life shall be reviewed. Non-replaceable components should be designed for a similar life to that of the pipeline, since premature failure will impact on the continued operation of the pipeline. NOTE: Normally replaceable components (eg seals and gaskets) that are required to have essentially an indefinite life if left in position and untouched should be selected from components whose properties will not diminish during that service. Replaceable components may have a lesser design life, reflecting the ease with which the component can be maintained, without impacting on the safe operation of the pipeline.

4.5.4 Maximum allowable operating pressure (MAOP)

The MAOP of a new pipeline shall be determined after the pipeline has been constructed and tested in accordance with this Standard. The MAOP shall be approved before the pipeline is placed in operation.

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


DR04561.doc

(a) The design pressure (PD)

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

F =

TPE

ML

PP 4.5.4.1

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

=

DP

WTPTPE t

tFF ..................................................................................................... 4.5.4.2

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

In T1 and T2 locations, the MAOP shall be no greater than the pressure that, in combination with the maximum credible hole size determined through the risk assessment, will result in a discharge rate equal to the maximum allowable discharge rate determined in accordance with the isolation plan.

Where the measured hydrostatic test pressure is to be used to confirm a pressure limit, the engineering design shall be critically reviewed to determine that all aspects of the design components are suitable for the pressure limit to be confirmed prior to the hydrostatic pressure test being carried out.

The MAOP of a pipeline is conditional on the integrity of the pipeline established by hydrostatic testing being maintained and on the design assumptions used to derive the design pressure.

Where the Licensee determines that the operating conditions or integrity have changed from those for which the pipeline was approved, the MAOP shall be reviewed in accordance with AS 2885.3.

4.5.5 Minimum strength test pressure

The minimum strength test pressure (PTMIN) of the pipeline system shall be calculated from the following formula:

TPEDTMIN FPP = ......................................................................................................... 4.5.5.1

Where the pipeline contains short lengths of increased strength or increased thickness pipe, the equivalent test pressure factor shall be calculated for the properties of the predominant pipe in the test section.

Where the pipeline test section includes a short or isolated section of T1 or S location class in an area that is predominantly R1 or R2 location class, the designer shall consider benefit of any additional safety to these locations that would be conferred by subjecting them to a separate strength test using an equivalent test pressure factor calculated in accordance with equation 4.5.4.2.

4.6 ISOLATION

4.6.1 General

Equipment shall be provided within a pipeline or pipeline system for the isolation of segments of the pipeline or pipeline system for maintenance purposes and for the isolation of segments of the pipeline or pipeline system in the event of a loss of containment within the segment.


DR04561.doc

Equipment shall be provided to isolate a pipeline or segment of a pipeline from pressure sources which could provide pressure higher than the MAOP of the pipeline or segment.

Equipment shall be provided for evacuation of the fluid from a pipeline where required for maintenance and for repairs after a loss of containment.

This isolation and depressurisation equipment shall be defined in an Isolation Plan.

The Isolation Plan shall be approved prior to the pipeline or segment of the pipeline being placed in service.

4.6.2 Isolation plan

The Isolation Plan shall define functions and loss of containment events for which isolation and pipeline depressurisation are required. The loss of containment events considered shall include: (a) In Location Classes T1 and T2, an unplanned loss of containment with ignition.

(b) For liquid pipelines, the environmental consequence of the loss of containment.

The Isolation Plan shall define the facilities provided to perform the functions required and shall consider at least the following items:

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

(b) The mainline pipework segments to be isolated, including the isolation valve locations and controls;

(c) The pipeline assemblies to be isolated from mainline pipework, including isolation valves and controls;

(d) The stations to be isolated from mainline pipework, including isolation valves and controls;

(e) The segments of the pipeline for which depressurising facilities are required, including length, stored gas volume, depressurisation time, and plan for depressurising each section;

(f) The isolation requirements for operation and maintenance of separable segments within pipeline assemblies and stations;

(g) The response time to effect isolation of mainline pipework, pipeline assembly and station segments in all location classes in the event of a loss of containment;

(h) For branches from the main pipeline, the consequence of a loss of containment in the branch on the supply to other locations along the main pipeline;

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

(j) A plan for isolating and de-pressuring stations.

4.6.3 Changes in Operating Conditions

The Isolation Plan shall be reviewed whenever: (a) The Location Class of a pipeline segment or system changes

(b) The MAOP of a pipeline segment or system changes

(c) The fluid carried by a pipeline changes from that for which it was designed


DR04561.doc

(d) Modifications are made to a pipeline which affect the Isolation Plan or require new isolation facilities

(e) At intervals not less than five years

4.6.4 Isolation valves Valves shall be provided to isolate the pipeline in segments for maintenance, operation, repair and for the protection of the environment and the public in the event of loss of pipeline integrity. The position and the spacing of valves shall be approved.

The location of valves shall be determined for each pipeline. An assessment shall be carried out and the following factors shall be considered:

(a) The fluid.

(b) The security of supply required.

(c) The response time to events.

(d) The access to isolation points.

(e) The ability to detect events which might require isolation.

(f) The consequences of fluid release.

(g) The volume between isolation points.

(h) The pressure.

(i) Operating and maintenance procedures.

Table 4.7.4.1 gives guidance for the spacing of mainline valves.

TABLE 4.7.4.1

GUIDE FOR THE SPACING OF MAINLINE VALVES

Location class Recommended maximum spacing of valves, km

Gas and HPVL Liquid petroleum

R1 As required As required

R2 30 As required

T1 and T2 15 15

Liquid hydrocarbon pipelines that cross a river or are located within a public water supply reserve shall be provided with isolation valves as follows:

(i) On an upstream section ................................................................... a mainline valve.

(ii) On a downstream section................................. a mainline valve or a non-return valve.

Valves shall be installed so that, in the event of a leak, the valves can be expeditiously operated. Non-return valves may be necessary.

Consideration shall be given to providing for remote operation of individual mainline valves to limit the effect of any leak that may affect public safety and the environment. Where such a facility is provided, the individual mainline valves shall be equipped with a closing mechanism that can be reliably activated from a control centre.

4.7 SPECIAL PROVISIONS FOR HIGH CONSEQUENCE AREAS 4.7.1 General Locations may exist along a pipeline route where special provisions are necessary to limit the consequence of pipeline failure on the community or the environment. For gas


DR04561.doc

pipelines, the consequence is likely to result from ignition of the fluid released, while for oil pipelines the environmental consequence may be dominant.

This Section defines the minimum requirements for compliance with this Standard in these locations.

4.7.2 No Rupture

In Residential (T1), Industrial (I), High Density (T2) and Special (S) location classes the pipeline shall be designed such that rupture is not a credible failure mode. For the purpose of this Standard, this shall be achieved by either:

(a) The hoop stress shall not exceed 30% of SMYS or;

(b) The largest equivalent defect length produced by the threats identified in that location shall be determined. The hoop stress at MAOP shall be selected such that the critical defect length is not less than 150% of the axial length of the largest equivalent defect. The analysis shall consider through wall and part through wall defects. Where the identified threat is an excavator, Table 5.5.2.1(B) nominates the minimum through wall defect by machine mass that shall be used in this analysis.

NOTES: 1 Section 4.9.4 defines the method to be used in calculating the critical defect length. 2 API 579 and BS 7910 provide methods for converting actual defects into the equivalent

through wall flaw.

4.7.3Maximum Discharge Rate

In all locations, consideration shall be given to providing means of limiting the maximum discharge rate through a pipeline segment in the event of a loss of containment in that segment.

In high consequence locations where loss of containment can result in jet fires or vapour cloud fires the maximum allowable discharge rate shall be determined and shall be approved.

For pipelines carrying flammable gases, HVPLs and other liquids with a flash point less than 20°C, the maximum allowable discharge rate shall not exceed 10 GJ.s-1 in Residential, Industrial and Sensitive locations or 1 GJ.s-1 in High Density locations.

NOTE:Clause 4.10 provides guidance on the methods for calculating energy release rate.

For pipelines carrying other combustible fluids, the maximum allowable discharge rate shall be determined by the risk assessment in accordance with this Standard.

NOTE: Operating pressure limit and flow restriction devices are two effective methods of limiting the maximum discharge rate. Designs that limit the maximum hole size may also be used to effectively control the maximum discharge rate.

4.7.4 Change of Location Class

Where land use planning changes along the route of existing pipelines to permit Residential, High Rise, Industrial, Heavy Industry and Sensitive development in areas where these uses were previously prohibited, a safety assessment shall be undertaken and measures implemented that will reduce the risk from a loss of containment involving rupture to ALARP.

This assessment shall include analysis of the alternatives of MAOP reduction (to a level where rupture is non-credible), pipe replacement, pipeline relocation and land planning modification and constraints. The assessment shall demonstrate that the chosen solution achieves the objectives of ALARP.


DR04561.doc

4.8 FRACTURE CONTROL

4.8.1 General

Except where the design of a pipeline provides for the carriage of a stable liquid where the minimum design pipe temperature, is above 0°C, the engineering design of the pipeline shall include preparation of a fracture control plan, which shall define the measures to be implemented to limit propagation of fast fracture.

NOTE: The following two fast fracture modes are known to occur in pipelines: (i) A brittle fracture in which the fracture propagates in the predominantly cleavage

mode at or below the transition temperature of the pipe steel. The appearance of the fracture surface is crystalline.

(ii) A tearing fracture (commonly called ductile fracture) in which the fracture propagates in the shear mode above the transition temperature. The appearance of the fracture surface is fibrous.

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

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

The fracture control plan shall be approved.

Gas and l iquid petroleum f luidsl iquidsStable

i.e. other gasesOther f luids

gas

and l iquids

naturalLean

FIGURE 4.8.1 CLASSIFICATION OF PIPELINE FLUIDS FOR THE FRACTURE CONTROL PLAN

NOTES: 1. Appendix F provides guidance upon the development of the fracture control plan. 2. Stable liquids have no significant vapour phase at atmospheric pressure, e.g. distillate or processed crude (not wellhead products). 3. Lean natural gas consists almost entirely of methane. For the purpose of this classification it may contain up to 5% ethane. However, it shall contain less than 1% total of higher hydrocarbons. 4. Other gases and liquids include all other fluids such as, but not restricted to, wellhead products, LPG, HVPL, rich natural gas, multiphase fluids and CO2.


DR04561.doc

4.8.2 Fracture control plan

The fracture control plan shall define

(a) The stresses and pipe temperatures for which arrest of fracture is to be achieved;

(b) The design fracture arrest length (expressed as the number of pipe lengths each side of the point of initiation); and

(c) The methods of providing for crack arrest.

(d) For all HVPL pipelines and for all natural gas pipelines greater than DN300 in T1, T2, I and S Class Locations, the Fracture Control Plan shall define the method for ensuring that the weld seam (weld metal and HAZ) has adequate levels of fracture toughness to minimise the risk of fracture initiation.

NOTE: Because higher levels of toughness are required to arrest propagating fractures than are required to avoid the initiation of a fracture, the specification of sufficient toughness to control fast fracture propagation will always ensure that the pipe body will be sufficiently tough so that initiation is flow stress controlled rather than toughness dependent.

The design fracture arrest length in each Location Class shall not exceed the values in Table 4.8.2.1

TABLE 4.8.2.1 FRACTURE ARREST LENGTHS

Location Class Arrest Length

R1 2 pipes unless otherwise justified in the fracture control plan

R2 2 Pipes

All others Arrest within the initiating pipe

The following information is required as part of the design and risk assessment and should be included as part of the fracture control plan:

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

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

(c) For all pipelines in T1, T2, I and S Class Locations, the method for ensuring:

(i) Rupture is not a credible failure mode in accordance with Clause 4.7.2.

(ii) The maximum energy release rate is controlled to the limit defined in Clause 4.7.3.

The stress, temperature and fracture arrest length parameters do not need to be uniform over the whole pipeline and may differ for each location class or for each relevant fracture mode.

The fracture control plan shall be approved.

The sequence of decision making required to develop and implement a fracture control plan to ensure arrest of fast fracture shall be in accordance with Figure 4.8.2.

Where this standard is used for pipelines constructed from Corrosion Resistant Alloy pipe, the fracture control plan shall be developed with a full understanding of the fracture behaviour of the pipe material.

NOTE: Appendix F does not deal with materials other than Carbon-Manganese steels and expert advice is recommended.


DR04561.doc

Fracturecontrol

control of br i t t lefracture

yes

yes

yes

stablel iquid

control of tear ingfracture

MAOP 40%SMYS

use Battel le shor tform equation

use Battel le two curvemodel & fudge factor

1.4 i f X80

T1 or T2

no rupture &control of energy

release rate

yes

yes

yes

yes

yes

DN 200 yes

br i t t le and tear ingfracture arecontrol led

Stablel iquid

Td 0˚C

Designstress

85MPa

FRACTURECONTROLPLAN NOTREQUIRED

t 5 mm or DN 300

DWTT FATT shallbe Td

DN 300

Lean gasMAOP 15.3 MPa

grade X70

DOCUMENTEDFRACTURE

CONTROL PLAN

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

FIGURE 4.8.2 FRACTURE CONTROL PLAN DECISION TREE


DR04561.doc

4.8.3 Specification of toughness properties for brittle fracture control

(a) Brittle fracture resistance

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

(b) Brittle fracture test temperature

The test temperature for brittle fracture control shall be the lowest temperature at which the pipe stress exceeds the threshold stress for brittle fracture (see Appendix G, Paragraph G2.4.2). The temperature should consider both operating and transient conditions, including any temperature and pressure limits established by in the Isolation Plan for pipeline depressurisation and repressurisation.

Appendix F contains detailed methods for conducting tests to determine fracture appearance and for evaluation of results.

4.8.4 Specification of toughness properties for tearing fracture control

4.8.4.1 Specification of fracture toughness properties for pipe body materials

Where the fracture control plan determines that it is necessary to specify pipe body fracture toughness, the following applies:

(a) Tearing Fracture Resistance

The resistance to tearing fracture propagation (ductile fracture) shall be determined from measurements of the transverse energy absorption of Charpy test specimens representative of the pipe body material in the line of the pipe axis. Test specimens may be taken from finished pipe or, after correlation has confirmed any effect of pipe making, may be taken from the strip or plate from which the pipes are made.

Appendix F contains detailed methods for conducting tests to determine energy absorption of pipe body materials and for evaluation of results.

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

(i) The design arrest length;

(ii) The pipe diameter and steel grade;

(iii) The wall thickness (tW) minus the thickness of vanishing allowances (for example, corrosion allowance).

(b) Calculation of tearing fracture arrest toughness

The tearing fracture arrest toughness Charpy energy requirements may be calculated using Equation 4.8.4.1.1 provided the following conditions are met:

(i) The design fluid is lean natural gas consisting almost entirely of methane.

(ii) The MAOP does not exceed 15.3 MPa.

(iii) The pipe grade does not exceed X70. 31

31

2510 )()(10*836.2 tDC Ha σ−= ............................................................................. 4.8.4.1.1 NOTES: 1 Equation 4.8.4.1 is derived from the Battelle short form formula for a 2/3 size specimen by

multiplying the formula by 3/2.


DR04561.doc

2 This equation is one of a number of similar relationships which correlate full scale arrest/propagate behaviour with small scale laboratory Charpy tests. The majority of the test results in the data base supporting the equation have been obtained upon relatively large diameter pipelines around DN750 and above, with gas pressures below 12 MPa, and strength levels of X70 and below. This is the reason for the design limits given above and in Figure 4.8.2 for the application of this equation.

Where the design does not meet all of the above conditions the arrest toughness shall be calculated using the Battelle Two Curve model with the decompression characteristics of the design gas at the most severe combination of composition and temperature, computed from MAOP.

Where the steel grade is X80, the specified toughness shall be at least the calculated toughness multiplied by 1.40.

For pipelines in which the calculated arrest toughness Ca10 exceeds 100J, the method of achieving arrest within the design length shall be the subject of an independent expert verification. Such verification shall be included in the Fracture Control Plan at the stage it is submitted for approval. NOTE: The technology of fracture control in pipelines is complex and needs to be empirically validated. Attention is directed to the absence of a experimental database supporting the fracture control design of small diameter, high-strength pipelines.

Some rich gas compositions require higher arrest toughness at temperatures higher than the design minimum temperature. Where the arrest toughness is determined using the Battelle Two Curve method, decompression characteristics shall be determined at the MAOP and the range of temperatures over which the pipeline is designed to operate.

(c) The tearing fracture test temperature shall be determined on the basis of: (i) For a transmission pipeline, the minimum steady state operating temperature of

the pipeline (normally minimum ground temperature at pipe depth) rounded down to the nearest 5°C.

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

NOTES: 1 The minimum temperatures normally occur after the winter diurnal lag. 2 Transient events such as repressurisation of a pipeline section may involve temperatures

lower than these minimum temperatures. Because the pressure in the pipeline at the time that the low temperature exists is low, the risk of fracture initiation and propagation of a brittle fracture must be controlled, rather than ductile tearing fracture. Control during activities of this type should be achieved by maintaining the pressure so that the hoop stress does not exceed the threshold stress at any time that the temperature is lower than the fracture initiation transition temperature (see 4.8.3).

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

(e) The arrest length specified in Table 4.8.2.1 is determined from a statistical assessment of the toughness distribution normally delivered in a project pipe order (the toughness distribution by heat).

(i) Where the number of heats in the order is small and in location classes other than R1 or R2, the minimum toughness for any heat in the pipe order shall be the specified arrest toughness.

(ii) Where the number of heats in the order exceeds XX and the pipe is to be installed in Location Classes R1 or R2 the all heat average toughness may be


DR04561.doc

specified as the specified arrest toughness. The minimum toughness for any heat may be specified as the specified arrest toughness multiplied by the statistical factor SF of 0.75.

(iii) Where the number of heats in a pipe order is less than XX, or where an analysis of the arrest requirements in Location Class R1 determines that arrest in more than 2 pipes is acceptable, the statistical factor SF shall be determined from either analysis of historic or actual toughness distributions, and the probability that a sufficient number of randomly distributed arrest pipes will exist in the constructed pipeline for fast tearing fracture to be arrested within the required number of pipes.

NOTE: For smaller diameter pipes the specified arrest toughness can usually be delivered by the pipe manufacturer for all heats without cost or technical penalty. Consequently it is expected that it is unlikely to be necessary to apply the statistical factor except for large diameter thin wall pipe, and for some rich gases, where the arrest toughness is unusually high.

4.8.4.2 Specification of fracture toughness properties for pipe weld seam materials

Where the fracture control plan determines that it is necessary to specify pipe weld seam fracture toughness, the following shall apply:

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

(b) Fracture initiation resistance. The resistance to fracture initiation shall be determined from Charpy tests conducted on the weld seam in accordance with AS1544.2 or equivalent. SAW pipe shall have tests conducted upon the weld metal and HAZ. ERW pipe shall have tests conducted upon the centre of the weld seam.

The requirements for Charpy energy for initiation shall be determined in the fracture control plan using a recognised method.

NOTES: 1 The results of Charpy tests upon ERW weld seams are likely to be highly variable, and are

very sensitive to notch locations. Great care and skill is necessary in the achievement of proper notch locations. The notch should be located within 0.1 mm of the weld centreline.

2 The method developed by Battelle in research sponsored by the American Gas Association is an acceptable method.

4.8.5 Critical Defect Length

When the axial length of a defect in the pipe wall exceeds a limiting value the defect will grow, and the pipe will rupture.

For high toughness steels, the critical defect length (CDL) can be calculated from:

T

flowH M

σσ = .............................................................................................................. 4.8.5.1

5.0

22

42

2

0135.0

2

255.11

−+=

WW

T

tDc

tDcM .......................................................... 4.8.5.2

cCDL 2= ............................................................................................................... 4.8.5.3

Equation 4.8.5.1 applies to the limiting condition of flow stress or plastic instability, recognising that increasing the steel toughness beyond a certain value will not increase the size of a limiting defect. The CDL determined from equations 4.8.5.4 and 4.8.5.5 is the


DR04561.doc

same as that determined from equation 4.8.5.1 at toughness values typically required for arrest of tearing fracture in accordance with Clause 4.8.4.

( )

=

flow

HTflowC

McK

σσπ

πσ

2sec.ln

8 22 ......................................................................... 4.8.5.4

KC can be estimated from the Charpy V Notch test toughness according to:

C

VC

AC

EK

=2

.............................................................................................................. 4.8.5.5

For design and risk assessment, the CDL shall be defined for σH at MAOP.

The above equations apply to through wall defects only. There is a family of curves that can be developed for part through wall defects predicted from the failure stress of rectangular flaws, using equation 4.8.5.6.

−

−=

TW

W

W

W

flowH

Mtdtd

1

1σσ ............................................................................................. 4.8.5.6

References:

Maxey W A Fracture initiation control concepts Proc 6th Symposium on Line Pipe Research, AGA, Houston 1979

Piper J, Morrison R and Fletcher L The integrity of ERW welds in high strength line pipe WTIA/APIA Panel 7 Research Seminar Welding high strength thin-walled pipelines WTIA, Wollongong 1995

Piper J and Morrison R The international database of full-scale fracture tests and its applicability to current Australian pipeline designs WTIA/APIA International Seminar Fracture Control in Gas Pipelines Sydney, 1997

4.9 LOW TEMPERATURE EXCURSIONS

4.9.1 General

A pipeline shall not be operated at combinations of high stress and low temperature that fall outside limits set in the design. These limits and their basis shall be documented in the design basis.

Low temperature conditions are associated with unusual operations, particularly in gas pipelines including:

(a) Commissioning

(b) Depressurisation

(c) Purging prior to repressurisation

(d) Repressurisation

(e) Throttling through a valve designed for the purpose to temporarily reduce the pressure in a downstream pipe (required, for example, for a pipe that has experienced damage)

(f) Throttling through a valve designed for the purpose to release off specification gas

The design shall consider each operating condition that has the potential to cause temperatures lower than the minimum design temperature of the pipeline, or its


DR04561.doc

components. The design shall document the controls incorporated in the design, and any operational procedures required to comply with the high stress-low temperature limits.

Unless the properties of the materials incorporated in the design support the use of an alternative limit the design and operating procedures shall control the pipeline so that the hoop stress in any component does not exceed 85MPa at any time that the temperature of the pipe wall is lower than -29°C. (See Appendix G, Clause G4.2).

The temperature limit for continuous operation at a hoop stress in excess of 85 MPa shall be established and documented.

Appendix I provide additional information on low temperature excursions, particularly during the repressurisation operation.

NOTES: 1 These requirements apply to all components loaded by pressure 2 Flange bolts are always stressed to levels higher than 85MPa 3 Since line pipe is usually the most highly stressed pressure containing component exposed to

low temperature excursions, consideration should be given to establishing the transition temperature of line pipe intended for operation at low ambient temperatures and pressures higher than 10.2 MPa.

4.10 ENERGY DISCHARGE RATE

Where this Standard requires the energy release rate to be determined (Clause 4.8) or the radiation contour (Clause 2.2.4.1 and Clause 4.5) shall be established by calculation of the quasi-steady state volumetric (or energy) flow 30 seconds after the initiating event, determined by a suitable unsteady state hydraulic analysis model, and the relevant equivalent hole size.

The radiation contour shall be calculated using the method described in API RP 521 for an energy contour of 12.6 kW/m2 and 4.7 kW/m2.

This calculation methodology is known to be conservative, but is considered appropriate for the uses required by this Standard.

Radiation contours for various pipe sizes and typical gases are provided in HB105. NOTES: 1 For gas pipelines with a MAOP of 10.2 MPa the radiation contour in metres is numerically

equal to the pipeline diameter in millimetres. 2 For pipelines transporting hydrocarbon liquids the total volume of the release should be

considered. 3 For pipelines transporting HVPLs the sustained energy release rate resulting from

vapourisation of the liquid phase should be considered.

4.11 RESISTANCE TO PENETRATION

The resistance to penetration of a pipe from excavator threats shall be calculated using the following:

+++=

14.3)4.22)(410(701.0

WWLtR UWP σ ............................................................. 4.11.1

The value of RP for a tooth consisting of two points of equal dimensions, the value of RP calculated for a single point shall be multiplied by 2. NOTE: The value of RP may reduce as the tooth dimensions at the point of contact changes with wear.

2)(045.047.7 OPBucket WF −= ....................................................................................... 4.11.2


DR04561.doc

BucketMAX FF 2= .......................................................................................................... 4.11.3

Where L and W are selected from Table 4.11.1 represent the smaller tooth dimensions typically used on excavators of various sizes, and are adopted by this Standard together with equation 4.11.3 to ensure a consistent analysis across the industry for generalised excavator machinery. Where the penetration resistance of a pipe is greater than FMAX the likelihood of penetration is extremely low.

Where the threat identification enables the physical dimensions of the excavator, and bucket teeth to be determined, these may be used in more accurate calculations, using equation 4.11.4 (see Reference)

ArmBucketMAX FFF 93.02.1 += ..................................................................................... 4.11.4 NOTES: 1 The relationship for FBucket was developed in research undertaken by APIA, and represents an

upper bound relationship. 2 Brookers research includes an analysis of the probability that an identified threat will

penetrate a given pipe. This form of analysis is considered useful, but should be used with caution.

TABLE 4.11.1

Dimensions in mm

General Purpose Tooth Twin Pointed “Tiger” Tooth Single Point Penetration Tooth

Excavator Weight (tonnes)

L at Point

W at Point

Max. L

Hole Dia.

L at Point

W at Point

Max. L

Hole Dia.

L at Point

W at Point

Max. L

Hole Dia.

5 51 4 70 53 6 5 65 54 6 5 65 40

10 56 14 70 58 8 7 70 59 8 7 70 44

15 63 13 82 66 11 9 82 69 11 9 82 52

20 76 13 92 75 13 10 92 77 13 10 92 58

25 89 18 96 82 11 17 96 83 11 17 96 62

30 102 21 110 94 12 20 110 95 12 20 110 71

35 121 23 124 107 14 22 124 107 14 22 124 80

40 127 24 136 116 16 25 136 118 16 25 136 88

55 143 30 140 124 17 25 140 121 17 25 140 91

Failure Analysis shall assess the consequence of puncture accordance with Table 4.11.1. The tooth maximum width (L) shall be assumed as the axial length of the defect, and shall be compared with the critical defect length for the pipe under design conditions.

When L ≥ Critical Defect Length, the failure mode shall be RUPTURE.

Where L < Critical Defect Length, the failure mode shall be LEAK. The hole diameter in Table 4.11.1 shall be adopted as the basis for determining the leakage rate from the defect when assessing the consequence of the failure. For the purpose of this calculation, the hole is considered to be a circular hole with the same circumference as the perimeter of the whole tooth at a penetration equal to 50% of the tooth length.

Other criterion and equations may be used where an analysis shows that they are valid for the threat being considered. Any change in the criterion or equations shall be approved.

Where resistance to penetration is adopted as a physical measure for external interference protection, for threats other than excavators, calculations shall be made using an Approved method, using project specific or published research.


DR04561.doc

NOTES: 1 The tooth dimensions in Table 4.11.1 are based on an analysis of the range of teeth that are

used on excavators of each size group. Generally they represent the dimensions of the smaller teeth supplied for the size group.

2 Alternative dimensions may be used where they are determined in the threat investigation. 3 The dimension of the contact point may change as the point wears with use. 4 The hole diameter in Table 4.11.1 represents a circular hole whose circumference equals the

perimeter of a tooth calculated for penetration to 50% of the tooth length.

Reference: Brooker D; Pipeline Resistance to External Interference Phase III Final Report; CRC for Welded Structures / Australian Pipeline Industry Association Research Project 2003-339.


DR04561.doc

S E C T I O N 5 P I P E L I N E D E S I G N


The design of the pipeline and fabricated assemblies such as isolation valves, scraper stations and branch connections are covered in this Section. Stations, including compressor and pump stations, meter stations and regulator stations are covered in Section 6.

The design requirements shall include, but are not limited to the following:

(a) The wall thickness shall be no less than that required for pressure containment determined from the design pressure and a design factor.

(b) Additional wall thickness may be required to provide protection against damage by external interference and for resistance to other load conditions and failure mechanisms or to provide allowance for loss of wall thickness due to corrosion, erosion or other causes.

(c) The pipeline shall be protected against corrosion and external interference.

(d) The successful pressure testing of the pipeline to accordance with AS 2885.5 to verify that it is leak tight and has the required strength.

(e) A pipeline may be telescoped where the design pressure decreases progressively along the pipeline and a suitable pressure control is provided.

(f) The pipeline should be designed so that its integrity can be monitored by the use of internal testing devices without taking the pipeline out of service.

NOTE: Where a pipeline is constructed from fibreglass material, ISO 14692 Part 3 provides guidance on design procedures for this material.

5.2 DESIGN PRESSURE

5.2.1 Internal pressure

The internal design pressure of any component or section of a pipeline shall be not less than the highest internal pressure to which that component or section will be subjected except during transient conditions.

For all pipelines the internal design pressure shall consider the pressure effect of the head associated with the density of the fluid.

Where the hydraulic gradient is used as the basis of establishing the internal design pressure at any location the method of detecting and controlling the internal pressure at any location within the design limit shall be documented in the Design Basis.

NOTE: Refer to Clause 8.1.1.3(A) for control system requirements.

5.2.2 External pressure

Pressures from external loads and hydrostatic pressures shall be considered in the pipeline design including the following:

(a) Soil load

Where pipe is buried with a depth of cover of more than 3 m, stresses in the pipe caused by soil loads shall be determined and combined with stresses due to other loads. Where pipe is buried with a depth of cover of not more than 3 m, stresses in the pipe caused by soil loads may be ignored.

(b) Hydrostatic pressure

The pipeline shall be designed to accommodate the external hydrostatic pressure.


DR04561.doc

5.3 DESIGN TEMPERATURES

The following conditions shall be considered and, where appropriate, a design temperature selected for that aspect of the pipeline:

(a) Fracture control.

(b) Material strength.

(c) Coating performance.

(d) Stress Corrosion cracking.

(e) Fluid/phase changes.

(f) Temperature excursions during Depressurisation, Repressurisation and Commissioning activities

(g) Temperature excursions associated with operating conditions, (eg temporary pressure reduction by throttling using a MLV bypass valve)

Where a pipeline is buried, fluid and ground temperatures are the most important. Consideration of ambient temperature is required for a pipeline wholly or partially aboveground, and during construction and maintenance.

Consideration shall be given to the effect of temperature differential during installation, operation and maintenance, and where appropriate, the temperature differential shall be specified.

Where a pipeline is aboveground, the temperature resulting from the combined effect of ambient temperature and solar radiation shall be specified for both operating and shut-in conditions

Special consideration may be required where the temperature of the fluid is changed by pressure reduction, compression or phase change.

Design temperatures shall be approved.

5.4 WALL THICKNESS

5.4.1 Minimum Wall Thickness

The minimum wall thickness at any location along the pipeline shall be the greater of:

(a) The sum of the thickness required for pressure containment and allowances.

(b) The thickness required for resistance to penetration by the design threat, if this is used as a method of providing external interference protection in accordance with Clause 5.5.2.1. In T1 and T2 location classes, where thickness is the method chosen to provide penetration resistance, the thickness necessary to provide a minimum level of penetration resistance.

(c) The thickness required to provide the minimum critical defect length needed to prevent rupture in Location Classes T1 and T2, or elsewhere if required by the Design Basis.

(d) The thickness required to satisfy the stress and strain criteria.

(e) The thickness required to control fast running fracture.

(f) The thickness required for special construction.

(g) The thickness required for constructability and maintainability of the pipeline, including provision for future hot tapping, where required.


DR04561.doc

(h) The thickness required to achieve a design stress level selected for its contribution to SCC mitigation at locations where the SCC risk is increased by operation at temperatures above 45°C, and at locations subject to high operating pressure range.

(i) The thickness required to achieve adequate fatigue life where this is determined to be a consideration in the operating life of the pipeline

(j) The thickness required to prevent collapse from external pressure.

5.4.2 Wall thickness for design internal pressure

The wall thickness (tW) for design internal pressure of pipes and pressure-containing components made from pipe shall be the thickness required for pressure containment (tDP) plus the thickness provided for allowances (G) determined by the following equations:

Gtt DPW += ........................................................................................................... 5.4.3.1

NOTE: It can be shown by stress analysis that the lowest stress in a bend is on the outside of the bend. A reduction in wall thickness on the outside of the bend up to the limits permitted in the material standards for induction bends (up to 10%) will not reduce the pressure strength of the bend.

The design factor (FD) for pressure design of pipe shall be not more than 0.80, except for the following for which the design factor shall be not more than the values nominated in Table 5.4.2.1:

TABLE 5.4.2.1

MAXIMUM VALUE OF DESIGN FACTOR

Location Maximum value of FD

Pipeline assemblies 0.67

Any section of a telescoped pipeline for which the MAOP is based on a test pressure factor of less than 1.25

0.60

Pipelines on bridges or other structures 0.67

5.4.3 Allowances

Allowances shall be added to the pressure design wall thickness of a pipe or a pressure-containing component made from pipe to provide for identified factors that may during construction, or over the life of the pipeline, reduce the pressure design thickness.

Allowance may be made to compensate for a reduction in thickness due to manufacturing tolerances, corrosion, erosion, threading, machining and any other necessary additions.

The allowance shall comply with the following:

5.4.3.1 Manufacturing tolerance

The manufacturing tolerance for line pipe manufactured from strip or plate to nominated standards such as API 5L shall not be applied to the required thickness calculated using equation 5.4.3.1

NOTE:This manufacturing tolerance relates to local thinning. General wall thickness is controlled by the weight tolerance of the pipe.

The seamless pipe manufacturing process can result in pipe of minimum thickness along one side of the length whilst still complying with the weight tolerance. Pipes manufactured by this process may require a specific manufacturing tolerance determined by the requirements of the nominated standard or the project specification (see Section 3).


DR04561.doc

5.4.3.2 Corrosion or erosion

Where a pipe or a pressure-containing component made from pipe is subject to any corrosion or erosion, G shall include an amount equal to the expected loss of wall thickness.

NOTE:A corrosion allowance is not required where satisfactory corrosion mitigation methods are employed.

5.4.3.3 Threading, grooving and machining

Where a pipe or a pressure-containing component made from pipe is to be threaded, grooved or machined, G shall include an amount equal to the depth that will be removed. Where a tolerance for the depth of cut is not specified, the amount shall be increased by 0.5 mm.

Where a significant allowance is included, consideration should be given to the benefits of appropriately increasing the strength test pressure. This may require the use of stronger fittings.

5.4.4 Wall Thickness Design for External Pressure

The permitted external pressure PEXT shall be determined from the following equation:

05.112 =+

++− °

PELEXTELPEXT PPPPt

DfPP ..................................................... 5.4.4.1

where

Gtt N −= ............................................................................................................... 5.4.4.2

( )3

212

−

=M

EL DtEP

µ............................................................................................. 5.4.4.3

=

MP D

tSMYSP DF2 ............................................................................................. 5.4.4.4

DDDf MINMAX −

=° .................................................................................................. 5.4.4.5

tDDM −= ............................................................................................................. 5.4.4.6

5.5 EXTERNAL INTERFERENCE PROTECTION

5.5.1 General

A pipeline shall be designed with the intent that identified activities of third parties will not cause injury to the public or pipeline personnel, loss of contents which would damage the environment, or disruption of service.

A pipeline shall be designed so that a combination of physical measures and procedural measures are implemented to prevent loss of integrity from external interference by identified threats.

Where the combination of physical measures and procedural measures specified in Table 5.5.4.2 cannot be fulfilled, failure analysis shall be conducted in accordance with Clause 2.3.4.

The purpose of physical measures is to prevent loss of integrity resulting from an identified third party interference event by either physically preventing contact with the pipe, or by providing adequate resistance to penetration in the pipe itself.


DR04561.doc

The purpose of procedural measures is to ensure that no third party activity, with potential to damage a pipeline, occurs without the knowledge of the pipeline operator, and that the people undertaking such activity are aware both of the presence of the pipeline and the possible consequences of damaging it.

A complete package of external interference protection measures also includes safe operating procedures for working near a pipeline and an emergency response plan. These are covered in AS2885.3.

5.5.2 Depth of Cover

Table 5.5.2.1 provides minimum depth of cover for each location classification. The minimum cover requirements may be reduced where other physical protection measures provide effective physical protection to the pipeline.

Additional protection shall be provided where the minimum depth of cover cannot be attained because of an underground structure or other obstruction, or maintained because of the action of nature (e.g. soil erosion, scour).

The depth of cover over a pipeline shall be taken as the distance from the top of the pipeline or casing to the lower side of the finished trench.

Specific requirements are established for road and rail in Clause 5.8.7.

TABLE 5.5.2.1

MINIMUM DEPTH OF COVER

Minimum Depth of Cover Contents Location Class

Normal Excavation Rock Excavation (See Notes 1 to 5)

U, HD, I, HI S, W 1200 900 HVPL (See Note 6)

R1, R2 900 600

S, W 1200 900

U, HD, I, HI 900 600

Other than HVPL

R1, R2 750 450

5.5.3 Depth of Cover —Rock Trench

Figure 5.5.2.1 shall be used in applying the reduced cover provisions of Table 5.5.2.1 in areas classified as continuous rock.

At locations where cover is reduced in rock, normal cover shall continue for a minimum distance of 1200 mm into the rock. The minimum length of continuous rock over which a reduction of the depth of cover for rock may be applied shall be 50 metres.


DR04561.doc

Natural ground elevation

Soil

50,000 Min.

1200 Min.1200 Min.

Rock cover(Table 4.2.5.3)



Normal cover(Table 4.2.5.3)

Normal cover(Table 4.2.5.3)

FIGURE 5.5.2.1 DEPTH OF COVER IN ROCK

NOTES: 1 This Standard defines rock as material with a uniaxial compressive strength greater than 50

MPa. For field assessment, hand held specimens of the weakest material in this classification can be broken by a single blow with a geological hammer. This material requires excavation by special rock excavation equipment, or by blasting. Material satisfying this criteria is defined as Class A Strong Rock in AS 1170 (currently 5212-PDR the earthquake code).

2 To provide effective physical protection, the rock forming the trench walls must be generally vertical, unbroken, and containing few fractures.

3 Good practice requires that the trench design is based on the depth required to provide the minimum cover at the lowest rock elevation. Pipe should be laid with the top of pipe at this elevation until changed by another governing feature, rather than varying the elevation as the rock surface elevation changes.

4 Design measures should ensure that selected material specified to protect the pipeline coating and to ensure continuity of an electrolyte for continuous cathodic protection will not erode with time when protected by a porous crushed rock backfill.

5 Marker tape shall be installed above the pipe over the full extent of rock excavation. 6 HVPL requirements shall apply to dense phase fluids.

5.5.4 Design for protection—General Requirements

The pipeline design shall identify and document the external interference events for which design for pipeline protection is required. Activities which could occur during the design life of the pipeline shall be considered.

NOTE: Appendix B provides guidance on the definition of design cases for protection.

External interference protection is to be achieved by selecting a combination of physical and procedural measures from the methods given in Table 5.5.4.1.

Compliance with the minimum requirements for pressure design wall thickness, depth of cover and marking shall not be considered to constitute design for protection.


DR04561.doc

TABLE 5.5.4.1

EXTERNAL INTERFERENCE PROTECTION MEASURES

Physical Procedural

Measures Methods Measures Methods

Separation Burial

Exclusion Barrier

Pipeline awareness

Landowner and third party liaison

One-call service

Marking

Resistance to penetration Wall thickness Barrier to penetration

External interference detection

Planning notification zones

Patrolling

Remote intrusion monitoring

Each of the methods given in Table 5.5.4.1 are considered separate independent protection measures and each can be used in conjunction with any other method in Table 5.5.4.1 to achieve compliance with the requirements of this Clause.

The minimum number of physical and procedural measures adopted shall comply with Table 5.5.4.2.

TABLE 5.5.4.2

MINIMUM NUMBER OF PROTECTION MEASURES

Classification of location

Physical measures (see Notes 1 and 2)

Procedural measures

R1 1 2

R2 1 2

T1 2 2

T2 2 2

CIC As Required 3 (Note 3)

NOTES:

1 The number of physical measures in locations Class T1 and T2 may be reduced to 1 where the designed physical measure is determined to provide absolute protection from the design event in the location. Note is not mandatory is clarify this

2 Physical measures for protection against high powered boring equipment shall not be considered absolute.

3 In CIC locations, formal procedures should be developed with other users of the CIC to control the activities of each user

5.5.5 Physical protection measures

Physical protection measures shall be selected from the following:

(a) Separation

Protection of the pipeline may be achieved by separation of the pipeline from the activities of third parties. Methods of separation include the following:

(i) Separation by burial

Burial is a protective method which separates the pipeline from most activities of third parties. Burial may be counted for compliance with Table 5.5.4.2 when the depth of burial is considered to preclude damage to the pipeline by the defined third party events relevant to the location.


DR04561.doc

Burial is not required where

(A) The pipeline is on land under the direct control of the pipeline licensee; or

(B) When approved, in Location Class R1 for pipelines carrying liquids where an approved investigation determines that the risks of external interference do not require burial. Pipelines carrying compressed gases, HVPLs or multiphase or dense phase fluids are excluded from this exemption.

For the purposes of this Clause, the depth of cover shall be taken as the distance from the top of the pipeline or casing to the finished construction measured at the lower side of the trench.

Specific requirements are established for road and rail in Clause 5.8.7.

Table 5.5.2.1 provides minimum depth of cover for each location classification where burial is used as a protective measure. The minimum cover requirements may be reduced where other physical protection measures provide effective physical protection to the pipeline.

(ii) Separation by exclusion

Exclusion is a physical protection measure intended to exclude external interference from access to the pipeline. Fencing is an example of exclusion. Exclusion is considered to meet the requirements of Table 5.5.4.2 where access to pipeline facilities is controlled by the pipeline licensee.

(iii) Separation by barriers

Barriers are a physical protection measure against certain types of external interference events, particularly those involving vehicles and mobile plant. Crash barriers on bridges carrying pipelines are an example of separation by barriers.

(b) Resistance to penetration

Resistance to penetration is a physical measure for protection if the resistance to penetration is sufficient to make penetration improbable. NOTE: For fibreglass pipe resistance to penetration is not considered to be an effective control for most pipe that would be considered cost effective as an alternative to steel.

Resistance to penetration may be achieved by the following:

(i) Wall thickness

The required wall thickness to resist penetration by the defined interference activities may be determined experimentally or from experience.

Wall thickness may be counted for compliance with Table 5.5.4.2 where the nominal thickness is greater than the thickness required to prevent penetration, for the design events relevant to the location.

NOTE: Wall thickness for resistance to penetration is not determined directly by stress calculations. An increase in penetration resistance may be achieved by changing the grade of the pipe used, provided the resultant stresses in the pipe comply with Clause 5.4 (Wall thickness).

(ii) Penetration barriers


DR04561.doc

Physical barriers may be used to resist penetration. Where a barrier prevents the design external interference threat (see Clause 5.5.4) from access to the pipeline the barrier may be counted for compliance with Table 5.5.4.2.

Barriers may be one of the following:

(A) Concrete slabs Slabs used to provide protection shall have a minimum width of the nominal diameter plus 600 mm. Slabs shall be placed a minimum of 300 mm above the pipeline.

(B) Concrete encasement Concrete encasement used to provide protection shall provide a minimum thickness of 150 mm on the top and sides of the pipeline.

(C) Concrete coating Concrete coating used to provide protection shall be reinforced and shall have a minimum thickness determined in the protection design.

