120708557 pipeline integrity

7/29/2019 120708557 Pipeline Integrity

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Phil Hopkins Penspen Group, UK

Final Draft for Editor, May 2002 Keywords Page 1 of 62

ELSEVIER PUBLISHERS

COMPREHENSIVE STRUCTURAL INTEGRITY

Volume 1

The Structural Integrity Of Oil And Gas TransmissionPipelines

by Phil Hopkins, Penspen Ltd., UK.


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CONTENTS

1. INTRODUCTION2. PIPELINES

2.1 Pipelines A Brief History2.2 Pipelines Types2.3 Pipeline Design, Regulation and Materials

2.4 Design Stresses, Hydrotesting, and Location2.4.1 Design Stresses2.4.2 Hydrotesting Pipelines2.4.3 Location of Pipelines

2.5 Pipeline Operation, Inspection and Maintenance2.5.1 Operation and Leak Detection2.5.2 Pipeline Protection2.5.3 Pipeline Inspection and Maintenance

2.6 Why Do Pipelines Fail?2.7 Ageing Pipeline Assets

3. PIPELINE INTEGRITY AND RISK MANAGEMENT3.1 Pipeline Integrity and Integrity3.2 Integrity Management and the Movement to Standardise

3.2.1 Legislation on Pipeline Integrity Management

3.2.2 Response to Legislation by Codes and Standards3.2.3 Intent of Legislation and Code

3.3 Risk Management

3.3.1 Risk Management in Law3.3.2 Corporate Responsibility3.3.3 The Move to Risk Management

3.3.4 Structural Integrity in Risk Management3.3.5 Risk and Gain3.3.6 Risk Management and Risk Analysis

4. STRUCTURAL INTEGRITY OF OIL AND GAS PIPELINES

4.1 How a Pipeline Fails4.1.1 Mode of Failure4.1.2 Running Fractures

4.1.3 Ductile Fracture4.2 Failure Process4.3 Fitness For Purpose (FFP)

4.3.1 Generic FFP4.3.2 Pipeline-Specific FFP

4.3.3 Legal Note4.4 History of Pipeline Defect Assessment Methods.

4.4.1 The Very Early Days

4.4.2 The Pioneers4.4.3 The Basic Equations

4.4.4 Summary Curves4.5 Structural Assessment of Defects in Pipelines

4.5.1 Safety Factors

4.5.2 Defect-Free Pipe under Internal Pressure4.5.3 Axially-Orientated Gouges or Similar Metal Loss Defects

4.5.4 Dents

4.5.5 Corrosion

4.5.6 Environmental Cracking

4.5.7 Material Defects4.5.8 Construction Defects

4.5.9 Defects in Girth Welds

4.5.10 Other Fitness -For - Purpose Methods For Transmission Pipelines

4.5.11. Sub-sea Pipelines

4.5.12. Repair and Rehabilitation4.5.13. Other Components of a Pipeline System5. THE ROLE AND IMPORTANCE OF STRUCTURAL INTEGRITY ASSESSMENTS OF

PIPELINES

6. CONCLUDING COMMENTS

Acknowledgements

References


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THE STRUCTURAL INTEGRITY OF OIL AND GAS TRANSMISSION

PIPELINES

1. INTRODUCTION

Oil and gas provide 60% of the worlds primary fuel. Therefore, it is not surprising todiscover that there are over 1 million tonnes of oil and 250 million cu metres of gasconsumed every hour around the world.

Most of this oil and gas is transported in pipelines. The larger of these pipelines arecalled transmission pipelines (Figure 1); the general public will not normally seethese lines as they are either under the sea, or buried on land, but they are the mainarteries of the oil and gas transportation systems.

Figure 1. Transmission Pipelines being Constructed in the Far East and Europe(Images copyright of Penspen Ltd., UK).

They are usually large diameter and operate at high pressures to allow high

transportation rates. They are designed, built and operated to well-establishedstandards and laws, because the products they carry can pose a significant hazard tothe surrounding population and environment, but the combination of good design,materials and operating practices has ensured that transmission pipelines have a good

safety record.

All pipelines must ensure:

i. Safety - the system must pose an acceptably low risk to the surroundingpopulation,


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ii. Compliance with Codes and Legislation the system must satisfy localand national standards and laws,

iii. Security of Supply - the system must deliver its product in a continuousmanner, to satisfy the owners of the product (the 'shippers') and theshippers' customers (the 'end users'), and have a low risk of supply failure,

iv. Cost Effectiveness - the system must deliver the product at an attractivemarket price, and minimise the risk of losing business.