(D) Other barriers Other physical barriers may be used.

Barriers shall have the mechanical properties necessary to provide the required protection for the design events, and have the electrical, chemical and physical properties necessary to maintain the efficacy of cathodic protection to be applied to the pipeline.

Where the performance of barriers cannot be established by calculation, the performance may be established by testing.

5.5.6 Procedural measures

Procedural measures shall be selected from the following:

(a) Pipeline Awareness Pipeline awareness measures are active or passive measures implemented to inform external parties of the presence of and potential danger from external interference to the pipeline. Pipeline awareness measures include:

(i) Marking Clause 4.4 defines the minimum requirements for marking. Where marking is to be counted as a procedural measure for compliance with Table 5.5.4.2 at any location, one of the following shall also apply:

(ii) Signs Signs shall be installed so they are visible to any party undertaking a design external interference event.

(iii) Buried marker tape Buried marker tape shall be installed so that the design interference event cannot damage the pipeline without first exposing the tape.

The design interference event is of such a nature that it is likely that at least one person involved in the event will see the marker tape immediately it is exposed.

Minimum requirements for buried marker tape are as follows:

(A) Tape shall be located a minimum of 300 mm above the pipeline.

(B) Tape shall be permanently coloured with a high visibility colour.

(C) Tape shall identify the nature of the buried pipeline.

(D) Tape shall have sufficient strength, ductility and slack to prevent it breaking before it becomes visible.

(E) Tape shall have a lifespan not less than the design life.

(iv) Landowner, occupier and public liaison Landowner, occupier and public liaison is an important measure in maintaining the awareness of landowners, authorities and the public of the presence of the pipeline and the limitations on


DR04561.doc

activities in the vicinity of the pipeline. Liaison is considered to contribute to compliance with Table 5.5.4.2 when:

(A) Systematic landowner and public liaison is carried out in accordance with AS2885.3, and

(B) The liaison program includes liaison with the developer, planning authority, or contractor responsible for the design interference event and, in the case of an event on private property, the owner and occupier of the land.

(C) The operator can demonstrate that the target audience has comprehended the information provided.

In developing public liaison programs, landowners and occupiers should be considered separately from public authorities such as shires, utilities, land use planners and contractors because of the different ways that each group can affect a pipeline.

(v) Participation in one-call service A one-call service which allows third parties to obtain accurate information on the location and nature of buried services before undertaking activities in the vicinity of a pipeline is an important measure for preventing unauthorized activities. One-call services are not considered to be as effective in R1 and R2 Locations. Participation in a one-call service is considered to contribute to compliance with the requirements of Table 5.5.4.2 when:.

(A) The location of the design interference event is within the area covered by the one-call service, and

(B) The pipeline operator has systems in place to ensure an accurate and timely response to one-call inquiries, and

(C) The pipeline operator has suitably qualified staff available to provide assistance and advice in cases where work is to be performed near the pipeline.

Where a one-call service is mandated by legislation or regulation, participation in a one-call service is considered to be of greater value and may substitute for one physical measure of protection.

(b) External Intrusion Detection External intrusion detection is a procedural measure which can reduce the occurrence of potentially damaging events. It includes the following:

(i) Patrolling Patrolling is an important measure in protecting the pipeline from external activities and also protecting it from damage caused by natural events such as erosion. Patrolling of the pipeline route is considered to contribute to compliance with Table 5.5.4.2 when:

(A) Systematic patrolling is carried out in accordance with AS2885.3, and

(B) The frequency of patrolling, and the methods of surveillance used, are such that there is a high probability of detecting the design interference event before the pipeline can be damaged

(ii) Planning notification zones Planning notification zones are considered to contribute to compliance with the requirements of Table 5.5.4.2 when:

(A) The design interference event is part of a project that is required by law to be notified to the pipeline operator at the planning stage.


DR04561.doc

(B) The pipeline operator has systems in place to ensure that the progress of the project is monitored regularly following notification.

(c) Remote Intrusion Monitoring Remote intrusion monitoring is considered to contribute to compliance with Table 5.5.4.2 when:

(A) The monitoring system is able to reliably detect the design interference event, and raise an alarm, before the pipeline is damaged, and

(B) The alarm indicates the location of the activity with sufficient accuracy that a person standing at the indicated location can readily see the threatening activity, and

(C) The pipeline operator has systems in place to ensure a patrol is mobilised after an alarm is raised, and can reach the indicated location before damage to the pipeline occurs, and

(D) The incidence of false alarms is low. 5.5.7 Other protection measures

Other measures which are effective in protecting the pipeline or in preventing events which could cause damage to the pipeline, may be approved by the pipeline licensee and counted towards compliance with Table 5.5.4.2.

Note: Additional information on the effectiveness of awareness measures can be found in Appendix D.

5.6 PRE-QUALIFIED PIPELINE SAFETY DESIGN

The pipeline design as set out below shall be deemed to be pre-qualified for AS2885 design to the extent as set out below and under the restrictions set out below.

The pre-qualified design is:

(a) Nominal wall thickness not less than in Table 5.6A.

(b) MAOP for pipe diameter, thickness and Grade not greater than in Tables 5.6A, 5.6B and 5.6C.

(c) Pipe material of API 5L Grade B to X60 inclusive.

(d) Depth of cover not less than 1200mm in T1 and R2 areas.

(e) Hydrostatic strength test pressure at the highest point not less than 1.5 * MAOP / 1.1.

(f) The number of procedural external interference protection measures shall not be less than the minimum number for the location class.

(g) Satisfactory corrosion mitigation measures implemented.

TABLE 5.6A

MINIMUM NOMINAL WALL THICKNESS FOR PREQUALIFIED PIPE

Pipe Nominal Diameter DN (mm) 50 80 100 150 200

For an MAOP not greater than 10.2 MPa and greater than 5.1 MPa

WT (mm) for API 5L Grade B 6.3 7.1 9.0 10.6 11.8

WT (mm) for API 5L X42 to X60 6.3 6.3 8.4 9.4 11.2

For an MAOP not greater than 5.1 MPa

WT (mm) for API 5L Grade B to X60 6.3 6.3 6.3 8.4 8.4


DR04561.doc

TABLE 5.6B

MAXIMUM MAOP OF PREQUALIFIED PIPE FOR API 5L GRADE B FOR SPECIFIC WALL THICKNESSES


Minimum pre-qualified WT (mm) 6.3 6.3 6.3 8.4 8.4

Maximum MAOP MPa 10.2 8.9 6.1 7.4 6.4

Schedule 160 XS XS

Schedule Wall Thicknesses (mm) 8.74 7.62 8.56 11.1 12.5

Maximum MAOP MPa 10.2 10.2 9.7 10.2 10.2

TABLE 5.3C

MAXIMUM MAOP OF PREQUALIFIED PIPE FOR API 5L X42 TO X60 FOR SPECIFIC WALL THICKNESSES


Minimum pre-qualified WT (mm) 6.3 6.3 6.3 8.4 8.4

Maximum MAOP MPa 10.2 10.2 7.4 8.9 7.7

Schedule 160 XS XS

Schedule Wall Thicknesses (mm) 8.74 7.62 8.56 11.1 12.5

Maximum MAOP MPa 10.2 10.2 10.2 10.2 10.2

This pre-qualified design shall be deemed to:

(a) Prevent propagation of rupture.

(b) Satisfy the AS2885.1 requirements for a fracture control plan.

(c) Satisfy the AS2885.1 requirements for resistance to penetration and for an assessment of resistance to penetration.

(d) Satisfy the AS2885.1 requirements for prevention of rupture in T1 class locations and for an assessment of prevention of rupture in those class locations.

(e) Satisfy the AS2885.1 requirements for maximum tolerable energy release rate in T1 class locations and for an assessment of prevention of rupture in those class locations.

(f) Satisfy the AS2885.1 requirements for external interference threat identification and external interference protection design.

(g) Satisfy the AS2885.1 requirements to limit releases in T1 class locations.

(h) Satisfy the AS2885.1 requirements for determination of wall thickness.

The design shall not be pre-qualified if any of the following apply:

(a) The fluid in the pipeline is an HVPL.

(b) The pipe diameter is greater than DN200.

(c) The pipeline length is greater than 10km.

(d) Pipe material is API 5L X65 or higher.

(e) MAOP is greater than 10.2 MPa.

(f) Maximum pipe temperature is greater than 60 deg C.

(g) Minimum pipe temperature is less than 0 deg C.


DR04561.doc

(h) The ratio of the lowest maximum hydrostatic test pressure to the MAOP is less than 1.5/1.1.

(i) It is apparent that there are unusual risks or extremely high risks or unusual complications or extreme complications, other than those normally expected in T1 areas.

The design shall not be pre-qualified in those specific locations where any of the following apply:

(a) There is any threading, grooving or machining of the pipe without a separate analysis including consideration of additional thickness allowances and fatigue analysis.

(b) There are significant stress concentrators on the pipe without a separate analysis including fatigue analysis.

(c) Depth of cover is greater than 3 metres without a separate combined stress analysis.

(d) There is significant external hydrostatic pressure without a separate analysis.

(e) The pipeline route is in a T2 location.

(f) The pipeline crosses fault lines or mining subsidence areas.

Use of this pre-qualified design shall be approved.

Granting of approval for a pre-qualified design shall be deemed to be granting of approval for:

(a) A fracture control plan.

(b) External interference protection threat identification.

(c) External interference protection design.

Unless this pipeline is to be part of a network which has an established procedural program, then such a program shall be established and approved.

The pre-qualified design is suitable for non-corrosive natural gas and for non-corrosive low vapour pressure liquids.

The pre-qualified design may be used for corrosive fluids provided corrosion and required corrosion allowance are assessed and the larger of the assessed corrosion allowance and 1.5mm be added to the minimum wall thicknesses.

The pre-qualified design shall otherwise comply with all other requirements of AS2885. NOTE: For information, the following lists a few of the other requirements of AS2885 with which a pre-qualified design has to comply.

An AS2885.1 Risk Assessment including threat identification for threats that are not external interference threats shall be carried out and approved.

In areas of Special Construction, the requirements of this Standard shall apply.

5.7 STRESS AND STRAIN

5.7.1 General

A pipeline shall be designed so that stresses, strains, deflections and displacements in service from normal and other load types are controlled and are within the limits of this Standard. Stresses, strains, deflections and displacements in service and during construction shall be calculated by a recognized engineering method.

Appendix W provides a definition of stress terms and other terms, formulae and units for the evaluation of stresses in pipelines to be carried out in accordance with this Clause. The use of any other formulae shall be approved.


DR04561.doc

Loads whose magnitude is affected by wall thickness (eg. pipe weight, expansion stresses) shall be calculated using the nominal wall thickness. Stresses shall be calculated using the nominal wall thickness less any allowances for corrosion, erosion, threading, grooving or machining.

5.7.2 Definitions

The following general definitions apply to this section:

(a) Normal Load

Load conditions that shall be considered as normal loads are as follows:

(i) Internal and external pressure

(ii) Transverse external loads, such as those due to soil

(iii) Weight of pipe, attachments and contents

(iv) Thermal expansion and contraction

(v) Imposed displacements, such as those due to movement of anchors, supports and subsidence due to mining, where defined as a design condition

(vi) Local loads, such as contact stresses at supports

(vii) Traffic loads at defined road and rail crossings.

Where the designer identifies a load not listed in Items (i) to (vii) above that might be considered normal for the pipeline being designed, it shall be considered as a normal load for the purpose of this Clause.

(b) Occasional Load Occasional loads are those which are unusual, and which occur with a very low and unpredictable frequency. Occasional loads include wind, flood, earthquake, relief valve discharge, transient pressures in liquid lines and land movement due to other causes, and may also include other loads such as those due to vehicle crossings if they are not expected to occur on a routine basis. NOTE: Stresses due to occasional loads are also referred to as primary stresses but are only present for a small fraction of the time.

(c) Sustained Load A load shall be considered to be sustained where it continues to act undiminished as the pipe undergoes elastic or plastic strain. NOTE: Stresses due to sustained loads are also referred to as primary stresses and are present at all times.

(d) Self-limiting Load

A load is considered to be self-limiting where deformation of the pipe under the influence of the load results in a reduction of the associated stresses. Self-limiting loads include those due to thermal expansion and imposed displacements in unrestrained pipes. NOTE: Stresses due to self-limiting loads are also referred to as secondary stresses.

(e) Restrained Pipe

A pipe is considered to be fully restrained when axial movement is prevented or fully constrained.

(f) Unrestrained Pipe Pipe that is free to undergo axial movement is considered to be unrestrained.


DR04561.doc

5.7.3 Stresses due to normal loads

The following calculation methods and limits shall be adopted, unless otherwise approved:

(a) Internal pressure. Design for internal pressure shall be carried out in accordance with Clause 5.4.2

(b) External pressure. Design for external pressure shall be carried out in accordance with Clause 5.4.4

(c) Transverse external loads

Transverse external loads occur due to the pressure of a soil load, plus the presence of superimposed loads (including impact), such as road and rail vehicles and other miscellaneous sources.

Appendix X provides further guidelines on methods and criteria for assessing the acceptability of external loadings in general.

The following shall apply:

(i) Road and rail crossings Pipeline design at road and rail crossings shall comply with the requirements of Section 4 of API RP 1102 Steel Pipelines Crossing Railroads and Highways. Where API RP 1102 formulae include a design factor the value used shall be 0.72 maximum, except as noted below for informal vehicle crossings. The hoop stress check to clause 4.8.1.1 of API RP 1102 is not required. The design for internal pressure and wall thickness shall be in accordance with Clause 5.4.2 of this Standard. The imposed loads for road crossing design shall be in accordance with the current relevant Australian state and/or national guidelines for vehicle loads, including allowance for dynamic effects. NOTE: Appendix X includes discussion of road vehicle loads.

The imposed loads for railway crossings, shall be determined from the maximum rail loading at the crossing, and shall not be less than the E80 load (356 kN per axle). NOTE: There are two governing 300-A-12 configurations, a 300 kN axle group and a 360 kN single axle case. The worst configuration governs. This standard acknowledges that the E80 loading with its 20 x 8 ft footprint is equivalent to the most severe 300-A-12 loading nominated by AS 4799.

For pipelines with pressure design factor greater than 0.72 the design factor used in this clause may be increased from 0.72 to the pressure design factor at informal vehicle crossings only. An informal crossing consists of any location where there is no defined road or track but a vehicle may nevertheless cross the pipeline on rare occasions (eg. farm paddocks used infrequently by agricultural vehicles).

(ii) Other load sources Where transverse external loads are applied to the pipeline from other sources or in situations that are not within the range of validity of API 1102, the load and/or configuration shall where possible be converted to an equivalent loading that can be analysed using API RP 1102.

Where transverse external loads cannot be converted to an equivalent suitable for API RP 1102, without unreasonable extrapolation, an alternative calculation method shall be used. Alternative calculation methods shall be approved.

(d) Axial/Bending loadsRestrained pipe Stress calculations shall be carried out for axial and bending loads in restrained pipelines as follows:


DR04561.doc

(i) Longitudinal stresses (including effects due to temperature changes, bending and imposed displacements) shall be calculated. The total longitudinal stress σT shall not exceed 72% SMYS.

(ii) A combined equivalent stress shall be calculated by combining the longitudinal stress with the hoop stress by means of either the Tresca or Von Mises theory. The combined equivalent stress σC shall not exceed 90% SMYS. NOTE: The Von Mises theory gives more accurate results. However the Tresca theory is simpler and more conservative. Both theories are permitted in this Standard, but the selected theory should be used consistently thoughout.

(iii) Where restrained lengths of pipeline are not provided with continuous support beneath the pipe the sum of the longitudinal stresses σSUS due to the sustained loads, occurring in normal operation, shall not exceed 0.75 x 72% SMYS.

(e) Axial/Bending loadsUnrestrained pipe Stress calculations shall be carried out for axial and bending loads in unrestrained pipelines as follows: (i) Sustained loads.

The sum of the longitudinal stresses σSUS due to the sustained loads occurring in normal operation shall not exceed 0.75 x 72% SMYS.

(ii) Self-limiting loads.

Stresses in unrestrained pipe due to temperature changes and/or imposed displacements shall be combined for the thermal expansion stress range. The expansion stress range σE shall not exceed 72% SMYS.

The expansion stress range σE represents the variation in stress resulting from variations in temperature and associated imposed displacements only. It is not a total stress.

Calculations of pipe stresses in pipes, loops, bends, and offsets shall be based on the total range of temperature from the minimum to the maximum normally expected (design values), including both installation and operating temperatures, regardless of whether the piping is cold sprung or not. In addition to the thermal expansion of the line itself, the linear and angular movements of the equipment to which it is attached shall also be considered.

The stresses to be calculated are those due to self-limiting loads only, and the contributions of sustained and occasional loads need not be included.

5.7.4 Stresses due to occasional loads The effect of occasional loads in service shall be assessed, and shall be included in the calculation of stresses whenever it is reasonably foreseeable that occasional loads will contribute significantly to the stress state.

Where an occasional load acts in combination with sustained loads, the maximum limit of σo the sum of the longitudinal stresses (in 5.7.3 (d)(iii) or (e)(i)) including the effects of the occasional load, may be increased to 80% SMYS.

Occasional loads from two or more independent origins (such as wind and earthquake) need not be considered as acting simultaneously.

5.7.5 Stresses due to Construction

This Standard does not limit stresses prior to hydrostatic testing. Strains, deflections and displacements shall be controlled so that:


DR04561.doc

(a) Strain does not exceed 0.5% except where strain is displacement controlled, (e.g. cold field bending within an approved procedure, forming of pipe ends for mechanical jointing, weld contraction etc.); and

(b) Diametral deflection does not exceed 5% of diameter.

5.7.6 Hydrostatic pressure testing

Stresses and strains in hydrostatic pressure testing are limited in this Standard by the requirement of AS 2885.5 that all hydrostatic testing which could cause yielding shall be carried out under volume-strain control.

Assessments of stresses, strains, deflections and displacements during hydrostatic pressure testing shall be made taking into account the effects of all other load types acting together with the hydrostatic internal pressure, per AS 2885.5.

5.7.7 Fatigue

Fatigue is generally not considered in most transmission pipeline designs principally because of the number of stress cycles that occur in the pipeline life are typically fewer than required to initiate a fatigue related failure. Appendix J provides guidance on methods used to assess when fatigue should be considered.

5.7.8 Summary of Stress Limits The following table summarises the allowable limits of stress for both restrained and unrestrained pipelines:


DR04561.doc

TABLE 5.7.8

SUMMARY OF STRESS LIMITS

Stress Type Symbol Stress Limit Applicable Pipeline Condition

Clause Reference

Hoop

σH

Fd SMYS All Clause 5.4.2

Circumferential due to external loads

Seff

72% SMYS Buried Clause 4.8.1.3 of API RP 1102

Fatigue due to external loads

∆SL (girth welds)

∆SH (longitudinal welds)

72% SFG (girth welds)

72% SFL (longitudinal welds)

Buried Clause 4.8.2 of API RP 1102

Sustained

σsus

54% SMYS Restrained and Unrestrained

Clause 5.7.3(d)(iii)

Clause 5.7.3(e)(i)

Total Longitudinal

σT

72% SMYS Restrained Clause 5.7.3(d)(i)

Combined Equivalent

σC

90% SMYS Restrained Clause 5.7.3(d)(ii)

Thermal Expansion Stress Range

σE

72% SMYS Unrestrained Clause 5.7.3(e)(ii)

Occasional

σo

80% SMYS All Clause 5.7.4

5.7.9 Plastic strain and limit state design methodologies

It is the intention of Clause 5.7.3 that pipelines designed in accordance with it will not experience plastic strain during operation, other than shakedown of unrestrained pipe when first put into service.

Plastic strain in a pipeline may be accepted under the following conditions:

(a) The pipeline is designed in accordance with a recognised alternative standard based on limit state design principles. The alternative standard shall be thoroughly reviewed to confirm that it is applicable to the circumstances of the pipeline under design. The review shall be documented and the alternative standard shall be approved.

(b) A pipeline exposed to risk of plastic strain as result of unforeseen circumstances such as ground movement. Plastic strain in a pipe that is already in service may be accepted provided that a thorough engineering investigation and risk assessment demonstrates that the strain does not significantly increase the risk of failure. The engineering investigation and risk assessment shall include but not necessarily be limited to consideration of:

(i) The stress-strain properties of the pipe steel (including strain ageing and work hardening)

(ii) The extent of plastic strain

(iii) The likelihood of further or continuing strain

(iv) The likelihood of wrinkling or buckling


DR04561.doc

(v) The likelihood of weld under matching (if longitudinal stress is tensile)

(vi) The possibility of cracks at points of stress concentration.

(vii) The effect of pipe deformation on operation (eg. pigging)

(viii) The accuracy of the information on the cause of the strain

(ix) The sensitivity of the analysis to variations in key parameters

(x) The risks that may arise from alternative methods of dealing with the plastic strain (such as exposing the pipe to release it from soil restraint, or cutting the pipe and consequential stress/strain reversal)

NOTES: 1 Plastic strain here refers to plastic deformation that occurs at stresses above those permitted

by Clause 5.7.3, including stresses above SMYS. 2 Most pipe stress analysis software assumes that the pipe is fully elastic and may not produce

valid models of pipe behaviour if calculated stresses exceed SMYS.

5.8 SPECIAL CONSTRUCTION

5.8.1 Location

Special requirements shall apply where a pipeline is

(a) above ground;

(b) beneath a road (major or minor);

(c) within a reserve for a major road;

(d) beneath a railway;

(e) within a reserve for a railway;

(f) within a tunnel with permanent access; or

(g) beneath a creek, river, stream or artificial waterway.

5.8.2 Above ground pipework

Where a pipeline is installed above ground, the engineering design shall be appropriate to the specific location and shall include provision for at least the following:

(a) Corrosion.

(b) Displacements/Expansion.

(c) Protection.

(d) Security.

(e) Cathodic protection.

(f) Access and egress.

(g) Thermal expansion of fluid.

5.8.3 Tunnels and shafts

Where a pipeline is installed in a tunnel or shaft, the engineering design shall be appropriate to the specific location and shall include provision for at least the following:

(a) Support of the pipeline.

(b) Restraint of the pipeline movement.

(c) Venting of enclosed spaces.

(d) Access for maintenance.


DR04561.doc

(e) Corrosion.

(f) Cathodic protection.

(g) Backfilling.

(h) Hydrostatic testing.

5.8.4 Directionally drilled crossings

Where a pipeline is installed by directional drilling technique, the engineering design shall be appropriate to the specific location, and shall include provision for at least the following:

(a) Protection of the coating.

(b) Cathodic protection.

(c) Hydrostatic testing.

(d) Installation stresses.

(e) geotechnical investigation

(f) subsidence (including mine subsidence)

(g) environmental risk associated with soil failure under the drilling fluid hydrostatic head and the consequential environmental damage.

(h) annulus fill maintenance (for cathodic protection)

(i) Combined stresses. NOTE:Guidelines are available from the Directional Drilling Industry Association and in the report Installation of Pipelines by Horizontal Directional Drilling - Engineering Design Guide PRCI project No. PR-227-9424 and Horizontal Directional Drilling Good Practices Guidelines, HDD Consortium March 2001

5.8.5 Submerged crossings

Submerged crossings include:

(a) Permanent waterways, where the pipe is continuously submerged.

(b) Flood Plains and ephemeral streams, where the pipe is submerged following specific weather events.

(c) High water table areas, where the water table is higher than the top of the pipe for extended periods.

Investigations shall be undertaken to develop design criteria for that crossing, including as applicable:

(a) A hydrological investigation to determine the stream power under peak stream, watercourse or waterway flows. Unless otherwise approved, the 1:100 year discharge event shall be used as the basis for this assessment.

(b) A geotechnical investigation to determine the physical parameters of the crossing, and using information from the hydrological investigation, the erosion potential. This assessment should consider the meander potential of the watercourse so that the limits of special construction can be defined.

(c) The requirements for external interference protection.

(d) The requirements for maintenance of pipe stability.

(e) An assessment of the construction methodology.

(f) An assessment of the environmental management measures required during construction, and during subsequent restoration. Particular attention shall be given to


DR04561.doc

the condition of the stream banks, and methods by which the banks will be restored and stabilised.

(g) An assessment of any specific requirements in relation to corrosion protection (including the presence of low pH ground water in locations of high water table).

(h) In the case of pipelines transporting hydrocarbon liquids, an assessment of the need for pipeline isolation facilities in the vicinity of the crossing.

Using these criteria, engineering designs shall be developed on a generic or location specific basis as applicable. They shall detail the pipe location, wall thickness and material, the methods of stabilising the pipe in the trench, protecting the pipeline from external interference, the presence of adjacent structures and from corrosion. Where applicable, the design drawings shall show the relationship of the pipeline to the natural bottom of the crossing. The engineering designs shall include generic, and where applicable specific methods of restoring the site after completion of construction. The floatation design and safety margin against floatation shall be approved.

Unless otherwise approved, the pipe shall be laid horizontal at the design depth for the full width of the crossing.

The design shall provide specific attention to the location of the pipeline in banks of crossings and to the position of pipelines across the bottom. In particular, the location of over and sag bends shall be designed to accommodate the restoration method proposed at each crossing, and where there is a potential for bank erosion should locate these bends beyond the extent of anticipated erosion.

5.8.6 Pipeline attached to a bridge

Where a pipeline is to be installed on or attached to a bridge, the engineering design shall be appropriate to the specific location and shall include provision for the following:

(a) Installation methods.

(b) Thermal expansion and displacement.

(c) Maintenance.

(d) Corrosion protection.

(e) Cathodic protection/electrical isolation.

(f) Isolation of the pipeline section, if appropriate.

(g) Access to and effect on adjacent services.

(h) Consideration of transfer of loads to the structure.

(i) Prevention of traffic damage.

5.8.7 Road and railway reserves

Where a pipeline is to be installed in a road reserve or railway reserve, the engineering design shall be appropriate to the specific location and shall include provision for the following:

(a) Traffic in the reserve.

(b) Effects on the pipeline from an accident involving traffic.

(c) Effects on the traffic from a puncture, rupture or leak from the pipeline.

(d) Inconvenience to other parties during inspection or repair of the pipeline.

(e) Risk of external damage to the pipeline.

(f) Requirements for corrosion mitigation.


DR04561.doc

(g) Liaison with the authority responsible for the reserve.

(h) Effect on pipeline of maintenance of the reserve.

(i) Fatigue at supports

Details of the requirements in road and railway reserves are shown in Figures 5.8.7(A) or 5.8.7(B), as appropriate.

NOTE: AS 4799 provides additional information on pipelines laid within railway reserves.


DR04561.doc

boundary or fence

Railway reserve-

Railway reserve-

boundary or fence

(b) Pipel ine paral lel to a rai lway

Pipel ine

Offset marker

Railway reserve-

boundary or fence

Pipel ine marker

Covering slab

boundary or fence

Railway reserve-

(a) Uncased and cased pipel ine crossing a rai lway

Pipel ine or casing Covering slab

Pipel ine marker

2000 min.

1200 min.

1000 min.

1200 min.

a

a

300 min.300 min.

2000 min.

b 1000 min.

1200 min.

b

FIGURE 5.8.7(A) COVER OVER A PIPELINE WITHIN A RAILWAY RESERVE


DR04561.doc

boundary or fence

Road reserve-

(b) Pipel ine paral lel to a road

Pipel ine

boundary or fence

Road reserve-

Pipel ine

encasement barr ier

(a) Uncased and cased pipel ine crossing a road

Protective

Pipel ine

Reinforced concrete

boundary or fence

Road reserve-

Pipel ine marker

barrier slab

Road reserve-

Pipel ine marker

boundary or fence

Pipel ine or casing

A C

B B

B

B

1000 mm min.

a

a

D

A

B

FIGURE 5.8.7(B) COVER OVER A PIPELINE WITHIN A ROAD RESERVE


DR04561.doc

5.9 PIPELINES ASSEMBLIES

5.9.1 General

Pipeline assemblies are considered to be integral parts of the pipeline, and shall be designed, fabricated and tested in accordance with this Standard.

Pipeline assemblies are elements of a pipeline assembled from pipe complying with a nominated Standard and pressure rated components complying with a nominated Standard or of an established design and used within the manufacturer's pressure temperature rating. They are intended to take advantage of the properties of formed components and where applicable, high strength materials. This enables the assemblies to be made from materials of compatible thickness and grade to the pipeline, thus avoiding mismatched internal diameter, transition pieces and special welding procedure.

Pipeline assemblies shall be designed, fabricated, inspected and tested in accordance with Section 5, unless otherwise approved.

Welding procedures complying with AS 2885.2 may be used for shop or field fabrication for pipeline assemblies designed in accordance with this standard. Where these assemblies are shop fabricated then suitably qualified procedures complying with another approved standard may be used.

It is not intended to prevent an assembly being designed and fabricated in accordance with another approved standard (such as a pressure vessel standard). When another standard is used, it shall be used in its entirety.

5.9.2 Scraper assemblies

Scraper assemblies, including scraper traps, closures and associated piping, shall be pipeline assemblies. Where a scraper trap within a scraper assembly is not fabricated from pipe complying with a nominated Standard, the trap shall be designed, fabricated, inspected and tested as a special assembly in accordance with Clause 5.9.7. The tested trap shall be treated as a pressure-rated component in the assembly.

5.9.3 Mainline valve assembly

Mainline valve assemblies shall be pipeline assemblies.

5.9.4 Isolating valve assembly

Isolating valve assemblies that are not included in designated stations shall be pipeline assemblies.

5.9.5 Branch connection assembly

Branch connection assemblies that are fabricated from pipe complying with a nominated Standard and pressure-rated components (forged tees, extruded outlets, integrally reinforced fittings, proprietary split tees) shall be pipeline assemblies.

Branch connection assembles that are not fabricated from pipe complying with a nominated Standard and pressure rated components shall be designed, fabricated, inspected and tested in accordance with AS 4041 or AS 1210, and the requirements of Table 5.9.5. The use of any other Standard shall be approved.

Reinforcement shall be provided as required by AS 4041 and the supplementary requirements of Table 5.9.5. Reinforcement may be integral in a forged tee or extruded outlet, or may consist of a pad, saddle, forged branch fitting (weldolet and the like) or member which fully encircles the header.

Integrally reinforced branches of the o-let type shall not be attached to pipelines where the pipe wall thickness is less than 7 mm unless specific design provision is made to properly


DR04561.doc

support the branch to prevent excessive stresses at the branch connection from loads imposed on the branch.

The design shall consider accidental damage, settlement and fatigue. NOTES: 1 The requirement relating to integrally reinforced branches reflects experience of these

connections failing in service by tearing at the toe of the weld. 2 Where a reinforced branch connection is made to an in-service pipeline, AS 1210 may be

used to assess the potential for buckling of the main pipeline by the test pressure.

TABLE 5.9.5

REINFORCEMENT OF WELDED BRANCH CONNECTIONS

d/D σσσσH/σσσσY (see Note 1) < 25% ∃∃∃∃ 25% <50% ∃∃∃∃ 50%

< 20% Reinforcement not mandatory

∃ 20% < 50% Reinforcement not mandatory for branch diameter # 60.3 mm

Reinforcement is required and may be

carried out by any of the methods in Clause 5.9.5

If reinforcement is required, and extends around more than half

of header circumference, full encirclement sleeve

shall be used

∃ 50% Smoothly contoured wrought steel tee of

proven design preferred. If tee not used, full

encirclement reinforcement is

preferred

Smoothly contoured wrought steel tee of

proven design preferred. If tee not

used, full encirclement reinforcement is

mandatory.

=Hσ Hoop stress or circumferential stress, in megapascals.

=Yσ Yield stress, in megapascals.

=d Branch diameter, in millimetres =D Pipeline diameter, in millimetres

NOTE: Design shall consider thin-walled headers and allow for the effects of vibration and external loads.

5.9.6 Attachment of pads, lugs and other welded connections

The welding of pads, lugs and other welded connections shall be carried out in accordance with AS2885.2. The potential for fatigue shall be considered.

Attachment of electrical conductors shall be in accordance with Clause 10.10.

5.9.7 Special fabricated assemblies

Special fabricated assemblies that are fabricated from pipe complying with a nominated Standard and pressure rated components shall be pipeline assemblies.

Where a component in a fabricated assembly is not included in a nominated Standard or is not used within the manufacturers pressure/temperature rating, and for which design equations or procedures are not given in Section 5, the suitability for service shall be evaluated in terms of the pressure strength of the component at the design temperatures.

Satisfactory service experience of special fabricated fittings which are not included in the nominated Standards, and for which design equations or procedures are not given in this Standard, may be used where the design of similarly shaped, proportioned, and sized components has been proven to be satisfactory under comparable service conditions. Interpolation may be made between similarly shaped, proven components with small differences in size or proportion. In the absence of such service experience, the design shall


DR04561.doc

be based on an analysis consistent with the general philosophy of this Standard, and substantiated by one or more of the following:

(a) Proof tests as described in AS 1210.

(b) Experimental stress analysis.

(c) Theoretical calculations.

5.10 JOINTING

5.10.1 General

Joints shall be capable of withstanding the internal pressures and the external forces without leaking.

5.10.2 Welded joints

Welded joints shall either comply with AS 2885.2 or, where of a different type of weld (e.g. friction welding, explosion welding), shall be approved.

5.10.3 Flanged joints

Bolted flanges shall be of an appropriate rating and shall comply with at least one of the following:

(a) A nominated Standard.

(b) AS 1210.

(c) An approved design method.

Bolted flanges should not be used on buried or submerged pipelines. Where such use is unavoidable, each flange shall be listed specifically in the engineering design for inspection and maintenance.

(a) Residual bolt tension in flanged joints

Flanged joints shall be tightened to the residual bolt tension necessary to satisfy the performance requirement of this Clause. Guidelines for determining the torque required to tension bolts in flanged joints are provided in Appendix T.. Permissible values of bolt stress levels shall comply with the following:

(i) The maximum residual bolt stress level in tension shall not exceed 2/3 of the minimum yield stress of the bolt material

(ii) The maximum combined shear stress level during tightening shall not exceed 90% of the shear yield stress of the bolt material

(iii) The maximum tensile stress level during tightening shall not exceed 90% of the minimum yield stress of the bolt material

(iv) The stress level in the bolts of any flange subjected to the pipeline hydrostatic pressure test shall not exceed the minimum yield stress of the bolt material

(v) For operational loads, the predicted bolt tension under all load cases shall not exceed 72% of the minimum yield stress of the bolt material for sustained loads and stress range and to 80% for occasional loads..

(vi) The bolt stress levels from the operating load cases shall individually not exceed the bolt stress level achieved during the hydrostatic pressure test of the flanged joint or of the notional hydrostatic pressure test bolt stress level of the flanged joint where the joint is not physically subjected to the hydrostatic pressure test.


DR04561.doc

For bolt temperatures up to 120 oC no de-rating of allowable stress is required. For bolt temperatures between 120 oC and 200 oC the permitted allowable bolt stress level shall be de-rated in accordance with an approved standard.

NOTES: 1 ANSI B31.3 Appendix Table A-2. Design Stress Values for Bolting Materials. 2 Where flanged joints are subjected to temperatures below the temperature rating of standard

flange and bolting materials, low temperature materials should be considered.

5.10.4 Threaded fittings

Threaded fittings shall be of the taper-to-taper type and aligned without springing of the pipe. Any thread sealant shall be compatible with the fluid.

5.10.5 Other types

Where any other types of joints are proposed to be used, including mechanical interference-fit joints, bells, spigots or proprietary joints are used, the following requirements apply:

(a) The joint shall:

(i) Be the subject of a national or international standard;

(ii) Have a documented history of successful use; and

(iii) Be approved.

or,

(b) The use of other joints is not precluded. However prototypes of these joints shall be subjected to proof tests to determine the safety of the joint under simulated service conditions. The design and use of such joints shall take account of;

(i) The installation process;

(ii) Pressure and structural loads including cyclic conditions, low temperature, thermal expansion or other expected service conditions;

(iii) Where appropriate, provision shall be made to prevent a separation of joints and to prevent longitudinal or lateral movement beyond the limits provided for in the joining member;

(iv) A jointing qualification procedure test shall be performed and documented. The jointing procedure specification shall include a set of essential variables which specify the qualified range of the critical variables beyond which requalification of the procedure shall be required;

(v) the essential variables shall include details of the dimensional tolerances and potential defects in the mating components of the joint;

(vi) The design of the joint and the jointing procedure qualification test shall be approved.

5.11 SUPPORTS AND ANCHORS

5.11.1 General

An anchor, support, or apparatus connected to pipework and piping shall be designed for the service conditions. Supports shall be designed to support the pipe without causing stresses that exceed those determined in accordance with Clause 5.7, or preventing the required freedom of movement. The adverse effects of changes in temperature-induced longitudinal forces that act on bends and offsets shall be reduced by the friction of the soil or by anchoring.


DR04561.doc

Where specified in the design of the cathodic protection system, supports and anchors shall be electrically isolated from the pipe.

5.11.2 Settlement, scour, and erosion

A pipeline shall be adequately supported under all service conditions to counteract the effects of settlement, scour, and erosion.

5.11.3 Design

Supports and anchors shall be designed to suit the service conditions, and be appropriate for the design life.

A clearance adequate for elastic strain during pressure testing and operation shall be maintained between the bore of a concrete anchor and the pipeline.

Supports shall be designed to control cyclic stresses (including vibrations) within the limits established by the fatigue design in accordance with Appendix J.

5.11.4 Forces on an above-ground pipeline

The stresses from forces on the above-ground pipeline shall not exceed those specified in Table 5.7.8.

5.11.5 Attachment of anchors, supports, and clamps

An anchor, support, or clamp shall be attached to a pipeline in such a way as will prevent excessive local stress concentration in the pipe wall. The combined stress shall not be greater than that specified in Table 5.7.8.

Where a pipeline is designed to operate at a hoop stress of less than 50% SMYS, a support or an anchor may be welded directly to the pipe.

Where a pipeline is designed to operate at a hoop stress of greater than 50% SMYS, a support and a clamp shall completely encircle the pipe. Where it is necessary to provide positive attachment, the pipe may be welded only to an encircling member, and the support or clamp shall be attached to the encircling member and not to the pipe. The weld between the encircling member and the pipe shall be continuous.

Supports, anchors and clamps should be designed to ensure that open crevices are not created adjacent to the pipe. On buried pipelines, such crevices may cause shielding of cathodic protection. On above-ground pipe, open crevices allow moisture and contaminants to accumulate.

Each of these conditions may result in accelerated corrosion rates within the crevice. Such corrosion may not be visible externally.

If design creates an open crevice it should also allow easy periodic removal of the support so that the crevice area can be examined for corrosion and repaired as necessary, and the need for removal and inspection highlighted in the pipeline operation and maintenance plan.

5.11.6 Restraint due to soil friction

The adequacy of anchorage by soil friction shall be determined and, where necessary, additional anchorage shall be provided.

5.11.7 Anchorage at a connection

The interconnection of pipelines shall have the strength and flexibility to cater for possible movement, or each pipeline shall be provided with anchors sufficient to develop the forces necessary to limit the movement.

Where a branch connection is made to an existing pipeline and consolidated backfill is removed, firm foundations shall be provided for both the branch and the pipeline. The stresses shall not exceed those determined in accordance with Table 5.7.8.


DR04561.doc

Lateral forces at a branch connection may greatly increase the stresses in the branch connection, unless the back fill is thoroughly consolidated or provision is made to resist the force.


DR04561.doc

S E C T I O N 6 S T A T I O N D E S I G N


Stations are facilities that allow for the control, measurement, storage or pressure maintenance of pipeline fluids. Stations covered by this Section include compressor and pump stations, storage facilities, pressure regulation and metering facilities. Other facilities that involve frequent operational activity or public access may also be designated stations for the purpose of this Standard. Pipeline assemblies (see Clause 5.9) are not considered as stations in this Standard. They may, however, be located within the physical boundaries of a station.

A Design Basis document shall record the criteria adopted for the design of each Station, including relevant design standards, process, mechanical, civil, electrical and process control criteria and philosophies.

This Standard establishes minimum requirements for Stations design however because the process, design, operating and maintenance conditions differ from those in a Pipeline, nominated Standards that govern the specific design and operating condition in the Station shall be adopted. Standards other than nominated standards, where used, shall be Approved.

Safety studies shall be undertaken for design (or modifications to a design) in accordance with the requirements of Section 2.

Stations shall be protected from damage caused by the environment and from external interference.

Stations shall comply with regulatory requirements for the safety of personnel and the public.

The limits of the station shall be defined in accordance with Section 4.

All pressure equipment shall comply with the conformity assessment requirements of AS 3920.1, Pressure Equipment Manufacture - Assurance of Product Quality.

6.2 DESIGN

6.2.1 Location

Stations shall be located on property controlled by the pipeline licensee. The following shall be considered in selecting the location of station sites:

(a) Compatibility of construction and operation of the station with existing and known future land planning requirements.

(b) Minimisation of the impact of noise or other emissions from the site on existing and known future users of the adjacent land, irrespective of statutory requirements.

(c) Incorporation of natural features with or without the contribution of constructed landscaping in the design to minimize the impact of the site on the adjacent land users and the visual aesthetics of the area.

(d) Provision of continuous access to the site.

(e) Minimisation of external interference threats external to the site, for example vehicle impact.

(f) Risks to adjacent land users from fire or fluid release for the station site and the land reserved for the site.


DR04561.doc

(g) Suitability of voice and data communications for the specific station function.

6.2.2 Layout

To reduce risk from the spread of fire, the separation distances from piping and equipment to adjacent buildings, adjacent properties, vegetation and road boundaries shall be considered.

A distance of at least 15 m should be observed between the fencing and the compressor or pump station building (or the compressors or pumps, if these are not installed in a building) in order to prevent the communication of fire from outside the fencing to this building or the equipment, if the latter are installed in the open. Likewise a minimum distance of 15 m should be observed within the area between the fencing and the installation for regulating and shutting off the fluid flow in the station.

No buildings of combustible construction may be present, and no combustible materials may be stored within 10 m of the compressor or pump building (or the compressor/pump) and of any regulating or metering installation.

Sufficient open space shall be provided around the compressor building to permit the free movement of fire fighting equipment.

The minimum spacing between buildings within the site should be 4 m.

6.2.3 Other considerations

Station design shall consider the impact of the following:

(a) Spacing of equipment and facilities.

(b) Pollution control.

(c) Security.

(d) Noise control.

(e) Venting and drainage.

(f) Liquid separation and disposal.

6.2.4 Safety

6.2.4.1 Hazardous areas

The extent of hazardous areas shall be determined for each site in accordance with AS 2430.1 and AS 2430.3 or other approved Standard. No hazardous areas of any site shall extend beyond the fenced or controlled boundary of the property controlled by the pipeline licensee unless specific approved plans are implemented to prevent public access to the hazardous area.

6.2.4.2 Personnel protection

Consideration shall be given to protection of operating personnel and visitors from hazards in the station. Adequate protection shall be achieved by a combination of passive equipment protection, guarding, isolation, layout and design. When adequate protection cannot be provided by these means, personnel protective devices shall be provided in sufficient quantity for the greatest possible number of people on the site.

6.2.4.3 Fire protection

The following requirements shall apply to fire protection:

(a) Firefighting equipment Adequate and approved firefighting equipment shall be provided.

(b) Detection of gas and fire Detectors for flammable gas or flammable vapour shall be installed at locations in buildings housing any compressor, pump or control, where an


DR04561.doc

accumulation of gas or vapours is considered to be hazardous. Smoke, fire detectors or both shall be installed in such buildings.

Detectors shall initiate action intended to make the station safe. NOTE: This action may include local alarms, remote alarms, automatic shutdown, automatic fire fighting, the isolation of the station, initiation of an Emergency shutdown (ESD), automatic emergency depressurisation and the prevention of remote restart until safe conditions are restored

(c) Power supply Power supplies for fire protection systems shall be independent of any power supply that may be shut down during an emergency.

(d) Hot surfaces Hot surfaces of engines and compressors shall be insulated or suitably cooled to prevent ignition of flammable vapours or gases that may be present, or be adequately ventilated to prevent the build-up of an explosive mixture of gases.

(e) Vegetation Vegetation within the station shall be controlled, so that it does not become a fire hazard.

(f) Disposal of flammable liquids Flammable liquids shall be disposed of in a controlled and safe manner.

6.2.4.4 Earthing/lightning

The station piping and equipment shall be properly earthed to discharge fault or induced voltages safely. The equipment and facilities, including fencing, shall be earthed to protect personnel and equipment from harm or damage in the event of lightning striking the facility.

The design of station earthing shall be compatible with the pipeline cathodic protection system and with corrosion protection of any buried pipe within the station. Compatibility may be achieved by electrical isolation of below ground pipe in conjunction with suitable surge diversion devices to protect the isolation mechanism.

Lighting damage to above ground facilities or hazard to personnel can arise in four ways:

(a) Lightning strikes directly to the above ground facilities

(b) Lightning strikes to ground near the facilities

(c) Lightning strikes to ground very near the pipeline

(d) Lightning strikes to incoming electricity supply or telecommunications conductors

Total elimination of hazards to personnel standing on the ground in proximity to metallic components is generally impractical. Extensive earth mats would be required which might nevertheless be only partially effective. Particularly in high resistivity soils, hazardous step potentials could still be present at the perimeters of extensive grounding systems, and conductor impedance may allow substantial voltages to be present between pipeline appurtenances and earth mats. When moderate to loud thunder is heard, persons working outdoors should avoid exposed locations and should seek adequate shelter. This particularly applies if thunder follows within 15 seconds of a lightning flash (corresponding to a distance of less than 5 km). Personnel should seek shelter in a substantial building with at least normal headroom or within a totally enclosed metal bodied vehicle such as a car or truck with a metallic roof, avoiding contact with metallic parts.

Protection of station piping and equipment can be achieved by installation of an appropriate lightning protection system. Typically this would include one or more lightning rods above the highest points on the structure, suitable downconductors, earthing electrodes and equipotential bonding. Lightning surges due to strikes on incoming electricity supply or telecommunications conductors can be mitigated using suitable voltage limiting (clamping) devices. Detailed information on design of lightning protection systems can be found in AS/NZS 1768.


DR04561.doc

Transfer of energy from lightning strikes to ground in close proximity to the pipeline can be largely mitigated by installation of suitable earthing. Further details of pipeline protection can be found in AS/NZS 4853.

6.2.4.5 Lighting

Adequate illumination shall be provided on walkways, at exits, around critical locations of a compressor or pump, and around control equipment.

In a building where the station control system shuts down the station power system automatically, emergency lighting shall be provided.

6.2.4.6 Fencing and exits

Stations shall be enclosed by a fence that

(a) Is not less than 2 m high;

(b) Restricts unauthorized entry;

(c) Has not less than two exits located so as to provide alternative widely-separated escape routes; and

(d) Carries appropriate warning and prohibition signs on each side complying with AS 1319.

Personnel gates situated at less than 60 m from a building within the fencing shall open outwards and shall be capable of being opened from the inside without a key.

At least one of the gates shall be so dimensioned and constructed as to ensure accessibility for firefighting equipment and ambulances.

Alternative methods of providing emergency exits which are equivalent to gates shall be approved.

6.2.4.7 Venting

Where flammable gas is to be vented to atmosphere, the location of the vent systems shall take into account the direction of the prevailing winds and minimize the possibility of gas entering the air intake of combustion engine driven equipment, areas normally zoned as non-hazardous or adjacent areas where low concentrations of gas may represent a hazard or nuisance.

6.2.4.8 Shut Down System

Each station shall be provided with a system that will safely isolate components of the station, or the whole station to prevent escalation of a potentially unsafe situation.

Usually the shut down system is implemented with an hierarchical structure. The highest level is a station emergency shut down (ESD) that isolates the station from its supply and delivery points, and for gas systems, safely depressurises the station. Lower levels in the hierarchy include unit stop, isolation and depressurisation, and unit stop without depressurisation.

The shutdown system should have provision for automatic, local and remote initiation, as appropriate.

Isolation valves shall be located outside building or enclosures to ensure that after depressurisation of process equipment, escalation is prevented by denial of the fuel source.

Where the shutdown system is designed to operate automatically, the consequence of the immediate cessation of supply on downstream processes shall be considered.


DR04561.doc

6.2.4.9 Marking

Equipment and piping shall be painted or marked so that the safety of operation is enhanced by clearly identified contents, purpose, or function within the station. Particular attention shall be given to the following:

(a) Identification and location of emergency valves and controls.

(b) Identification of piping contents to AS 1345.

6.2.5 Station pipework

6.2.5.1 Design Standard

Except as provided in Clause 3.2 and Clause 3.4.3, design of station pipework shall comply with AS 4041 or ASME B31.3. The use of any other Standard shall be approved.

Carbon steel flanges and flanged valves in Station Piping need not be derated at temperatures up to 120 oC as stated in Clause 3.4.3.

6.2.5.2 Pipework Subject to Vibration

Station equipment operation may cause vibration and the possibility of fatigue failure in pipework and pipe supports.

Piping design shall eliminate acoustical frequencies that coincide with piping or compressor mechanical frequencies. It shall minimise forces due to pressure pulsations that will permit piping to be restrained by conventional pipe guides, anchors or supports and remain within allowable stress levels.

Pipe restraints shall be designed to prevent vibration but still allow freedom to accommodate thermal movement.

6.2.6 Station equipment

6.2.6.1 General

Forces applied by piping to equipment shall not exceed the maximum specified by the manufacturer of the equipment.

6.2.6.2 Pressure vessels

Pressure vessels shall comply with AS 1210 or a nominated Standard. NOTE: Australian Standards committee ME-1 is considering provisions that would allow the flange temperature derating provision of Clause 3.4.3 to be applied to pressure vessels designed in accordance with the AS 1200 standards.

6.2.6.3 Proprietary equipment

Where proprietary equipment is used either directly or as part of a prefabricated system, that equipment shall comply with an approved Standard, or the manufacturer's standard where no suitable approved Standard is available. Equipment normally supplied as proprietary equipment includes the following:

(a) Meters.

(b) Regulators.

(c) Test or monitoring equipment.

(d) Turbines and engines (gas or liquid fuelled).

(e) Valves.

(f) Heat exchangers.

(g) Tankage.


DR04561.doc

(h) Filters and strainers.

(i) Compressors

6.2.6.4 Equipment isolation

All equipment shall be installed in a manner which allows effective isolation for maintenance. Where equipment is of a size that allows full or partial personnel entry, the design shall provide means of positively isolating the equipment during service, such as spectacle blinds or similar devices.

6.2.6.5 Station valves

Station isolating valves and station bypass valves shall be installed at each meter, compressor, pump or regulator station, so that the station can be expeditiously isolated. Such valves shall be designed to an approved Standard and identified for safe and reliable operation.

Isolating valves that are installed above ground and intended to isolate all or part of a station in the event of an emergency shall be 'fire-safe' to an approved Standard.

The failure position of each actuated valve shall be determined in the process design and the design failure mode documented.

Isolating valves below relief valves shall be locked in the open position.

Bypass valves shall be installed at meter, compressor and pump stations.

Piping that is supplying process or fuel gas to a building shall have an isolating valve located in an easily accessible position outside of the building.

Consideration shall be given to providing a maintainable pressurising bypass valve around each station isolating valve and other valves that cannot be maintained without interrupting flow.

6.2.7 Structures

6.2.7.1 General

Structures, including buildings and foundations, shall be designed to comply with the appropriate Australian Standards. Wind and earthquake loads shall be considered for each site and approved.

6.2.7.2 Buildings

Buildings shall be designed in accordance with the following:

Building materials Buildings that contain equipment or piping used to convey hydrocarbons shall be constructed of materials that are not combustible, as specified in AS 1530.1.

Lighting Lighting shall be provided in areas where access is required at night time for operations and maintenance. Such interior lighting shall comply with AS 1680.2.1 and such exterior lighting shall comply with AS 1158.1.

An emergency lighting system that is independent of any plant automatic shut down shall be provided in each building that houses operational plant or equipment.

Emergency exits Where personnel are likely to be prevented from reaching a single exit in an emergency, additional exits shall be provided as required.

The distance from any point in the building to the nearest exit shall be less than 25 m measured along the centre-lines of the aisles, walkways and stairways.

Doors in emergency escape routes shall be hinged and shall open from the inside in the direction of egress without the use of a key.


DR04561.doc

Exits and escape routes shall be clearly marked and kept free from obstructions at all times.

Ventilation Ventilation shall be provided in compressor buildings, pump buildings and other buildings housing pipework containing hydrocarbons, to ensure that personnel in the building are not endangered by the accumulation of dangerous concentrations of flammable or toxic gases or vapours under normal operating conditions.

Ventilation systems shall be appropriate for the fluid that may be released within the equipment structure and shall

(a) discharge safely in a safe location;

(b) safely exhaust any ignitable concentrations of flammable vapour or gas from the equipment structure in a way that will make the internal atmosphere safe within an approved time after the source of leakage has been isolated;

(c) prevent sources of ignition reaching the interior of the equipment structure;

(d) provide a means outside the equipment structure for checking its operation; and

(e) restrict entry of foreign matter.

6.2.7.3 Below ground structures

Pits and other below ground structures that house components containing hydrocarbon fluid shall be located, designed and constructed to provide the following:

(a) Limitation of stresses on pipework.

(b) Necessary protection of components from the elements.

(c) Necessary support and constraint of components within equipment structures.

(d) Protection against accidental ignition of flammable fluids within equipment structures.

(e) Protection of components from damage caused by a third party or loads on pit covers (e.g. from traffic and other external loads).

(f) Prevention of unauthorized entry.

(g) Sufficient space for safe and efficient installation, operation and maintenance of the equipment, as specified in the engineering design.

Care shall be taken to ensure the design of the pit lid is such that it cannot fall into the pit during removal or replacement.

Valves to be positioned so that the spindles will not present a hazard should an operator slip or fall through an access to an underground pit.

Each equipment structure that has an internal volume of not more than 6 m3 and is located so that no part of the equipment structure is above the surface of the ground, shall be ventilated or sealed. Where a structure is ventilated it shall generally comply with the requirements of Clause 4.4.6.2(d).

Sealed equipment structures shall

(a) Be impervious to the passage of flammable vapour or gas;

(b) Be provided with necessary pressure and vacuum relief;

(c) Have on each opening a cover, hatch or door that is both gastight and vapourtight; and

(d) Have provision for testing the atmosphere within the equipment structure without opening the cover, hatch or door.


DR04561.doc

6.2.8 Corrosion protection

Corrosion protection systems shall be applied to station piping and equipment consistent with the design life.

When the station design requires pressurized pipes to be constructed below ground, provision shall be made to protect them from external corrosion. This may include a cathodic protection system similar to that required for the pipeline.

6.2.9 Electrical installations

Electrical installations shall comply with AS 3000 or another approved Standard.

6.2.10 Drainage

6.2.10.1 General

The station site shall be designed to manage liquid effluent to prevent contamination of offsite areas. Generally the site should be designed to segregate clean and contaminated rainfall runoff, oily water, and process fluids.

Collected fluids shall be disposed of in an approved manner.

6.2.10.2 Process liquids

Process liquids emanating from drains, pressure relief systems and equipment leakage shall be segregated and transferred to a storage vessel where they can be returned to the process or transferred to an appropriate container for disposal.

6.2.10.3 Rainfall runoff

The station site should be designed to segregate rainfall runoff in areas which are not subject to contamination by the operation of the facility, and rainfall runoff which may be contaminated.

Uncontaminated runoff should be discharged to appropriate offsite drains.

Runoff which may be contaminated should be discharged through a separator which will prevent contamination from being discharged offsite. If there is a risk of the spillage volume exceeding the capacity of the separator, consideration should be given to providing an isolation valve at the point of discharge to retain all spillage within the site.

6.2.10.4 Oily water

An oily water system shall be provided for those facilities where the normal operation of the facility has the potential to discharge oil-water mixtures. Oily water shall be processed to separate oil and water. The discharged water quality shall be nominated and approved.

The oily water system capacity should be sufficient for the greater of the following:

(a) Fire system water runoff.

(b) Rainfall runoff.

(c) Equipment discharge.

The oily water system shall be designed to prevent explosive vapour/air mixtures from entering or forming in the drainage system. The drainage system shall be designed with fire traps to prevent the spread of fire through the drainage system.

6.2.10.5 Sewage

Sewage and other sanitary waste shall be collected, treated and disposed of in an approved manner.


DR04561.doc

6.2.10.6 Equipment below ground

Where an equipment structure is partly or wholly below ground and flooding would endanger safe operation, an approved drainage system shall be installed. The drainage system shall be appropriate to the fluid in the pipeline and to the site conditions.

Instrumentation linked to the facility control system shall be installed to monitor the safe performance of the below ground equipment drainage system.


DR04561.doc

S E C T I O N 7 I N S T R U M E N T A T I O N A N D C O N T R O L D E S I G N


A pipeline shall be designed with an appropriate system for monitoring and managing its safe operation, having regard to its location, size and capacity and obligations for data recording and reporting. The system may include a range of pipeline facilities such as isolation valves, scraper traps, and generally, a communications and control system, together with appropriate operations and maintenance procedures. The system design shall incorporate any outcomes of the risk analysis, in as much as the control system may be required to monitor, record and report operating data.

The control system may be used for functions related to commercial activities in addition to its function in pipeline control. This Standard does not deal with the commercial functions.

The remote and unmanned facilities shall be designed with an appropriate local control system capable of safely operating that section of the pipeline and if required, safely shutting it down during any time that the communication and supervisory control system is unserviceable.

The design parameters for the system shall be defined and approved.

The following factors should be considered in designing the control and management system:

(a) Suitable facilities provided along the pipeline to allow isolation and inspection for operating and maintenance purposes.

(b) Control of the pipeline in the overall context of the management system for the business.

(c) Safety of operations for both personnel and assets.

(d) Compliance to regulatory requirements.

(e) Prolongation of asset life.

(f) Operations efficiency.

(g) Commercial obligations.

(h) Maintenance planning and dispatching.

(i) Integration of control systems with Geographical Information System.

7.2 CONTROL AND MANAGEMENT OF PIPELINE SYSTEM

7.2.1 Pipeline pressure control

Each pipeline is permitted to operate continuously at a pressure not exceeding MAOP at any point in the pipeline, having regard to the pipeline elevation.

Pressure control systems shall be provided and shall control the pressure so that nowhere on the pipeline does it exceed

(a) The MAOP under steady-state conditions; and

(b) 110% of the MAOP under transient conditions.

For pipelines intended to be operated at a set point equal to MAOP, the control system shall control the maximum pressure within a tolerance of 1%.


DR04561.doc

Pressure control and a second pressure limiting system are mandatory. The second system may be a second pressure control or an overpressure shut-off system or pressure relief.

The transient pressure at any point in the pipeline shall not exceed 110% of the MAOP. Transient pressure is the over pressure that is associated with the unsteady flow situation when flow changes from one steady-state situation to another steady-state situation. This is an event with a duration typically measured in seconds for liquids and seconds or minutes for gases.

For a pipeline transporting liquids (including HVPL, two phase and dense phase fluids), a transient hydraulic analysis shall be undertaken to confirm compliance with the requirements of this clause under all credible operating scenarios.

For a pipeline transporting gas, an analysis of its control systems, including shutdown and pressure control systems that may exist downstream of the point of interconnection to determine whether there are fast acting events that could cause transient pressures. Where this analysis determines that the transient pressure limit to be exceeded, a transient hydraulic analysis shall be undertaken.

Pressure control and overpressure protection systems and their components shall have performance characteristics and properties necessary for their reliable and adequate operation during the design life of the pipeline.

The design of pressure control systems and overpressure protection systems for pipelines shall include an allowance for

(a) an effective capacity of these systems;

(b) the pressure differentials between individual control or protection systems; and

(c) the pressure drops that occur between sources of pressure and the control and protection systems.

NOTE:The engineering design life of some control components may differ from the system design life of the pipeline.

Consideration shall be given to the following conditions when a pipeline is shut-in between isolation points:

(a) Pressure equalization.

(b) Fluid static head.

(c) Fluid expansion and contraction due to changes in fluid temperature, particularly in above ground pipelines.

Where any pressure control or overpressure protection will discharge fluids from the pipeline, the discharge shall be safe, have minimal environmental impact and not impair the performance of the pressure control or over pressure protection system. Particular care shall be taken with the discharge of liquid petroleum and HVPL.

Accidental and unauthorized operation of pressure control and overpressure systems and changes to settings of this equipment shall be prevented.

7.2.2 Separation of pipeline sections with different MAOP

Sections of a pipeline system that have different MAOP shall be designed to prevent the MAOP of each section from being exceeded.

Where isolation is used to separate sections with a different MAOP, the minimum requirement for separation by isolation is two isolation components, two valves or one valve and a blind. A method of venting the space between the two isolation components shall be provided.


DR04561.doc

Where pressure control is used to separate sections with a different MAOP, the minimum requirement for isolation by pressure control is a pressure control system complying with the requirements of Clause 7.2.1.

Where hydraulic gradient is used to control the pressure, the pipeline control system shall ensure that the MAOP's of the sections are not exceeded.

7.2.3 Pipeline facility control

Most facilities are remote from their point of operation and generally designed for unattended operation. Each facility shall be designed with a local control system to manage the safe operation of the facility.

The local control system shall

(a) Continue to operate in the event of a communications failure;

(b) If electric powered, be provided with an uninterruptible power supply with sufficient capacity to ensure continuous operation through a reasonable power outage;

(c) Use reliable technology;

(d) Be designed to fail in a safe manner; and

(e) Be designed with appropriate security.

Each facility may also be configured to enable remote monitoring or control of the facility. .......

7.3 FLUID QUALITY ASSURANCE

Where the properties of the fluid can exceed the limits for which the pipeline was designed:

(a) appropriate instrumentation shall be installed on a pipeline to enable each relevant fluid property to be monitored or.

(b) Where suitable data is available from upstream systems, that data may be used

Where the pipeline facility does not incorporate equipment to control the quality, the control system shall be capable of excluding non-complying fluid from the pipeline.

The Design Basis shall document the maximum excursion and duration of that excursion which if exceeded will require the exclusion system to be activated.

7.4 SCADA

7.4.1 Supervisory Control and Date Acquisition (SCADA system)

Where a pipeline is provided with a SCADA system, it shall

(a) Be reliable;

(b) Supervise the operation of the pipeline system;

(c) Be capable of issuing operating and control commands;

(d) Be capable of collecting and displaying data, facility alarms and status;

(e) When specified, gather operating data and present it in a form which can be used by system operators and managers, including data required for the commercial operation of the pipeline;

(f) Not prevent control systems at remote facilities operating safely, irrespective of the condition of the SCADA system; and

(g) Be fail-safe on loss of power or communication.

It may also incorporate one or more of the following:


DR04561.doc

(a) A leak detection system.

(b) Business management systems.

(c) Personnel management systems.

7.5 COMMUNICATION

A communication system is normally required for the operation of a SCADA system. The communication system shall

(a) Be reliable;

(i) Have an appropriate speed, considering the data acquisition, control response and emergency/safety response required for the pipeline;

(ii) Interface with control and controlled equipment; and

(iii) Be capable of data and voice transmission.

(b) The designer shall consider the use of multiple communication routes.

(c) Distributed devices shall be capable of safely operating the process systems and equipment under their control, and acquiring data for future recovery by the SCADA system in the event that communication with the SCADA master station and control room is lost. Where required, provision may be made for local control to permit continued operation of the facility in the event of extended communications system failure.

7.6 CONTROL FACILITIES

A control facility should be designed with adequate functionality to ensure the operator is fully informed of the status of the entire system, and where required, of each component of the system.

When designing a control room, consideration should be given to its accessibility from the emergency control centre.

Appropriate security systems shall be provided to assure the safe and reliable operation.

7.7 CRITICAL EQUIPMENT AND REDUNDANCY/BACKUP

The SCADA system design shall be assessed to determine the consequence of system failure to system safety, supply continuity, and business viability.

Consideration shall be given the ability of the pipeline system to continue safe operation following an event that results in complete loss of the control room and associated computer hardware, software and data storage.

Redundant equipment and/or a hot standby SCADA Master station may be necessary to maintain safe, continuous operation of the pipeline network and business management systems.


DR04561.doc

S E C T I O N 8 M I T I G A T I O N O F C O R R O S I O N


Measures shall be taken to mitigate corrosion and other destructive processes, such as environment-related cracking, which could affect the integrity of the pipeline.

When determining necessary measures, consideration shall be given to the potential for both internal and external corrosion and degradation.

The corrosion mitigation strategy shall address the design of corrosion and condition monitoring programs to provide assurance that the measures implemented are successfully achieving their objectives.

Any changes to the operation of the pipeline, which could result in a change in the potential for corrosion, shall be reviewed and their impact assessed. Appropriate changes to the mitigation program shall be implemented.

The corrosion mitigation strategy shall be approved.

Where this standard is used for construction of pipelines using Corrosion Resistant Alloy pipe, the corrosion design shall take full account of the materials used.

The provisions of this Section should not be applied to CRA materials without expert advice.

8.2 PERSONNEL

The design, installation, operation and maintenance of corrosion mitigation systems shall be carried out by, or under the direction of, persons qualified by experience and training in the appropriate aspects of corrosion mitigation in pipelines. Where the pipeline is influenced by stray electrical currents, the persons shall have had experience with the mitigation of such currents.

8.3 RATE OF DEGRADATION

8.3.1 Assessment

An assessment shall be made of the degradation mechanisms that could affect a pipeline, and an estimation made of the potential rate of degradation. In making this assessment, consideration shall be given to

(a) internal and external conditions, and

(b) changes expected to occur over the life of the pipeline. NOTE: A list of factors that should be taken into consideration in this assessment is contained in Appendix N, together with a discussion of the impact of each item.

In cases where it is not possible to accurately assess the rate of degradation, appropriate provision should be made for corrosion mitigation.

8.3.2 Internal corrosion

8.3.2.1 Gas pipelines

Where any water is present or is likely to form in a hydrocarbon gas pipeline, the gas shall be considered to be corrosive. Appropriate measures to mitigate the corrosion shall be adopted unless the system can be demonstrated to be non-corrosive. Gas that is dry (i.e. free of liquid water) shall be considered non-corrosive. Hydrocarbon gases transported at temperatures that are at all times 8°C higher than the water dewpoint of the gas may also be considered non-corrosive.


DR04561.doc

8.3.2.2 Liquid hydrocarbon pipelines

The corrosiveness of liquid hydrocarbons, shall be assessed to establish likely corrosion rates. Where the corrosiveness is not already known from previous tests, investigations or experience testing shall be conducted and shall simulate the most aggressive conditions expected over the life of the system. Appropriate mitigation methods shall be selected.

8.3.3 External corrosion

Where the rate of external corrosion is assessed to affect the integrity of the pipeline over the expected life of the system, an approved coating system shall be applied. For underground pipe, the coating system shall be supplemented by cathodic protection and shall be selected in conjunction with the cathodic protection design, taking into account pipeline environment, operating conditions and required design life. Where appropriate, provision shall be made for stray current drainage.

8.3.4 Environmentally assisted cracking

The potential for environment related cracking of the pipeline shall be assessed and, if warranted, appropriate control measures shall be incorporated in the design or operation of the pipeline to prevent failure within its design life.

NOTE: Guidance on environment related cracking of carbon steels is given in Appendix O.

8.4 CORROSION MITIGATION

8.4.1 General

Where corrosion could affect the integrity of a pipeline during its design life, the pipeline shall be provided with one or more of the methods set out in this Section.

8.4.2 Corrosion mitigation methods

Corrosion may be mitigated by one of the methods listed in Table 8.4.2.

TABLE 8.4.2

APPLICABLE METHODS FOR MITIGATING CORROSION

External corrosion (see Clause 8.7) Mitigation measure

Internal corrosion (see Clause 8.6) Buried Submerged Above ground

Lining X

Inhibitor and/or biocide

X

Coating X X X

Cathodic protection (with stay current mitigation in stray current areas)

X X

X = applicability NOTES: 1 Cathodic protection would normally only be used in conjunction with an appropriate coating system.

However, in specific circumstances, such as temporary lines and gathering lines, cathodic protection may be applied to uncoated pipelines.

2 Where the pipelines is externally coated, cathodic protection would normally be applied.

3 The addition of an allowance for the effect of corrosion does not mitigate corrosion, but is a valid method for providing for its effect during the design life of the pipeline.


DR04561.doc

8.4.3 Corrosion allowance

A corrosion allowance is an increase in the wall thickness of the pipe by an approved amount in excess of that required to withstand internal pressure, external loads and other defined requirements.

A corrosion allowance may be used as all or part of the corrosion mitigation measures for both internal and external corrosion. Where internal corrosion is expected, a corrosion allowance should be used in conjunction with other active corrosion mitigation methods to provide additional protection against unexpected corrosion rates or failure of the other methods.

A corrosion allowance may be appropriate for above-ground pipelines, particularly where the conditions are conductive to minimal or general external surface corrosion, and in particular where external coating systems may be difficult or impractical to maintain. An external corrosion allowance would be unusual on buried pipelines, except in conjunction with other corrosion mitigation methods, unless it can be shown that the external corrosion is uniform and generalized.

Where a corrosion allowance is used, systems capable of determining the corrosion rate or loss of wall thickness shall be employed.

NOTE:A corrosion allowance will provide little surety of long-term integrity in situations where pitting corrosion is likely.

A corrosion allowance shall be approved.

8.5 CORROSION MONITORING

The performance of corrosion mitigation systems shall be monitored.

The effectiveness of the corrosion mitigation systems shall be assessed by at least two independent methods.

Where corrosion is detected or anticipated, systems capable of determining the corrosion rate or loss of wall thickness shall be employed.

The corrosion monitoring and assessment measures shall ensure corrosion is detected before it adversely affects the integrity of the pipeline. Monitoring systems may include physical inspection, removable coupons, proprietary instrumentation, and internal inspection devices and equipment.

Corrosion monitoring programs shall be maintained for the life of the pipeline.

The frequency of monitoring shall be appropriate to the expected corrosion rate.

Corrosion monitoring methods shall be approved. NOTE: An example of multiple measures for monitoring external corrosion would be monitoring of cathodic protection levels plus coating defect surveys and examination of defects detected.

8.6 INTERNAL CORROSION MITIGATION METHODS

8.6.1 General

The interior surface of a pipeline conveying a corrosive or potentially corrosive fluid shall be protected against corrosion.

When internal corrosion is anticipated, and provision is made in the design to mitigate internal corrosion, the design shall include an appropriate method for the operator to easily monitor the rate of internal corrosion. The monitoring method shall be maintained for the life of the pipeline.


DR04561.doc

8.6.2 Internal lining

Any lining applied to mitigate internal corrosion shall be rated by tests for the service conditions of the pipeline and for the design life of the pipeline. A lining used for the purpose of preventing of corrosion shall be continuous across welds and repairs to the pipeline.

NOTES: 1 Linings prevent corrosion while they are physically intact. As it is difficult to assure this in

service, it is normal practice to supplement the lining with inhibitor addition. No inhibitor is considered necessary if the lining is installed solely to reduce friction.

2 Lining selection should take account of any intended pigging program for the pipeline, to prevent mechanical damage to the lining.

8.6.3 Corrosion inhibitors and biocides

Selection of corrosion inhibitors and/or biocides to be added to the process stream shall be based on the effectiveness of the chemical under the operating conditions of the pipeline. Effectiveness of the chemicals shall be determined in laboratory tests or by previous experience. Such tests shall take into account the levels of turbulence in the system. Chemicals added to the fluid in this way shall be

(a) Chemically and physically compatible with the pipeline components and linings, with any other chemicals added to the pipeline and with the downstream facilities; and

(b) Injected at sufficient concentrations and intervals to achieve the desired purpose.

8.7 EXTERNAL CORROSION MITIGATION METHODS

8.7.1 General

Where external corrosion is expected to affect the integrity of the pipeline over the life of the system, appropriate corrosion control methods shall be implemented.

Corrosion control on buried pipelines shall be by two independent measures, such as protective coatings in conjunction with cathodic protection. In specific circumstances such as temporary lines or gathering lines, cathodic protection may be applied to uncoated pipelines, or protective coating may be used as the sole protective measure.

8.7.2 Coating

External anti-corrosion coatings, and materials used for the repair of defects or for protection of site field welds shall have physical, electrical and chemical properties that have been demonstrated by tests, investigations or experience to be suitable for the installation and service conditions of the pipeline and the environment for the duration of the design life of the pipeline.

NOTE: A factory-applied coating is preferred for all pipeline components, to ensure adequate surface preparation and coating application under controlled conditions.

Repair material shall be compatible with the original coating and shall provide similar performance capabilities. Where cathodic protection is to be applied, the coating and repair material shall be compatible with the level of protection envisaged.

Procedures for preparation of the surface of the pipe and application of the coating and repair material shall be developed. Criteria for acceptance of the coating prior to installation shall be developed. The application of the coating and of site repairs shall be subject to a quality assurance program.

The integrity of the coating on buried pipelines shall be tested in accordance with AS 3894.1 using the high voltage method immediately prior to final placement, and any coating defects detected shall be required.


DR04561.doc

For onshore pipelines, the integrity of the coating should be confirmed by coating defect survey once the soil has been allowed time to settle and stabilize around the pipe, and the significance and need for repair of any defects evaluated. Coating defect surveys carried out using soil contact electrodes shall be conducted when soil surface conditions are suitable to allow adequate electrical contact between electrode and soil. Appropriate techniques shall be employed to ensure the survey is carried out directly above the pipeline.

Any repairs shall be effected using approved materials and procedures.

Where the coating is liable to damage from stones and rocks in the ditch, the long-term integrity of the coating shall be assured by use in the ditch of sand padding, selected backfill or protective outerwraps, or a combination of these.

NOTES: 1 For an above-ground pipeline, painting may be suitable. 2 Where a coated pipe is to be installed by thrust boring, directional drilling or similar methods,

an abrasion resistant coating should be used.

8.7.3 Cathodic protection

Design, operation, commissioning, monitoring and documentation requirements for cathodic protection shall comply with AS/NZS 2832.1.

Steel may be protected from corrosion by the application of direct current to maintain the potential of the metal sufficiently negative with respect to its environment. Direct current may be provided by the use of galvanic anodes, or by means of an impressed current system. The potential of a structure with respect to its environment can provide a reliable measure of the degree of protection.

Cathodic protection systems for pipelines shall not cause unacceptable levels of interference on other underground or submerged structures. The cathodic protection system shall be compatible with the coating used on the pipeline.

Cathodic protection shall be applied to each section of a pipeline. The method and timing of the installation of temporary and permanent cathodic protection systems shall be documented and approved.

Stray currents from traction systems, other impressed current systems or telluric sources shall be investigated and appropriate mitigative measures implemented, as necessary. It may not be possible to determine the necessary mitigative measures until pipeline laying is complete and the backfill fully consolidated.

NOTES: 1 Further information for cathodic protection is given in Appendix I. 2 In some Australian states, the installation and/or operation of cathodic protection systems

requires approval from a regulatory authority.

Levels of protection shall be controlled, so that potentials that could be deleterious to the structure or to the coating are avoided.

8.7.4 Protection criteria

Protection criteria shall be in accordance with AS/NZ 2832.1.

8.7.5 Design considerations

8.7.5.1 Cathodic protection current requirements

The current requirement for cathodic protection shall be determined by trial or by calculation. Calculations may draw on experience with the pipeline coating being used. The assumptions used for the derivation of the total current requirement shall be clearly documented. Allowance shall be provided:-

(a) To cater for structure coating deterioration over the life of the system; and


DR04561.doc

(b) To mitigate interference effects with any secondary structures.

8.7.5.2 Environment resistivity

The environment resistivity at the site of each cathodic protection installation shall be determined and documented.

8.7.5.3 Anode characteristics

The performance characteristics of the anodes to be used for the system shall be determined by test or reference to previous experience and shall be documented. In particular, the actual consumption rate of the anode in the particular environment shall be determined and confirmation made that the anode will achieve the system requirements in terms of current output and life.

8.7.5.4 Pipeline layout

Details of the structure shall be collected and documented. Features that could affect the successful implementation of the cathodic protection system shall be documented and considered in the design.

NOTE: A list of terms that may need to be considered is given in Appendix P.

In addition, relevant details of the following features shall be gathered and assessed:

(a) System features Structure isolation points, coating details and road and rail crossings.

(b) Other features Any d.c. traction systems, foreign structure crossings, foreign corrosion protective systems and neighbouring a.c. power systems.

8.7.5.5 Test points

A sufficient number of test points shall be installed at appropriate locations, to obtain the necessary electrical measurements to adequately monitor the cathodic protection system. Consideration shall be given to the installation of additional test points at road, rail, waterway and foreign structure crossings.

NOTE: For guidance on test point spacing, refer to AS/NZS 2832.1.

Cable attachments shall be made in accordance with Clause 6.10, and the connection and any damage to the coating repaired with an approved matieral that is compatible with the structure coating and the cable insulation.

8.7.5.6 Materials

Materials shall comply with the appropriate codes and Standards and shall be suitable for the installation in the proposed environment. Guidance on materials for use in cathodic protection systems is given in AS 2832.1 and AS 2239. In particular

(a) Cables shall be appropriately sized for the currents they carry and shall be suitably protected from the environment, particularly those cables to be used in impressed current anode groundbeds; and

(b) Where anodes are to be directly mounted on a submarine pipeline, the back face of the anodes shall be coated to prevent corrosion.

Sacrificial anodes on onshore pipelines should not be directly connected electrically to a pipeline, but rather connected via a test point so that anode output can be measured.

On submerged pipelines with bracelet anodes, the bracelets shall be firmly attached to the pipe by welding or clamping, so that no rotation or axial movement will occur during installation. In positioning, the anodes, no metallic contact between the bracelets and the reinforcing mesh of any weight coating shall be allowed. Electrical connection to the pipeline shall be by not less than two cables, attached to the pipeline in accordance with Clause 10.10.


DR04561.doc

8.7.5.7 Reference electrodes

Permanently installed reference electrodes shall last the life of the structure, or provision shall be made for replacement. The potential of a reference electrode shall be able to be verified, so that passivation of the electrode is detectable.

8.7.5.8 Electrical isolation joints

Electric isolation joints shall be designed to take account of the operating conditions of the pipeline in terms of vibration, fatigue, cyclic conditions, temperature, thermal expansion and construction installation stresses. The materials selected shall be resistant at the pipeline design temperature to the fluids in the pipeline, including any corrosion inhibitors or flow modifiers that may be added to the product. Before installation into the pipeline, the joint shall pass

(a) A hydrostatic pressure test without end restraint at a pressure equal to the pipeline test pressure; and

(b) An electric insulation test at ambient temperature and the pipeline test pressures.

8.7.5.9 Electrical isolation

Where specified in the design of cathodic protection systems, supports and anchors shall be electrically isolated from the pipe by insulating.

8.7.6 Measurement of potential

During measurement of the potential, the reference electrode shall be positioned as close as practicable to the pipeline.

On buried pipelines where galvanic anodes are used, the potential shall be measured at test points that are electrically remote from the anodes.

Means shall be provided to enable the potential to be measured while the cathodic protection system is operating. Such means also apply to a submerged pipeline.

In areas where stray traction currents occur, the measurement and recording of potential shall include times when there are extreme adverse effects of the stray current on the pipeline. For example, in an urban area, the morning and evening transit peaks should be included.

NOTES: 1 Provision should be made to enable earthing systems to be decoupled during measurements. 2 Where possible, the potential should be measured by the use of cyclic on/off techniques, and

the instantaneous off or polarization potential of the pipe should be compared with the −850 mV criterion.

3 For guidance on the measurement of instantaneous off-potential, refer to AS/NZS 2832.1.

8.7.7 Electrical earthing

Where potentially hazardous potential rises could occur with respect to the neighbouring earth, the pipeline shall be electrically earthed or otherwise protected by a suitable means. Such potential rises could occur by virtue of parallelisms with high voltage a.c. powerlines or proximity to power earthing systems.

8.8 EXTERNAL ANTI-CORROSION COATING

8.8.1 Coating system

The performance of a coating system is not solely dependent on the materials used, but also on the standard of surface preparation achieved and the method used for application. Therefore, surface preparation, coating material, application methods and testing methods shall be subject to quality control. The procedures for quality control shall be approved.


DR04561.doc

8.8.2 Coating selection

The coating used for corrosion protection of a pipeline shall have physical and chemical properties suitable for the engineering design. It shall be compatible with the pipeline service and its environment for the full design life.

Consideration shall be given to the possibility of coating damage occurring in handling, installation, pressure testing and in service, due to environmental or operating temperatures and loads.

The suitability of the material for the service and environmental conditions of the pipeline shall have been demonstrated by tests, investigations or experience.

NOTES: 1 AS 2832.1 lists the chemical and physical properties that a coating should possess and

provides guidance on the types of coating available. AS 2518 provides further guidance. 2 For an above-ground pipeline a thin film (less than 200µm) paint coating may be suitable;

however, thicker and more robust coating systems are generally required for underground or submarine applications.

8.8.3 Coating application

Procedures for application of the coating shall be developed so that the desired physical and chemical qualities are obtained. The application thereafter shall be in strict accordance with the procedures. Surface preparation, application and testing of the coating shall be subject to an approved quality control program.

Factory applied coatings generally achieve a higher standard than site applied coatings, due to the better control of ambient conditions.

8.8.4 Joint and coating repair

Where a joint is made in a pipeline or the external coating is repaired, the material used shall be compatible with the original coating and shall have been demonstrated by test, investigation or experience to be suitable for the method of installation, the service conditions and the environment.

Procedures for application of the coating to a joint and for making a repair shall be developed so that the desired physical and chemical qualities are obtained. The application thereafter shall be in strict accordance with the procedures. Surface preparation, application and testing of the coating shall be subject to an approved quality control program.

8.9 INTERNAL LINING

8.9.1 Pipeline lining

The purpose of the lining (e.g. short-term corrosion protection, long-term corrosion protection and friction reduction) shall be specified and documented and the materials used shall achieve the specified purpose. The need to apply lining to welds and site repairs is dependent on the purpose of the lining and shall be clearly specified in the project documentation.

The suitability of the material for the service and environmental conditions of the pipeline and of the application method shall have been demonstrated by tests, investigations or experience.

Procedures for application of the lining shall be developed, so that the desired physical and chemical qualities are obtained and the application thereafter is in strict accordance with the procedures. Surface preparation, application and testing of the coating shall be subject to an approved quality control program.

Where a two-component catalysed epoxy lining is specified, the methods of application and inspection and the criteria of acceptance should comply with API RP 5L2.


DR04561.doc

8.9.2 Joint and repair lining

Materials used for the lining of joints and repairs to the lining shall be compatible with the original lining. The suitability of the material and the application methods for the service conditions and the environment shall have been demonstrated by tests, investigations or experience.

Procedures for application of the repair material shall be developed and shall be subject to an approved quality control program.


DR04561.doc

S E C T I O N 9 U P G R A D E O F M A O P


An increase in the MAOP of a pipeline may be contemplated when:

(a) The design factor adopted for a pipeline is lower than the permitted design factor

(b) The permitted design factor is changed to a higher value

(c) The pressure limit determined using equation 4.5.4.1 from the measured pressure of the hydrostatic strength test exceeds the design pressure.

The following principles shall apply in the establishment of an increase in the MAOP of a pipeline:

(d) The pipeline shall be treated as a new pipeline, and shall comply with all of the requirements of the current edition of this Standard AS 2885.

(e) The risk profile of a pipeline following a change to the MAOP of the pipeline (or to the MOP of a pipeline operated below the MAOP) shall comply with the requirements of this Standard.

(f) The ability of the pipeline to operate safely at an increased operating pressure shall be demonstrated by an engineering review of each component of the pipeline system to determine its suitability for the increased pressure.

(g) The increased MAOP shall not be higher than the value determined in accordance with this Standard from the hydrostatic strength test pressure divided by 1.25.

(h) Where the proposed increase in MAOP is based upon a hydrostatic strength test which was conducted more than 5 years prior to the proposed increase, then the engineering review shall identify and analyse pipe degradation to provide a basis for assessing its fitness for safe operation at an increased pressure. This shall include coating defect and in-line inspection inspections together with physical investigation to confirm and size pipe wall defects and an engineering critical analysis of discovered defects and potential time dependent, mechanical damage, fatigue, and environmental degradation mechanisms.

(i) The upgraded MAOP shall be approved

9.2 MAOP UPGRADE PROCESS

Each MAOP upgrade shall be implemented through a structured engineering review process including at least the following:

(a) Investigation: The investigation shall determine the target MAOP required and shall define the parts of the pipeline system that will be incorporated in the MAOP upgrade. The investigation shall identify and document the pipeline operating history and other information necessary as an input to the analysis including at least:

(i) Operating condition history including the fluid being transported, pressure, pressure profile, pressure range and cycle period, temperatures.

(ii) Changes in operating conditions from those for which the pipeline was designed.

(iii) Historic pipeline integrity data and shall identify each integrity threat known to exist in the pipeline.

(iv) Criteria set for quality assurance of the pipeline when it was constructed.


DR04561.doc

(v) Engineering critical analysis of potential time dependent, external interference and environmental degradation mechanisms shall be undertaken. Conditions examined shall include at least:

(A) metal loss due to general corrosion;

(B) stress corrosion cracking (SCC);

(C) fatigue cracking;

(D) damage due to external interference.

This analysis shall establish limiting conditions for defect size at the proposed MAOP as criteria for assessment of defects.

The investigation shall be documented in an MAOP Upgrade design basis. This document shall be approved.

NOTE:Threats to integrity that are known with a reasonable level of confidence not to exist in the pipeline should also be documented

(b) Data Gathering: The same data as required to for the design of a new pipeline shall be compiled using a combination of original records of the design and current data. The data shall be sufficient to allow demonstration of the integrity of each component of the pipeline system, and its suitability for operation at the changed MAOP . At least the following data shall be gathered or where necessary, developed:

(i) Each regulatory compliance requirement that may be affected by the changed operating condition.

(ii) For pipelines designed and constructed to a previous revision of AS 2885, or to another standard, each departure from the current revision of this Standard .

(iii) Fluid properties for the changed operating condition.

(iv) Hydrostatic strength test records for each part of the pipeline, for each pipeline station, each component and for each pressure vessel. Where the hydrostatic test record of a part of the pipeline of component cannot be sighted, the component strength shall be re-established by hydrostatic test in accordance with this Standard.

(v) Material certificates for the pipe, for each component of station piping and for each pressure containing component. Where material certificates do not exist the suitability of the component shall be established in accordance with Section 3.