These are achieved by ensuring our pipeline is correctly designed and does not

experience a structural failure due to:

- burst,- puncture,- overload,- structural collapse (buckling),- fatigue, and- fracture,

and we do not want our pipeline to become unserviceable due to:

- ovalisation,- blockages,

- distortions, and- displacements.

Therefore, the structural integrity of pipelines commences with good design andconstruction practices, which will eliminate most of the above potential failure modes,

but as pipelines can operate in hostile environments (underground or subsea) they areconstantly threatened by defects and damage that occur in-service. These in-servicedefects are the major cause of pipeline failures; therefore to understand and controlstructural integrity, in-service defects must be understood and controlled.

The occurrence and behaviour of defects in pipelines has been the subject of extensiveresearch and development for over 35 years, and this chapter presents an overview of

this work, detailing the current best practices in their structural assessment. Thechapter also covers some of the key design aspects of a pipeline that affect structuralintegrity.


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2. PIPELINES

2.1 Pipelines A Brief History

Our ancestors used wood and clay pipes many centuries ago; the Chinese usedbamboo pipe to transmit natural gas to light their capital, Peking, as early as 400 BC,and 1000 years ago, tired Iraqi women forced their men folk to build pipelines to save

them carrying water from the wells. The Romans used lead pipes to distribute water inhighly developed towns in 500 BC, and the use of steel or iron pipelines started in theUK in 1820 when cast iron musket barrels left over from wars were used to transportgas made from coal.

At the same time (1821), hollowed out logs were used in the USA to transport naturalgas used for lighting, but it was not until 1843 that iron pipe was used to reduce theobvious hazards.

The oil and gas industry first started using steel pipelines in the USA in the mid-1800s. In those days oil was transported in barrels on rivers by horse-drawn barges;

this was dangerous because weather and labour disputes often disrupted flow. Therailway relieved this, but the oil was now controlled by the rail bosses and theirteamsters.

In 1879 a 173km (108 mile), 152mm (6in) diameter line was built in Pennsylvania totransport crude oil, to tank cars for the New York market and 12 years later the firsthigh pressure, long distance pipeline was built. The pipeline reduced the transport costof oil from $3 to $1 per mile.

Figure 2. Pipeline under Construction in the UK (Image copyright of PenspenLtd., UK).


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Initially, all steel pipes used to construct the pipeline had to be threaded together. Thiswas difficult to perform for large pipes, and they were liable to leak under high

pressure. The application of welding to join pipes in the 1920s made it possible toconstruct leak-proof, high-pressure, large diameter pipelines.

Long distance pipelines were pioneered in the USA in the 1940s due to the energy

demands of those war years, and now most countries ar ound the world have atransmission pipeline system in place. These systems range from relatively small (the

UK has 30,000 km of transmission oil and gas pipelines) to very long (the USA hasover 500,000 km of natural gas transmission pipelines). Figure 2 shows a moderntransmission pipeline under construction.

2.2 Pipelines - Types

There are many types of oil and gas pipelines:

i. FLOWLINES & GATHERING LINES These short distance linesgather a variety products in an area and move them to processing facilities.

They are usually small diameter (50mm (2in) to 305mm (6in)).ii. FEEDER LINES - These pipelines move the oil and gas fluids from

processing facilities, storage, etc., to the main transmission lines. They can

be up to 508mm (20in) in diameter.iii. TRANSMISSION LINES These are the main conduits of oil and gas

transportation. They can be very large diameter (Russia has 1422mm (56)diameter lines) and very long (the USAs liquid pipeline system is over250,000 km in length). Natural gas transmission lines will usually deliverto industry or a distribution system, whereas crude oil transmission linescarry different types of product, to refineries or storage facilities.

iv. PRODUCT LINES - Pipelines carrying refined petroleum products fromrefineries to distribution centres are called product pipelines.

v. DISTRIBUTION LINES - These allow local, low pressure, distribution

from a transmission system. Distribution lines can be large diameter, butmost are under 152mm (6in) diameter.

This chapter focuses on steel (lin epipe see next Section) product, transmission,feeder, flowlines and gathering lines; it does not cover distribution lines as they can

be made out of differing materials to steel (e.g. cast iron, plastic).

Finally, it should be noted that a pipeline is part of a very large and complex systemthat includes the linepipe pumps, storage facilities, valves, etc.. This chapter considers

the pipeline, and not the associated plant.

2.3 Pipeline Design, Regulation and Materials

The prime role of pipeline design is safety. Most transmission pipelines are designedto the American Society of Mechanical Engineers (ASME) standards (ASME B31.8for gas lines and ASME B31.4 for oil lines) or standards based on these. The designand operation of pipelines is usually regulated or subject to local laws. In the UK,


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pipelines are covered by the Pipelines Safety Regulations 1996, which detail design,construction, operation and maintenance requirements for pipelines.