(vi) The pipeline shall be examined to locate each defect that may affect pressure containment.

(vii) The pipeline shall be examined to locate stress corrosion cracking colonies for assessment. This examination shall include an examination of the pipeline maintenance history, and its operation to assess the likelihood of it containing significant SCC.

(viii) The pipe condition over its entire length shall be assessed using one or more in-line inspection tools. The sensitivity (discrimination) of the inspection tool shall be sufficient to permit defect dimensions to be assessed against the limiting criteria established in the Investigation part of the MAOP Upgrade process.

Where it is not practical to assess the pipe condition by in-line inspection, the pipeline fitness for pressure containment at the target MAOP shall be demonstrated by a hydrostatic strength test in accordance with the requirements of this Standard.


DR04561.doc

NOTES: 1 Since SCC cannot be reliably detected by current in-line inspection equipment it is unlikely

that the MAOP of a pipeline or parts of a pipeline with a history or a high risk of SCC could be safely upgraded without re-hydrostatic testing.

2 Special care should be taken in the assessment of dents. It is recommended that every dent discovered by in-line inspection should be exhumed to ensure that gouging is present.

(ix) The documents required by this Standard for a new pipeline including the fracture control plan, the pipeline isolation plan, the thickness calculations shall be revised using the target MAOP. Compliance criteria for each shall be established for each revised condition.

(x) Each control and control set point required to control the pressure and temperature of the pipeline together with each associated system including transient pressure control, throughput and gas quality measurement, and associated business system.

(xi) The original design life assumptions shall be reviewed and the revised design life be determined for the target MAOP.

(c) Analysis of the pipeline: The data shall be analysed to establish compliance with each design criteria at the target MAOP. Each item identified as non-compliant shall be documented for rectification or a revised MAOP for which compliance is achieved shall be identified.

For pipelines designed and constructed to a previous revision of AS 2885, or to another Standard, each departure from this Standard shall be analysed, and where significant, a plan for rectification of the departure developed.

Reliability (limit state) analyses may be undertaken to provide additional knowledge on the ability of the pipeline to sustain the target MAOP, but shall not be used as the sole basis for establishing the target MAOP.

The analysis shall include reassessment of each process unit of Stations including pressure and flow control, filtration, heating, compression/pumping when operated at the changed conditions.

Analysis of pressure rated components:

(d) Where a pressure rated component is included in a pipeline assembly or station piping whose MAOP is to be increased above the manufacturers pressure rating for that component, an investigation shall be conducted of the suitability of the component to meet the new MAOP for the remaining life. Components not suitable shall be replaced.

Use of pressure rated components at pressures above their nominated working pressure is subject to the following absolute limitations:

(i) The MAOP shall not exceed the nominal working pressure by more than 25 per cent

(ii) The component shall have been subjected to a hydrostatic strength test of at least two hours at a pressure 1.25 times the new MAOP or higher. The strength test may be the original strength test or a new test.

The investigation shall include consideration of:

(iii) The prior hydrostatic test history of the component.

(iv) The condition of the component. Any reduction in wall thickness or change in material properties from new shall be accounted for in determining suitability for the new MAOP.


DR04561.doc

(v) The effect of the new MAOP on the functionality and operability of the component. Where the functionality or operability of the component at the new MAOP is not equivalent to the functionality or operability of the component required, the component shall be modified or replaced.

(vi) The stresses applied to the component at the new MAOP. Stresses, strains and displacements shall comply with Section 5.7.

The results of the investigation and the proposed actions in relation to pressure related components shall be approved.

(e) Risk Assessment: The risk assessment shall be revised to assess compliance of the pipeline with the requirements of this Standard when it is operated at the target operating pressure. The risk assessment shall include revision of each risk assessment methodology required by this Standard. NOTE:A higher operating pressure will not affect the external interference design, because puncture resistance is not materially changed by internal pressure. A higher operating pressure will affect the likelihood of environmental damage mechanisms such as stress corrosion cracking. The consequence (critical defect length, rupture, fluid release rate and radiation contour distance) are changed by an increased operating pressure. The severity of each failure event should be reassessed against the changed criteria.

(f) Rectification: Each pressure containing component identified as not complying with the requirements for pressure containment at the target MAOP shall be rectified or replaced.

Safe pressure containment of the pipeline at the target MAOP may be established by a hydrostatic strength test in accordance with this Standard. Where defects (for example SCC) are known to be contained within limited sections of the pipeline, the hydrostatic strength test may be restricted to only those sections of the pipeline.

(g) Revised MAOP: After completion of the analysis, risk assessment and rectification work a revised MAOP shall be established and the basis for the revised MAOP shall be documented. The document shall explain the background and rationale for the MAOP upgrade proposed, and any change or extension of service life.

(h) Approval: The MAOP upgrade analysis shall be Approved prior to any change to the MAOP being implemented.

(i) Commissioning and Testing: Prior to commencing operation at a new MAOP a commissioning and testing plan shall be developed to manage the safe implementation of the changed operating conditions. The plan shall address the setting and testing of each instrument and control, and the management of the transition from the original operating condition to the new condition. NOTE:AS 2885.3 contains the minimum requirements for commissioning and testing.

(j) Records: Records complying with the requirements of this Standard for a new pipeline shall be developed and integrated with existing records of the pipeline.


DR04561.doc

S E C T I O N 1 0 C O N S T R U C T I O N


The pipeline licensee shall be responsible for ensuring that the pipeline construction and the completed installation are in compliance with the engineering design and the following:

(a) Construction shall be carried out to ensure the safety of the public, construction and operating personnel, equipment, adjacent property and the pipeline (see Section 2).

(b) During construction, care shall be taken to prevent damage to the environment. On completion of construction, any necessary restoration along the route shall be carried out to minimize long-term degradation of the environment.

(c) Construction personnel shall be competent and where required, qualified for their task.

10.2 SURVEY

A survey shall be made to locate the pipeline relative to permanent marks and benchmarks complying with Mapping Grid of Australia (MGA94) or other approved datum. The construction survey shall adopt the same marks and benchmarks as used in the engineering design unless otherwise approved.

The survey shall establish the coordinates that locate the pipeline as suited to the location and the engineering design. The accuracy of the X-Y coordinates shall not exceed 100mm. The accuracy of the as built cover shall not exceed 100 mm.

Where the survey is required to establish the elevation of the pipe, the accuracy of the elevation measurement shall be documented.

NOTE: Global Positioning Systems (GPS) can determine the east and north coordinate with reasonable accuracy however the accuracy of the elevation measurement is poor unless high quality differential GPS instrumentation is used.

The survey shall develop sufficient information on the constructed pipeline to satisfy the materials traceability requirements of Section 3. Where the pipeline centreline is straight the survey shall establish the location of at least every sixth (6th) weld, the weld sequence, and the pipe number sequence.

The existence of services, structures and other obstructions in or on the route shall be checked, identified and recorded before construction begins, and the location of these shall be recorded in the as-constructed survey record.

A record of surveys shall be made so that, after the pipeline has been constructed, an accurate record of the constructed pipeline can be made to show the precise location of the pipeline and its related facilities.

NOTES: 1 Data should be in digital format, suitable for incorporating in a geographic information

system (GIS). 2 Electronic and paper records of the as constructed design may also be required.

10.3 HANDLING OF COMPONENTS

10.3.1 General

Pipes, including any coatings, coating material, welding consumables and other components shall be handled, transported and stored in a manner that will provide protection from physical damage, harmful corrosion and other types of deterioration. In particular


DR04561.doc

(a) Pipes shall be stacked to prevent excessive localized stresses and to minimize damage;

(b) Supporting blocks and bearers shall not damage pipes or anti-corrosion coatings;

(c) Pipes that may be subjected to damage from traffic shall be located either at a safe distance from the traffic or be guarded by protective barriers; and

(d) Where in temporary storage along the route and during stringing operations, pipes shall be protected from damage.

10.3.2 Pipe transport

Pipe shall be loaded, transported and unloaded in a manner which does not cause damage to the pipe or coating. Transport shall comply with the requirements of the appropriate API recommendations, unless otherwise approved.

Pipes shall be lifted and lowered by suitable and safe equipment. Care shall be taken to prevent pipes from being dropped or from striking objects. Hooks and slings shall be designed so that they will not damage anti-corrosion coatings, will not damage pipe ends, will not slip and will not allow pipes to drop.

10.3.3 Construction loads

The loading condition during construction shall comply with Clause 5.7.5. Where necessary, construction loads and the resultant stresses and strains shall be determined and assessed.

10.4 INSPECTION OF PIPE AND COMPONENTS

10.4.1 General

Pipes and components shall be inspected before any anti-corrosion coating is applied. Anti-corrosion coatings shall be inspected and subjected to a holiday test immediately before the pipe is installed.

Damage judged to be a defect shall be removed or repaired.

10.4.2 Ovality

The minimum internal diameter of pipes shall be approved and shall be not less than 95% of the nominal internal diameter of the pipe being examined.

10.4.3 Buckles

Except for ripples or buckles formed during cold-field bending, a buckle shall be deemed to be a defect where

(a) It reduces the internal diameter to less than the approved minimum;

(b) It does not blend smoothly with the adjacent pipe as evidenced by an identifiable notch (see Clause 10.4.5); and

(c) The height of the buckle is greater than 50% of the wall thickness.

10.4.4 Dents

Pipelines shall not contain any dents that

(a) Will impede the passage of any pig that may be used for operations or surveillance;

(b) Occur at a weld;

(c) Contain a stress concentrator, such as an arc burn, crack, gouge or groove; or

(d) Have a depth which exceeds

(i) 6 mm in a pipe having a diameter not more than 323.9 mm; and


DR04561.doc

(ii) 2% of the diameter in a pipe having a diameter of more than 323.9 mm.

Dents shall be repaired in accordance with Item (c) of Clause 10.4.6.

10.4.5 Gouges, grooves and notches

A gouge, groove or notch in a pipe is deemed to be a defect where it is deeper than 10% of the nominal wall thickness or has an angular profile.

10.4.6 Repair of defects

A defect shall be repaired by

(a) Grinding, provided that the remaining wall thickness is sufficient to withstand the strength test;

(b) Installing an encirclement sleeve over the defect; or

(c) Replacing the section of pipe containing the defect.

Insert and weld-on patches shall not be used.

10.4.7 Laminations and notches

Where a lamination or a notch occurs on the end of a pipe, the damaged end shall be removed as a cylinder and the weld preparation remade.

10.5 CHANGES IN DIRECTION

10.5.1 Accepted methods for changes in direction

Changes in direction, including sags and overbends required to enable pipelines to follow the required routes and the bottoms of trenches, shall be made by

(a) Bowing the pipe, without the need of an external force to keep the pipe in position before backfilling;

(b) Springing the pipe, to follow the line of the trench;

(c) Cold bending the pipe in accordance with Clause 10.6;

(d) Use of induction bends;

(e) Use of forged fittings;

(f) Use of a butt-welded joint; or

(g) Use of another approved method.

10.5.2 Internal access

Where it is intended to use internal inspection tools, bends shall not impede a free passage of those tools.

The type and radius of a bend shall not impede the passage of pigs of a type and size that may be specified by the pipeline licensee.

10.5.3 Changing direction at a butt-weld

A change of direction of less than 3° at the intersection of the centre-lines of two straight pipes is permitted at a butt weld.

10.5.4 Bend fabricated from a forged bend or an elbow

Where a bend is fabricated from transverse sections that are cut from a forged bend or an elbow

(a) The bend shall be used within the specified pressure rating of the forged bend or elbow; and


DR04561.doc

(b) The length of the arc measured along the crotch shall be not less than four times the nominal wall thickness of the fitting.

10.5.5 Roped bends

The longitudinal bending stresses induced by roping are not limited by this Standard, but strain shall comply with Section 4. External forces shall not be used to add to the self-weight of the pipe in the roping operations.

10.6 COLD-FIELD BENDS NOTE: The basis of this Clause is given in Paragraph S2, Appendix S.

10.6.1 General

Cold-field bends in line pipe complying with this Standard shall be made by qualified and experienced operators using a cold-field bending procedure qualified and approved in accordance with this Clause before production bending commences.

10.6.2 Qualification of cold-field bending procedure

The qualification of cold-field bending procedures shall be as follows:

(a) One or more test bends shall be made in each bending machine to be used for production bends. Pipes having metallurgical characteristics sufficiently different to affect the stress-strain behaviour of the steel should be tested separately. Pipes and coatings should be representative of the pipes that will be bent in the field. NOTE: The bend procedure qualification should be made in accordance with Appendix J.

(b) The qualification test shall be fully documented and the qualified procedure shall be approved.

(c) The bend qualification procedure shall establish

(i) The acceptance limits for buckles, surface strains and ovality for field bends;

(ii) The methods for measuring buckle height and length and pipe ovality; and

(iii) The methods to be used during production bending for ensuring that acceptance limits are not exceeded.

(d) Where surface strain may affect the integrity of an anti-corrosion coating, calculation or measurement of surface strain is recommended.

10.6.3 Acceptance limits for field bends

Unless approved by the pipeline licensee on the basis of a specific test program, acceptance limits defined in the cold-field bending procedure shall be as follows:

(a) The height of any buckle shall not exceed 5% of the peak-to-peak length dimension in Figures 6.6.3(A) and 6.6.3(B).

(b) Ovality shall not exceed that specified in Clause 6.4.2.


DR04561.doc

(c) Surface strain shall not exceed the lesser of the strain tolerance of the coating being used, or 10%.

Pipe wall

STRAIGHT EDGE

Height 1

Length

Height 2

Pipe wall

STRAIGHT EDGE

Height

Length

10.7 FLANGED JOINTS

Flanged joints shall be installed in accordance with the following requirements:

(a) Bolt holes in flanged joints shall be aligned without springing of the pipes.

(b) Flanges in assemblies shall bear uniformly on the gasket.

(c) Bolts and stud-bolts shall be uniformly stressed.

(d) Gaskets shall be compressed in accordance with the design principles applicable to the type of gasket.

(e) Bolts and stud-bolts shall extend not less than one thread beyond the nut.

Appendix T provides guidelines for calculation of bolt tightening.

10.8 COVERING SLABS, BOX CULVERTS, CASINGS AND TUNNELS

Installation of pipelines in casings, culverts and tunnels and beneath covering slabs and their construction shall be in accordance with the engineering design.

Where a pipeline is being installed in a casing, culvert or tunnel, damage to the pipeline and its anti-corrosion coating shall be prevented.

10.9 SYSTEM CONTROLS

Control devices, safety devices, instruments and equipment required for pipelines shall be installed in accordance with the recommendations of the manufacturer and the engineering design.


DR04561.doc

Forces applied to equipment shall not exceed those specified by the manufacturer.

Instruments shall be located and installed so as to enable inspection and calibration, without undue interruption to operation of the pipelines.

10.10 ATTACHMENT OF ELECTRICAL CONDUCTORS

10.10.1 General

Any copper electrical conductor that is connected to a pipe or to another pressure-containing component (including conductors used for cathodic protection) shall be installed so that the connection will remain mechanically secure and electrically conductive throughout the design life of the pipeline. Stress concentrations should be minimised. The conductor shall be installed without tension.

Any buried bare conductors and other buried metallic items at the point of connection shall be coated with an electrical insulating material that is compatible with the insulation of the conductor and the anti-corrosion coating of the pipeline.

NOTE:The preferred methods for attaching conductors to pipelines or other pressure-containing components are aluminothermic welding or fillet welding a lug, boss or pad to the pipe or component (see AS 2885.2). The latter method is preferred when the nominal wall thickness of the pipe is less than 6mm.

10.10.2 Aluminothermic welding with qualification

10.10.2.1 General

An aluminothermic weld on a pipeline may be made without qualification where it is in accordance with Clause 10.10.2.2. An aluminothermic weld not in accordance with Clause 10.10.2.2 shall be qualified and tested in accordance with Clause 10.10.2.3.

10.10.2.2 Aluminothermic welding without qualification

Aluminothermic welding without qualification shall comply with the following:

(a) The wall thickness of the pipe shall be not less than 4.8 mm.

(b) The size of the aluminium powder and copper oxide cartridge for aluminothermic welding shall be not more than 15 g.

(c) The cross-sectional area of the cable conductor for each weld nugget shall be not more than 10.5 mm2 or the equivalent of four wires each of 1.78 mm diameter.

(d) The depth of insertion of the conductor shall be sufficient for the weld material to contact the conductor and at the same time obtain a good weld to the pipeline.

(e) The surface of the pipe for an area of not less than 50 mm square shall be cleaned by filing or grinding to remove all surface coatings.

10.10.2.3 Aluminothermic welding with qualification

Aluminothermic welding with qualification shall comply with the following:

(a) An aluminothermic weld not carried out in accordance with Clause 6.10.2.2 shall be qualified separately for each material composition, size of conductor, cartridge size and type of surface preparation.

(b) A procedure test shall be conducted on three nuggets, each of which shall pass a test of one firm side blow from a hammer having a mass of approximately 1 kg, after which each nugget shall be visually examined for adequate bonding and the absence of lifting. One of the test nuggets shall then be sectioned and metallographically examined for copper penetration (including penetration of the grain boundaries) using optical microscopy at a magnification of at least 100X. Copper penetration shall be


DR04561.doc

(i) For nominal wall thicknesses of 4.8 mm or greater .. not more than 0.50 mm; and

(ii) For nominal wall thicknesses of less than 4.8 mm not more than 10% of the nominal wall thickness.

10.10.2.4 Inspection

A production aluminothermic weld shall be subjected to the hammer test specified in Item(b) of Clause 10.10.2.3.

An unsatisfactory weld shall be removed and remade in a new location at least 75 mm distant.

NOTE: The use of copper aluminothermic welding for welding directly onto pipe carries the risk of copper liquid metal embrittlement of the steel by penetration of molten copper into the grain boundaries of the steel. Experience indicates that problems are unlikely to exist unless the pipe wall thickness is less than approx. 5 mm, and other contributory factors such as worn moulds or inadequate conductor insertion exist.

10.11 LOCATION

10.11.1 Position

Pipe shall be positioned in the pipeline as required by the engineering designs according to wall thickness, SMYS, diameter and coating.

10.11.2 Clearances

Pipelines shall be installed at a safe distance from any underground structure, service or pipeline. Precautions shall be taken to prevent the imposition of external stresses from or on, any other underground structure or pipeline.

Where a pipeline is laid parallel to or crosses an underground structure, service or pipeline with a clearance of less than 300 mm, the pipeline shall be protected from damage that might be caused by the other structure or pipeline and protected from electrical contact.

Unless otherwise approved, there shall be no electrical contact between a pipeline and any other underground structure, service or pipeline.

Where practicable, there shall be sufficient clearance for any maintenance or repairs to be carried out on the pipeline.

NOTE: In a Class T1 or Class T2 location, a pipeline should be installed below any existing underground services, except those services designated as deep sewers or deep drains.

10.12 CLEARING AND GRADING

The route shall be cleared to the width necessary for the safe and orderly construction of the pipeline.

The requirements specified for the protection of the environment shall be observed at all times.

Where a route is graded, permanent damage to the land shall be minimized and soil erosion prevented.

In developed farmland, liaison with property owners is to be maintained to minimize disruption to farming activities.

10.13 TRENCH CONSTRUCTION

10.13.1 Safety

Excavation shall be performed in a safe manner. Damage to buried services, structures and other buried pipelines shall be avoided.


DR04561.doc

Blasting shall be carried out in a safe manner and in accordance with AS 2187.2 and regulatory requirements.

10.13.2 Separation of topsoil

Where required, topsoil from trenches shall be stored separately from other excavated and backfill materials.

NOTE: Consideration should be given to preventing the transfer of noxious weeds.

10.13.3 Dimensions of trenches

The width of trenches shall be sufficient to allow pipelines to be installed in position without being damaged and to permit full consolidation of padding and backfill material.

10.13.4 Bottoms of trenches

Where a pipe is installed in a trench, the bottom of the trench shall be free from cave-ins, roots, stones, rocks, welding rods and other debris that could cause damage to anti-corrosion coatings on installed pipes.

10.13.5 Scour

Where scour could occur in a trench, barriers shall be installed to prevent scour. Barriers shall be built of masonry, non-degradable foam, sandbags or an approved material.

Anti-corrosion coatings should be inspected for holidays immediately before any barrier is installed around a pipe. Where required, repairs shall be made.

10.14 INSTALLATION OF A PIPE IN A TRENCH

10.14.1 General

The installation methods, materials, compaction and restoration shall support and protect the pipeline for its design life.

A pipeline shall have a firm continuous bearing on the bottom of the trench or padding and rest in the trench without the use of an external force to hold it in place, until the backfilling is completed. This should be achieved by a combination of trench excavation and pipe shape (bending).

A typical pipe installation requires:

(a) The trench profile designed to achieve the design cover and to minimise bending, while recognising landform and other constraints, including environmental objectives

(b) Bending the pipe so that its shape mirrors that of the trench. Overbends should ride high, sag bends and side-bends should rest on the bottom of the trench and well away from the trench wall.

(c) Placing bedding material to support the pipe with its coating undamaged

(d) Installing the pipe

(e) Covering with shading material to secure the pipe in position and protect the coating from damage

(f) Application of backfill

(g) Backfill Compaction NOTE: Techniques that support the installed pipe, and place bedding and padding in a single operation may be used.

The following principles shall form the basis for developing specifications and procedures for installing a pipeline in a trench, and covering it.


DR04561.doc

(a) Unless other provisions are made, the installed pipe shall be supported (restrained) in its intended position by the trench and the compacted backfill.

(b) Any settlement that occurs after installation, or when loaded with hydrostatic test water shall not impose stresses on the pipe as a result of differential settlement.

(c) The backfilling materials surrounding the pipe shall protect the pipe coating both during installation and through subsequent operation. This may be selected soil or a barrier coating. Barrier coatings, when used shall maintain their properties for the design life of the pipeline

(d) The properties, including resistivity, of the backfilling materials surrounding the pipe, shall permit the cathodic protection system to work effectively over the full surface of the pipe.

(e) The permeability of the backfilled and compacted trench shall be similar to that of the unexcavated material to minimise drainage along the trench invert, and potential tunnel erosion.

(f) The standard of compaction shall be sufficient to deliver the required engineering properties of the backfill.

(g) Environmental controls shall prevent soil inversion during backfill and where specified, shall preserve excavated material and return it to the trench in the sequence that it was removed.

NOTES: 1 To ensure the efficacy of a cathodic protection system, padding and shading should be as

homogeneous as practicable and be in continuous contact with the pipeline. 2 The excavated subsoil, screened where necessary, may be suitable for padding and shading. 3 Screening machines may require the screen size to be changed as the particle size distribution

in the spoil being processed varies with soil and excavation type. Periodic field testing by screen analysis may be required. When screening machines process spoil in two passes (to provide bedding material prior to pipeline installation and padding after pipe installation), the particle size distribution of material in the padding pass shall be monitored to ensure that the specified particle size is delivered, with particular concern to the percentage of material passing a 2.36 mm screen.

4 When screening machines apply bedding and padding in a single pass machine the pipe support shall be designed to deliver firm continuous bearing to the pipeline recognising the soil load imposed on the pipe, and the difficulty of completely filling the gap beneath the pipe. The support should allow the pipeline to settle as the bottom padding compacts to ensure that there is proper support, and that voids that could compromise cathodic protection are not present. Some experience suggests that foam pillow support may shield the pipe from cathodic protection.

5 The engineering properties of cement stabilised backfill materials, including "flowable" fill should be considered and specified for the locations where their use is nominated. The factors to be considered include compressive strength for external loadings, resistance to external interference and the ability for the material to be removed, if required, for pipeline maintenance.

10.15 PLOUGHING-IN AND DIRECTIONALLY DRILLED PIPELINES

Where a pipeline is to be installed by ploughing-in or directional drilling the procedures shall be approved and appropriate measures taken to ensure compliance with those procedures.


DR04561.doc

10.16 SUBMERGED CROSSINGS

Procedures shall be developed for the construction of each submerged crossing. Specific procedures shall be developed for crossings for which a location specific design is developed. The procedures shall be approved.

The procedures shall address the following:

(a) The construction method

(b) Pre-testing (where applicable)

(c) Buoyancy control

(d) Installation loads and their management

(e) Pre-installation investigation

(f) Measures to comply with the environmental management plan

(g) Restoration measures

10.17 REINSTATEMENT

After backfilling has been completed, construction tools, equipment and debris shall be removed. Areas that have been disturbed by the installation shall be reinstated. Appropriate measures shall be taken to prevent erosion (e.g. the construction of contour banks or diversion banks) and minimize long-term degradation of the environment.

Fences that have been removed to provide temporary access to the route shall be re-erected.

Reserves shall be reinstated in accordance with the requirements of the appropriate authority.

In developed farmland, it shall be ensured that topsoil is being replaced without contamination, and drains and general contours are reformed.

NOTE: Reinstatement should be completed as soon as is practicable.

10.18 CLEANING AND GAUGING PIPELINES

After completion of the construction and before pressure testing, the inside of pipelines shall be cleared of foreign objects. Suitable inspection pigs should be used to determine whether the pipeline contains dents or ovality in excess of that specified in Clause 10.4.


DR04561.doc

S E C T I O N 1 1 I N S P E C T I O N S A N D T E S T I N G

11.1 GENERAL

The pipeline licensee shall ensure that inspection and testing are undertaken as necessary during manufacture, transport, handling, welding, pipeline construction and commissioning, to ensure that the completed pipeline complies with the engineering design and relevant standards and has the intended quality and integrity.

11.2 INSPECTION AND TEST PLAN AND PROCEDURES

The pipeline licensee shall prepare and document a plan and procedures covering all inspections and tests required by this Standard and the engineering design. Inspections and tests shall be made in accordance with the documentation.

Corrective action shall be taken where an inspection or test reveals that specified requirements are not satisfied.

11.3 PERSONNEL

Inspectors shall have appropriate training and experience.

Inspectors shall be qualified in accordance with the relevant requirements of this Standard and as determined by the pipeline licensee.

Each aspect of construction shall be inspected by a competent inspector to assure compliance with the engineering design.

11.4 PRESSURE TESTING

Drafting Note: THIS SECTION NEEDS final review against AS 2885.5

11.4.1 Application

Except for components that are exempted from field pressure testing, pipelines shall pass an approved strength test and an approved leak test.

11.4.2 Exemptions from a field pressure test

The following items may be exempted from field pressure tests:

(a) Pipes and other pressure-containing components that have been pre-tested to a pressure that is not less than that specified for the strength test.

(b) Components that have not been pre-tested, but have an adequate design pressure or an appropriate pressure rating complying with the Standard used for their manufacture.

(c) Components, other than those covered by Items (a) or (b) above, that have had their strength proved by experience and have been exempted from a pressure test.

(d) Tie-in welds made in accordance with AS 2885.2.

(e) Small-bore controls, instruments and sampling piping.

11.4.3 Pre-tested Pipe

Pipe installed in locations where it is difficult or impractical to gain access to the pipe to locate a leak, or to repair the pipe after it is installed, or where a failure of the pipe during hydrostatic test creates a threat to an adjacent facility, or a risk to the public should be pre-tested in accordance with this Standard prior to installation. Locations may include:

(a) Submerged crossings (permanent waterways).


DR04561.doc

(b) Rail and major road crossings.

(c) Pipe installed in the vicinity of a location where the consequences of pipe failure during test are unacceptable.

11.4.4 Test procedure

Approved strength tests and approved leak tests shall comply with AS 2885.5. Notwithstanding the requirements of AS 2885.5, air or a gas may be used as a test fluid, where the use of a liquid is impracticable and subject to the requirements of Clause 11.4.6.

The approved test procedure shall include

(a) the maximum and minimum strength test pressures (see Clause 11.4.5);

(b) the methods for monitoring and controlling the tests;

(c) the precautions necessary to ensure the safety of the public and testing personnel; and

(d) the criteria for assessment of leak tightness.

11.4.5 Minimum test pressures

The minimum pressure for strength tests of pipelines shall be determined by the pipeline licensee.

The following factors shall be considered in determining the end point:

(a) The minimum value of hydrostatic test pressure, PM, which the strength test is terminated shall be not less than the MAOP multiplied by the equivalent test pressure factor factor, FTPE, in accordance with Clause 4.5.4.

(b) PM shall be determined at the highest elevation in the test section using the methods permitted in AS2885.5.

(c) The maximum value of PM shall not exceed an end point selected in accordance with AS2885.5. NOTE: Tests for which the maximum pressure has the potential to result in yielding of any pipe under test are required to be conducted in a manner that monitors the amount of straining during the test. This is called a volume/strain-controlled test, for which the end-point is determined during the test. The maximum pressure may be limited by the acceptable amount of strain (defined by a volume/strain end-point), by a maximum pressure or a maximum stress.

The current edition of AS 2885.5 2002 recommends that volume/strain end point used for pipe which is not cold expanded should be the 0.4% offset end point. Until the next revision of AS2885.5 it is suggested that this recommendation should be treated with caution and that a volumetric strain of 0.2% should not be exceeded.

(d) The maximum value of hydrostatic test pressure in a test section will be PM plus the pressure arising from the elevation difference between the lowest and highest points in the test section. Guidance on the design of test sections, including the choice of maximum elevation difference, is given in AS2885.5 Appendix I. NOTE: For all pipelines which are to be hydrostatically tested at a pressure exceeding 90% SMYS at any part of the test section, the design of the section including the elevation difference, shall be assessed using the principles set out in AS2885.5. Engineering software which has been developed for this purpose under the auspices of the APIA Research Program is recommended.

11.4.6 Testing with a gas

11.4.6.1 Safety

Where the test fluid for pressure testing is air or some other gas, the risk identification and risk evaluation procedures of Section 2 should be followed to identify the threats, failure


DR04561.doc

analysis and effects and consequences of a loss of integrity of the pipeline during testing. The failure analysis shall consider the effect of the following on the fracture control plan:

(a) The test pressure being higher than the MAOP of the pipeline.

(b) The decompression performance of air and other gases being different from that of natural gas.

Where the test fluid is air or a flammable gas, the potential for an explosion or for a fire shall be considered, including the risk of explosion from

(i) A mixture of air and hydrocarbon that may be in the pipeline; and

(ii) Lubricating oil from the compressor that may be contaminating the compressed air.

The test procedure shall include the following precautions to ensure public safety:

(a) A preliminary test at a pressure within the range of 10% to 30% of the design pressure.

(b) Controlling the test fluid temperature so as not to damage the coating.

(c) Keeping people who are not involved in making the test at a safe distance from the test section, from when pressure is first applied until it is either reduced to atmospheric pressure or, following a successful test, to the MAOP.

(d) Locating and eliminating leaks occurring during the preliminary test and, if necessary, repeating the preliminary test.

(e) Choosing a test pressure appropriate to the volume and location of the test section. NOTE: Whenever possible, pipelines should be pressure tested using liquid as the test fluid, for safety reasons. However, it is recognized that under certain circumstances, air or gas may have to be used where it is not possible to use a liquid. The use of air or gas can be dangerous unless precautions are taken. Those concerned should be fully aware of the consequences of departing from an approved safe procedure.

The result of risk evaluating and considerations of explosion and fire and the procedures to be implemented to ensure public safety shall be approved.

11.4.6.2 Limitations

Testing with air or natural gas may be used within the limits of Table 11.4.6.2 in location Class R1 and R2. Testing with air or gas in locations Classes T1 and T2 is restricted to the testing of instrument piping.

The limits in Table 11.4.6.2 may be extended in Location Class R1 where the risk evaluation determines the risk class in negligible and the fracture resistance of the pipe is determined to be sufficient to prevent fracture propagation at the proposed test pressure.

TABLE 11.4.6.2

MAXIMUM HOOP STRESS WHEN PRESSURE TESTING WITH NATURAL GAS, INERT GAS OR AIR

Maximum hoop stress allowed as a percentage of SMYS

Class Location

Natural gas Inert gas or air

R1 80 80

R2 30 75


DR04561.doc

11.4.7 Pressure testing loads

AS 2885.5 specifies that where yielding is likely to occur during the strength test, the test shall be monitored by volumetric or other strain measurements. For a pipe acting as a beam, superimposed bending stresses require consideration in deciding where volumetric or strain control is necessary.

11.4.8 Acceptance criteria

The criteria for the acceptance of strength tests and leak tests may be summarized as follows:

(a) A strength test, including withstanding a specified pressure for a specified period to show that the pipeline has the required pressure strength.

(b) A leak test consisting of one of the following:

(i) Visual assessment in which no leakage of fluid can be observed with the naked eye at the end of the hold period.

(ii) Small volume test section in which change in pressure during the hold period does not indicate leakage.

Large volume tests for which the unaccountable pressure change is less than that nominated in the test procedure. (Determination of the acceptable unaccountable change is included in the development of the test procedure as specified in AS 2885.5.)

11.5 COMMENCEMENT OF PATROLLING

Operational patrolling of the pipeline in accordance with AS 2885.3 shall commence immediately the leak and strength tests of the pipeline are completed.


DR04561.doc

S E C T I O N 1 2 D O C U M E N T A T I O N

12.1 RECORDS

On completion of construction, survey data and as-executed drawings complying with AS 1100.401, that identify and locate the pipeline, stations, crossings, valves, pipe fittings and cathodic protection equipment shall be prepared.

All spatial data shall be referenced against MGA94 or another approved datum. Where necessary, permanent reference marks and benchmarks shall be provided. The scale and detail shall be appropriate to the location class and complexity of that location. The following information shall be included:

(a) The design basis

(b) The design drawings

(c) Relevant project specifications and data sheets

(d) Design calculations

(e) The fracture control plan and the isolation plan

(f) The materials and components used in the pipeline. NOTE: The name of the manufacturer and process of manufacture should be included.

(g) Manufacturing Data Records

(h) Hydrostatic test records (including pressurization and strength test records)

(i) The type and pressure/temperature rating of each valve and fitting.

(j) The location of each change of wall thickness, grade and diameter of pipe.

(k) The location and details of each corrosion test point, take-off point, bypass, unusual feature or component.

(l) The locations of any unstable areas where differential settlement or subsidence could occur together with any relevant measurements. NOTE: AS 1170.4 gives information on earthquake activity zones.

(m) The location class.

(n) The records of land ownership.

(o) Any construction information that may be relevant to maintenance of the pipeline.

(p) Each component of the Safety Assessment, including supporting documents, including the location and type of protection measures and operating procedures which form part of the Risk Management

(q) The operating procedures which form part of the design.

Electronic records that can be accessed by common text, database or spreadsheet programs are preferred since electronic data is readily stored with a level of security not possible with paper based documentation. Where documents are only available on paper, they should be scanned into an appropriate format.

While the use of proprietary programs is discouraged, where they are required to interpret the data these should become part of the project record.


DR04561.doc

12.2 RETENTION OF RECORDS

A record of the results of the inspections and tests shall be retained by the pipeline licensee, until the pipeline is abandoned or removed.


DR04561.doc

APPENDIX A

REFERENCED DOCUMENTS

(Normative)

A1 IDENTIFICATION OF DOCUMENTS

The name of the issuing body of documents is identified by the prefix letters in the number of the document as follows:

ANSI American National Standards Institute

API American Petroleum Institute

APIA Australian Pipeline Industry Association

AS Standards Australia

AS/NZ Standards Australia/Standards New Zealand

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

BS British Standards Institution

ISO International Organisation for Standardisation

MSS Manufacturers Standardization Society of the Valve and Fitting Industry, USA

NACE National Association of Corrosion Engineers, USA

A2 REFERENCED DOCUMENTS

The following documents are referred to in this Standard:

AS

1100 Technical drawing 1100.401 Part 401: Engineering survey and engineering survey design drawing

1158 Code of Practice for public lighting (known as the SAA Public Lighting Code)1158.1 Part 1: Performance and installation design requirements

1170 Dead and live loads 1170.4 Part 4: Earthquake loads

1210 Unfired Pressure Vessels (known as the SAA Unfired Pressure Vessels Code) 1210, Sup 1

Sup 1: Advance design and construction

1319 Safety signs for the occupational environment

1330 Method for the dropweight tear test of ferritic steels

1345 Identification of the contents of piping, conduits and ducts

1349 Bourdon tube pressure and vacuum gauges

1376 Conversion factors

1391 Method for tensile testing of metals

1518 Extruded high density polyethylene protective coating for pipes

1530 Methods for fire tests on building materials, components and structures


DR04561.doc

1530.1 Part 1: Combustibility test for materials

1530 Methods for fire tests on building materials, components and structures

1544 Methods for impact tests on metals 1544.2 Part 2: Charpy V-notch

AS

1680 Interior lighting 1680.2.1 Part 1: Circulation spaces and other general areas

1855 Methods for the determination of transverse tensile properties of round steel pipes

1929 Non-destructive testingGlossary of terms

1978 PipelinesGas and liquid petroleumField pressure testing (known as the SAA Code for the Field Pressure Testing of Pipelines)

2430 Classification of hazardous area 2430.1 Part 1: Explosive gas atmospheres

2518 Fusion-bonded low-density polyethylene coating for pipes and fittings

2528 Bolts, studbolts and nuts for flanges and other high and low temperatureapplications

2706 Numerical valuesRounding and interpretation of limiting values

2812 Welding, brazing and cutting of metalsGlossary of terms

2832 Guide to the cathodic, protection of metals 2832.1 Part 1: Pipes, cables and ducts

2885 PipelinesGas and liquid petroleum 2885.2 Part 2: Welding 2885.3 Part 3: Operation and maintenance

3000 Electrical installationsBuildings, structures and premises (known as the SAAWiring Rules)

3859 Guide to the effects of current passing through the human body

3862 External fusion-bonded epoxy coating for steel pipes

4041 Pressure piping

4799 Installation of utility services and pipelines within railway boundaries

AS/NZS

2648 Underground marking tape 2648.1 Part 1: Non-detachable tape

ANSI

B18.2.1 Square and hex bolts and screwsinch series

ANSI/ ASME


DR04561.doc

B16.5 Pipe flanges and flanged fittings

B16.9 Factory-made wrought steel buttwelding fittings

B16.11 Forged fittings, socket-welding and threaded

B16.21 Non metallic flat gaskets for pipe flanges

B16.25 Buttwelding ends

B16.28 Wrought steel buttwelding short radius elbows and returns

B16.34 ValvesFlanged, threaded and welding end

B31.3 Chemical plant and petroleum refinery piping

API

RP 5L2 Recommended practice for internal coating of line pipe for non-corrosive gas transmission service

RP 579 Recommended Practice for fitness for Service

RP 1102 Recommended practice for liquid petroleum pipelines crossing railroads andhighways

RP 1162 Public Awareness Programs for Pipeline Operators

Spec 5L Specification for line pipe

Spec 5LC Specification for line pipe for corrosive service

Spec 6D Specification for pipeline valves (gate, plug, ball and check valves)

Std 600 Steel gate valvesFlanged and butt-welding ends

Std 602 Compact steel gate valves

Std 603 Class 150, cast, corrosion-resistant, flanged-end gate valves

API 11P Packaged High Speed Separable Engine Drive Reciprocating Compressors

API 618 Packaged Reciprocating Compressors for Oil and Gas Production Services

API 619 Rotary Type Positive Displacement Compressors for Petroleum, Chemical andGas Industry Service

APIA

Cold field bending of pipeline

Code of Environmental practice

Construction Safety Guidelines

ASTM

A 53 Specification for pipe, steel, black and hot-dipped, zinc-coated welded and seamless

A 105 Specification for forgings, carbon steel, for piping components

A 106 Specification for seamless carbon steel pipe for high-temperature service

A 193 Specification for alloy-steel and stainless steel bolting materials for high-temperature service


DR04561.doc

A 194 Specification for carbon and alloy steel nuts for bolts for high-pressure and high temperature service

A 234 Specification for piping fittings of wrought carbon steel and alloy steel formoderate and elevated temperatures

A 307 Specification for carbon steel bolts and nuts, 60 000 psi tensile

A 320 Specification for alloy-steel bolting materials for low-temperature service

A 325 Specification for structural bolts, steels, heat treated, 120/105 ksi minimumtensile strength

A 350 Specification for forgings, carbon and low-alloy steel, requiring notch toughness testing for piping components

A 354 Specification for quenched and tempered alloy steel bolts, studs and otherexternally threaded fasteners

A 420 Specification for piping fittings of wrought carbon steel and alloy steel forlow-temperature service

A 449 Specification for quenched and tempered steel bolts and studs

A 524 Specification for seamless carbon steel pipe for atmospheric and lowertemperatures

BS

1560 Circular flanges for pipes, valves and fittings (class designated) 1560.3 Part 3: Steel, cast iron and coper alloy flanges 1560.3.1 Section

3.1: Specification for steel flanges

1560.3.2 Section 3.2:

Specification for cast iron flanges

1640 Specification for steel butt-welding pipe fittings for the petroleum industry 1640.3 Part 3: Wrought carbon and ferritic alloy steel fittings. Metric units 1640.4 Part 4: Wrought and cast austenitic chromium-nickel steel fittings. Metric

units

3293 Specification for carbon steel pipe flanges (over 24 inches nominal size) for thepetroleum industry

3381 Specification for spiral wound gaskets for steel flanges to BS 1560

3799 Specification for steel pipe fittings, screwed and socket-welding for the petroleum industry

5351 Specification for steel ball valves for the petroleum, petrochemical and allied industries

7910 Guide on methods for assessing the acceptability of flaws in metallic structures

ISO

14692 Petroleum and Natural Gas IndustriesGlass reinforced Plastic Piping 14692.1 Part 1: Petroleum and Natural Gas Industries 14692.4 Part 4: Glass reinforced plastics (GRP)

MSS


DR04561.doc

SP-6 Standard finishes for contact faces of pipe flanges and connecting-end flanges of valves and fittings

SP-25 Standard marking system for valves, fittings, flanges and unions

SP-44 Steel pipe line flanges

SP-67 Butterfly valves

SP-75 Specification for high test wrought butt welding fittings

NACE

MR0175/ ISO 151556

Parts 1 to 4 - Petroleum and Natural Gas Industries - Materials for use in H2S containing environments in oil and gas production


DR04561.doc

APPENDIX B

DESIGN CONSIDERATIONS FOR EXTERNAL INTERFERENCE PROTECTION

(Informative)

B1 INTRODUCTION

This Appendix provides information for use in the design of pipelines to achieve compliance with the requirements of Clause 5.5. The explicit requirements for external interference protection design are new in this Standard and represent a recognition that the largest cause of unintentional releases of fluids from petroleum pipelines is damage to such pipelines by external events.

External interference protection design provides protection for the pipeline and the public from such events. In contrast to the previous edition, this edition provides no mechanism for rule-of-thumb design for protection and no provision for deeming adequate protection based on design factor or external interference factor.

Design for protection is required over the whole length of the pipeline.

B2 DEFINITION OF DESIGN EVENTS

The process of design for external interference protection requires definition of the design events for which external interference protection is to be provided in each location, followed by protection design. The external interference events are a subset of the threats to the pipeline for which analysis is required under Clause 2.3.

Definition of the eternal interference events involves systematic assessment along the pipeline of the activities of third parties which could damage the pipeline, together with an assessment of the type(s) of plant or equipment which those activities would involve in the location. This assessment requires considerable knowledge of the land uses at all points along the pipeline, and knowledge of the plant, equipment, and practices of entities which may conduct activities in the vicinity of the pipeline route.

The definition should include assessment of the probable changes to land use and external interference events which may occur along the pipeline route throughout the design life of the pipeline, to enable a cost effective protection design strategy to be developed.

Example:

Consider a pipeline in Location Class R1. The following situations may occur:

(a) Portions of the route may be ploughed for agriculture, and for these the design event would be determined from the largest equipment in common use for such ploughing operations. Along fence lines, the design event could be determined by the largest posthole borer in common use.

(b) Portions of the route may be used for grazing in fenced paddocks. The design events would include posthole boring at fence lines and, in some isolated locations, dam construction for stock water.

(c) Portions of the route may be in land which is not farmed at all; desert, national parkland, forest, scrubland and the like, for which no mechanized plant activities are current or anticipated. Nil design events would be the logical and valid description.

(d) The route would cross easements of other services, such as powerlines and communications cables and public and private transport corridors such as roads, tracks and railways. The design events would be determined by current practices for maintenance of such corridors, future plans for new construction and would include


DR04561.doc

such events as derailment of the heaviest locomotive which currently uses the railroad or a heavy-vehicle accident from the road.

A similar systematic assessment of the design events is required in Location Classes R2, T1 and T2. Because the consequence of a fluid release in Location Classes T1 and T2 is much greater than in rural areas, particular attention is required to developing a full inventory of design events in these locations.

The zone of influence is considered to be the zone within which the consequences of a loss of pipeline integrity would include human fatality or injury. The size of the zone is larger for all flammable fluids, and is affected by wind strength and direction for some fluids.

B3 PROTECTION DESIGN

Protection design is required over the full length of the pipeline even where the consequences of fluid release would not impact on humans. Design is required in each location for all of the design events identified for that location.

Protection design in accordance with Clause 5.5.4 involves the selection of physical measures and procedural measures to minimize the potential for the design event to damage the pipeline and either release fluid, or reduce the pipeline MAOP. Table 5.5.4.2 defines the minimum number of measures of each type which are to be provided.

Elimination of the design events may leave a residual risk of damage from design events which could not be anticipated in the design, and this risk residual is assessed as part of the risk assessment required in Section 2 of this Standard.

The typical design response to the design events in the above example would be as follows:

(a) Burial with a cover substantially larger than the maximum depth of ploughing would provide separation by burial as a physical protection measure.

If the maximum ploughing depth is 400 mm, a minimum cover of 1000 mm might be defined. In addition, since ploughing is an annual activity conducted at much the same time of the year, appropriately timed annual landowner liaison, would provide a meaningful procedural protection measure.

For the fence lines, where ploughing does not take place, but fence posts are buried to 600 mm, 1000 mm cover may be sufficient, but since the replacement of fence posts is not an annual event, conspicuous marking at all points where the pipeline crosses a fence line would be added to the annual landowner liaison.

Patrolling in the R1 Location Class would probably be from the air, but the patrolling schedule could be made specific to determine any change in the location, extent or practice of the annual ploughing and to assess when the condition of the fences made installation of new fence posts likely.

For pipelines requiring a wall thickness for pressure design which cannot be penetrated by either the ploughing equipment in common use or the post hole boring equipment in common use, the protection design could reduce the depth of cover to the minimum allowed where cover is not used for protection (750 mm in Table 5.5.2.1), since resistance to penetration, wall thickness would be the physical measure, not cover. The procedural measures would probably be unchanged.

(b) No design events would apply for most of the route, but at fence lines, the design events and design provisions would be the same as in Item (a) above.

In locations where dam construction is a possibility, the design event would be impacted by the largest earthmoving plant used for such dam construction in that area. Since only pipelines with wall thicknesses more than 10-12 mm are immune from loss of integrity from such plant, and since dam construction is likely to involve


DR04561.doc

depths similar to or larger than pipeline cover, protective measures may not be capable of total protection from an event which may never actually take place. If the dam is built, it is a once-only event in each location. The primary focus of protection design is to ensure that the construction activities do not take place over the pipeline. Selection of physical measures would probably be limited to standard depth of cover, but re-routing may be required in some instances.

The protection design would concentrate on procedural measures aimed at preventing construction in the relevant location. Landowner liaison and patrolling would be particularly important, and pipeline marking at the potential dam site would be appropriate.

Once such a dam is built and no further construction is contemplated at the location, future reviews of threats would not include dam construction at the same location but may include dam maintenance and potential failure. This would alter the focus of landowner liaison and patrolling.

(c) Except at roads and tracks, there would be nil design events, so that minimum protection design; burial to minimum depth of cover, marking at required and patrolling would be the measures adopted.

(d) At tracks, roads and railways, the design event would be specific to the location and the responsible authority, and procedural and physical protection design measures would be specific to the design event. Increased depth of cover to provide separation by burial, thus placing the pipeline below any equipment activities is the commonest physical protection measure, supplemented in some locations with concrete slabs as a resistance to penetration physical protection measure.

Liaison with an authority should be linked to patrolling so that the pipeline operator is aware of the timing of construction or maintenance activities of the authority at the location of the pipeline crossing.

B4 PENETRATION RESISTANCE

Resistance to penetration of steel pipelines by earthmoving plant and boring equipment is not well documented. Work by European Pipeline Research Group (EPRG) forms the basis of the requirements of Section 4.11, together with research published by Australian Pipeline Industry Association (APIA).

Resistance to penetration of steel pipelines is strongly influenced by wall thickness, ultimate tensile stress and the contact tool dimensions.

Some references suggest that only very large plant can gouge the wall thickness to a depth of more than 4 mm. The effect of a partial wall thickness defect of 4 mm on the pressure containment integrity of a pipeline can be calculated by fracture mechanics methods. A conservative estimate of the effect of loss of metal on pressure containment integrity can be made using the methodology of AS 2885.3. This method does not include the effects of pipe steel toughness.

Protection design based on resistance to penetration using wall thickness as a physical protection measure should derive

(a) The relationship between plant size and loss of wall thickness; and

(b) The relationship between loss of wall thickness and loss of pressure containment integrity.

The design should derive the required thickness to preclude penetration from the design event.


DR04561.doc

APPENDIX C

INTEGRITY ASSESSMENT OF PIPELINE RISK ASSESSMENTS CONDUCTED IN ACCORDANCE WITH AS 2885

(Informative)

C1 INTRODUCTION

The pipeline risk assessment process required under Section 2 is of fundamental importance to pipeline design, operation and maintenance. It is the means by which pipeline safety is demonstrated. It also forms the basis for the operations and maintenance of the pipeline which provide for ongoing pipeline safety. Therefore, it is of critical interest to those providing any form of approval of the pipeline (be it technical, financial or regulatory) that the pipeline risk assessment process can be trusted / has integrity. (ie. Does the report demonstrate that the process has been carried out with sufficient rigour?)

The objective of this Appendix is to provide a framework / tools for any competent reviewer to make a reasonable assessment as to whether a pipeline risk assessment has been conducted with sufficient rigour.

C2 CRITICAL CONCEPTS/UNDERLYING PHILOSOPHY

C2.1 Approvals

One of the principles upon which the AS 2885 series is based is that important matters relating to safety, engineering design, materials, testing and inspection shall be reviewed and approved by a responsible entity.

Accordingly, each key step in the pipeline risk assessment is required to be approved. The intent is to ensure that all steps in the process have been completed and reviewed. The presence or absence of explicit, written approvals is the first step to gaining assurance that all of the process elements have indeed been implemented.

C2.2 Specificity

The pipeline risk assessment process for design against external interference threats is predicated on the understanding that specific threats to pipeline integrity occur at specific locations using specific equipment, undertaken by specific parties at specific times. Effective mitigation can only be developed and implemented if there is a high level of detailed information regarding the specific threat.

Generic solutions to generic threats do not demonstrate that rigorous engineering assessment has been undertaken, and therefore the assessment does not comply with AS 2885.

The level of specific information that can be identified in a report provides an indication of the degree of rigour applied to the pipeline risk assessment process.

C2.3 Effectiveness

Any mitigation measure is required to be demonstrated to be effective. As stated above, effectiveness can only be determined if there is sufficient information about the threat is generated.

The risk assessment team must then critically assess whether the proposed mitigation measure is effective against the specified threat. For example, patrolling on weekdays cannot be considered an effective mitigation measure if the identified threat is known to be carried out on weekends only.


DR04561.doc

C2.4 Positive Confirmation

Where possible, pertinent information should be positively confirmed and documented, rather than assumed. Where assumptions are made, these should be documented. It is preferable to explicitly discount and issue rather than infer it by silence. This demonstrates that any given issue has been thought of and discounted rather than simply forgotten.

C3 INTEGRITY CHECKING

A blank pro-forma for integrity checking pipeline risk assessment reports is shown as Table C3.

(a) The integrity checking process concentrates on three major aspects:

(b) Methodology the methodology has been followed correctly

(c) Personnel the risk assessment process has been conducted by the correct personnel

(d) Information the risk assessment process has identified, developed, or collated information which is sufficient for the process to be carried out.

C3.1 Methodology

Assurance on adherence to the pipeline risk assessment methodology is gained if it is clear from the report that the process has been followed and that all key steps have been approved.

The following check questions apply:

(a) Have all elements of the process requiring approval been explicitly approved in writing by the appropriate officer?

(b) Is it clear that the process in Section 2 has been adhered to? This is determined by comparison of the process followed in the report compared to that provided in Section 2 and Flowchart YY. Care must be taken to differentiate between the stated process and the actual process demonstrated by review of the report.

C3.2 Personnel

The pipeline risk assessment process relies on involving the right people in the risk assessment workshops. It is preferable that all disciplines involved with the life-cycle of the pipeline be involved. The principle of specificity needs to be applied here. Personnel with knowledge of the specific issues associated with the specific pipeline need to be involved.

Every effort should be made to involve operations personnel in the risk assessment workshops. This is important for facilitating transfer between the operators and the designers, (including documentation transfer from Part 1 to Part 3). In addition, operators familiar with the location specific issues are particularly important for critical assessment of the effectiveness of procedural measures.

Another critical person in the process is the chair of the workshop. The chair must be thoroughly familiar with the pipeline risk assessment process, and also have the ability to ensure that any particular issues is debated openly and thoroughly. The chair should have skills in drawing information out of all attendees in a workshop environment.

The following check question applies: Is the risk assessment conducted by personnel who are sufficiently familiar with the pipeline design operation, maintenance, management and environment (ie. so that an effective risk assessment will be carried out)?

C3.3 Information

Information is the raw material that dictates the success of the pipeline risk assessment process. A pipeline risk assessment cannot be considered to have integrity unless it is


DR04561.doc

based on information specific to the pipeline, which is sufficient to allow informed decision-making on design against specified threats.

The following general check question applies: Is the information generated sufficient for the purposes of the risk assessment?

Information requirements can be split into the following categories:

(a) Location Analysis Information

(b) Threat Analysis Information

(c) Design Information

(d) Failure Information

(e) Documentation / Drawings / GIS

(f) External Interference Protection Measures Information???

C3.3.1 Location Analysis Information

The location analysis must describe:

(a) The general environment for the section in question, and include an identification of sensitive areas which may be affected by a pipeline loss of integrity. The principle of positive confirmation is particularly important in this case.

(b) All foreign crossings.

(c) Population density within a corridor which may be affected by a pipeline loss of integrity. Special attention should be paid to sensitive developments such as hospitals and schools. The principle of positive confirmation is particularly important in this case.

(d) Land use

(e) Location class

The following check question applies:

(f) Does the location analysis generate sufficient information to determine:

(i) The types of threats that will occur, and

(ii) The consequences of any loss of integrity event?

C3.3.2 Threat Analysis Information

The elimination of threats by external interference protection and engineering design must be based on quantifiable data. Consequently, the threats analysis must generate sufficient information about each threat to allow such design to take place.*

In other words, design against any threat to pipeline integrity cannot be effective unless the threat is sufficiently defined. For any threat, the following minimum information must be generated and documented:

(a) Who does it?

(i) Effective liaison programs can only be developed if the parties likely to dig up a pipeline are identified and contacted regularly.

(b) What is done?

(i) Equipment used Can the equipment used put a hole in the pipe? If so, what does the hole look like?

* SAA HB105-1998 Guide to pipeline risk assessment in accordance with AS 2885.1


DR04561.doc

(ii) Depth of excavation Will the activity result in the pipeline being struck be excavation equipment.

(c) Where is it done?

(i) The location of the activity is required to determine the consequences of any pipeline loss of integrity. Specific physical and procedural measures may be required for that particular location.

(d) When is it done?

(i) This is used to generate frequency information in the risk assessment phase. It is also critical for the development of effective patrolling programs (or may demonstrate that patrolling is not an effective measure in certain locations).

(e) Why is it done?

(i) Again, this is useful in developing strategies of liaison and patrolling programs.

C3.3.3 Design Information (Pipeline Properties)

In order to determine the performance of the pipeline in the event that a threat materializes, the following information must be generated and used in the workshop process. The information should be documented in the risk assessment report.

(a) Pipe wall thickness

(b) MAOP

(c) Pipe Grade

(d) Fracture Toughness

(e) Depth of Burial

(f) Special Protection Measures

(g) Special Crossings

(h) Other

This information must be tied to specific locations. The following check question applies:

(i) Has location specific pipeline property information been developed for the full length of the pipeline?

C3.3.4 Failure Analysis Information

Drafting Note: this needs a bit more work. Any suggestions are most welcome.

Fundamental to the threat evaluation process is an understanding of the types of threat that will result in a pipeline loss of integrity. The size (power) and type of equipment that can penetrate the pipe wall must be clearly documented.

The failure analysis must also estimate the consequences of an ignited pipeline leak, for both a full-bore rupture (if credible) and hole.

C3.3.5 Documentation

The risk assessment must be based on a complete and accurate set of construction drawings (or as-built drawings for existing pipelines) and PIDs.

Modern mapping techniques using a GIS system greatly improve the effectiveness of risk assessment workshops. Indeed, the integrity of a pipeline risk assessment of a major pipeline project may be called into question if such technology is not used.


DR04561.doc

C3.3.6 External Interference Protection Design

For every identified threat for which eternal interference protection design is determined to be sufficient, the following information must be recorded.

(a) Location class and the associated minimum physical and procedural protection measures required.

(b) The physical protection measures

(i) Confirmation that the number of physical measures is sufficient

(ii) Demonstration that the physical measures are effective against the identified threat.

(c) The procedural protection measures

(i) Confirmation that the number of procedural measures is sufficient

(ii) Demonstration that the procedural measures are effective against the identified threat.

C3.3.7 Loss of Integrity Events/Failure Analysis

All threats for which sufficient external interference protection measures cannot be applied are required to be subject to failure analysis. Where this demonstrates that a failure will occur, the threat is determined to be a failure event.

All failure events are required to be identified and documented. This documentation needs to carry with it all of the previous information developed for the threat at the specific location.

The failure analysis is required to include the consequence information for the specific location.

C3.3.8 Risk Evaluation

This requires a bit of discussion and debate. The question is Given that your role is to review the risk report but you were not involved in the workshop process / development of the report, what indicators would you look for to provide confidence in the outcome?

Risk evaluation is conducted for loss of integrity events only. Where risk evaluation of threats other than loss of integrity events is conducted, a fundamental lack of understanding of the pipeline risk assessment process is demonstrated. This demonstrates that none of the workshop participants have understood the process, which is grounds for diminished confidence in the final outcome. In this case, all of the foregoing should be subject to even greater scrutiny.

Risk evaluation in AS 2885 is a qualitative process based on subjective judgements. While the judgements are ultimately approved, the quality of these judgements needs to be tested. While this is not straightforward and subjective in itself, the following guidelines apply:

(a) The process by which frequency and consequence estimates are made should be clearly documented. Estimates made as a result of the workshop process will tend to have more credence than those made by individuals.

(b) The reviewer should test the results against his/her own estimates, and if still not comfortable, ask the report authors to justify the results.

C3.3.9 Risk Management

This also requires discussion and debate, particularly with respect to what constitutes reduction of risk to ALARP, and how one makes a judgement on this.


DR04561.doc

(a) For high risks, the report must clearly demonstrate how the issue has been re-engineered to reduce risks to intermediate. (High risks are unacceptable).

(b) For intermediate risks, the report must clearly document how risks are reduced to ALARP.

(c) For low risks, a management plan must be documented.

(d) Negligible risks must be clearly recorded for future review.

On this basis the following check questions applies:

(e) Have appropriate risk management actions been taken?

C3.3.10 Actions Items

A pipeline risk assessment report will inevitably result in a series of action items to be closed out at a later date. This should be clearly documented in the report.

The report should also generate a list of items to be transferred to the Safety and Operating Plan.

Follow-up on the close out of actions items should be conducted to confirm they have been completed.


DR04561.doc

TABLE C3 RISK ASSESSMENT INTEGRITY CHECKLIST

ITEM

COMMENT Not

app

licab

le

Una

ccep

tabl

e

Cla

rify

Acc

epta

ble

Methodology (Adherence to AS 2885 process)

Location Analysis Approved

Threats Analysis Approved

External Interference Protection Approved

Design Review Process Approved

Failure Analysis Approved

Risk Severity Classes Approved

Risk Evaluation Approved

Risk Management Actions Approved

Process

People (Risk Assessment Workshop) Is the risk assessment conducted by personnel who are sufficiently familiar with the pipeline design operation, maintenance, management and environment (i.e. So that an effective risk assessment will be carried out)?

General comment

Designers

Operators

Maintenance

Field Personnel

Environmental

Chair

Other

INFORMATION Is the information generated sufficient for the purposes of the risk assessment?

Location analysis: Does the location analysis generate sufficient information to determine:

The types of threats that will occur

The consequences of any loss of integrity event

Environment

Crossings

Population


DR04561.doc

Land Use

ITEM

COMMENT Not

app

licab

le

Una

ccep

tabl

e

Cla

rify

Acc

epta

ble

Location Class

Threat Analysis Does the threats analysis generate sufficient information about each threat to allow effective design against that threat to take place?

Who? (identification of the person responsible is essential for: having a source of information to determine what activity is carried out; developing effective liaison)

What? (detailed specification is essential for determining the EIP design requirements. Information required typically includes: the power of the equipment; the depth of the excavation, etc)

Where? (essential to determine where EIP is applied. Essential to determine consequence information)

When? (essential for determining procedural defence measures eg. Patrolling frequency, timing of liaison, etc. Essential for consequence analysis)

Why? Eg. Routine, emergency-can be used for determining procedural defence measures eg. Patrolling frequency, timing of liaison etc. May provide a leading indicator for patrollers/liaison.

Design Information Has location specific pipeline property information been developed for the full length of the pipeline?

Pipeline properties

Wall thickness

MAOP

Grade

Fracture Toughness

Critical Defect Length

Depth of burial

Special protection measures

Special crossings

Other


DR04561.doc

Failure Information

ITEM

COMMENT Not

app

licab

le

Una

ccep

tabl

e

Cla

rify

Acc

epta

ble

Equipment

Consequence

Full bore rupture

Jet fire

Documentation

As-built diagrams

Current

Complete

PIDs

Current

Complete

GIS??

External Interference Protection Design

Location Class Identified

Physical measures

Number of measures sufficient

Demonstrated Effectiveness

Procedural measures

Number of measures sufficient

Demonstrated Effectiveness

LOSS OF INTEGRITY EVENT

Identification of Loss of Integrity Events

Failure analysis demonstrates loss of integrity?

All location specific information included?

Consequence information included?

RISK EVALUATION How have estimates of frequency and consequence been developed? Do they seem reasonable?

Frequency


DR04561.doc

Consequence

Risk evaluation

ITEM

COMMENT Not

app

licab

le

Una

ccep

tabl

e

Cla

rify

Acc

epta

ble

RISK MANAGEMENT Have appropriate risk management actions have been taken?

High Risk High risks are unacceptable and need to be re-engineered.

Intermediate Risk Reduced to ALARP?

Low Risk Management plan recorded?

Negligible Risk Recorded for future review?

ACTION ITEMS

Action List developed

Actions for design changes

Actions for Safety and Operating Plan

Actions Closed Out

GENERAL COMMENTS


DR04561.doc

APPENDIX D

EFFECTIVENESS OF PROCEDURAL MEASURES FOR THE PREVENTION OF EXTERNAL INTERFERENCE DAMAGE TO PIPELINES

(Informative)

D1 SCOPE

This Appendix gives advisory information on development of the procedural measures required by Clause 5.5.6 of this Standard, that form part of the overall package of measures to prevent, or minimise the consequences of, damage to buried pipelines caused by activities such as excavation, boring, horizontal directional drilling, cable ploughing, etc.

The information in this Appendix is based largely upon the following reference:

Cooperative Research Centre for Welded Structures Report on Project 1999/69, The Prevention of Damage to Buried Pipelines Caused by Unsupervised Excavation.

D2 PURPOSE

The purpose of procedural measures is to ensure that no human activity with potential to damage a pipeline occurs without the knowledge of the pipeline operator, and that the organisations and individuals that carry out such activity are aware of the presence of a pipeline, and of the possible consequences of damaging it.

A full package of damage protection measures includes:

(a) Procedural measures as defined above.

(b) Rules and procedures for working safely close to a pipeline.

(c) Physical measures to prevent or minimise damage to the pipeline if items 1 or 2 fail.

(d) An emergency response plan to minimise injury, damage to property and the environment, and interruption to supply, in the event of serious damage to the pipeline.

D3 EFFECTIVENESS OF PROCEDURAL MEASURES

The procedural measures can be considered to be completely effective if every person or organisation intending to undertake excavation, or similar activities;

(a) Contacts the pipeline operator, either directly or via a one-call service, prior to commencing work.

(b) Does not commence work until either;

(i) It is advised by the pipeline operator that it has no assets in the area, or

(ii) In conjunction with the pipeline operator it has developed a safe procedure for the work, and a representative of the pipeline operator is present.

(c) All personnel involved in the work are thoroughly familiar with the work procedure.

Landowner liaison, third party liaison, planning notification zones, and one-call service membership may be effective in bringing about this ideal behaviour.

In case the excavator fails to contact the pipeline operator before commencing work, other measures need to be in place.

Pipeline markers may be effective in alerting an excavator to the presence of a pipeline before excavation commences nearby.


DR04561.doc

Buried marker tape may be effective in alerting an excavator, who has commenced work close to a pipeline, that contact with the pipeline is imminent.

Pipeline patrols may be effective in detecting un-notified excavation activity before any damage can be done.

Remote intrusion monitoring may be effective in alerting the pipeline operator that potentially dangerous activity is taking place near its pipeline, while there is still time to intervene and prevent any damage occurring.

D4 GENERAL

This standard requires that effective measures be put in place against every identified threat to the pipeline. Therefore the effectiveness of each procedural measure implemented is to be evaluated in respect of each individual threat, and not solely in an overall or statistical manner.

Awareness measures are dependent, for their effectiveness, on human action, and thus cannot be guaranteed to be completely effective in every set of circumstances. Therefore, in this Standard: (a) Criteria, that must be met if a measure is to be considered effective against a

particular threat, are given.

(b) At least two awareness measures, that meet these criteria, are required to be in place for every identified external interference threat.

The greater the number of effective procedural measures that are in place, the lower is the probability that all will fail. When two or more effective procedures are in place this probability is very low, but it can never be zero.

Certain measures, for example pipeline markers, are mandatory, and minimum standards are prescribed for them. The minimum standard may, or may not, provide effective protection against a particular threat. Where a measure is being relied upon for protection against a particular threat it must comply with both the minimum standard and the criteria for effectiveness.

D5 CAUSES OF FAILURE OF PROCEDURAL MEASURES

All procedural measures can be rendered ineffective by human failures. There are four types of human failure, failures of attention, failures of memory, failures of knowledge, and deliberate violations of safety rules. Some procedural measures are more susceptible to a particular type of human failure than others. For example, signposting may be useful against the threat from an excavator operator who has forgotten to check for the presence of buried pipes and cables, but may not be very effective against the threat from an excavator operator who believes he has the knowledge and skill to carry out his work without help from the operators of buried facilities.

D6 LANDOWNER AND THIRD PARTY LIAISON

It has been shown that the effectiveness of measures such as pipeline markers, buried marker tape, and one-call systems, is greatly enhanced if effective liaison is maintained with the owners and occupiers of land through which a pipeline runs, and with those organisations and individuals who are involved, in any capacity, with activities that could threaten the pipeline.

Landowner and third party liaison is the heart of the external interference damage protection system.


DR04561.doc

D7 LANDOWNER LIAISON

In this section, for simplicity, the word landowner includes the occupiers of land, whether they own it, or are tenants or employees of the owner.

Landowners are both potential victims of a pipeline accident, and patrol personnel who are on duty at all hours. Good liaison with the landowners has been found to be very effective in preventing external interference damage to pipelines on private property.

Face to face contact is more effective than supplying information by post. The person who carries out pipeline patrols is often the best person to make contact with the landowners in the area he covers. Where possible a semi formal contact should occur at least annually, preferably on the property. During this contact important safety information can be reviewed, and materials, such as a handbook for landowners, can be distributed. Informal contact from time to time, possibly during patrols, helps to reinforce the safety message.

It is more effective to provide landowners with a direct contact number for the person responsible for their area, than to require them to make contact via the operating companys office.

Effective landowner liaison requires up to date information on land ownership and occupancy. Arrangements can be made with the land title, or other appropriate, authorities to ensure that the pipeline operator receives timely notification of changes to the ownership or occupancy of properties on which it has an easement.

An effective landowner liaison program should include comprehensive records of contacts made. The records should be reviewed at regular intervals to assess the effectiveness of the program in reaching the target audience.

D8 THIRD PARTY LIAISON

The number of organisations and individuals, that could potentially be involved in activity that damages a pipeline, is very large, and the first problem of third party liaison is to discover who they are. The threat analysis, required by this standard, lists all the identified threats to the pipeline, and is therefore a good place to begin the search. As well as those directly involved in the activities that threaten the pipeline, liaison should be maintained with the planning authorities that must approve development work in the area. AS2885.3 contains lists the various classes of people and organisations that should be included in an effective Third Party Liaison Program. It also details the types of information that should be communicated.

Remember that the information needs of different organisations are not the same, nor are the needs of different groups of people within large organisations. The information provided should be targeted to the particular audience. It is not wise to assume that information provided to one person, or one level, in an organisation will be effectively transferred to others in the organisation who need to have it.

There are thousands of small contractors who undertake work, such as excavation and boring, that could damage a buried pipeline. To liaise with all of these, and their employees, is probably impossible. Effort spend on liaising with the planning authorities, the larger contractors, and the organisations, such as local government, roads authorities, and utility companies, that employ them, will be more effective.

During the risk analysis, required by this standard, it may be found that the risks associated with some threats to the pipeline are acceptable, but cannot be reduced to zero, or negligible. Giving high priority to liaison with the people and organisations involved in these threats enhances the effectiveness of the external interference prevention program.

Liaison may, and should, take many forms. These include formal processes such as toolbox meetings, distribution of safety literature, and processes for advising of new development


DR04561.doc

plans, and informal processes such as an occasional telephone call to ask if anything interesting is happening. Regardless of the method of communication it is necessary that the target groups are made aware that damaging a pipeline can be both dangerous and expensive, and that they must contact the pipeline operator, either directly or via a one-call service, prior to commencing work at a new site.

In some legal jurisdictions working near a pipeline without notifying the pipeline operator is an offence, and substantial penalties, such as fines, can be imposed. These penalties can be effective in deterring unsafe behaviour. However, a person detected performing un-notified work near a pipeline, and members of his organisation, are prime candidates for education, and education may be more effective than penalties in many cases.

An effective third party liaison program includes comprehensive records of contacts made. The records are analysed regularly to evaluate the effectiveness of the program.

API Recommended Practice RP1162, Public Awareness Programs for Pipeline Operators, contains useful guidance for the development of both Third Party and Landowner Liaison. API RP1162 was written with the regulatory framework of the U.S.A. in mind, and allowance needs to be made for differences between this and the environment in which a pipeline designed in accordance with AS2885 will operate.

D9 ONE-CALL SERVICES

Participation in a one-call service has been shown to be very effective in ensuring that pipeline operators are notified, in good time, of any activity that could damage their facilities. A high proportion of all notifications and inquiries is received via the one-call system. One-call services are effective for pipelines located on both public and private land, but are most effective for public land in populated areas. One-call services are available to cover the whole of Australia. Where a one-call service is available AS2885.3 makes it mandatory for a pipeline operator to participate in it.

The effectiveness of a one-call system is highly dependent on the pipeline operators internal systems being able to respond accurately and rapidly to all inquiries, and to follow up, when necessary, with competent and timely assistance and advice.

Operators of pipelines located in densely populated areas can expect to receive many inquiries every day. In such cases the efficiency and speed of response can be enhanced by employing simple computerised systems to generate standardised responses.

Inquiries are of two main types, those generated during the planning or design stages of a project, and those generated shortly before construction work is to be carried out. Working with developers, architects, and engineering consultants, to design out problems at the planning stage, can save trouble and expense later.

It is poor practice to issue drawings showing the location of a pipeline to a person who is about to commence excavation close by.

The issuing of drawings to competent engineering and architectural organisations, for use during the planning and design phases of a new development is acceptable, and can help ensure there are no major problems when the work eventually goes ahead, which could be months or even years later. However, when this is done it is important to stress the need to place a new inquiry, preferably using the one-call service, shortly before work at the site is planned to begin.

Where the response to a one-call inquiry indicates that there is a pipeline near the proposed work, it is more effective to give the name and direct contact number of the person who will be responsible for providing assistance to the inquirer, than to only provide the telephone number of the operating companys office.


DR04561.doc

It is better to contact an inquirer in person, soon after the response to the inquiry has been forwarded via the one-call system, than to wait for a contact from him.

D10 PIPELINE MARKERS

The purpose of pipeline markers is to alert people, who are planning to work near a pipeline but have not contacted the pipeline operator, to the presence of the pipeline, and the possible consequences of damaging it.

Pipeline markers are considered to be effective against a particular threat if at least one marker can be seen by the person undertaking the threatening activity.

In practice it is usually found that there are few locations where dangerous activity could never occur. Consequently it is considered by many pipeline operators to be sound practice to locate markers:

(a) At every property boundary.

(b) Both sides of every crossing of a road, railway, water course, buried service, etc.

(c) At every abrupt change of direction.

(d) So that from any position on the pipeline route a person can see at least one sign in each direction.

Where structures that might require maintenance or replacement, for example power poles, are located close to a pipeline, attaching a suitable sign to the structure will enhance the effectiveness of the marking system.

Effective pipeline marking applies these rules regardless of land use in the area, and including in remote areas.

Commonly used marker styles, listed in descending order of effectiveness, are:

(a) Large cylindrical signs mounted at eye level.

(b) Large double sided flat signs mounted at eye level.

(c) Large single sided signs mounted at eye level.

(d) Small flat signs at low level, or short tubular signs.

(e) Stencilled kerb signs.

(f) Adhesively attached kerb signs.

(g) Flush mounted pavement signs.

The difference in effectiveness between the first three styles listed above is not very great.

In some locations, for example residential areas, pipeline markers may be considered unsightly, and there have been cases where markers have been removed or relocated by people who found them offensive. A highly visible marker is not effective after it has been removed, and one of the less conspicuous designs may be a better choice in these locations.

Where it is possible to do so, it is more effective to locate markers directly above the pipeline, within a reasonable tolerance of say one metre. It has been observed that most people assume that this is the case. If a person carries out unauthorised excavation believing that he knows exactly where the pipeline is it is best that it actually is where he thinks it is.

Experience has shown that it is impossible to guarantee that every marker will be installed, and will remain for the life of the pipeline, in precisely the correct location. Therefore, while markers should be placed accurately, and preferably directly above the pipeline, it is unwise to indicate, on a marker, the precise location of the pipeline relative to the marker. Doing this may encourage unauthorised excavation by people who do not wish to wait for


DR04561.doc

help from the pipeline operator. It is much better simply to state that there is a pipeline in the vicinity, or words to that effect. Accurate location of a pipeline must be carried out, before commencement of excavation or similar activity, by the pipeline operator using appropriate equipment and procedures.

Special markers are often provided for the assistance of land or aerial patrols. These include kilometre posts that can be read from the air, and brightly coloured fences where pipelines cross property boundaries. These markers can be very useful, but are not considered to be effective against external interference threats.

D11 BURIED MARKER TAPE

Buried marker tape is considered to be effective against a particular threat if it is not possible to damage the pipeline without first exposing the tape, and if a person carrying out the threatening activity is likely to see the tape immediately it is exposed.

There are some threats, for example horizontal directional drilling or deep ripping, where buried marker tape is clearly not effective. However, it is necessary to carefully study the operation of any type of equipment, against which tape is intended to provide protection, to confirm that the criterion for effectiveness will be met, before relying on buried marker tape as a protective measure.

Consideration should also be given to how the equipment is likely to be operated. Buried marker tape is more effective when the equipment operator has an assistant standing on the ground who can watch the progress of the work and who may see the exposed tape earlier than the equipment operator himself. This is often the case when work is being conducted on congested sites where there is a possibility of finding buried obstructions, but is less common in open areas.

The greatest benefit is derived from buried marker tape when it is used in developed areas, or in particularly vulnerable areas such as crossings.

D12 PATROLLING

Patrolling has many functions. The only function considered here is the detection of un-notified activity before the pipeline is damaged.

(a) Patrols contribute to protection from third party damage in three ways. Regular patrolling keeps the patrol personnel up to date with activity in their patrol area such as land development and seasonal agricultural activity. They get to know the people and organisations that live and work in the area and with whom it is necessary to maintain liaison. In this way they may become aware of future excavation activity long before it poses any threat to the pipeline.

(b) Patrolling identifies missing, damaged, or defaced pipeline markers and allows repair or replacement to be carried out in a timely fashion, thus ensuring the marking system remains as effective as possible.

(c) Patrolling may discover activity, with potential to damage the pipeline, that has not been notified to the pipeline operator in advance.

While the value of items one and two above is very real, there are circumstances where a threat to a pipeline may only be detectable for a short period before the danger becomes immediate. To be effective against such threats the patrol frequency needs to be such that the activity will be detected before any damage is done.

Daily patrols will be eff ective against most threats, but each case should be considered on its merits. Patrols at less than daily intervals will usually not be effective, as defined in this Standard, but again each case should be considered on its merits.


DR04561.doc

Where an area is patrolled daily, on working days only, particular attention should be given to liaison with organisations likely to carry out work on weekends and public holidays. These include the emergency repair departments of utility companies.

In rural and remote areas the resources required to mount daily patrols would, in most cases, be more effectively used for landowner and third party liaison.

D13 REMOTE INSTRUSION MONITORING

Remote intrusion monitoring is a recent development and there is little experience in applying it to the protection of pipelines. However it is clear that the ability to detect a potentially dangerous activity, and raise an alarm at an appropriate remote location, is not sufficient to constitute an effective measure. The pipeline operator must also have the ability to mobilise a patrol, and reach the location of the threat, before any damage occurs.

Systems that generate a significant number of false alarms are not likely to be effective.


DR04561.doc

APPENDIX E

PREFERRED METHOD FOR TENSILE TESTING OF WELDED LINE PIPE DURING MANUFACTURE

(Informative)

E1 APPLICABILITY

This method of determining the tensile properties is applicable to pipe having an outside diameter of not less than 168.3 mm and manufactured in all other respects in accordance with API Spec 5L.

E2 METHOD FOR DETERMINING TENSILE PROPERTIES

The tensile properties of pipe should be determined as follows:

Yield strength The yield strength of pipe should be determined in accordance with the method set out in AS 1855.

The frequency of testing should include one for each production batch at least. NOTES:

1 The use of this method normally results in a more correct determination of yield strength. The reported ratio of yield strength to tensile strength may be higher than that determined when other methods are used.

2 The lot size is determined by reference to the Standard to which the pipe is manufactured.

Tensile strength and elongation The tensile strength and the elongation of a rectangular specimen taken transversely from the strip, skelp or plate should be determined. The minimum frequency of testing should be one of each heat.

NOTE: The tests on strip or plate fulfil the requirements of the mill control tensile test. The results of these tests are also applicable to the pipe.

Weld The tensile strength of a rectangular specimen taken transversely from a longitudinal or spiral weld made with electrodes or wire should be determined. The frequency of testing should be one for each production batch.

The weld tensile test is not required for welds made without electrodes or wire.

E3 CRITERIA OF ACCEPTANCE

The criteria for acceptance of tensile properties should be as specified in API Spec 5L unless otherwise approved.


DR04561.doc

APPENDIX F

FRACTURE TOUGHNESS TEST METHODS

(Normative)

F1 SCOPE

This Appendix gives test methods for determining the resistance of pipe material to brittle fracture and low energy tearing ductile fracture.

F2 SAMPLING

Test specimens for determining fracture appearance and transverse energy absorption shall be removed from a sample so that the length of the test specimens is in the circumferential direction, in the approximate position shown in Figure F2. Samples may be taken from a finished pipe, strip or plate with the same orientation, providing any changes in properties are determined and taken into account. A test specimen showing material defects or incorrect preparation, whether observed or after breaking, may be replaced by another. The replacement test specimen shall be considered as the original.

F3 FRACTURE APPEARANCE TESTING FOR CONTROL OF BRITTLE FRACTURE

F3.1 General

Fracture appearance testing for control of brittle fracture shall be performed using the drop-weight tear test (DWTT) in accordance with AS 1330 or an alternative Standard for the same test method. No other method is approved for this purpose.

F3.2 Test specimens

Two test specimens shall be taken from one sample from each heat.

F3.3 Test temperature

The test temperature shall be as specified in Clause 4.8.4.

F3.4 Criteria of acceptance

If the average value of the shear fracture appearance of the two test specimens taken from the sample representing the heat is not less than 85%, all pipes from that heat shall be acceptable.

If the average shear fracture appearance of the two specimens is less than 85%, two more samples shall be selected and two test specimens taken from each sample shall be tested. If the average shear fracture appearance of these four additional test specimens is not less than 85%, all pipes from that heat shall be acceptable.

If the average shear fracture appearance for the four additional test specimens is less than 85%, two test specimens taken from each sample in the heat may be tested. If the average shear fracture appearance of 80% of all the test specimens is not less than 85%, all pipes from that heat shall be acceptable.

If the average value of the shear fracture appearance of the two specimens representing a pipe is not less than 85%, that pipe shall be acceptable.

NOTE: Neither AS 1330 or API RP5L3 contain a requirement that in order for a test to be considered valid, there should be a region of cleavage fracture within the area directly beneath the notch. Strictly speaking, such a requirement should exist. However, until agreement is reached on


DR04561.doc

alternative methods of test for steels in which fracture initiation is difficult, no such action can taken.

F4 ENERGY ABSORPTION TESTING FOR CONTROL OF LOW ENERGY TEARING DUCTILE FRACTURE

F4.1 General

Energy absorption testing for control of low energy tearing ductile fracture shall be performed using the Charpy V-notch impact test in accordance with AS 1544.2 or alternative Standards for the same test method.

F4.2 Test specimens

Three test specimens (see FigureF2) shall be taken from one sample from each heat. The thickness of each test specimen shall be the greatest of 5 mm, 6.7 mm, 7.5 mm and 10 mm that can be obtained by cutting and machining from unflattened pipe, strip or plate.

F4.3 Test temperature

The test temperature shall be as specified in Clause 4.10.3.

F4.4 Criteria of acceptance

The average absorbed energy shall exceed the requirement calculated according to Clause 4.3.7.2 after taking into account the thickness of the test specimens. The method of allowing for the thickness of the test specimen may be either the ratio of the thickness of the test piece used to the standard 10 mm Η 10 mm test specimens, or alternatively upon the basis of an experimental correlation for the material under consideration.

90˚

(b) Spiral welded pipe(a) Longitudinal welded pipe

90˚

or

Weld Weld

or

FIGURE F2


DR04561.doc

APPENDIX G

FRACTURE CONTROL PLAN FOR STEEL PIPELINES

(Informative)

G1 SCOPE

This Appendix provides advisory information on the development of the fracture control plan required by Clause 4.8.

The fracture control plan may be required to define the measures to be implemented to limit the extent of fracture propagation in the event that a pipeline rupture occurs. A pipeline rupture will occur when there is a weakening flaw larger than the critical size determined by the pipeline operating parameters and the resistance of the pipe material in fracture initiation. Fracture mechanics analysis methods provide a method of assessment of the critical size.

Where this standard is used for pipelines constructed with Corrosion Resistant Alloy pipe, attention is drawn to the requirements of Clause 3.1

Appropriate references are the following:

(a) Fracture Control in Gas Pipelines, Proceedings of the WTIA/APIA/CRC for Materials Welding and Joining Int'l Seminar, Edited by B Rothwell, WTIA, Sydney 1997.

(b) Eiber R J & Bubenik T J, Fracture Control Methodology, Proceedings of the Eighth Symposium on Line Pipe Research : American Gas Association, Houston 1993.

(c) Eiber R J, Bubenik T J and Maxey W A, Fracture Control Technology for Natural Gas Pipelines, American Gas Association NG18, Report No. 208, December 1993.

Two modes of propagating fracture have been recognized in pipelines. These are brittle fracture and tearing fracture. Tearing fracture is commonly referred to as ductile fracture.

G2 FACTORS AFFECTING BRITTLE AND TEARING (DUCTILE) FRACTURE

G2.1 General

The following factors are recognized in the control of propagation and arrest of fracture in petroleum pipelines:

(a) The fluid parameter speed-of-decompression wave, which is determined by the type of fluid and the pressure.

(b) The operating parameters pipe wall stress and temperature.

(c) The pipeline parameters: pipe fracture toughness, pipe wall thickness, pipe diameter and pipe backfill or water depth.

The data in this Appendix is derived from the results of research undertaken on gas pipelines, but not on liquid petroleum pipelines.

G2.2 Exclusions from the need for a fracture control plan

Fracture control plans are not required where the pipeline is operating with a stable liquid at temperatures above 0ºC. A fracture control plan is required in all other circumstances as shown in the decision tree figure 4.10.2(A)


DR04561.doc

G2.3 Fluid parameters

The phase of the fluid (i.e. gas, liquid, or mixture of gas and liquid) and the actual composition of gases and liquids and their physical constants affect the speed of propagation of a fracture and the conditions of arrest. Fracture arrest is sensitive to the ratio of the speed of propagation of the fracture and the speed of the decompression wave in the fluid. The speed of the decompression wave can be measured experimentally or calculated from the physical constants for most fluids. It can also be influenced by the presence of small droplets of hydrocarbon liquids carried as a mist or vapour, which change phase during decompression.

In a pipeline that is conveying only a liquid (including water), the low energy tearing fracture mode cannot be supported, because of the high speed of the decompression wave in the liquid. Also, the pressure in a ruptured pipeline conveying a liquid falls rapidly with a loss of relatively small amounts of liquid, because of the high bulk modulus. For these reasons, a fracture control plan for a pipeline that conveys only liquid is only required if there is potential for fast fracture propagation in the brittle mode. This is only deemed to occur if the design temperature is 0ºC or lower..

In a pipeline that is conveying compressed gas, a decompression wave travels slower than it would in a liquid. As brittle fractures have fracture speeds faster than the decompression wave speed for most operating conditions of gas pipelines, neither the stress in the steel nor the temperature of the steel ahead of the crack is affected by decompression. A fracture control plan is required to ensure that arrest occurs by reduction of the fracture speed below the decompression wave speed. This is effected by the change of fracture mode from brittle fracture to tearing (ductile) fracture, which occurs above the fracture appearance transition temperature. Sufficient fracture energy absorption capacity must also be present above the fracture appearance transition temperature to slow the fracture velocity, otherwise the fracture may propagate in the low energy ductile tearing mode.