The pipelines are made by welding together lengths of steel pipe (called linepipe),typically bought to the American Petroleum Institute standard API 5L, Figure 3.

Figure 3. Pipeline Welding Crews on a Pipeline in the Americas (Image

copyright of Penspen Ltd., UK).

The linepipe is known by its diameter, wall thickness, weld type (either longitudinallywelded, spiral welded, or seamless), and grade; grade X60 has a minimum specifiedyield strength of 60,000 lbf/in2 (414N/mm2). Figure 4 gives some typical yieldstrengths in operating pipelines in the US A. The highest grade in use today is X80.

The toughness (ability of the steel to withstand the presence of cracks) is also

important. Modern steels can be purchased with Charpy toughnesses of 300J(221ftlb), but older steels can have much lower toughnesses, Figure 4.


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Figure 4. Variations in Yield Strength and Impact Toughness of Older LinepipeSteels in the USA [Eiber et al, 2000]1

2.4 Design Stresses, Hydrotesting, and Location

2.4.1 Design Stresses

Pipelines must be able to withstand a variety of loads, ranging from the high loadsthey see during construction (e.g. during laying offshore) and during operation (e.g.due to frost heave).

However, the major stress in most pipelines is that caused by the internal pressure2,

and this hoop stress is usually the major design consideration. Most design codes usethe following equation for calculating the hoop stress:

Hoop stress = h = PD/2t =y = SMYS (1)

P = pipeline pressure,D = outside pipe diameter,t = pipe wall thickness, = design factor (see below),

1 These are approximate values. See Eiber et al, 2000 for details. This figure shows his torical data, andtherefore the old units are retained. Toughness: 1J=0.738ftlb. Strength: 1lbf/in 2 = 0.006895N/mm2 .

The pipeline business started in the USA, and it has retained many USA stress units: 1 ksi = 1000 psi =1000 lbf/in

2= 6.89 MPa = 6.89 MN/m

2= 6.89N/mm

2.

2Pressure is the force per unit area exerted by the medium in the pipe. There is often confusion over

pressure terminology around the world you may often see pressures written as gauge pressure orabsolute pressure, or psia or psig. Atmospheric pressure (Patmos) is the pressure due to the

weight of the atmosphere (air and water vapour) on the earth's surface. The average atmosphericpressure at sea level has been defined at 1 bar (=105Pa or 14.5 lb/in2) absolute. Pressure absolute (Pa)

(denoted psia in imperial units) is pressure in excess of a perfect vacuum. Absolute pressure is

obtained by adding gauge pressure to atmosphere pressure: Pa = Pg + Patmos. Pressures reported inAtmospheres are usually taken to be absolute. Pressure gauge (Pg) (denoted by psig in imperialunits) is the pressure above atmospheric pressure. Gauge pressures below atmospheric pressure arecalled vacuum. In the pipeline industry, gauge pressure is in common use.

0

10

20

30

40

50

60

70

80

90

Strengt

h

(lbf/in2

)

30 3 5 42 52 60 70

G r a d e

Min Av e Max

0

10

20

30

40

50

60

70

80

Toughn

ess

(ft

lb)

35 42 5 2 60 70

G r a d e

Min Ave Max

axial

hoop


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y = the yield strength of our linepipe (the linepipe is purchased to themanufacturers specified minimum yield strength (SMYS)).

Most pipeline design codes use outside diameter in the hoop stress formula. Thisgives a conservative stress. The more accurate cylinder hoop stress formula (using

both internal and outside diameter) gives values of hoop stress within 5% of the abovesimple formula for D/t>20.

ASME uses nominal (specified) wall thickness in its design stress calculation, but

other codes in other countries may use minimum wall thickness.

The pressure also causes both a hoop stress and an axial stress, that tries to elongatethe pipeline. This can be visualised by a long thin balloon being inflated - its diameterand length expands. The magnitude of this axial stress is:

- 0.3xhoop stress if expansion of the pipe is restricted, e.g. it is buried andrestrained by the surrounding soil,

- 0.5xhoop stress if the pipe is capped and free to expand, e.g. at bends.

The maximum hoop stress in pipelines around the world is 72% SMYS (giving a

design factor (hoop stress/SMYS) of 0.72), although there are some pipelinesoperating at higher factors (e.g. the maximum design factor in Canadian pipelines in

0.8). Note that most pipeline codes allow overpressures of typically 10% over thismaximum stress; therefore, a pipeline at 72% SMYS can experience an overpressureto 79% SMYS.

The Design Factor is a safety factor and allows for:- variability in materials,- variability in construction practices,- uncertainties in loading conditions,- uncertainties in in-service conditions.