A pipeline conveying a mixture of liquids and gases can be expected to closely follow the behaviour of a gas pipeline, and for fracture control purposes, should be treated as such.

The fracture control plan for a pipeline conveying an HVPL should be based on the decompression behaviour of the fluid being transported.

Where a pipeline is initially intended to convey petroleum liquids and is later to convey gas, mixed fluids or HVPL, the fracture control plan should reflect the future use. This Standard requires a pipeline intended to convey HVPL to be designed as a gas pipeline.

The fracture control plan for a pipeline that is intended to convey gas or a mixture of gas and liquid should prevent both brittle fracture propagation and low energy ductile tearing fracture propagation.

G2.4 Operating parameters

G2.4.1 Introduction

Both forms of fracture propagation are affected by the operating stress in the pipe wall. Brittle fracture occurs only below the fracture appearance transition temperature.

G2.4.2 Brittle fracture

Provided the stress level is above the threshold level, brittle fracture propagation is not very sensitive to operating stress and, therefore, different fracture appearance requirements are not required for different operating stresses. The energy to propagate a brittle fracture is derived from the elastic energy of the steel, which is derived from the fluid pressure. Where the operating stress is less than the threshold stress, usually taken as 85 MPa, the fracture control plan need not specify fracture appearance requirements. The operating stress shall be assessed at the lowest pipe body temperature, which will exist concurrently with a stress greater than the threshold stress.


DR04561.doc

Propagating brittle fractures in longitudinal welds (ERW or SAW) have not been recorded in operating pipelines to date. The fracture appearance tests that have been developed to determine the resistance to fracture propagation in the body of the pipe are not applicable to the weld metal or the heat-affected zone. In many weld metals, it is not possible to interpret the fracture appearance as shear or ductile fracture zones. This Standard requires that the longitudinal joints be offset at butt welds. Therefore, it is not necessary for the fracture control plan to specify fracture appearance properties for longitudinal welds or the heat-affected zones.

G2.4.3 Ductile tearing

Operating stress and diameter are significant for ductile fracture. The higher the operating stress or the larger the diameter, the greater is the chance of ductile failure.

This Standard adopts DN200 as the diameter below which neither tearing (nor brittle) fracture need be considered.

Operating stresses below a threshold stress defined for the purposes of this Standard as 30% of the flow stress (Figure 4.8.2(A)) adopts 40% SMYS as a default approximation) are not regarded as capable of supporting low energy ductile tearing. Calculation methods for determining the level of pipe body toughness required, to arrest a propagating fracture have been developed by several authorities.

The level of toughness to be specified in the fracture control plan is affected by the length of the pipeline within which the fracture must be arrested either side of the point of initiation, and by the expected spread of toughness results in the pipe relative to the arrest value. A default value of 0.75 of the calculated toughness for immediate arrest may be used for pipe grades up to X70; However, for pipe of X80 grade (550 MPa), a unique value must be established. The use of the default value of 0.75 is designed to provide more than a 95% chance of arrest within two pipe lengths by ensuring that 50% of pipes in an order meet the predicted arrest requirement. The choice of fracture arrest length should be appropriate for the pipeline design and in particular the location class. The fracture control plan may define a different control strategy e.g. the use of crack arrestors.

Ductile tearing fractures are not known to have occurred in either the weld metal or heat-affected zones of longitudinal weld seams. In addition, AS 2885.2 requires longitudinal welds to be staggered. For these reasons, the energy absorption properties that are specified by this Standard are limited to the pipe body.

G2.4.4 Temperature

The inherent fracture toughness of pipe steels shows a marked change over a transition temperature range. The change is from brittle fracture below the transition range to ductile fracture (tearing) above the transition range. The change is usually characterized by the fracture appearance transition temperature (FATT), measured as the temperature at which 85% of the surface appearance of a propagating fracture is shear.

The local temperature of pipeline steel is dependent on the climate (for a submerged pipeline this is the temperature of the water), the location relative to the surface of the ground and the contents of the pipeline, which may be modified by thermodynamic effects. Except where stress is lower than the threshold stress for brittle fracture, a pipeline should be pressure tested and operated at a temperature above the fracture appearance transition temperature.

G2.4.5 Limitations on testing

Meaningful tests for fracture appearance and energy absorption become more difficult as the diameter decreases and the wall thickness reduces. This Standard requires that fracture appearance testing be conducted using the dropweight tear test method set out in AS 1330. AS 1330 states that the dropweight tear test is intended for the line pipe, or strip or plate


DR04561.doc

intended for line pipe, having an outside diameter of not less than 300 mm and that difficulty may be experienced in applying the test to material of less than 5 mm thickness. AS 1330 excludes testing of weld metal.

This Standard permits the testing of pipe materials for fracture properties to be carried out on strip, plate or finished pipe. With modern pipe steels, the effect of pipe forming on fracture properties is usually very small.

G2.5 Calculation of Charpy energy requirements for the arrest of ductile tearing fracture

The Charpy energy requirements of the fracture control plan for the arrest of ductile tearing fracture should be determined by an appropriate method taking into account the pipeline design, especially the MAOP, SMYS, diameter, the conveyed fluid, the backfill conditions, and the required arrest length. Suitable methods for most pipeline designs are given in the references listed in Paragraph G1 (see also Clause 4.8.4).


DR04561.doc

APPENDIX H

STATION PIPING STANDARDS AND DESIGN FACTORS

(Normative)


DR04561.doc

APPENDIX I

SHORT TERM TEMPERATURE EXCURSIONS PAPER 4.14

(Normative)


DR04561.doc

APPENDIX J

FATIGUE

(Informative)

J1 GENERAL

Fatigue is generally not considered in most pipeline designs, principally because the number of stress cycles that occur in the pipeline life are typically fewer than required to initiate a fatigue related failure in the pipe shell.

However special consideration shall be given where:

(a) There are welded connections of any kind onto the pipe because as-welded joints have no fatigue crack initiation life;

(b) The pipeline experiences significant pressure cycling range and/or frequency;

(c) Welded connections onto the pipe are subject to cyclic structural or inertial loads

An engineering assessment undertaken to revalidate the pipeline for changed operating conditions, including an extension of the design life should include an assessment of the fatigue life of a pipeline.

Fatigue may be an issue in Station piping design. However with the nominated piping standards, AS 4041 and ASME B31.3 each contain methods for considering, and designing for fatigue. Compliance with these Standards will ensure that that the matter is properly addressed.

The following guidance information is extracted from IGE/TD1 Steel Pipelines for High Pressure Gas Transmission Edition 4, and may be used as reference information in assessing conditions where fatigue may require more detailed assessment. Changes have been made to the numbering and cross referencing used in TD1 to ensure its consistency with AS 2885.

NOTE: The TD1 guidance information applies to plain pipe shells and not to welded connections. Welded connections should be assessed in accordance with AS 1210 or other approved Standard.

J2 MATERIALS

Provided linepipe steels are purchased in accordance with the specifications referenced Section 3 of this Standard and the design complies with Section 4 this Standard, all fatigue design requirements should be satisfied.

J3 DESIGN

J3.1 General

Consideration should be given to the fatigue life of any pipeline, to ensure that any defect which survives the hydrostatic test, or which is not detected by subsequent on-line inspection, does not grow to a critical size under the influence of pressure-cycling.

(A) Special consideration should be given to the adequacy of fittings. NOTE: Generally, fittings are designed to a standard which will ensure that they experience lower stress ranges than linepipe when a pipeline is pressure-cycled. Where such circumstances prevail, fittings need not be subjected to a fatigue evaluation.

Consideration should be given to other sources of cyclic stressing, for example thermal loading immediately downstream of a compressor station, which may affect the fatigue life


DR04561.doc

of the pipeline. Specialist advice should be obtained if these are likely to be significant, as the guidance in clause J3.2 is appropriate only for pressure-cycling.

J3.2 Definition of fatigue life NOTE: Fatigue life may be defined by the simplified approach described in clause J3.2.1 provided the pipeline has been hydrostatically tested to the requirements of this Standard and is constructed from linepipe purchased to Clause 3 of this Standard. Alternatively, a detailed fracture mechanics calculation, as described in clause J3.2.2 may be used if: 1 the pipeline has been hydrostatically tested to a level lower than specified in Table 11 or 2 the pipeline will experience maximum stress ranges in excess of 165 MPa.

The required fatigue life of the pipeline should be defined in terms of allowable pressure (stress) ranges and associated numbers of cycles. For the purposes of these Recommendations, a 40-year life has been assumed but other lives may be appropriate in which case they should be documented.

NOTE: Where the maximum daily hoop stress range is less than 35 MPa, a fatigue assessment is not required assuming the required life is less than 15,000 cycles

J3.2.1 Simplified approach

(d) Constant daily pressure-cycling

Where the magnitude of daily pressure-cycling is constant, the fatigue life should be determined from:

S3N = 2.93 x 1010

S = constant amplitude stress range (MPa)

N = number of cycles NOTES: 1 For example, if a life of 15,000 stress cycles is required (equivalent to one cycle per day over

40 years), the equation limits the maximum daily variation in hoop stress to 125 MPa.. 2 The relationship between stress range and the number of cycles is shown in Figure J3.2.1.

Where S exceeds 165 MPa, specialist advice should be obtained or the method given in Clause J3.2.2 used.

(e) Variable pressure-cycling NOTE: Where the magnitude of daily pressure cycling is not constant, the fatigue life may be evaluated on the basis of (a) above, by totalling the usage of fatigue life from each stress range.

The following condition for the damage fraction should be satisfied to obtain an acceptable fatigue life.

0.1≤=∑i

iF N

nD

Where:

ni = the actual number of cycles accumulated at stress range Si

DF = damage fraction

SI = stress range

Ni = number of stress cycles allowed at stress range Si (clause J3.2.1(a))

If the anticipated value of DF exceeds 0.5, the actual cycles accumulated during operation should be recorded in accordance with clause J3.3.

FIGURE XX2.1 RELATIONSHIP BETWEEN STRESS RANGE AND NUMBER OF CYCLES


DR04561.doc

J3.2.2 Detailed fracture mechanics approach NOTE: Where the maximum daily stress range exceeds 165 MPa, and/or the simplified method in clause 6.6.2.1 is not appropriate or where it is required to assess the fatigue life of defects detected in service, a detailed fracture mechanics calculation may be used to determine the fatigue life. Recommended methods for such calculation are given in BS 7910.

Account should be taken of the deleterious effect of pipe ovality and local shape deviations.

The analysis method, material properties and other input data used in the assessment should be documented and fully justified.

The actual cycles accumulated during operation should be recorded in accordance with clause J3.3.

J3.3 Definition of stress cycles

Any complex (variable amplitude) stress cycles should be recorded and then converted to an equivalent spectrum of constant amplitude stress cycles using a documented algorithm such as the Reservoir or Rainflow method. The appropriate method from clause J3.2 should then be used to define the fatigue life.

NOTE: Further details of these algorithms may be found in ASTM E1049-85.

J3.4 Revalidation

When records or estimates show that the design fatigue life has been reached, the pipeline should be revalidated by hydrostatic testing, or by on-line inspection using a tool capable of the detection of longitudinal crack-like defects, particularly in or near the seam weld. If inspection is used, the detection limits of the inspection tool for crack-like defects should be taken into account when establishing the future fatigue life of the revalidated pipeline.


DR04561.doc

APPENDIX K

MAOP UPGRADE

(Informative)

THIS APPENDIX HAS NOT BEEN WRITTEN.

GIVEN THE DETAIL IN SECTION 9, THE APPENDIX IS PROBABLY NOT REQUIRED


DR04561.doc

APPENDIX L

SUITABILITY OF ASSOCIATED STATION EQUIPMENT

(Normative)


DR04561.doc

APPENDIX M

FACTORS AFFECTING CORROSION

(Informative)

M1 GENERAL

The internal and external surfaces of a steel pipeline are potentially subject to corrosion. Whether corrosion will occur to any significant extent depends on many environmental and operational factors. The total effect of these factors on the likely rate of corrosion usually cannot be assessed until the pipeline has been installed. Even then, a complete assessment may not be possible because the corrosive effects of many of the factors may vary daily or seasonally, and some of the factors may have a synergistic effect when taken in combination. The principal factors that should be considered when assessing the rate of corrosion are given in Paragraphs N2 to N4.

M2 INTERNAL CORROSION

Factors to be considered for internal corrosion are as follows:

Features of fluid transported, to include

(a) chemical composition;

(b) hydrogen sulphide, carbon dioxide and other acidic components;

(c) oxygen content;

(d) water content/water dewpoint

(e) microbiological organisms.

Operation, to include

(f) frequency and magnitude of fluctuations of pressure and temperature;

(g) maximum, minimum and average pressures and temperatures

(h) flow rate and regimes

M3 EXTERNAL CORROSION

Factors to be considered for external corrosion are as follows:

Environment, to include

(a) chemical composition of dissolved salts;

(b) degree of aeration;

(c) moisture content;

(d) presence of sulphate reducing bacteria, and their state of activity;

(e) the pH value

(f) resistivity.

Abnormal environmental factors, to include

(g) ash, cinders or other corrosion-inducing material in the right of way;

(h) mineral ores in the pipeline route that are cathodic to steel;

(i) the presence of large quantities of organic material, including marine growth;


DR04561.doc

(j) Termites, rodents and other pests that may attack coatings and other pipeline materials.

Electrical currents, to include

(a) occurrence of d.c. currents from traction systems and other man-made sources;

(b) occurrences of telluric currents from solar and other celestial sources;

(c) induced a.c. currents;

(d) a.c. voltage gradients as may exist near power stations;

(e) lightning strikes.

Climate and tides, to include

(a) atmospheric pollution;

(b) frequency of wetting and drying of the surface of the pipe;

(c) fluctuations in watertable level,

(d) humidity;

(e) presence of mist and spray.

Operation, to include

(f) maximum, minimum and average surface temperatures of the pipe;

(g) frequency and magnitude of fluctuations of temperature;

(h) stress level of the pipeline, and magnitude and frequency of stress variations.

Other factors, to include

(a) incompatibility of materials (e.g. those in earthing systems and concrete reinforcement);

(b) dissimilar metals in contact;

(c) deterioration of protective coatings;

(d) resistance to ageing of the corrosion protection system in air, water and sunlight;

(e) abrasion and erosion.

M4 ENVIRONMENTALLY ASSISTED CRACKING

Steel pipelines can experience environmentally assisted cracking by the following three different mechanisms:

Hydrogen induced cracking (HIC)

Sulphide stress corrosion cracking (SSCC)

Stress corrosion cracking (SCC) (high and low pH types)

Hydrogen assisted cold cracking (HACC).

Further information on environmental related cracking is given in Appendix H.

M5 CORROSION PRIOR TO COMMISSIONING

Pipe may be subject to corrosion in the period between manufacture and the commissioning of the pipeline. Means should be taken to protect against this corrosion.

Pipe that is properly stored or installed in a dry environment usually does not suffer significant corrosion.


DR04561.doc

Factors that can cause corrosion include:

(a) Stockpile sites located in a corrosive atmospheric environment (including marine and coastal environments)

(b) Exposure to salt water during marine transport

(c) Poor stockpile management, that allows moisture retaining material (like dust and grass) to accumulate between and in the pipe

(d) Storage in stockpile for an extended period

(e) Pipes stored in direct contact with sand or soil

(f) Water accumulation in pipe while in stockpile

(g) Exposure to floodwater while in stockpile

(h) Poor construction practice that allows water to enter the installed pipe during the construction period

(i) Floodwater entering the installed pipe

(j) Improperly managed hydrostatic test water

(k) The presence of sulphate reducing or acid producing bacteria in water used for hydrostatic test

(l) Poor drying of the pipeline after hydrostatic testing

(m) A prolonged period between hydrostatic testing and pipeline commissioning, particularly if the pipe is not filled with an inert atmosphere, or is allowed to breathe during the period

(n) Failure to install an adequate temporary cathodic protection system on pipe that is installed in the ground

Pipe that is damaged by corrosion prior to commissioning must be assessed for its structural integrity in accordance with AS 2885.3 prior to being approved for service at its design conditions.


DR04561.doc

APPENDIX N

ENVIRONMENT RELATED CRACKING

(Informative)

N1 GENERAL

This Appendix provides guidelines on the assessment of environmentally assisted cracking as required in Clause 8.3.4.

Environmentally assisted cracking occurs as a result of the exposure of a stressed steel to a specific environment. There are five main types of environmentally assisted cracking that can affect steels commonly used in pipelines:

(a) Stress corrosion cracking (SCC) in high pH carbonate/bicarbonate solutions that can be generated by the action of cathodic protection in the environment around the pipe and affect the external surface of the pipe at regions of coating defects. (see Paragraph H2).

(b) SCC which occurs in low pH (< 7.5) anaerobic environments containing dilute carbon dioxide solutions. Carbonic acid and bicarbonate ions are usually present in proximity to the steel surface. (see Paragraph O3).

(c) Hydrogen induced cracking (HIC) due to hydrogen sulphide in the fluids within the pipeline.

(d) Sulphide stress corrosion cracking (SSCC); a different form of stress corrosion cracking which is primarily related to the hardness of the steel.(see Paragraph O4).

(e) Hydrogen assisted cold cracking (HACC) due to generation of hydrogen caused by high cathodic protection current density in conjunction with a susceptible steel. (see Paragraph O5).

N2 HIGH pH (CLASSICAL) STRESS CORROSION CRACKING

N2.1 Description

High pH stress corrosion cracking is a form of cracking caused by dissolution of grain boundaries in stressed metals that are in contact with aqueous solutions. Stress corrosion cracking is most frequently observed in the form of intergranular cracking and generally occurs as a group or 'nest' of small cracks parallel with the axis of the pipe. It has been found most commonly on pipes coated with field applied coal tar enamel, tape or asphalt, or in similar factory applied coatings where the surface preparation did not involve grit blasting. It is generally accepted that abrasive blast cleaning together with application of high quality coating materials is a significant factor in reducing the likelihood of SCC initiation.

N2.2 Conditions

Pipeline steels can develop high pH stress corrosion cracking if the following conditions are present:

(a) The stress level is in excess of a value of stress called the threshold stress. The threshold stress is determined in laboratory tests conducted under conditions which greatly accelerate the initiation and propagation of cracking. The value of the threshold stress determined in that way should not be used to determine a safe value of pressure stress in an operating pipeline. Cyclic variations of stress in pipe steel have the effect of reducing the threshold stress.


DR04561.doc

(b) Note:SCC will not occur below some value of operating stress (not numerically the same as the "threshold stress" as defined above) unique to the particular conditions in a given pipeline. However when the mean operating stress and any superimposed cyclic stresses are such as to allow the initiation and propagation of SCC, then any further increase in stress will accelerate the rate of cracking. The corollary of this is that reductions in operating stress will have the effect of reducing the rate of cracking.

(c) The surface of the pipe is in contact with an alkaline aqueous solution of carbonate, bicarbonate, nitrate or hydroxide and having a pH in the approximate range of 8 to 12.

(d) The pipe-to-soil potential is within the range of -550 mV to -750 mV, measured against a calomel electrode or −625 mV to −825 mV measured against a copper/copper sulphate electrode.

NOTES: 1 The potentials stated are those measured at the steel-to-electrolyte interface at coating defects

or within crevices beneath disbonded coating, not those taken at the soil surface as with conventional pipe-to-soil potential measurements. Application of cathodic protection will usually shift the conventional pipe-to-soil potential to more negative than -850 mV to copper/copper sulphate, but the interface potential may still lie within the cracking range.

2 The range of potential over which cracking can initiate is temperature dependent. Increasing the operating temperature leads to a more rapid crack growth and widens the range of critical pipe-to-soil potential for the initiation of cracking.

Under normal conditions SCC usually takes some years to initiate. In some cases the rate of growth may accelerate and lead to failure of the pipeline. In other cases the cracks may slow down and even stop. The growth rate through the wall usually slows considerably with an increase in depth. Adjacent cracks may join others to form a single defect having a critical length, which may leak or (more frequently) result in a burst.

N3 LOW pH (NEAR NEUTRAL) STRESS CORROSION CRACKING

N3.1 Description

Low pH SCC is a form of mainly transgranular cracking occurring in a near neutral (pH 5-7.5) environment of dilute bicarbonate/carbonic acid solution and is characterized by very high densities of cracks in localized regions.

Low pH SCC was first recognized in 1985 in Canada but has since been found on pipelines in the USA, Italy and parts of Russia. It has been associated predominantly with the use of tape coatings, only occasionally on asphalt coated pipes. Extensive investigations into this form of cracking have been carried out on pipelines in Canada.

N3.2 Conditions

Pipeline steels can develop low pH stress corrosion cracking if the following conditions are present:

(a) The stress level is above 40% SMYS, although crack growth rates appear to be independent of applied stress. Fluctuating stresses are important in the growth of SCC cracks.

(b) The surface of the pipe is in contact with low conductivity near neutral pH trapped water containing carbonic acid, bicarbonate and several other species.

(c) The cathodic protection potential is below the fully protected level.

The severity of SCC appears to be increased by the presence of bacteria including sulphate reducers and the absence of oxygen.


DR04561.doc

Temperature has no apparent effect on transgranular stress corrosion cracking.

The occurrence of low pH SCC usually involves disbondment of the anti-corrosion coating. In some circumstances the cathodic protection current penetrates only a short distance under a disbonded coating. For tape coatings, soils such as heavy clay type soils, which enhance disbondment, are associated with SCC sites. Susceptible locations are generally anaerobic and have poor soil drainage.

It has been suggested that the mechanism of low pH SCC is a hydrogen related process with the source of hydrogen believed to be dissolved carbon dioxide.

N4 HYDROGEN SULPHIDE CRACKING

N4.1 General

Hydrogen sulphide in the presence of free water can cause cracking and failure of pipeline steels in two unrelated ways, known as hydrogen induced cracking (HIC) and sulphide stress cracking (SSCC). In both cases, the hydrogen generated by the corrosion reaction between the pipeline steel and the hydrogen sulphide enters the steel matrix and causes cracking. Only low levels of hydrogen sulphide are necessary for attack to occur; however, free water must also be present. In the absence of water, the corrosion reaction, which releases hydrogen, cannot occur and no cracking results.

N4.2 Hydrogen induced cracking (HIC)

HIC is also called stepwise cracking or blistering, and is caused by a migration of hydrogen ions formed in the hydrogen sulphide corrosion reaction into suitable sites within the steel microstructure. The hydrogen ions combine to form hydrogen molecules, which are then too large to diffuse out of the steel. The resulting hydrogen pressure build-up at sites within the steel lattice exceeds the material yield strength and causes blisters and cracks to develop. Inclusion stringers in 'dirty' steels provide sites for the hydrogen to gather and recombine. 'Clean' steels contain no such sites and are immune to HIC attack.

The catalytic action of the sulphide ion causes a several-fold increase in the amount of hydrogen diffusing into the steel and, without the presence of iron sulphide on the steel surface, HIC is unlikely to occur.

The best approach to preventing HIC in new structures is to use 'clean' steels or steels with modified inclusion shape that do not have suitable sites in their microstructure for hydrogen to accumulate and cause cracking. NACE TM0284 describes procedures for evaluating the resistance of pipeline steels to stepwise cracking. Steels passing this test are referred to as HIC-resistant steels.

N4.3 Sulphide stress corrosion cracking (SSCC)

SSCC results from the embrittling effect of hydrogen penetration and is typically observed in regions of reduced ductility in high strength steels or hardened zones in the lower strength steels used for pipelines. These hardened zones may be the heat affected zone of welds, or hard spots due to problems in the rolling of the steel.

The susceptibility of steels to SSCC is indicated by a hardness of more than 22 HRC (Hardness Rockwell C). By limiting the hardness of the pipeline steel to this value, failure by SSCC can be completely avoided.

Further information on preventing SSCC is contained in NACE Standard Materials Requirements MR0175.

N5 HYDROGEN ASSISTED COLD CRACKING (HACC)

Levels of cathodic protection applied to pipelines in accord with AS 2832.1 are generally insufficient to result in significant evolution of hydrogen; nevertheless hydrogen may be


DR04561.doc

evolved from small, narrow coating defects in lower resistivity soils in some situations. If the pipeline contains regions in which the microstructure is susceptible to HACC due to the presence of hard spots or mechanical damage the evolution of hydrogen from the cathodic protection system may become a problem and could cause failure.

With modern pipeline steel manufacture, hard spots would not be expected to be present, and are only likely to arise from causes subsequent to pipe manufacture.

Mechanical damage may be caused by inadvertent and unobserved contact of equipment working in the vicinity of the pipeline. It is therefore important to avoid excessive levels of cathodic protection and to avoid or repair instances of mechanical damage as far as practicable.

NOTE:On pipelines subject to stray current fluctuations or telluric effects it may not be possible to avoid intermittent periods of highly negative potentials and the hydrogen evolution that may result.

N6 DESIGN CONSIDERATIONS TO MITIGATE STRESS-CORROSION CRACKING

N6.1 General

Stress-corrosion cracking has to be carefully considered during the design of a pipeline, particularly where the pipeline will be subjected to cyclic stresses and to high temperatures (e.g. downstream of a compressor station in a gas pipeline).

Stress corrosion cracking requires the presence of a cracking environment, a stress, and a susceptible steel. If one of these parameters is absent SCC cannot occur. All pipeline steels have been found to be susceptible to SCC to some extent. Mitigating the risk of SCC by selection of steels based upon threshold stress tests is not recommended. Because at least two of the remaining conditions need to be simultaneously present for external stress-corrosion cracking to occur, the pipeline design should eliminate or at least minimize the effect of some or all of these conditions.

Research studies in recent years have produced methods for estimating SCC susceptibility based on analysis of the various contributing factors. The effects of the various contributing factors are weighted, allowing the pipeline designer to trade off one factor against another in the design process to produce a given susceptibility outcome. The chief factors to be included in the analysis are as follows:

(a) Surface preparation prior to coating.

(b) Hoop stress.

(c) Stress fluctuations.

(d) Pipeline operating and maximum temperatures.

(e) Type of coating.

(f) Age of pipeline.

(g) Type of soil.

(h) Soil resistivity.

(i) Soil moisture.

(j) Level of cathodic protection.

(k) Initial test pressure.

When designing a pipeline to meet a given requirement in terms of SCC risk, it is essential that both the current and future operating regimes of the pipeline are taken into account.


DR04561.doc

The design parameters should be clearly documented and SCC risk re-evaluated if any of the operational conditions move outside of these constraints.

N6.2 Stress

The threshold stress levels determined in accelerated laboratory tests are not applicable to the pressure stress of the operating pipeline. Such threshold stresses can only be used for comparing different steels. However since no systematic investigation has ever been conducted into the within laboratory and between laboratory reproducibility of the test method no conclusion can be drawn upon the slight differences that are observed on different steels. The values that are measured are typically measured in the range 75% to 85% of the actual yield stress, as measured in the longitudinal direction.

On this basis, whilst reductions in growth rate, and a lengthening in service life can be expected to result from reductions in mean operating pressure stress and cyclic stress range, it is not possible to use material selection as a means of mitigating SCC.

N6.3 Cyclic variation of stress

The frequency and the range of cyclic stresses strongly influence the growth rate and initiation life of both high and low pH SCC.

Cyclic variations of pressure are often inevitable in gas pipelines that serve mixed industrial, commercial and domestic markets, or where line pack is used to assist in meeting daily gas demand fluctuations. The effect of these variations must be taken into account when evaluating the overall SCC susceptibility of a given section of pipeline.

N6.4 Pipeline anti-corrosion coating

Since it has been shown that the pipe-to-soil potential is likely to remain within the critical range for SCC under disbonded coating, a well applied good quality anti-corrosion coating will reduce the risk of stress-corrosion cracking.

The bond between the anti-corrosion coating and the pipe must resist mechanical and cathodic disbonding, particularly in the regions adjacent to holidays. Coatings that are prone to cathodic disbonding and include a highly insulating layer such as polyethylene should not be used when other SCC risk factors are high.

N6.5Age of pipeline

Stress corrosion cracking of a pipeline is a phenomenon that follows phases of initiation and growth prior to reaching a state where pipeline failure can occur. The initiation phase generally occurs over several years, followed by growth of cracks in length and depth. Cracks then continue to initiate and grow over time, generally in nests where conditions are favourable. Failure usually occurs when cracks grow sufficiently to link together to extend beyond a critical length, resulting in pipe rupture. Other factors being equal, older pipelines are therefore at greater risk of failure due to SCC. Most SCC failures have occurred on pipelines that have been in service for 20 years or more, although failures have been known to occur in as little as 6 years after commissioning.

N6.6 Soil environment

The soil surrounding a pipeline can play a part in many ways in establishing conditions that are conducive or otherwise to development of SCC. For example, expansive soils such as some clays can damage coatings susceptible to soil stress, resulting in exposure of the pipe surface or causing loss of coating adhesion. In some situations high resistivity soils may reduce the flow of protective current, allowing the potential to fall to within the cracking range. In other situations low resistivity soils may result in high current density at coating defects, causing accelerated disbonding of susceptible coatings. Soils that are in locations where wet/dry cycling can occur may provide a damp environment in crevices beneath disbonded coating but may block protective current at times when the surrounding soil is


DR04561.doc

dry. The likely impact of the soil environment must therefore be considered on a case-by-case basis.

N6.7 Surface preparation

The presence of corrosion pits on the pipe surface accelerates the onset of SCC. Because an oxidised surface has a greater propensity for stress-corrosion cracking than a clean grit-blasted surface, close attention should be paid to surface preparation prior to applying anti-corrosion coatings. Furthermore, grit blasted surfaces that are free from contamination (such as chlorides) produce better coating adhesion and lower susceptibility to cathodic disbonding. Contamination, and especially residual oxide films adversely affect the native potential of the steel surface. Blast cleaned surfaces that have not developed oxide films exhibit free corrosion potentials generally more negative than the SCC range. Application of cathodic protection would move the potential further away from that range.

N6.8 Cathodic protection system

Cathodic protection systems are essential for protection against general corrosion. However where too negative a potential is applied to a pipeline, it is possible for hydrogen to be evolved on the surface of the steel.. The presence of hydrogen has the effect of limiting the flow of current to steel under a disbonded coating and allowing the potential on the surface to remain at or near the cracking potential. Where stress-corrosion cracking may occur, pipe-to-soil potential should be maintained at a voltage of not more negative than −1.2 V (instant off copper/ copper sulphate half-cell potential) as far as practicable. On pipelines subject to stray current fluctuations or telluric effects it may not be possible to avoid intermittent periods of more negative potentials.

NOTE:The instant off potential measured on a pipeline represents an (approximate) average value of the instant off potential of all exposed steel at coating defects on the pipeline in the broad region of where the measurement is taken. Some defects will be more negative than this value, whilst others will be less negative. In pipeline sections at higher risk of SCC it may be prudent to limit the nominal off potential to less negative values.

N6.9 Pipe wall temperature

For high pH SCC, the initiation life and the rate at which cracking progresses is temperature-dependent. Thus, reduced operating temperature will slow the onset of cracking and the rate of crack growth. Where pipeline temperatures are high, such as downstream of compressor stations, the increased likelihood of SCC can be compensated by measures such as using thicker wall pipe to reduce stress levels.

For low pH SCC there is a lack of correlation between temperature and cracking. One possible explanation put forward is that the solubility of carbon dioxide in solution increases with decreasing temperature thus acidifying the solution and concentrating the carbonic acid species in the solution which increases the probability of SCC occurring. The effect of lower chemical activity associated with low temperatures may be offset by the increased corrosivity of the solution.

N7 REFERENCES

The following documents contain material relevant to this Appendix.

(a) Protocol to Prioritize Sites for High pH Stress-Corrosion Cracking in Gas Pipelines Pipeline Research Council International, Project No. PR-3-9403, published September 1998.

(b) Conditions that Lead to the Generation of SCC Environments - A Review Pipeline Research Council International, Project No. PR-230-9914, published January 2000.


DR04561.doc

(c) Assessment of the Effects of Surface Preparations and Coatings on the Susceptibility of Line Pipe to Stress Corrosion Cracking. Pipeline Research Council International, Project No. PR-186-917, published February 1992.

(d) Cathodic Protection Conditions Conducive to SCC. Pipeline Research Council International, Project No. PR-186-9807, published October 2002.


DR04561.doc

APPENDIX O

INFORMATION FOR CATHODIC PROTECTION

(Informative)

The design of a cathodic protection system for a pipeline requires details about the pipeline and its route to be gathered, documented and considered. Full details required are listed in AS 2832.1; however, as a minimum, the following should be determined:

(a) Structure details The diameter, length, and wall thickness of the pipeline is required for design calculations. The life requirement of the pipeline should also be clearly established as this has very substantial impact on many aspects of the design.

(b) Coating details The type and quality of coating used, including the coating used for field joints and repairs, has a significant bearing on the effectiveness of cathodic protection and on the amount of current that needs to be provided to protect the pipeline. In addition, the impact of handling on the coating and the nature of the pipeline backfill (i.e. the material immediately in contact with the pipeline) needs to be understood, so that an assessment of coating integrity can be made. The coating selection process should take into consideration the design life of the pipeline, requirements for factors such as stress corrosion cracking, the operating environment of the coating and the cathodic protection design.

(c) Structure isolation points For cathodic protection to be successfully applied, the pipeline to be protected must be electrically continuous and should be electrically isolated from other structures. Certain pipeline fittings and joint couplings are naturally isolating, and these may need to be electrically bonded to allow the cathodic protection to extend to the whole structure. Additionally, isolating joints or insulating flanges may need to be installed, to limit the cathodic protection to the pipeline and prevent its effect being dissipated to other underground structures.

(d) Road, rail and river crossings Details of crossings need to be considered, to ensure that effective cathodic protection is provided at such locations. Steel casings may shield the carrier pipeline from the cathodic protection if the casing comes into metallic contact with the carrier, and measures to electrically insulate the casing from the carrier pipe must be implemented. Bridged crossings may need to be electrically insulated from the support structure, to prevent excessive current drain to the support structure. In all cases, provision for test connections needs to be made in the design.

(e) Pipeline route Features along the pipeline route that may impact on the cathodic protection system need to be identified, and provision incorporated in the design. Typical features include the following:

(i) Soil types and soil resistivity along the pipeline route.

(ii) The presence of abnormal backfill material, such as cinders, ashes or highly acidic soils.

(iii) Presence of a.c. or d.c. transmission systems within close proximity to the pipeline.

(iv) Proximity of d.c. transportation systems.

(v) Proximity of other cathodic protection systems.

(vi) River crossings.

(f) Water levels Any fluctuation of water levels both diurnally and seasonally should be noted and possible effects on cathodic protection determined.


DR04561.doc

(g) Pipeline operating conditions Elevated temperatures result in increased rates of corrosion and may alter the nature of the backfill.


DR04561.doc

APPENDIX P

MITIGATION OF A.C. EFFECTS FROM HIGH VOLTAGE ELECTRICAL POWERLINES

(Informative)

P1 GENERAL

P1.1 AC effects

Modern pipelines are usually coated with high quality anti-corrosion coatings that have highly effective electrically insulating properties. Pipelines are often laid in roadway easements that also carry high voltage electricity distribution lines, and in recent times there is an increasing trend to run pipelines and powerlines together in energy transmission corridors. The overall result is that pipelines are now much more prone to being subject to electrical effects as a result of the powerlines. Significant voltages can be induced under normal steady-state powerline operating conditions and more substantial effects can occur under fault conditions when surges of very high currents can flow.

Electrical fault conditions are not uncommon and can occur at frequencies ranging from less than once per year up to several times per year, depending on factors such as location and type of powerline construction. They can cause electric shock to personnel working on pipelines adjacent to the powerlines, and can present a number of possible hazards to the pipelines, such as:-

(a) Damage to electrical insulation in devices such as monolithic isolation joints, isolating flanges, isolating couplings and isolating unions.

(b) Damage or puncture of protective coatings.

(c) Damage to electrical and electronic equipment.

(d) Electrical arcing which can fuse the pipeline steel, or can act as a source of ignition for escaping product.

P1.2 Mitigative measures

Mitigative measures employed to control or minimise the effects of powerlines include:-

(a) Surge diversion devices such as varistors, spark gaps and polarisation cells coupled with:

(i) Electrical earthing in the form of discrete electrodes, earthing beds or lengths of earthing cable or ribbon.

(ii) Earth safety mats or grids to limit step and touch potentials adjacent to accessible points on the structure.

(b) Measures that restrict access to direct contact with the structure or its appurtenances.

The protective measures employed need to be appropriate to the specific circumstances and to the level of exposure. Although most electrical hazards arise under powerline fault conditions, effects that can cause risk to integrity of structures or safety of personnel can also arise during normal powerline operation. Further information on requirements for electrical safety on pipelines subject to power system influences can be found in AS/NZS 4853.


DR04561.doc

P2 NATURE OF ELECTRICAL HAZARDS

P2.1 General

The presence of alternating current on metallic structures can result in a number of types of potential hazards:

P2.2 Physical damage to the structure or its coating.

High energy electric current can result in metal loss, and possible fusion of the steel, to the extent that escape of product arcs occurs.

High voltage can cause dielectric breakdown of the coating, resulting in formation of through-penetration defects in the coating.

High voltage surges can also cause damage to electrical equipment and electronic control systems that are connected to the structure.

P2.3 Risk to personnel who may be in contact or close proximity to the structure.

Persons in contact with the structure may be subject to electric shock when high voltages are present, both under powerline operating and powerline fault conditions. Voltage levels due to lightning strikes on the powerline may be sufficient to result in arcing to personnel or equipment in close proximity.

Persons who could possibly be at particular risk from electric shock, such as personnel requiring heart pacemakers or with known heart conditions, should consider seeking medical advice prior to engaging in work on metallic structures where voltages may be present which could deliver electric shock.

P2.4 Cathodic protection

The presence of high levels of alternating current on a pipeline, which may arise under normal powerline operating conditions, can result in a reduction in the effectiveness of cathodic protection. This reduction may be sufficient for corrosion to occur, even though the standard cathodic protection criteria have been met.

P3 HAZARD MECHANISMS

P3.1 General

Electrical hazards can arise on metallic structures through a number of sources. Conductive coupling occurs when actual contact is made with a powerline or a live powerline appurtenance, or when an object is sufficiently close for an electrical arc to become established.

Low frequency induction arises due to the electrical coupling between long structures, such as between pipelines and powerlines where they run parallel for some distance.

Earth potential rise occurs when current discharges from a powerline earth, such as from a transmission tower footing when there is a fault on that tower.

Capacitive coupling occurs when an insulated above ground section of pipe is in close proximity to a powerline, such that a powerline and structure can be considered to form the two plates of a capacitor. Although the capacitance of this capacitor is small, if a person touches the structure sufficient current may flow to ground to cause electric shock, or to cause a small spark if metallic contact to the structure occurs.

The principal means whereby an electrical hazard may arise on an existing pipeline are through low frequency induction (LFI) and earth potential rise (EPR). Concerns with conductive coupling generally need only be addressed when machinery is operating which could contact the powerline, and capacitive coupling is usually grounded through coating defects or other connections to the pipeline. Nevertheless these latter two factors still


DR04561.doc

require consideration when preparing designs and procedures for construction, operation and maintenance of pipelines. P3.2 Low frequency induction under operating conditions

Under normal operating conditions a three phase powerline can be expected to be operating as a balanced system such that the surrounding electromagnetic field is small. However some induction will result due to the slightly different distances of each phase conductor from a nearby pipeline, or due to current imbalance between phases. Long distances of exposure, typically of the order of several kilometres, may result in voltage levels sufficient to reduce the effectiveness of cathodic protection system, or possibly result in voltages sufficient to present a risk to personnel. P3.3 Low frequency induction under fault conditions

Under powerline fault conditions substantial voltages can be induced on adjacent parallel structures such as pipelines. Phase to earth fault currents can be of the order of tens of thousands of amperes, flowing from the substation(s) via the faulted power conductor and returning via earth. This presents a highly unbalanced condition to any nearby pipeline, and electromagnetic induction can result in induced voltages of many thousands of volts unless mitigation is installed.

Severe LFI conditions can also occur on single phase power transmission systems utilising an earth return. Such systems include AC traction systems using the rails as a return conductor, and single wire earth return (SWER) power distribution systems that are used extensively in some rural areas. P3.4 Earth potential rise

Rise in potential of local earth results when a powerline fault to earth occurs. Under these conditions a high potential gradient exists due to the radial flow of current in the vicinity of the fault location, which is typically a powerline tower or earthed pole. The voltage rise of the earth near the fault can be of the order of tens of thousands of volts, decreasing inversely with distance from the fault. Extended structures, such as pipelines, generally adopt the potential of remote earth. Any such structure intercepting the gradient will thus be subjected to the rise in local earth potential in the vicinity of the fault. Earth potential rise will be reduced, often by orders of magnitude, if the electricity supply is earthed into a distributed earthing system. P3.5 Capacitive coupling

Capacitive coupling occurs when an insulated above ground part of a structure is in proximity to a powerline, such that a powerline and structure can be considered to form the two plates of a capacitor. Although the capacitance of this capacitor is small, if a person touches the structure sufficient current may flow to ground to cause electric shock, or to cause a small spark if metallic contact to the structure occurs. In general, mitigation of capacitive coupling is required mainly during the construction phase of structures such as pipelines, when they are strung above ground during operations such as welding. In most circumstances the current that can flow to ground due to capacitive coupling is insufficient to be lethal. However the electric shock that can occur if a person touches the pipe may result in a reflex action that might cause a hazard. Mitigation may also be required on above ground structures that are not earthed and isolated from buried sections, such as may occur at line valves, scraper stations, etc, if they are in close proximity to overhead powerlines. Often the mitigation devices installed to protect insulated fittings will reduce voltages due to capacitive coupling to low levels, although additional measures such as direct earthing may at times be required. Note, however, that in many situations above ground steelwork will be earthed via the electric supply earth on electrically operated equipment.


DR04561.doc

P3.6 Conductive coupling

Conductive coupling occurs when actual contact is made with a powerline or a live powerline appurtenance, or when an object is sufficiently close for an electrical arc to become established. In most instances, conductive coupling is only likely to arise when machinery such as cranes and other lifting equipment are operating under powerlines. Machinery of this nature is usually only required during construction activities or during major maintenance operations. It should be noted that conductive coupling might also become relevant during those instances where a powerline conductor short circuits or arcs to a tower. Under these conditions the tower itself and any associated earthing can become live and can present a hazard to anyone who happens to be in near or direct contact with it.

P3.7 Lightning

The major problem with a lightning hazard in high voltage transmission corridors is that the overhead earth wires on the transmission lines act as a collector for lightning incidents in the corridor. Such flash attachments do not proceed further than the nearest tower, because of the effective wire impedance and the fast rise time of the lightning surge. The net result is that during a thunderstorm the towers are caused to discharge about 15 times more often than the flash density for that area. Thus the hazard to pipeline and personnel is increased near the towers.

Apart from sheltering in an all metal vehicle cabin, paradoxically the most shielded location in a thunderstorm is under the power transmission line, mid span.

A pipeline is very different to other structures in its behaviour on receiving lightning flash current. The pipe is essentially a very long capacitor which, when covered with most modern coatings, can withstand very high voltages. The capacitance of the pipeline may be around 5 microfarads per kilometre, although this figure is reduced on segments where the backfill is nearly chemically dry.

The outcome is that a partial charge from a lightning side flash, or a charge from a very small lightning flash, can be contained on this pipeline resulting in the storage of upwards of half a coulomb at 1000 V. This storage of electricity is potentially lethal at any point over the whole length (say 100 km), and it should be noted that this point may be far from where any storm is visible.

A large direct flash to the pipeline at an exposed point, or to the ground directly above where the pipeline is laid is more likely to damage the coating, but may then arc to earth. This arcing results in the draining away of most of the charge, but it may destroy nearby CP or telemetry equipment. The local risk to personnel is no worse than would be when standing in the open during the storm. This risk, although small, is by no means fully negligible.

Field experience on pipelines suggests that an earth resistance of 5 Ω, installed at each end of each isolated section is satisfactory mitigation. A 5 Ω electrode at each end of a 100 km pipeline section would discharge any lightning charge to a safe value in around 0.01 s. Such discharge systems need to be capable of carrying high currents for a very short time and the conductors should have a cross-sectional area of at least 25 mm2.

P4 ACCEPTABLE VOLTAGE LIMITS

P4.1 General

Acceptable voltage limits as specified in AS/NZS 4853:2000 can be summarised as below. In addition, the breakdown voltage of the structure coating should not be exceeded.

It should also be noted that continuous application of relatively low levels of AC can cause reduction in the effectiveness of cathodic protection and even corrosion. It is currently


DR04561.doc

generally accepted that no more than 15 V AC. should be continuously present, although further research is in progress that may result in reduction of this value in some situations. P4.2 Category A (see AS/NZS 4853)

Touch voltage limits for pipelines or appurtenances accessible to the public or to unskilled staff are shown in Table Q1

TABLE Q1

TOUCH VOLTAGE LIMITS FOR PUBLIC AND UNSKILLED STAFF

Protection fault clearance time Volts AC Volts DC

≤ 100 ms 350 500

> 100 ms ≤ 150 ms 300 450

> 150 ms ≤ 300 ms 200 400

> 300 ms ≤ 500 ms 100 300

> 500 ms ≤ 1 s 50 200

> 1 s, including continuous 32 115

NOTE: Buried sections of pipeline, or pipeline facilities that are securely locked and can only be accessed by authorised personnel, are considered to be not accessible to the public.

P4.3 Category B (see As/NZS 4853)

Touch voltage limits for pipelines with restricted public access and only access by authorised personnel are shown in Table F2

TABLE Q2

TOUCH VOLTAGE LIMITS FOR AUTHORISED PERSONNEL

Protection fault clearance time Volts AC Volts DC

≤ 1 s 1,000 1,000

> 1 s, including continuous 32 115

Category B touch voltage limits are applicable to accessible parts of pipelines which have restricted public access. (Such parts include compounds with security fences, buried sections, etc.) They may also be applied when Category A touch voltage limits are technically or economically not achievable and when the hazards are deemed to be negligible or controllable.

Prior to applying Category B touch voltage limits, a risk assessment should be carried out in accordance with Clause 5.2 of AS/NZS 4853:2000. (Section 2 of AS 2885.1 describes risk assessment principles applicable to pipelines.) P4.4 Voltage limits during construction or maintenance activities.

Compliance with AS/NZS 4853:2000 requires that precautions shall be taken to limit touch voltages to Category A limits during construction or maintenance activities. Measures include restricting the length of welded or jointed pipeline prior to application of earthing, use of equipotential surface mats and wearing of appropriate protective clothing and footwear.

P4.5 Voltage limits on buried sections of pipeline.

Where a section of pipeline is underground, the voltage rise on that section of pipeline should not exceed the breakdown voltage of the pipeline coating. Coating breakdown voltages can vary widely and should be individual assessed.


DR04561.doc

P5 ASSESSMENT OF HAZARD It is not possible to specify in simple terms the minimum safe separation from sources of electrical hazard. Many factors determine the extent of the hazard zone due to induced voltages and each case requires an assessment to be made.

Factors to be considered in the assessment include but are not limited to

(a) Fault current at the location in question, plus likely future fault current within the expected life of the structure.

(b) Typical maximum operating current at the location in question, plus likely future operating current within the expected life of the structure.

(c) Separation distance between powerline and structure.

(d) Structure geometry size and depth of burial.

(e) Electrical parameters of structure coating.

(f) Earthing systems (both intentional and otherwise) installed on the structure.

(g) Length of structure running (approximately) parallel to powerlines.

(h) Powerline geometry separation between phase conductors, height of conductors above ground, presence & position of shield wires, etc.

(i) If shield wires are present, average distance between pylons/poles that are earthed.

(j) Soil resistivity at and in the vicinity of the affected location.

(k) Resistance per unit length of phase and shield wires

(l) Phase angle of each conductor on multi-circuit systems.

(m) Location of any phase transpositions within the area under study.

(n) Resistance to earth of pylon footings, pole earthing electrodes, etc.

(o) Powerline operating voltage.

(p) Fault clearance time.

(q) Fault frequency. NOTE:Fault and steady-state currents on HV distribution powerlines (e.g. 22 kV) can be more than sufficient to result in potentials requiring mitigation on adjacent structures. It should not be assumed that only HV power transmission lines require consideration.

P6 PROTECTIVE MEASURES

Protective measures should be designed to render the structure safe for operations personnel and for the general public, and to avoid damage to the structure and its facilities. Earthing should be designed to limit the voltage gradient that might exist across the structure coating a value appropriate to the coating employed. At locations with exposure to voltages greater than 1,000 V due to LFI or EPR, earthing grids should be installed at accessible locations such as at CP test points and within facilities compounds to reduce touch and step potentials. In addition, public access to exposed steelwork or cabling should be prevented by means of fencing or locked covers over equipment and monitoring points. Long-term exposure of the structure to alternating current induced from electric powerlines should be designed to a limit value of no greater than 15 V a.c.

Protective measures that might be applied include:

(a) Provision of earthing grids around accessible plant, exposed steelwork or CP test points where necessary to limit touch and step potentials to safe values


DR04561.doc

(b) Use of Faraday cage principles to limit touch and step potentials within underground pits.

(c) Installation of structure earthing in the form of discrete electrodes or runs of zinc ribbon or other suitable metallic conductor. Earthing of this nature can be installed in relatively short lengths to provide a localised point of low resistance to ground, and in other locations long sections may be required extending along several kilometres to provide distributed grounding.

(d) Installation of above-ground appurtenances within security compounds that prevent public access.

(e) Use of lockable cathodic protection test point boxes that prevent public access to terminals or leads connected to the pipeline buried below.

(f) Surge protection devices fitted across insulated joints, to protect the joint from electrical damage and to control voltage differentials to safe limits.

In order to prevent direct current flow between earthing and structure, test point earthing grids and metallic ribbon earthing may need to be connected to the structure via suitably rated surge diverters. In the case of cathodically protected structures, such DC isolation may be essential to enable effective operation of the CP system. Possible CP shielding effects from earthing grids and Faraday cages should also be taken into account in the CP design.

P7 PERSONNEL SAFETY DURING PIPELINE OPERATION AND MAINTENANCE

P7.1 General

In areas classified as Category B in AS/NZS 4853 the provisions as follows are recommended.

P7.2 Operational activities

All normal operational work that may result in personnel making contact with the protected pipeline, such as CP monitoring or work in facilities, will require measures as follows, or otherwise provide equivalent levels of personnel safety.

(a) Personnel to wear either 1000 V rated rubber soled boots or 1000 V rated rubber gloves in dry conditions.

(b) Personnel to wear both 1000 V rated rubber soled boots and 1000 V rated rubber gloves in wet conditions.

(c) No work should be carried out if there is evidence of lightning within 50 km of the site or if advice from weather forecasting services indicates lightning activity.

P7.3 Pipe excavation

Where pipe is to be excavated, measures as follow are to be applied, or equivalent measures that provide equivalent levels of safety.

(a) If the pipe is to be left unattended it should be provided with a fence and locked gate that will prevent unauthorized access.

(b) All personnel that may contact the pipe should use either 1000 V rated rubber soled boots or 1000V rated rubber gloves in dry conditions.

(c) In wet conditions, all personnel that may contact the pipe should use either 1000 V rated rubber soled boots or 1000 V rated rubber gloves, plus an equipotential mat.

(d) No work should be carried out if there is evidence of lightning within 50 km of the site or if advice from weather forecasting services indicates lightning activity.


DR04561.doc

P7.4 Equipotential mats

If an equipotential mat is required it should comply with the following, or otherwise provide equivalent levels of safety.

(a) The mat should be sufficiently robust to resist damage due to the service conditions, sufficiently flexible to conform to the ground surface so as not to cause trips or falls, and of a type of construction that ensures good electrical continuity to all parts of the mat.

(b) Connection to the mat should be made at least at two points, which are in turn connected to the pipe, either directly or via suitable surge diverters, by two separate cables.

(c) The mat shall extend at least one metre beyond the working area so that it is not possible to contact the pipe without standing on the mat.

P7.5 Protective equipment

Care shall be taken to ensure that if gloves or boots are worn, no other part of the body can make contact and provide a conductive path for the fault current:

(a) If rubber soled boots are worn to isolate from earth, no other part of the body should contact the earth if contact is also being made with the pipe.

(b) If rubber gloves are worn to isolate from the pipe, no other part of the body should contact the pipe if contact is also being made with the earth.

P7.6 Pipe continuity

If the pipe is to be cut, or broken by other means such that one section is isolated from another:

(a) Bonding cables should be run across the break during cutting, welding and at other times unless appropriate personnel isolation or surge diversion is provided.

(b) 1000 V rated rubber gloves should be used when making the bonding cable connections.


DR04561.doc

APPENDIX Q

CHANGE IN INTEGRITY (DUE TO DEFECTS IN SERVICE) KNOWN CORROSION DEFECTS PAPER 5.13

(Normative)


DR04561.doc

APPENDIX R

PROCEDURE QUALIFICATION FOR COLD FIELD BENDS

(Informative)

R1 INTRODUCTION

Modern thin-walled pipes made from low carbon steels of excellent weldability cannot sustain high levels of field bending without forming buckles. Acceptance levels for such buckles based on functional and structural considerations are aesthetically unacceptable.

Control of field bending by means of a qualified procedure involves establishing the practical details of the procedure, the agreed acceptance criteria and the agreed method of measuring or assessing buckles against the acceptance criteria.

The procedure development method described in this Appendix is advisory. Users are invited to record their experiences and advise Standards Australia, so that subsequent revisions of the Standard may benefit.

As there may be variations in the stress-strain behaviour between nominally identical pipes, the operator should exercise judgement during bending. The angle limits given should be treated as the maximum that are permitted. It is possible that bending to these limits may cause higher levels of buckling than the agreed acceptance levels. In this case, the maximum bend angles should be reduced, to ensure that the maximum buckle height stays within the agreed acceptance limit.

R2 BASIS OF REQUIREMENTS FOR COLD FIELD BENDS

Over the last 30 years, pipeline design and materials have developed to the point where currently high strength, highly weldable and fracture-resistant line pipes with medium to high D/δN ratios are normally specified and used. These developments have been driven by the need for more economical pipeline designs involving the use of less materials and higher pressures.

Recent experiences in Australia led to the initiation of a research program into the cold field bending of modern line pipe. The results of this research are detailed in APIA/TN1. A number of the important conclusions reached are summarized below:

(a) It is reasonably difficult to bend modern high D/δN line pipe without forming small buckles.

(b) The presence of small buckles does not have any effect on the integrity of a pipeline, if minimal pressure cycling is occurring.

(c) The peak to peak wavelength of a buckle was shown to approximate the value given by the equation

( )( )( ) 25.022 112/6.1 µδπ •= Nb rL ...................................................................................... J2

Where

r = Peak radius, in millimetres

δ = Nominal wall thickness, in millimetres

µ = Poisson's ratio

(d) The height at which a buckle was deemed to be unacceptable was set by workmanship standards at 5% of the length of the buckle.


DR04561.doc

(e) The achievable bend angle per diameter at which a buckle becomes unacceptable can vary significantly between 0.5 and 4 degrees per diameter.

(f) The best method of determining the maximum achievable bend angle is by a test on a length of the pipe to be bent.

(g) Residual ovality is significantly reduced by a high level hydrostatic test.

Figure S2 provides a method for making a preliminary assessment of the development of compression buckles during pipe bending by conventional methods. It may be used to determine a starting point for procedure development and qualification.

R3 OBJECTIVES

The aims of the bending procedure qualification laid out in this Appendix are the following:

(a) To determine the following:

(i) The bend angle at which buckles first form on the compression surface of the pipe.

(ii) The height of the buckles on the compression surface of the pipe that are deemed to be unacceptable for both single and multiple push bends.

(iii) The maximum allowable loaded bend angle and the residual bend angle for any single push.

(iv) The maximum allowable loaded bend angle and residual bend angle that are made as part of a sequence (excluding the first and last pushes of any sequence, which should be treated as single pushes).

(v) The spacing between pushes.

(vi) The die radius to be used.

(vii) Whether an internal mandrel is required and, if so, the operating pressure and details of any shimming on the mandrel.

NOTE: If the use of the mandrel is to be optional, separate procedures should be qualified with and without the mandrel.

(viii) The maximum operating pressure of the hydraulic system.

(ix) The final procedure to be used in production field bending.

(b) To verify that a section of pipe that has been bent using the maximum bend angle allowed under the field bending procedure results in a bend, is deemed to be acceptable to the pipeline licensee and complies with Clauses 10.6.2 and 10.6.3.

(c) To qualify operators for production bending.

R4 SUGGESTED METHOD

A suggested method for qualifying a bending procedure is as follows:

(a) All information and data pertinent to the testing, as listed under Item (m) below.

(b) Establish the nominal acceptance limits for buckle height, ovality and surface strain.

(c) Ensure that instrumentation is accurate to within 20% of the amount being measured.

(d) Prepare the bending machine in accordance with the manufacturer's specifications, using bending shoes suitable for the pipe to be bent.

(e) Set the relief valve on the hydraulic circuit to zero, adjusting it during the course of the qualification to the pressure required to make the bend.


DR04561.doc

(f) Load the test pipe into the machine and set up instrumentation suitable for measuring the bend angle.

(g) Where an internal mandrel is used, position and energize it in accordance with the maker's instructions.

(h) Make the first push to establish the loaded and residual bend angles at which buckles first appear. A number of pushes may be made to determine these angles.

(i) Make the second push at a distance of not less than two pipe diameters from the first push, to establish the loaded and residual bend angles at which the size of any buckle equals the agreed nominal acceptance limit. This push may be repeated if required. At the conclusion of this Step, the contractor and the pipeline licensee should agree on the acceptance limits for buckle heights.

The height of a buckle is normally reduced by subsequent pushes, thus the limiting angle for a single push may be increased when the push is made as part of a sequence. The first and last pushes in any sequence should be treated as single push bends.

(j) Establish the loaded and residual angles for multiple push bends by making a series of six pushes at a suitable spacing; the first and last pushes to a loaded angle as defined in (h) and (i) above, and the middle four pushes to a constant loaded angle, which it is felt will ensure that the buckle heights do not exceed the agreed acceptance limit. The contractor may use the loaded and residual angles in (h) and (i) above for all pushes in the bend. When the bend is made, measure the buckle heights. If they exceed the agreed acceptance limit, repeat the test at a lower bend angle. Once a satisfactory bend is made, the pipe may be removed from the machine.

(k) Measure the pipe for ovality in the centre of the bend produced by (h) and (i) above. On the basis of this result, establish and agree on the acceptance limit for ovality.

(l) Calculate the surface strain for the agreed maximum bend angle. On the basis of this result, establish and agree on the acceptance limit for surface strain.

(m) Record the test results and agreed acceptance limits. The records form should include the following information and should be signed by an authorized representative of the contractor and the pipeline licensee:

(i) Date of procedure tests.

(ii) Pipe specification, pipe grade, nominal wall thickness and manufacturer.

(iii) Bending machine make, model, serial number, die radius and operating pressure.

(iv) Mandrel make, model, serial number, level of shimming and operating pressure.

(v) Pipeline licensee.

(vi) Contractor.

(vii) Operator(s).

(viii) Maximum allowable loaded bend angle and residual bend angle for any single push bends and any multiple push bends.

(ix) Spacing to be used between pushes.

(x) Procedure for cold field bending.

(xi) Results from section of pipe bent during the procedure qualification test; to include

(A) buckle heights; and

(B) ovality.


DR04561.doc

(xii) Agreed acceptance limits; to include

(A) buckle heights;

(B) ovality; and

(C) surface strains.


DR04561.doc

0-1%

0

20

0

ratio

NdD/60

40

thicknessto

Diameter80

120

100as a percentage of peak to peak

buckle length

Code l imit

degrees per diameterBend angle

21 3 4 65

Lines represent buckle height

3%2% 5%4%

FIGURE S2 INDICATOR CHART FOR D/δN RATIO VERSUS BEND ANGLE FOR DIFFERENT BUCKLE HEIGHT RATIOS


DR04561.doc

APPENDIX S

GUIDELINES FOR THE TENSIONING OF BOLTS IN THE FLANGED JOINTS OF PIPING SYSTEMS

(Informative)

S1 INTRODUCTION

This Appendix has been written to provide a guideline basis for the derivation of the value of torque necessary to provide adequate tension in the bolts of a flanged joint for an effective gasket seal after the nuts have been tightened up by a torque wrench. It also provides information relating to the consideration of applied loads during operation as this aspect of bolt tension is related in some instances to the remaining allowable stress after pre-tensioning the bolt prior to being put into service.

Current Standards limit the design strength of bolts to a relatively low value of stress, typically 24% SMYS for ASTM A 193-B7 steel bolts. The construction industry has found that when the bolts of some flanged joints are tensioned to the full permitted stress levels the gaskets do not provide a tight seal during service.

Leak tight flange joints require the correct residual bolt tension to be achieved in all bolts. The residual bolt tension may be achieved by one of the following:

(a) Direct tensioning of the bolts

(b) Torque wrench tightening of the bolts to achieve a bolt extension

Where the torque wrench method is used, calibration of the applied torque against bolt extension is strongly recommended to ensure the correct residual tension is achieved.

The required torque may be estimated using the following procedure, which provides a basis for calculating the value of torque to be applied to the nuts based on the gasket/bolt manufacturers recommendation of permitted bolt stresses for effective gasket sealing. The basis used in the calculation of the worked example is bolt stress. As an alternative to bolt stress, gasket compression load can be used, by relating the load and effective stress area of the gasket back to the total bolt load.

In general the bolt stresses suggested by the manufacturer will be higher than the values permitted by current standards. These guidelines recognise therefore that additional precautions should be taken to calculate the sealing and operating bolt stresses to ensure that bolt yielding does not occur. In this respect it is considered necessary that the design of the piping take into account fully all of the applied loads that may exist during the operating life of the pipeline system and in particular the stress levels during installation. Under some conditions it may not be possible to achieve the manufacturers recommended residual bolt loads due to high installation stress levels.

A worked example is provided in section 15 of this Appendix to demonstrate the methodology of these guidelines.

S2 NOTATION

Throughout this Appendix the following notation has been adopted: Symbol Description Units µ Coefficient of friction

λ Lead angle of the helix degree


DR04561.doc

α Angle between flank of thread and plane perpendicular to helix

degree

π Constant

bf Recommended bolt stress psi

yf Yield stress MPa

A Nominal bolt area mm2

bA Stress area of bolt mm2

gA Internal area at gasket force mm2

pA Internal area at gasket force mm2

rA Root area of bolt in2

c Radius to outermost fiber mm

C Celsius degree

d Nominal bolt diameter inch

bd Minor diameter inch

cd Mean radius of nut face inch

pd Pitch diameter of bolt inch

F Factor

F Applied force lb

dF Design factor

fs Factor of safety

G Reaction load diameter mm or inch

h Projected thread height

J Polar moment of inertia of cross section mm4

k Constant

bk Stiffness of bolt material N/m

fK Stress intensification factor

jk Stiffness of joint material N/m

ksi Stress kips/inch2

L Lead of screw inch

M Bending moment in.lb

N Number of bolts in a joint

NPS Nominal pipe size inch


DR04561.doc

P Load capacity of bolt N p Pitch of thread p Static internal fluid pressure MPag

dp Dynamic internal fluid pressure increment MPag

psi Pressure or stress lb/in2

avP Average load N

dP Dynamic load N

extP External load N

iP Initial load N

mP Manufacturers recommended load N

pP Load from test pressure N

sP Force in bolt from fluid pressure in joint N

Q Axial load in bolt N or lb

1S Stress in bolt from tensile load MPa

2S Stress in bolt from applied torque MPa

aS , allS Allowable stress MPa

bS Stress in bolt ksi

cS Stress in joint from applied loads MPa

dS Stress in joint from surge MPa

ES Stress due to expansion MPa

eS Endurance limit MPa

gS Compressive stress in bolt to compress gasket MPa

pS Static stress in bolt from pressure in joint MPa

rS Alternating stress MPa

sS Shear stress MPa

tS Total stress MPa

uS Ultimate tensile strength MPa

yS Yield stress MPa

SYMS Specified minimum yield stress MPa


DR04561.doc

T Torque N.m or lb.ft

tT Torque on threads N.m or lb.ft

TPI Threads per inch

S3 THE EFFECT OF THE GASKET ON THE LOAD CARRIED

The load on the bolt depends on the initial tension Pi and the external load Pext.

The load on the bolt also depends on the relative elastic yielding (springiness) of the bolt and the connected members as follows:

(a) If the connected members are very yielding compared with the bolt the resultant load on the bolt Pav will closely approximate the sum of the initial tension Pi and the external load Pext.

(b) If the bolt is very yielding compared with the connected members the resultant load will be either the initial tension or the external load whichever is the greater.

To estimate the resultant load on the bolt the following formula can be used:

( )( ) extjbbiav PkkkPP ++= 2/

For flanged joints with flexible gasket the value in brackets approaches unity, for a solid gasket such as metallic ring jointed gasket the bracketed value is small and the resultant load is due mainly to the initial tension Pi (or to Pext if it is greater than Pi).

S4 STRENGTH CAPACITY OF A BOLT

It is relatively easy to calculate the static tensile strength of a bolt.

The load may be assumed to be uniformly distributed across the root section of the bolt and stress concentration can be neglected.

The stress area of the bolt can be obtained from the dimensions of the standard to which the bolt is manufactured and used with the yield strength yf of the bolt material to determine the load carrying capacity P of the bolt as follows:

yr fAP =

S5 INITIAL LOAD

The initial load is highly indeterminate but can be estimated from the following formula which is attributed to J.H. Barr:

,kdPi =

where k = a constant and d = the nominal diameter of the bolt in inches.

The constant k for a streamtight joint is 16000.

The judgement of the person applying the force with a wrench cannot be predicted accurately.

Theoretically it is possible to relate the tightening load to the dimensions of the bolt screw thread and the applied torque. In practice there is considerable error in the calculation of the torque required, because of the wide variation of the effect of surface finish and lubrication of the sliding components on the torque required to overcome frictional resistance.


DR04561.doc

S6 RELATIONSHIP BETWEEN APPLIED TORQUE AND TENSION

The torque required to turn the nut can be related to the axial load in the bolt by the following formula:

,2/FQdT p=

where Q = the axial load, dp = pitch diameter of the screw and T = the applied torque.

The factor F is a function of the lead angle of the helix λ , the angle between the flank of the thread and a plane perpendicular to the helix of the thread α , the coefficient of friction µ and dc the mean radius of the nut face as follows:

( ) ( )[ ]( )pc ddF /tancos/tancos µλµαµλα +−+=

where L = the lead of the screw thread and tan pdL πλ /= .

Alternatively the torque can be calculated using the simplified screw jack formula of A P Farr, rewritten using the notation of these guidelines, as follows:

( ) ( )[ ]2/cos2/2/12/ cp ddLQT µαµπ ++=

Coefficients of friction vary between 0.06 and 0.40. These are practically independent of load and vary only slightly with different combinations of materials and rubbing speed.

S7 IMPOSED LOADS ON A BOLT

Loads may be separated into two categories, loads imposed during installation and externally applied loads after installation.

The following is a list of the loads imposed on the bolts of a flanged joint during installation:

(a) Load on a bolt imposed by the connected piping from misalignment (note this load should be either eliminated or minimised by careful constructions).

(b) Load on a bolt to compress the jointing gasket (bolt pretension).

The following is a list of the loads imposed on the bolts from operating conditions:

(a) Static load from internal pressure

(b) Dynamic load from external pressure

(c) Loads applied externally from connecting piping.

S8 COMBINED STRESSES

The stresses in a bolt will also fall into installation and operating stress categories.

S8.1 Stresses during installation

During installation the minor diameter cross-section of the portion of the screw thread of the bolt between the nut and the flange will be subjected to a biaxial stress condition. This stress condition is comprised of a tensile stress due to the axial force and a shear stress only due to the applied bolting torque.

The stress S1 in the bolt from the tensile load is as follows:

rAQS /1 =

The stress S2 in the bolt from the applied torque is as follows:

JcTS t /2 =


DR04561.doc

Where Tt = torque on the threads, c = distance of neutral axis to the extreme fibre and J = Polar moment of inertia. The torque on the threads Tt is:

( ) ( )[ ] 2/tancos/tancos λµαµλα −+= pt QdT

The maximum shear stress level in bolt will yield when the maximum shear stress Ss is equal to the shear yield strength of the material which is equal to half of the yield stress in simple tension Sy/2.

The maximum tensile (principal) stress during torquing is:

( ) st SSS += 2/1

The bolts should have sufficient strength to withstand the required applied torque during installation.

After torquing has been completed the shear stress from the torque will cease to exist.

S8.2 Stresses during the operation

The design of the bolts should also have adequate strength to withstand the applied loads during operation.

The stress in a bolt Sg to keep the gasket in compression can be calculated from the manufacturers minimum recommended bolt load as follows:

( )NAPS rmg /=

The static operational stress Sp in the bolt from internal fluid pressure p is given as follows:

( )NAPS rsp /=

where Ps = p Ag (Ag is the internal area using the diameter at the location of the gasket force).

The dynamic stress in the bolt from fluid pressure Sd will be a percentage of the static stress, as determined by analysis:

( )NAPS rdd /=

where Pd = p Ap (Ap is the internal are at the gasket force location).

The loads from connected piping will be determined from analysis and the stress in the bolt Sc will be determined from these loads.

The total stress St in the bolt from the operational loads will vary depending upon the type of gasket being used in the bolted joint.

For flexible gaskets the total stress will be the sum of the individual stresses as follows:

cdpgt SSSSS +++=

For rigid gaskets the total stress will be either:

gt SS =

or

cdpt SSSS ++=

which ever is greater.

The required load capability of the bolt can then be back calculated from the greater of Sg and St above.


DR04561.doc

S8.3 Stresses during Hydrostatic Pressure Test

The design of the bolts should also have adequate strength to withstand the applied loads during the hydrostatic pressure test.

The hydrostatic test pressure produces the following flange load:

4/2GpPp π=

and the stress in a single bolt is:

( )NAPS bpp //=

For flexible gaskets the total stress will be the sum of the individual stresses as follows:

pgt SSS +=

For rigid gaskets the total stress will be either:

gt SS =

or

pt SS =

whichever is the greater.

S9 FATIGUE FROM OPERATING LOADS

It can be shown from the Soderberg triangle that the following is true:

( )( )rfeyavys SKSSSSf // +=

where:

( ) 2/minmax SSSr −=

( ) 2/minmax SSSav +=

Stress Range = minmax SS −

The equation above for its effectively states that the total stress is the sum of the weighted stress reversed component and the steady stress component.

The equation above can be used to calculate the total stress range due to the cyclic load.

The total stress is given by:

( ) rfeyavt SKSSSS /+=

Values of the endurance limit Se lie within the range 0.45 to 0.6 Su, with an upper limit of about 100 ksi, a value 0.5 Su is commonly used in design.

S10 THE EFFECTS OF PIPING LOADS ON FLANGED JOINTS

For routine design on the effects of loading on flanged joints other than internal pressure, i.e. loads from the connected piping, the method of M W Kellogg Company is provided.

M W Kellogg found that, with a properly pretightened flange, the bolt load changes very little when a moment is applied to it.

Further, M W Kellogg have found from experience that it is satisfactory to first calculate the maximum load per inch of gasket circumference due to the applied longitudinal bending


DR04561.doc

moment and force. Then the internal pressure equivalent to this loading is then determined. The formula proposed by M W Kellogg is as follows:

( ) ( )( )23 /4/16 GFGMPe ππ +=

The equivalent force in each bolt NAPF ge /= , and the stress in the bolt can be calculated as for other pressure load calculation i.e.:

rc AFS /=

Simplistically if the mean moment resistance of the bolts about a line tangential to the reaction load diameter G is taken and if the load in the bolts is taken to be equal, then it can be shown that the equivalent pressure from an applied moment is:

( )3/8 GMPem π=

It is believed therefore that the M W Kellogg formula above may be conservative for the application of applied moments to the flanged joint.

Regarding torsion, if the frictional resistance of the gasket is ignored and all of the bolts are put in shear it can be shown that the shear stress in the bolts is:

( )NdTS ps3/8 π=

Stresses can then be combined in accordance with the theory in section 8.1.

S11 COEFFICIENT OF FRICTION

There is a wide variance of the values of coefficient of friction for the calculation of applied torque. These variations are caused by a number of factors such as the condition of the threads the condition of the flange to the nut bearing surface and the type of lubricant used. The following table provides some indicative values for various conditions:

Coefficient of Friction for screw threads

Average coefficient of friction µ Condition

Starting Running

High grade materials and workmanship and best running conditions

0.14 0.10

Average quality of materials and workmanship and average running conditions

0.18 0.13

Poor workmanship or very slow and infrequent motion with indifferent lubrication or newly machined surfaces

0.21 0.15

It is not possible to accurately determine a value of the coefficient of friction existing at site, some conservatism is therefore recommended in the selection of the value used in the calculations unless the conditions have been well established.

It does not necessarily follow that the coefficient of friction of the lubricant is the same as the coefficient of friction of the moving components of the joint.

S12 COMPONENTS OF THE FLANGE ASSEMBLY

All of the components of the flange assembly should be designed to carry the required load capacity of the bolts.

The other components of the assembly to be considered in the design of the flanged joint are as follows:


DR04561.doc

(a) The nut threads

(b) The bolt threads

(c) The gaskets

(d) The flanges

If the flange is purchased as an assembly in accordance with a recommended standard at the appropriate design pressure and temperature then it may be assumed that the strength of the flange components will match the strength of the bolts. Whilst these guidelines provide a basis to review the strength of the bolts of the flanged joints, they do not provide any basis for reviewing the strength of the flange, the nuts or the gaskets.

S13 DERATING OF ALLOWABLE STRESS AT ELEVATED TEMPERATURE

The upper limit of temperature for the standard is 200oC fluid temperature. These guidelines only apply to steel bolts to ASTM standards up to 200oC.

For bolt temperatures up to 120oC no de-rating of allowable bolt stress level is required. For temperatures between 120oC and 200oC the permitted allowable bolt stress level shall be de-rated in accordance with an approved standard.

S14 ALLOWABLE STRESS LIMITS

Evaluation of loading of the bolts of flanged joints is treated as being similar to the evaluation of the pipe itself. On this basis the allowable stress limits in the bolts for steel materials where referenced and where otherwise provided by these guidelines are as follows:

Load Case Load Type Stress Type Stress Limit Reference

Installation Torque + Axial Shear 45% Yield

(90% Shear Stress)

These guidelines

Installation Torque + Axial Tension 90% Yield These guidelines

Installation Residual (Pretension)

Axial 2/3rd Yield These guidelines

Hydrostatic Pressure Test

Sustained Axial <100% Yield AS 1978 Cl 4.3.3

Operation Sustained Axial 72% Yield AS 2885.1 Cl 4.3.6.5

Operation Cyclic stress range Axial 72% Yield AS 2885.1 Cl 4.3.6.5

Operation Occasional Axial 110% Yield Fd AS 2885.1 Cl 4.3.6.6

S15 WORKED EXAMPLE

It is required to install an ASME B16.5 flange assembly using a 24 inch NPS Class 150 flange with raised face flanges. The bolt material is ASTM A 193-B7 material requiring 20 number 11/4 inch bolts. The yield strength of the bolts is 105 ksi, and the ultimate tensile strength of the bolts is 125 ksi.

The manufacturer has advised that for a compressed fibre gasket the recommended bolt tension be such as to produce a bolt stress of 45 ksi in the minor area in order to provide the necessary pretension for an efficient seal for installation. The reaction load diameter G of the gasket has been taken to be 666.76 mm.

The screw threads of the bolt have been stated to be 8UN with an external diameter of 11/4 inches, a pitch diameter of 1.1688 inches, a minor diameter of 1.0966 inches, a stress area


DR04561.doc

of 0.9985 in2 and a dimension h = 0.866025 p. The vee formation of the screw thread is 60° and the relationship between the lead angle to the pitch diameter dp and the lead L is tan

pdL πλ /= . The bolts are single screw thread (L = 1/p) with 8 TPI. The width across the flats of the nut face is 1.875 inches.

It is assumed that the coefficient of friction is 0.15 for the threads and 0.15 for the nut face. It is also assumed that the resultant load on the bolt is the sum of gasket compression load and the external load.

The maximum internal operating pressure is 1.5 Mpag, the allowance for liquid surge is 10% of the operating pressure. The flange is subject to a sustained bending moment of 25,000 N.m and a thermal bending moment of 120,000 N.m from the connected piping. The thermal moment is cyclic in nature. The hydrostatic test pressure is 1.5 times the maximum internal operating pressure.

S15.1 The estimated Load for Tightness

The estimated load Pi for a tight seal is:

NPlbkdP

i

i

960,88000,2025.0001,16

====

The corresponding stress in the bolt is:

ksiSb 03.209985.0/000,20 ==

The manufacturer recommends a pretension of 45 ksi or 2.25 times this value.

S15.2 The Applied Load Q

The applied load Q in the minor area is:

NQlbAfQ bb

000,189500,424/0966.1000,45 2

==== π

S15.3 The Applied Torque T

The constants tan λ and cos α are:

( ) ( )( ) 866.02/60coscos

034.01688.1/8/1/tan==

===

αππλ pdL

Taking the mean radius of the nut face equal to the mean of the bolt diameter and width across the flats of the nut then:

( ) inchesdc 5625.12/25.1875.1 =+=

The applied torque T is:

( ) ( )[ ]( )( ) ( ) ( )[ ]( )

ftlbTmNT

TddQdT pccp

.28.846.34.1147

1000/2/1688.1/5625.151034.150.0866.0/15.0034.8660.04.168825.1000,189

2//tancos/tancos

==

+−+=

+−+= µλµαµλα

Alternatively, as the tangential force acts at the pitch radius, using the Farr formula:

( ) ( )[ ]( ) ( )[ ]

ftlbTT

ddLQT ccp

.99.8432/5625.151.30cos2/1688.1.15.2/8/112/500,42

2/cos2/2/12/

=++=

++=

πµαµπ


DR04561.doc

S15.4 Combined Stress Level during Installation

During tightening the maximum combined shear stress level can be obtained as follows:

MPaksiS 35.310451 == (45 ksi from the manufacturer)

4444 092,59142.032/0966.132/ mmindJ b ==== ππ

( ) ( ) ( )[ ]

( )( ) ( )( ) ( ) ( )( )

MPaSSSS

MPaJTcSmNT

T

s

s

t

t

54.20782.1372/35.3102/

82.137092,59/2/4.096625.1771000.584/.77.584

1000/2/034.150.0866.0/15.0034.8660.04.168825.1000,189

5.0225.022

21

2

=+=+=

====

−+=

MPaSksiksiS

y

y

07.3622/5.522/1052/

=

==

%32.57=sS yield in shear during tightening, and reduces to 310.35Mpa or 42.86% yield in tension after tightening.

The maximum combined tensile stress St is:

( ) MPaSt 72.36254.2072/35.310 =+=

%09.50=tS yield in tension during torquing.

S15.5 Stress Level during Hydrostatic Pressure Test

As the gasket is a flexible gasket the stress in the bolts Sg from the preload will add to the hydrostatic pressure test load. It is assumed that the piping is well supported during testing and that there are no additional imposed piping loads.

( ) ( )

MPaSMPaS

MPaNAPS

NP

t

t

bpp

p

33.37198.6035.310

98.6020/4.998525.0/618,785//

618,7854/76.6665.51.12

2

=+=

===

== π

or 51.28% yield in tension

S15.6 Sustained Stress Level during Operation

As the gasket is a flexible gasket the stress in the bolts Sg from the preload will add to the operating loads. During operation, the operating stresses are Sp+Sd+Sc. Note that the dynamic load from surge has been conservatively included in this sustained load case.

( )MPaS

MPaAPS

NPMPaSg

d

bpp

p

07.465.140.065.4020/4.998525.0/745,523/

745,5234/76.6665.135.310

2

2

==

===

==

=

π

The pressure equivalent to the bending moment is:

( )MPaPGMP

e

e

4295.076.666/0001000,1625/16 33

=== ππ


DR04561.doc

The applied load from the bending moment in each bolt is:

( )420/76.6664295.0 2π=F

NF 498,7=

The stress in each bolt from the moment is:

( ) MPaSc 64.119985254.0/498,7 2 ==

The total stress is:

MPaSMPaS

t

t

71.36664.1107.465.4035.310

=+++=

or 50.64% yield in tension

MPaksiSa 93.4773.6966105.0 ===

S15.7 Fatigue Stress Level during Operation

As the gasket is a flexible gasket the stress in the bolts Sg from the preload will add to the operating loads. During operation the operating stresses are Sp+Sd+Sc with Sc comprising the static component and the cyclic component of stress. The stress intensification factor of the vee thread is taken to be 2.5.

The pressure equivalent to the bending moment is:

( )MPaPGMP

e

e

0618.276.666/0001000,16120/16 33

=== ππ

The applied load from the bending moment in each bolt is:

( )NF

F995,35

420/76.6660618.2 2

== π

The stress in each bolt from the moment is:

( ) MPaSc 88.554.998525.0/995,35 2 ==

The stress due to the cyclic load Sr is equal to Sc.

The steady stress is the same as that in 15.6 above.

The maximum stress is:

MPaS 59.42288.5571.366max =+=

The minimum stress is:

MPaS 83.31088.5571.366min =−=

The average stress is:

( ) MPaSav 71.3662/83.31059.422 =+=

The total stress is:

( )( )

MPaSS

SKSSSS

t

t

rfeyav

41.60188.555.207.5862.0/14.72471.366

/1

=+=

+=


DR04561.doc

or 83.05% yield in tension.

The stress range from the alternating stress = stress range SrorSSSE 2minmax =−=

88.255=ES

MPaSE 76.111=

The allowable stress range is:

MPaSall 38.52114.72724.0 ==

The following table summarises these results:

TABLE 15.0

SUMMARY of STRESS LEVELS

Case Type Total value of stress

MPa

Total %SMYS Total stress excluding Residual

MPa

%SMYS

Installation Torque 207.54

Installation Torque 362.72

Installation Residual-Pretension

310.35 42.86 310.35 42.86

Hydro Sustained 371.33 51.28 60.98 8.42

Operation Sustained 366.71 50.64 56.36 7.78

Operation Cyclic 601.41 83.05 291.06 40.19

It can be seen from the table above in this example that the bolt pretension comprises the majority of the total stress in the flanged joint apart from the cyclic loading.

For stress compliance the following table summarises the calculated values:

TABLE 15.1

SUMMARY of STRESS COMPLIANCE

Case Type Value of stress MPa

Stress Limit MPa

Allowable Stress MPa

%Allowable

Installation Torque 207.54 90% Shear 362.07 57.32

Installation Torque 362.72 90% Yield 651.72 55.66

Installation Residual-Pretension

310.35 2/3rd Yield 482.76 64.29

Hydro Sustained 371.33 100% Yield 724.14 51.28

Operation Sustained 366.71 72% Yield 521.38 70.34

Operation Cyclic 111.76 72% Yield 521.38 21.44

S16 VALIDATION OF THE TORQUE WRENCH TIGHTENING PROCEDURE

The following procedure may be used to establish the method for the tensioning of the bolts of flanged joints, for installation at site:

1. Establish the residual bolt preload for leak tightness including any operating forces using this appendix.


DR04561.doc

2. Establish the manufacturers recommended minimum value of residual bolt tension.

3. Adopt the higher value of 1 and 2 above.

4. Calculate the bolt torque necessary to achieve the required residual load in 3 above using this appendix.

5. Estimate the coefficient of friction of the nut/flange face and the threads individually.

6. Calculate the combined stress level to ensure that the bolts will not be over stressed during tightening. If the calculated stress value indicates that the bolts would be overstressed, then the application shall be amended until the calculated stress value shows that the bolts will not be overstressed. If the value of residual bolt tension is reduced it shall not be less than that established for the leak tightness of the joint.

7. Validate the estimated value of coefficient of friction by measuring the torque and the axial deformation (extension) of at least one bolt at site during the tightening of the bolt of the first joint. A G frame with feeler gauges, a caliper or a dial gauge can be used to measure the change in bolt length at the observed value of torque. The value of torque measured should be the static value of torque not the running value of torque.

8. Adjust the calculated value of coefficient of friction to match the measured values of extension (use the measured extension to calculate the bolt stress level) and torque. Where different values of friction are estimated for nut/flange face and bolt threads the new values may be individually amended in their prior proportion to achieve the adjusted values.

9. Recalculate the value of torque to meet the required bolt pre-load/stress level using the confirmed value of coefficient of friction.

10. Recheck the combined stress level using the confirmed value(s) of coefficient of friction and torque and reassess the application if necessary.

11. Tighten all bolts to the confirmed torque value for the flange used for validation purposes if required, and all other identical flanges for a duration not exceeding the day of the validation of the value of the coefficient of friction.


DR04561.doc

APPENDIX T

STRATEGIC SPARES PAPER 5.21

(Normative)


DR04561.doc

APPENDIX U

RECORD KEEPING PAPER 5.2


DR04561.doc

APPENDIX V

STRESS TYPES & DEFINITIONS

(Normative)

V1 GENERAL

There are fundamental differences between the calculation of stresses of restrained pipelines and unrestrained pipelines. This document provides the formulae to enable calculation of stresses in accordance with the requirements of this code and defines the stress terminology and units for both of these types of pipeline restraint condition.

These statements have been written to cover the operating design stresses and not construction design stresses. For the calculation of stresses during hydrostatic pressure testing of a new pipeline the wall thickness to be used shall be the wall thickness defined below except that the wall thickness allowances for corrosion and erosion may be added to the specified thickness.

The equations and components of stress in this appendix are as accurate and comprehensive as is reasonable for inclusion in a document of this nature. Unusual or complex circumstances may arise in which there are additional stress components. The general principles expressed here shall continue to be applied, and the omission from the calculated stress state if it is relevant.

In many piping configurations it is not possible to calculate the stresses from simple formulae such as provided here and stress state can be predicted only through finite element analysis (i.e. pipe stress analysis software). For example, it is very common in buried pipelines that the longitudinal expansion stress ( EAσ Section W1.3) does not reach the theoretical value given by Equation X1.3.1 as a result of slight relaxation of the pipe at end points or changes of direction, although the longitudinal stress may still be high. As another example, the bending stresses due to thermal expansion at changes in direction of a buried pipeline may be very high if the temperature differential is high (e.g. Compressor station discharge) but cannot be expressed by any formula. The general principles expressed here shall continue to be applied, regardless of whether the stresses are calculated by simple formulae or sophisticated numerical methods.

V2 STRESSES IN RESTRAINED PIPELINES

This section provides the definition of stress terms, formulae and units for the evaluation of stresses in pipelines fully restrained in an axial direction, denoting +ve as being tensile.

V2.1 Hoop or Circumferential Pressure Stress Hσ

The Barlow formula for thin wall cylinders

δσ

2DPd

H = ...............................................................................................Equation W2.1.1

where

dP = Design pressure, in Mpag

D = Nominal external diameter, in mm

δ = Nominal wall thickness minus allowances G, in mm


DR04561.doc

V2.2 Longitudinal Pressure Stress Lσ

The longitudinal stress from the Poisson effect of hoop stress

HL µσσ = ...............................................................................................Equation W2.2.1

δµσ

2DPd

L = ............................................................................................Equation W2.2.2

where µ = Poissons ration

Pd = Design pressure, in Mpag


δ = Nominal wall minus allowances G, in mm

V2.3 Longitudinal Thermal Expansion Stress Eσ

The fully constrained axial thermal expansion stress in straight pipe is

( )TTE cEA −= ασ ....................................................................................Equation W2.3.1

where

Tc = Closing temperature, in °C

T = Design temperature, in °C

E = Youngs modulus, in Mpa

α = Coefficient of thermal expansion of steel

Consider two values of T.

T1 at the upper design temperature and T2 at the lower design temperature, i.e. both compressive and tensile stress types.

NOTE: That EAσ may not achieve the value given by Equation W2.3.1 where the pipe is not perfectly restrained. In particular, in analysis of pipe restrained by anchors it is necessary to include in EAσ the effects of anchor displacement under thermal expansion load.

In addition, substantial bending stresses can arise due to thermal expansion at changes in direction, particularly in buried pipe where the lateral restraint of the soil gives rise to complex deformation and stress patterns. Generally this stress can be calculated only by finite element methods (i.e. pipe stress analysis software). Where such stresses exist they shall be included in the longitudinal thermal expansion stress.

Bending stress due to thermal expansion = EBσ

The longitudinal thermal expansion stress

EBEAE σσσ += .......................................................................................Equation W1.3.2

V2.4 Bending Stress σσσσW

Bending stresses may be due to gravity from unsupported spans. Note that axial compressive stress increases beam bending stresses in these unsupported spans.

Unsupported span (beam bending, buckling) = wσ

Consider both tensile and compressive stress types. From beam theory one side will be in tension and the other in compression. wσ may be calculated from conventional beam theory.


DR04561.doc

The section modulus Z to be used to calculate the bending stresses shall be based on the wall thickness δ in W2.1 above.

V2.5 Direct Axial Stresses Fσ and otherσ

V2.5.1 Direct stress from externally applied forces/displacements/pressure

S

FF A

P=σ .................................................................................................Equation W2.5.1

Consider both tensile and compressive stress type.

Where

PF = Direct axial force, in N

AS = ( )4

22iDD −π

, in mm2


Di Internal diameter (D-2δ ), in mm


V2.5.2 Stress from other imposed force otherσ

V2.6 Sustained Stress susσ

otherFWLsus σσσσσ +++= ....................................................................Equation W2.6.1

Evaluate the maximum value of stress considering both tensile and compressive stress type combinations.

Note that for calculation of sustained stress the components Fσ and otherσ should not include displacement of anchors under thermal expansion load; this effect should be included in the longitudinal thermal expansion stress EAσ .

V2.7 Total Longitudinal Stress Tσ

EsusT σσσ += .........................................................................................Equation W2.7.1

Evaluate both tensile and compressive stress types.

V2.8 Total Shear Stress τ

Shear stresses may not be large in buried fully restrained pipelines. However, shear stresses may be caused by lateral loads due to unsupported valves, and also caused from torsion from various sources.

The shear stress due to torsion

ZM t

t 2=τ ...................................................................................................Equation W2.8.1

where

Mt = Torsion moment, in Nm

Z = Section modulus based on δ in 1.1 above

In addition, if direct (plane) shear stress is significant it shall be included in the calculation of total shear stress.


DR04561.doc

The shear stress due to direct shear

ST

Td A

S=τ .................................................................................................Equation W1.8.2

where

ST = Total design shear force in N

AST = Total area resisting shear in mm2

Total shear stress dt τττ += ....................................................................Equation W2.8.2

V2.9 Combined Equivalent Stress Cσ

Use either the Tresca Maximum Shear Theory for biaxial stress without shear.

THC σσσ −= , when 0<Tσ ...................................................................Equation W2.9.1

NOTE: That this is equivalent to adding the absolute values of the hoop and longitudinal stresses, i.e. when the longitudinal stress Tσ < 0 it is negative, then according to the Maximum Shear theory this negative stress adds directly to the hoop stress to increase the onset of yielding.

Where the longitudinal stress Tσ is tensile the combined equivalent stress Cσ shall be taken as the greater of Tσ or Hσ .

( ),, THC Max σσσ = when Tσ >0...............................................................Equation W2.9.2

or alternatively use the Maximum Distortion Energy theory, Von Mises for biaxial stress with shear.

222 3τσσσσσ ++−= TTHHC ..............................................................Equation W2.9.3

Which when the shear stress is zero reduces to

22 TTHHC σσσσσ +−= .......................................................................Equation W2.9.4

Evaluate both tensile and compressive stress types.

V3 STRESSES IN UNRESTRAINED PIPELINES

This section provides the definition of stress terms, formulae and units for the evaluation of stresses in unrestrained pipelines, denoting +ve as being tensile.

V3.1 Hoop or Circumferential Pressure Stress Hσ

The Barlow formula for thin wall cylinders

δσ

2DPd

H = ...............................................................................................Equation W3.1.1

where




V3.2 Longitudinal Pressure Stress Lσ

The longitudinal stress from the capped end pressure effect


DR04561.doc

HL σσ 5.0= .............................................................................................Equation W3.2.1

δσ

4DPd

L = ...............................................................................................Equation W3.2.2

where



δ = Nominal wall minus allowances G, in mm

V3.3 Thermal Expansion Stress Range Eσ

The unrestrained thermal expansion stress range in isolation from other stress types, uniaxial with shear, from the maximum shear stress theory.

22 4τσσ += bE ....................................................................................Equation W3.3.1

or alternatively, using the maximum distortion energy theory

22 3τσσ += bE .....................................................................................Equation W3.3.2

where

bσ = The longitudinal bending stress, in Mpa

τ = The resultant torsional shear stress, in MPa

Either the maximum shear stress theory or the maximum distortion energy theory may be used, but shall be used consistently.

( ) ( )Z

MiMi otoitib

22 +=σ .......................................................................Equation W3.3.3

ZM2

=τ ....................................................................................................Equation W3.3.4

ii = Stress intensification factor in plane

io = Stress intensification factor out of plane

Mit = Thermal bending moment in plane, in Nm

Mot = Thermal bending moment out of plane, in Nm

M = Torsional shear moment, in Nm

The section modulus Z to be used to calculate the bending and torsional stresses shall be based on the wall thickness δ in W3.1 above.

Evaluate two values of dT, from the installed temperature

Expansion (T1 - T) at the upper design temperature and

Contraction (T - T2) at the lower design temperature

Thermal Stress Range then considers T1 to T2.

V3.4 Bending Stress Wσ

Bending stresses may be due to gravity from unsupported spans.


DR04561.doc

( ) ( )Z

MiMi ogoigiW

22 +=σ .....................................................................Equation W3.4.1



Mig = Gravity bending moment in plane, in Nm

Mog = Gravity bending moment out of plane, in Nm

The section modulus Z to be used to calculate the bending stress shall be based on the wall thickness δ in W3.1 above.

V3.5 Direct Axial Stresses Fσ and otherσ

V3.5.1 Direct stress from externally applied forces/displacements/pressure

S

FF A

P=σ .................................................................................................Equation W3.5.1

Consider both tensile and compressive stress type.

Where

PF = Direct axial force, in N

AS = ( )4

22iDD −π , in mm2


Di = Internal diameter (D 2δ), in mm

δ = Nominal wall thickness minus allowances G, in mm.

V3.5.2 Stress from other imposed force otherσ

V3.6 Sustained Stress susσ

otherFWLsus σσσσσ +++= ....................................................................Equation W3.6.1

Evaluate the maximum value of stress considering both tensile and compressive stress type combinations.

V3.7 Shear Stress τ

The shear stress from sustained loads due to torsion

ZM t

t 2=τ ...................................................................................................Equation W3.7.1

where

Mt = Torsion moment, in Nm

Z = Section modulus based on δ in 2.1 above

In addition, if direct (plane) shear stress is significant it shall be included in the calculation of total shear stress.

Shear stress due to direct shear = dτ

Total shear stress dt τττ += ....................................................................Equation W3.7.2


DR04561.doc

V4 STRESSES IN ALL PIPELINE APPLICATIONS

V4.1 Occasional Stress oσ

occsuso σσσ += ........................................................................................Equation W4.1.1

where occσ is the stress from the occasional load.

( ) ( )od

oooioiocc Z

MiMiσσ +

+=

22

............................................................Equation X3.1.2

and



Mio = Occasional bending moment in plane, in Nm

Moo = Occasional bending moment out of plane, in Nm

odσ = Direct longitudinal stress due to the occasional load, MPa

Evaluate the maximum value. The section modulus Z to be used to calculate the occasional stress shall be based on the wall thickness δ in W3.1 above.


DR04561.doc

APPENDIX W

EXTERNAL LOADS

(Informative)

W1 GENERAL

Section 5.7.3(c)(ii) addresses the stresses due to transverse external loads and specifies that stresses in pipelines crossing roads and railways shall be calculated by the methods defined in API RP 1102. However external loads can arise from a variety of situations not covered by API RP 1102. This appendix provides guidelines on methods and criteria for assessing the acceptability of external loadings in general, with emphasis on those outside the scope of API 1102.

The purpose of the following information is to provide broad guidance and to identify the key issues that need to be addressed when considering these other types of external loadings. This appendix is not intended to be a comprehensive design manual. Users will need to obtain and use the referenced documents in order to acquire an understanding of the methods discussed herein.

W2 API RPI 1102

API RPI 1102 (1993) is based on research carried out by Gas Research Institute (GRI) from 1989-1991, and reported in the following documents:

GRI-91/0283: Guidelines For Pipelines Crossings Railroads

GRI-91/0284 : Guidelines For Pipelines Crossings Highways

GRI-91/0285 : Technical Summary and Database for Guidelines for Pipelines Crossings Railroads and Highways.

The research involved a combination of analytical methods, finite element modelling and experimental measurements. The later consisted of strain gauging, which was used to validate and calibrate the analytical and numerical modelling.

This broad foundation provides a high level of confidence in the results produced by the API RP 1102 calculation procedures. For this reason API RP 1102 is the preferred approach for the range of loads and depths of cover that are within its scope.

W3 LOAD SITUATIONS

Load situations, together with the recommended engineering methods, can be classified as follows:

(e) Within the scope of API RP 1102 (including all normal road and railway crossing)

Use API RP 1102 (mandatory under this Standard)

(f) Capable of conversion to an equivalent API RP 1102 situation (e.g. some loadings due to aircraft, heavy cranes, etc)

Convert to equivalent loading and use API RP 1102

(g) All other load types Use another approved method

Situation (a), (b) and (c) above are discussed in the following section of this Appendix. All methods require interpretation of the loading to translate it into a form that is suitable for the chosen analysis procedure.


DR04561.doc

W4 VEHICLE LOADS

API 1102 recommends vehicle loads based on practice in the USA. Australian design loads are higher and should be used in preference to the API 1102 recommendations. The best source of information on vehicle loads for ordinary public roads is AS 5100.2-2004: Bridge designDesign loads. Design guidelines for road pavements are less appropriate as they are based on fatigue criteria.

Relevant load cases from the AS 5100.2 are:

W80 wheel loading and A160 axle loading, comprising a single wheel and two-wheeled axle respectively, with wheel load of 80 kN on a tyre footprint 400 x 250 mm, giving an applied surface pressure of 800 kPa.

M1600 moving traffic loading, a complex load footprint which for the purpose of pipeline design consists of a series of axles each bearing 120 kN at spacings as close as 1.25 m. Tyre footprint is 400 x 200 mm, giving an applied surface pressure of 750 kPa.

AS 5100.2 also nominates a dynamic load allowance (DLA) to account for the dynamic effects of vehicles moving over typical road profile irregularities. The DLA varies from 0 to 0.4 and the design load is increased by factor of (1+DLA). For buried structures the recommended value for DLA is 0.3 at the surface decreasing linearly to 0.1 at depth ≥ 2 m.

To use the Australian design loads and DLA in API 1102, the terms Fiw in Equations 5 and 6 should be replaced with the (1 + DLA)wA, where wA is the appropriate Australian applied surface design pressure.

API 1102 distinguishes between single-axle and tandem-axle vehicle configurations and provides guidance on which is the more critical. However that guidance is applicable to the API 1102 recommended loads. For Australian vehicle loads it is expected that the tandem-axle configuration will always be more severe, and hence the tandem-axle values for R and L should be selected from API 1102 Table 2.

W5 EQUIVALENT API RP 1102 LOADS

Because the results of an API RP 1102 analysis are considered to have a markedly higher credibility than those from any other currently available method, it is reasonable to expect that the best results for non-standard loadings will be achieved if the bearing pressure on the ground can be converted to a form that is compatible with the assumptions of API RP 1102.

Suggested below are some conditions under which an equivalent-loads approach may be valid. Care and judgement is required, and the greater the deviation from these conditions the greater the care that must be taken in interpreting the suitability of the application of the method. Particular caution is necessary if cover is low; a load applied to the ground surface in a discrete or irregular pattern will lead to soil stresses that are more uniform at greater depth, but at shallow depth the pattern of soil stresses may remain irregular and may not be a good approximation to the distributions of soil stresses on which API RP 1102 is based.

For railway loads API RP 1102 considers the load from the rail vehicle to be applied to the ground over an area 6.1 x 2.4 m (20 x 8 ft) to which a uniform pressure is applied. Other loads that are widely spread may, with care, be converted to an equivalent load and used in the API RP 1102 calculation. For example, the load due to a large tracked vehicle (bulldozer or excavator) may be suitable for this approach.

For road vehicles API RP 1102 considers both single-axle and tandem-axle load patterns, represented by two or four concentrated load application areas each of 0.093 m2 (144 sq in). It may be possible to approximate other relatively concentrated loads by equivalent vehicle loadings. Examples may include a crane outrigger placed temporarily over the pipe, an


DR04561.doc

aircraft loading (depending on the distribution of the load in both examples), or construction vehicles.

This equivalent-load approach can be recommended only when:

(a) The area over which the load is applied is similar to the load footprint assumed by API RP 1102

(b) The load is evenly distributed over the load application areas

(c) The magnitude of the load does not deviate greatly from the range of loadings covered by API 1102

(d) The depth of cover is 0.9 m or more (if the API RP 1102 road crossing method is used) or 1.8 m or more (if the API RP 1102 railway crossing method is used).

W6 OTHER DESIGN METHODS

Prior to the GRI research leading to API RP 1102 the standard method for analysis of external loads on pipes was due to Spangler et alia. The GRI work cast various doubts on the validity of the Spangler method for high pressure steel pipelines. GRI note that At low internal pressures the Spangler equations predict circumferential stresses much greater than those based on the Cornell/GRI methodology. At high internal pressures, the two design methods are in reasonable agreement , although the reason for the agreement is considered by the researchers to be due to the counterbalancing of two spurious but opposing effects (pressure re-rounding and springline soil support) rather than accurate representation of real behaviour (GRI 91/0285, Executive Summary).

The Spangler method may be used, with appropriate caution, in situations where API RP 1102 cannot be applied either directly or indirectly.

It is not appropriate here to present a full description of the Spangler methods; reference documents should be consulted. Because this approach has been superseded (for most purposes) since about 1990 the best reference material has become dated and may be hard to obtain.

One reference is:

Spangler M.G. & Handy R.L. Soil Engineering, Harper & Row, New York, 1982 (currently out of print, but may be available in libraries),

another reference is:

Guidelines for the Design of Buried Steel Pipe, American Lifelines Alliance (ASCE/FEMA), July 2001 (PDF file available to download from www.americanlifelinesalliance.org).

Other sources may also provide useful information.

There are two parts to the calculation of pipe stress due to external load:

(a) Determination of the loading applied to the top of the pipe, which is a relatively straightforward problem in soil mechanics, and most soil mechanics texts will provide a range of suitable methods

(b) Calculation of the pipe stresses in response to the applied loading, which is where the GRI researchers disagreed with the Spangler approach.

Designers using the Spangler approach should be familiar with the background to the method, and its limitations, and interpret the results accordingly.

Consideration should also be given to the diametral deflection of the pipe, particularly under condition of zero internal pressure. Out-of-roundness may interfere with the passage of pigging devices during commissioning and operation.


DR04561.doc

Where circumferential stress, under zero or low internal pressure, is expected to be significant under soil load or soil reaction, the pipe should be checked to ensure that buckling or denting is avoided.

The guideline usually adopted is that the deflection should not exceed 5% of the pipe diameter.


DR04561.doc

APPENDIX X

COMBINED EQUIVALENT STRESS

(Informative)

X1 INTRODUCTION

Standard AS 2885.1 has limits for hoop stress, total longitudinal stress and combined equivalent stress. These are provided in Clause 5.7. The stress types and their definitions are given in Appendix W.

In AS 2885.1 combined equivalent stress limits are applicable only to that part of the pipeline with full axial restraint. In AS 2885.1 combined equivalent stress means the stress calculated from the combination of the three principal stresses using either the Tresca theory or the von Mises theory of failure.

Where the total longitudinal stress is compressive any increase in the design factor for hoop stress from internal pressure will result in a corresponding reduction in the permissible longitudinal stress because there has been no increase in the allowable value for combined equivalent stress. There will also be a reduction in the thermal expansion (and/or bending and axial) compressive stress components of the total longitudinal compressive stress. In addition there will be a reduction in the permissible longitudinal tensile stress and a reduction in the thermal (and/or bending and axial) tensile components of the total longitudinal tensile stress.

This Appendix sets out a basis for evaluating the longitudinal thermal stresses and corresponding permitted temperature differentials for the buried and fully restrained pipeline. This Appendix assumes that there are not any bending or applied axial stress components (which is typical of the restrained and fully supported pipeline) in the calculation of longitudinal stresses. The methodology provided however could be extended to include these effects where present by modifying the longitudinal stresses accordingly.

X2 DESIGN LIMITS

AS 2885.1 has a design factor related to internal pressure (circumferential hoop) stress design. The upper limit of design factor is currently 0.80 for all location classes. However the hoop stress may be less than 80% SMYS where wall thickness is greater than that required for pressure containment alone, such as resistance to penetration, prevention of rupture and the like.

The limit for total longitudinal stress in AS2885.1is set at 72% SMYS. Where hoop stresses are towards or at the upper limit allowed by the pressure design factor, permissible longitudinal compressive stresses will be significantly lower than this limit because AS 2885 requires combined equivalent stresses to be assessed and limited. This does not apply to longitudinal tensile stresses, however, which may be the same as, but not greater than, the limit allowed by the total longitudinal stress.

AS 2885.1 requires combined equivalent stresses to be assessed where longitudinal stresses are combined with the internal circumferential pressure stress. The total longitudinal stresses may be tensile or compressive or both. Similarly, the combination of stresses applies to the less common torsional stresses. For the fully restrained pipeline, however, there will not be any torsional stress and therefore torsional stress is not considered further in this Appendix.

This Appendix considers triaxial stresses without shear and the three directly applied stresses have been taken to be the three principal stresses. Further, the radial pressure stress


DR04561.doc

has been taken to be zero because it is usually small compared to the other stresses in the pipeline. Whilst the radial pressure stress has been taken to be zero, a triaxial stress state still exists in the pipeline. Note that this is not the same as considering only a biaxially stressed system.

The limits in AS 2885.1 for combined stresses are set at 90% SMYS for long-term stresses. AS 2885.1 permits stresses to be combined using either the maximum shear stress (Tresca) theory or the maximum distortion energy theory (von Mises).

X3 DISCUSSION OF DESIGN FACTOR, STRESS AND TEMPERATURE

The effect of a higher pressure-design factor (new design) or increased MAOP (upgrade) will be to narrow the allowable longitudinal compressive (or torsional) stress limit. Using the full internal pressure design factor of 0.72 for an existing pipeline, an increase to 0.80 will result in a reduction of the allowable longitudinal compressive stress from 50.50% SMYS to 41.45% SMYS using the von Mises theory of failure (and from 39.6% SMYS to 34% SMYS using the Tresca theory of failure). Note that the von Mises theory permits significantly higher longitudinal stresses than the Tresca theory for both compressive and tensile stress.

If all of the total longitudinal stress less the longitudinal pressure component of stress is attributed to thermal stress then for a change in design factor from 0.72 to 0.8 there will also be a reduction in the maximum permitted upper temperature differential from 115oC to 95oC for Grade X80 material and from 50oC to 41oC for Grade B material using the von Mises theory (Refer to clause AX5. of this Appendix for the derivation). For a tie in temperature of 20oC the lowest value of maximum operating temperature is 61oC for Grade B material. This is not considered to be a significant limitation to the use of a design factor of 0.80 because temperatures are usually limited to 60oC for the majority of buried pipelines. Buried pipelines with design temperatures above 60oC require special consideration anyway.

For longitudinal tensile stress there will also be a decrease in the net longitudinal stress and a corresponding decrease in temperature differential. As longitudinal tension permits much higher temperature design differentials than compression it is considered that the higher design factor of 0.8 imposes no additional constraint on combined equivalent stress design for design temperatures less than the closing temperature.

For those parts of the buried pipeline containing significant bending or applied axial loads the thermal stresses and temperature differentials would be reduced below those values stated above.

X4 DESIGN ENVELOPES

Values of combined equivalent stress from the von Mises and Tresca formulae given above have been plotted against longitudinal thermal stress and the equivalent temperature differential in the graphs for temperature and pressure provided at the end of this Appendix as Figures 1.0 to 8.0 inclusive. These are the upper design bounds of the graphs for temperature and pressure only.

Also plotted on the graphs are the plots of longitudinal thermal stress and the equivalent temperature differential but for temperature only, excluding pressure. These are the lower design bounds of the graphs. Together with the combined equivalent stress limit of 90% SMYS these lines together then all form the design envelopes for the two theoretical bases with separate design envelopes for design factors of 0.72 and 0.8.

From the graphs it is possible to see the differences in the design envelopes over any pressure/temperature combination or at the upper and lower limits of pressure and temperature. One significant feature of these envelopes is that the combined equivalent stresses resulting from the design values of temperature and pressure in combination cannot


DR04561.doc

lie outside them. In addition it should be noted that the vertical dotted lines represent the design longitudinal thermal stress and temperature limits for full internal pressure and that greater temperatures beyond these dotted lines are only compliant with AS 2885.1 at a reduced value of pressure. For these greater temperatures the points considered shall still lie within the boundaries of the envelopes.

It should be emphasised that these graphs apply only to positive internal pressure differential and not to a negative internal pressure differential (external pressure). The latter is subject to a different theoretical basis and constraints.

It should also be emphasised that apart from longitudinal pressure stress these graphs only include longitudinal thermal stress and exclude any stresses from bending or from applied loads.

The methodology provided in this Appendix could be adapted to consider additional longitudinal stresses with or without thermal stress to consider the necessary compliance with the limits of combined equivalent stresses required by AS 2885.1.

It is the responsibility of the designer to ensure that all worst case analyses for appropriate combinations of all of the necessary load cases are covered in the evaluation of the combined equivalent stresses for compliance to AS 2885.1.

X5 DERIVATION OF STRESS AND TEMPERATURE VALUES Derivation of the allowable longitudinal compressive stress and tensile stress factors (of yield) and temperature differentials for design factors of 0.72 and 0.8 for pipelines with full axial restraint are provided in this section.

The following derives stress factors, longitudinal stresses and temperature differentials for both the von Mises and Tresca theories of failure for the case of triaxial stress without shear. Also provided are the calculated values of these parameters for design factors of 0.72 and 0.8 for Grade B and Grade X80 materials to demonstrate the differences between them resulting from the different design factors and also from the different material strengths.

The von Mises formula is:

( ) ( )[ ]213

232

221equivalent combined )(5.0 fffffff −+−+−=

and where there is no shear stress:

RthermalHH fffffff =±== 321 ,, µ ,

where ƒ1, ƒ2 and ƒ3 are the three principal stresses, ƒH is the circumferential hoop stress and ƒR is the radial pressure stress.

1. For Fd = 0.72

Putting the limit of combined stress at 0.9ƒy, ƒH = 0.72ƒy and taking ƒR = 0 then:

( ) ( ) LyLyy fffff 72.072.09.0 22 −+=

from which ƒL = -0.2890ƒy and +1.0090ƒy, where ƒy is the material yield strength.

However ƒL is not the longitudinal thermal compressive stress component ƒcomp, it is the net longitudinal stress. To derive the longitudinal thermal compressive stress component the calculation has to consider the longitudinal tensile pressure stress (which is always present in the buried pipeline as longitudinal stress together with the hoop pressure stress).

Hence

Lf = compH ff −µ


DR04561.doc

= compy ff −)72.0(3.0

And as

Lf = yf2890.0−

= ycompy fff 2890.0)72.0(3.0 −=−

From which ycomp ff 5050.0= ,

And 279−=compf MPa for Gr X80 and 122 MPa for Gr B material.

Given that the preceding only applies to fully axially restrained pipe the maximum upper temperature differential that is permitted, assuming that there are no other longitudinal stresses, can be established as follows:

compf

= E T∆α

T∆ = 0.5050 αEf y /

= 0.2085 yf

For Grade X80 pipe with ƒy = 552 MPa the allowable ∆T is 115°C.

For Grade B with ƒy = 241 MPa the allowable ∆T is 50°C.

For the tensile case:

Lf = tensH ff +µ

= 0.3(0.72 yf ) + tensf

And as yL ff 0090.1=

ytensy fff 0090.1)72.0(3.0 =+

from which, ƒƒƒƒtens = 0.793ƒƒƒƒy, where ƒtens is the longitudinal thermal tensile stress component,

and ƒtens = 438 MPa for Gr X80 and 191 MPa for Gr B material.

The corresponding ∆ts are -180oC and -79oC for Gr X80 and Gr B respectively. 2. For Fd = 0.80

Putting the limits of combined stress at 0.9ƒy and ƒH = 0.80ƒy then:

( ) ( ) LyLyy fffff 80.080.09.0 22 −+=

from which yL ff 1745.0−= and yf9745.0+

Hence

Lf = compH ff −µ

= ( ) compy ff −80.03.0

And as

Lf = yf1745.0−


DR04561.doc

ycompy fff 1745.0)80.0(3.0 −=−

from which ycomp ff 4145.0= ,

and 229−=compf Mpa for GrX80 and 100− MPa for Gr B material.

Using the same logic as above, yfT 1711.0=∆ and:

For Grade X80 pipe with 552=yf MPa the allowable T∆ is 95°C.

For Grade B with 241=yf MPa the allowable T∆ is 41°C.

For the tensile case:

tensHL fff += µ

( ) tensy ff += 80.03.0

and as yL ff 9745.0=

ycompy fff 9745.0)80.0(3.0 =−

from which

ytens ff 7345.0=

and 405=tensf MPa for Gr X80 and 177 MPa for Gr B material.

The corresponding T∆ s are -167°C and -73°C for Gr X80 and Gr B respectively.

The Tresca formulae are:

( )

( )

HRce

RthermalHce

thermalHHce

RthermalHH

equivalentcombined

equivalentcombined

equivalentcombined

fff

ffff

ffff

then

fffffff

shearwithoutstresstriaxialforand

fff

fff

fff

−=

−±=

±−=

=±==

−=

−=

−=

3

2

1

321

133

322

211

,,

µ

µ

µ


DR04561.doc

For the upper bounds of pressure and temperature the maximum combined equivalent stress and the corresponding maximum longitudinal thermal stress and temperature differential are as follows:

For thermal compression 1cef governs until Hcomp ff µ=

For thermal tension 2cef governs until HHtens fff µ−=

Between these two points 3cef governs, and taking 0=Rf the factors are as follows:

3. For Fd = 0.72

For compression:

( ) compyy fff +−= 03172.09.0

and ycomp ff 3960.0=

The corresponding stress and t∆ values are:

-219 MPa and 90oC in compression for Gr X80 material,

and

-95 MPa and 39oC in compression for Gr B material.

For tension:

( ) tensyy fff += 3.720.09.0

and ytens ff 684.0=

The corresponding stress and ∆t values are:

378 MPa and -156oC in tension for Gr X80 material,

and

165 MPa and -68oC in tension for Gr B material. 4. For Fd = 0.80

For compression:

( ) compyy fff +−= 3.0180.09.0

and ycomp ff 340.0=


-188 MPa and 78oC in compression for Gr X80 material,

and

-82 MPa and 34oC in compression for Gr B material.

For tension:

( ) tensyy fff += 3.800.09.0

and ytens ff 660.0=


364 MPa and -150oC in tension for Gr X80 material,

and


DR04561.doc

159 MPa and -66oC in tension for Gr B material.


DR04561.doc

438405

405

-229

497

438

-279

-279

-229

552

-497

0.00

100.00

200.00

300.00

400.00

500.00

600.00

-600 -400 -200 0 200 400 600

LONGITUDINAL THERMAL STRESS MPa(Compressive or tensi le)

CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

NoTemp

SMYS

90%SMYS

94

-181

-167

-167205 -205

115

115

94 -181

552

0.00

100.00

200.00

300.00

400.00

500.00

600.00

-300-200-1000100200300

TEMPERATURE DIFFERENTIAL oC

CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

No Temp

SMYS

90%SMYS


DR04561.doc

191177

177

-100

217

191

-122

-122

-100

241

-217

0.00

50.00

100.00

150.00

200.00

250.00

300.00

-300 -200 -100 0 100 200 300

LONGITUDINAL THERMAL STRESS MPa(Compressive or Tensi le)

CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

NoTemp

SMYS

90%SMYS

41-79

-73

-7390 -90

50

50

41 -79

241

0.00

50.00

100.00

150.00

200.00

250.00

300.00

-150-100-50050100150

TEMPERATURE DIFFERENTIAL o C

CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

No Temp

SMYS

90%SMYS


DR04561.doc

378364

364-219

-219 -188

-188-497 378

552

497

0.00

100.00

200.00

300.00

400.00

500.00

600.00

-600 -400 -200 0 200 400 600

LONGITUDINAL THERMAL STRESS MPa(Compressive or Tensile)

CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

NoTemp

SMYS

90%SMYS

77 156

156150

150205 20590

90 77

52

0.00

100.00

200.00

300.00

400.00

500.00

600.00

-300-200-1000100200300


CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

No Temp

SMYS

90%SMYS


DR04561.doc

165159

159-95

-95 -82

-82-217 165

241

217

0.00

50.00

100.00

150.00

200.00

250.00

300.00

-300 -200 -100 0 100 200 300

LONGITUDINAL THERMAL STRESS MPa(Compressive or Tensile)

CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

NoTemp

SMYS

90%SMYS

34 -68

-68-66

-6690 -9039

39 34

241

0.00

50.00

100.00

150.00

200.00

250.00

300.00

-150-100-50050100150


CO

MB

INE

D E

QU

IVA

LE

NT

ST

RE

SS

MP

a

Fd 0.72

Fd 0.80

No Temp

SMYS

90%SMYS


DR04561.doc

APPENDIX Y

PIPE STRESS ANALYSIS

(Informative)

Y1 GENERAL

This Appendix provides some commentary to aid in understanding the criteria for longitudinal and combined equivalent stresses in Clause 5.7. Not addressed here are limitations on hoop stress (no commentary required), and stresses due to transverse external loads (discussed in Appendix YY).

Y2 FAILURE MODES AND CRITERIA

The stress criteria used in this standard are based on limiting the allowable working stress in the pipe.

For restrained pipe the limitation on longitudinal stress (regardless of hoop stress) is consistent with the margin of safety applied to hoop stress. It protects against local buckling (wrinkling) if the load is compressive, and against failure at girth weld defects if the load is tensile.

The limitation on the combined equivalent stress for restrained lines ensures that the biaxial stress state resulting from combined axial and hoop stress does not approach the yield condition. If the combined stress were to result in yielding the plastic deformation would be in both the hoop and axial directions (the exact direction depending in a non-linear way on the magnitude of each stress component). Compliance with this criterion prevents both longitudinal and circumferential deformation.

For unrestrained pipe the limitation on longitudinal stress due to sustained loads provides a large margin of safety against uncontrolled collapse due to loads, which continue to act as the pipe deforms, typically weight and internal pressure. Stresses due to temperature changes are not included in the calculation as they are self-limiting and cannot contribute to uncontrolled collapse.

The limitation on expansion stress range ensures that the variation in stress through each thermal cycle remains fully within the elastic range, i.e. no approach to yield. If yield was repeated on every thermal cycle the variation in stress may rapidly lead to failure due to work hardening. However, it is possible that yielding may occur the first time the pipe experiences the full range of temperature. Calculation of the combined stress from sustained and thermal expansion loads using the Tresca or Von Mises formula for an unrestrained pipe (not required to be calculated by this Standard) can produce values above 100% SMYS despite having individually acceptable values for longitudinal stress and expansion stress range. Such a calculation may indicate that yielding is likely. However, such yielding is acceptable provided that it is not repeated. The limitation on expansion stress range ensures that yielding does not recur. The phenomenon of initial yield followed by elastic behaviour is known as shakedown.

There are no other failure modes associated with longitudinal or combined stresses for normal pipelines. Hence the four criteria defined in the code as discussed above are sufficient to provide a high degree of protection against failure. In unusual circumstances it may be necessary to consider additional failure modes, such as buckling of laterally free but axially restrained pipes.


DR04561.doc

Y3 RESTRAINED AND UNRESTRAINED PIPE

As noted above, the distinction between restrained and unrestrained pipe has implications for the failure mode and hence the stress criteria. However, the distinction between them is not always clear. An alternative terminology that is closely equivalent (and which assists insight) is the distinction between displacement-controlled and load-controlled loading conditions, such as used in DNV OS-F101 (AS 2885.4).

Fully restrained conditions normally occur only in long buried pipelines constrained by soil friction, or in pipe controlled by anchors that are much stiffer than the pipe (difficult to achieve in practice), and only when the pipe is more or less straight. Few other situations offer sufficient resistance to the very high axial force that may occur in a fully restrained pipe. However, conditions approximating full restraint are common, and the stress criteria for fully restrained pipe should be applied.

In a fully restrained pipe, temperature changes result in the development of axial stress with zero change in pipe length, and imposed axial displacements are absorbed entirely by axial strain of the pipe. It is therefore straightforward to calculate the theoretical maximum axial force and stress due to temperature change in a fully restrained straight pipe length.

Unrestrained pipe occurs where the restrictions on pipe movement are relatively minor, such as piping at scraper stations and the like. Buried pipe bends of large angle, and particularly of small radius, (eg. 90° induction bends) are also effectively unrestrained because the resistance offered by the soil is small relative to the forces in the pipe.

In practice, pipes are frequently partly restrained in that they are not completely free of axial restraint but the restraint is not sufficient to develop the very high axial force that develops in a fully restrained pipe.

In cases where the restraint status is unclear it is suggested that consideration also be given to:

(a) The magnitude of the axial force in the pipe relative to the theoretical maximum force required to fully restrain the pipe

(b) The loading condition (displacement-controlled or load-controlled)

(c) The possible failure modes.

If the pipe is not vulnerable to collapse due to the action of sustained loads then it is likely that it should be considered as restrained. However if the pipe is subject to bending moments and the expansion stress range is significant then it may be prudent to apply the criteria for unrestrained pipe.

If doubt still remains regarding the type of restraint condition to be considered then the stress criteria for both restrained and unrestrained situations should be checked.

Y4 SUSTAINED AND SELF-LIMITING LOADS

Sustained loads (i.e. those which continue to act undiminished as the pipe deforms) consist mainly of those due to internal pressure and weight. Certain other loads such as those due to wind, water and earthquake may also be considered as sustained but are rarely encountered as pipe loads. Stresses due to sustained loads are also known as primary stresses.

Self-limiting loads (i.e. those which are relieved as the pipe deforms) consist of those due to thermal expansion/contraction and displacements imposed by the movement of anchors, pipe supports or the surrounding ground. Stresses due to such loads are also known as secondary stresses.

THEORIES OF FAILURE (TRESCA AND VON MISES)


DR04561.doc

There are a number of theories of failure, of which the two most commonly used are known as the Maximum Shear Stress theory due to Tresca and the Maximum Distortion Energy theory due to Von Mises. These two theories are the most appropriate for ductile materials such as steel linepipe. Each theory predicts that yielding will commence when the combined equivalent stress (calculated from the appropriate formula) exceeds the uniaxial yield stress of the material in simple tension. Figure W4 shows the yield locus for each of the two theories. Stress combinations that fall on the locus are at the point of yielding while those inside are still in the elastic range.

It is clear from the figure that the Von Mises theory predicts somewhat greater stresses in certain regions (up to about 15% higher) than the Tresca theory. The Tresca criterion is more conservative, and because it is simpler to calculate it is a useful basis for quick assessment of cases where there is no incentive to maximise the predicted combined equivalent stresses in the pipe. This Standard permits either theory of failure to be used, but once one theory is adopted it should be used throughout unless the most conservative combinations of the two theories are used. Calculations carried out to API RP 1102 need not be included in this consideration.

Y5 YIELDING

The term yielding of the pipe is used in the Standard and may have different values for the same pipe depending on the way in which it is derived and the context in which it is used. Some of the meanings relating to yielding are as follows:

W5.1 The result from a sample specimen tested in simple tension to determine the yield point of the material under test

W5.2 The result from a sample specimen tested using the ring expansion test to determine the yield point of the material under test

W5.3 The prediction of the onset of yield in a tubular cylinder from internal pressure using the Barlow formula and the SMYS of the material being considered

W5.4 The prediction of the onset of yield using an equivalent stress theory such as the Tresca or Von Mises formula

W5.5 The end point in a volume-strain controlled hydrostatic pressure test equal to 0.4% offset volume strain.

Each of these references will have a different numerical value for a particular application. The terms yield, yielding, and yield pressure should be qualified by the basis to which they are being referred.

The reference in W5.1 and W5.2 above relate to the establishment of the yield point (or SMYS) using a specimen flattened from a circular test piece and a tubular specimen expanded in a ring test respectively. The yield stress for a pipe is determined in accordance with API 5L, which defines it as the stress corresponding to 0.5% total strain. In normal linepipe steel this yield stress is at a point on the stress-strain curve where there has already been a small amount of plastic strain.

Before and during the hydrostatic pressure test the onset of yield may be predicted from W5.3 above for monitoring the expected deviation from the slope of the P-V plot during pressurisation.

The theories of failure in W5.4 above relate to the evaluation of the equivalent stresses and comparison to the value of yield in simple tension. These references are appropriate to the design evaluation of the stress conditions from the applied loads. These theories are also used in comparing the strength of the pipe steel in the mill pressure test to the in ground strength of the pipeline. For more discussion of this aspect of yield refer to AS 2885.5.


DR04561.doc

Y6 COMPUTATION OF STRESSES

It is normal to use proprietary pipe stress analysis software to calculate stresses and compare them with the allowable criteria, although there is no reason why calculations should not be done by hand, spreadsheet, or general purpose, finite element software. A major advantage of using proprietary pipe stress analysis software is that can greatly simplify the comparison of calculated stresses with the specified code criteria. Users of this Standard may wish to note that the stress criteria adopted in this Standard are functionally identical with those of ANSI/ASME B31.4, and B31.4 code calculations in standard software may be used without modification. However, the allowable stress limits in B31.4 may need to be amended to comply with this Standard.

The appropriate design factor and other factors relating to allowable stress criteria of this Standard will need to be considered. For example the default design factor to B31.4 may be 0.72 and may need to be overridden in the input file where the design factor has some other value to this Standard. The occasional load factor may also need to be overridden to conform to the requirements of this Standard. The longitudinal joint factor for pipes manufactured in accordance with this Standard will be unity. The correct insertion of these factors will need to be confirmed by the users of the software. Where factors are overridden in proprietary software, the software may not issue a compliance statement to B31.4. This is acceptable provided the allowable limits of this Standard are not exceeded.

Y7 Plastic strain and limit state design methodologies

It is the intention of Clause 5.7.3 that pipelines designed in accordance with it will not experience plastic strain during operation, other than shakedown of unrestrained pipe when first put into service.

Plastic strain in a pipeline may be accepted under the following conditions:

(a) The pipeline is designed in accordance with a recognised alternative standard based on limit state design principles. The alternative standard shall be thoroughly reviewed to confirm that it is applicable to the circumstances of the pipeline under design. The review shall be documented and the alternative standard shall be approved.

(b) A pipeline exposed to risk of plastic strain as result of unforeseen circumstances such as ground movement. Plastic strain in a pipe that is already in service may be accepted provided that thorough engineering investigation and risk assessment demonstrates that the strain does not significantly increase the risk of failure. The engineering investigation and risk assessment shall include but not necessarily be limited to consideration of:

(i) The stress-strain properties of the pipe steel (including strain ageing and work hardening).

(ii) The extent of plastic strain.

(iii) The likelihood of further or continuing strain.

(iv) The likelihood of wrinkling or buckling.

(v) The likelihood of weld under matching (if longitudinal stress is tensile).

(vi) The possibility of cracks at points of stress concentration.

(vii) The effect of pipe deformation on operation (e.g. pigging).

(viii) The accuracy of the information on the cause of the strain.

(ix) The sensitivity of the analysis to variations in key parameters


DR04561.doc

(x) The risks that may arise from alternative methods of dealing with the plastic strain (such as exposing the pipe to release it from soil restraint, or cutting the pipe and consequential stress/strain reversal)

NOTES: 1 Plastic strain here refers to plastic deformation that occurs at stresses above those permitted

by Clause 5.7.3, including stresses above SMYS.

Most pipe stress analysis software assumes that the pipe is fully elastic and may not produce valid models pf pipe behaviour if calculated stresses exceed SMYS.

PREPARATION OF AUSTRALIAN STANDARDS

Australian Standards are prepared by a consensus process involving representatives nominated by organizations drawn from all major interests associated with the subject. Australian Standards may be derived from existing industry Standards, from established international Standards and practices or may be developed within a Standards Australia technical committee.

During the development process, Australian Standards are made available in draft form at all sales offices and through affiliated overseas bodies in order that all interests concerned with the application of a proposed Standard are given the opportunity to submit views on the requirements to be included.

The following interests are represented on the committee responsible for this draft Australian Standard:

Australasian Corrosion Association

Australian Chamber of Commerce and Industry

Australian Institute of Petroleum Ltd

Australian Petroleum Production and Exploration Association

Australian Pipeline Industry Association

Bureau of Steel Manufacturers of Australia

CRC for Welded Structures

Department of Business Industry & Resource Development (NT)

Department of Energy, Utilities and Sustainability (NSW)

Department of Industry and Resources (WA)

Department of Labour New Zealand

Department of Natural Resources and Environment (Victoria)

Department of Natural Resources and Mines (Qld)

Gas Association of New Zealand Inc

Primary Industries and Resources SA

The Australian Gas Association

Welding Technology Institute of Australia