2.4.2 Hydrotesting Pipeli nes

When the as-built condition of a structure cannot be proven it will have a low designfactor (e.g. bridges, ships cannot be proof tested, so their design factor is ~0.6. If thestructure may buckle, the factor is reduced to ~0.5 [Leis & Thomas, 2001]). However,if the structure cab be proven prior to service, or if it has a high redundancy in thestructure, it can tolerate higher design factors.

Structures have been proof tested for many centuries. In our own experience we know as children, - that if you want to go ice-skating on a frozen pond, it is best to sendthe fat kid onto the thin ice first. If the ice holds, we go skating, if the ice fails, welose the fat kid.

In the middle ages, civil engineers would build bridges, but would not be able tocalculate their true strengths. Therefore, they would invite the local army battalion to

open the bridge by marching across it with its horses, cannons, etc.. The armythought they were part of a celebration in fact they were the proof load.


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Pipelines can be proof tested by pumping them full of water to a high stress; therefore,they can tolerate higher design factors. This proof test takes the form of a hydrostatictest prior to service, to a high stress levels (e.g. 100% SMYS for gas lines in theUSA).

The proof test ensures we have a guaranteed margin of safety on entering service,Figure 5.

Figure 5. Margin of Safety3 at Start of Life for a Pipeline

The concept and value of hydrostatic testing of transmission pipelines started in theearly 1950s when Texas Eastern Transmission Company in the USA wanted torehabilitate their War Emergency Pipelines and convert them to gas [Kiefner and

Maxey, 2000]. Before any testing, these lines failed frequently in -service because oforiginal manufacturing defects in the linepipe. Battelle Columbus Laboratories in the

USA suggested that these lines should be hydrotested prior to conversion. The lines

failed 100s of times on test, but never in-service from manufacturing defects4

.

Typically a pre-service hydrotest will be conducted at a pressure of 1.25 times themaximum design pressure. The hydrotest is now widely accepted as a means of:

checking for leaks, proving the strength of the pipeline, removing defects of a certain size (the higher the stress level in the test, the

more defects likely to fail),

blunting defects that survive, and this increases subsequent fatigue life,reducing residual stresses, and

warm prestresses defects that survive, and this improves their lowtemperature properties.

3 Failure stress of defect-free linepipe is at least 1.25xSMYS but cannot exceed UTS [Leis and

Thomas, 2001].4It is interesting to note that many 1000s kms of pipelines have since been tested, and there has never

been a subsequent in-service rupture from manufacturing/construction defects [Kiefner and Maxey,

2000].

0.72

Design Hydrotest Failure

0

0.5

1

1.5

DesignFactor

Safety Factor

based onhydrotest

Safety Factor

based onfailure

Actual failure stress of defect free

linepipe is UTS or >1.25xSMYS


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The hydrotest was originally used to detect (by failing) original manufacturinglinepipe defects, but modern linepipe is usually free from these older type defects, andlinepipe is now highly quality assured before delivery to site. Therefore, the primerole of the hydrotest today is a leak test, not a strength test.

2.4.3 Location of Pipelines

Most countries have laws or regulations that require pipelines carrying hazardousproducts to be built in areas either away from local population, or in low population

density areas. This ensures that the pipeline operates in a safe corridor and theconsequences of any failure are limited.

Pipeline codes treat oil and gas pipelines different. For oil pipelines:- no account is usually taken of population density in the location of the

pipelines (but note the new movement in USA in Section 3.2, later),- there is no specified distance to occupied buildings,- you can generally build an oil pipeline with a high design factor (design

factor is hoop stress/material yield strength) of 0.72 in most locations.

However for pipelines carrying a more hazardous product such as natural gas (Figure6) :

- account is taken of population density,

- a minimum distance (a proximity) from occupied buildings is specified,- design factor is lowered in populated areas (0.3 in UK, 0.4 in USA).

Figure 6. Locating Pipelines Carrying Hazardous Products in Populated Areas

2.5 Pipeline Operation, Protection, Inspection and Maintenance

Pipeline operation and maintenance is both comprehensive and diverse. The followingsection gives some key elements that relate to pipeline integrity.

CorridorWidth Proximity

No restr ic t ion in th is zone

Prevent, or severely limit,

building in this zone

Prevent, or severely limit,

bu i ld ing in th is zone

Limit bui ld ing

in th is zone

L imi t bu i ld ing

in th is zone

No restr ic t ion in th is zone


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2.5.1 Operation and Leak Detection

Modern long-distance pipelines are operated mainly automatically by a computer atthe headquarters of the pipeline company. The computer monitors the pressure, flowrates, and other parameters at various locations along the pipe, performs many on-linecomputations, and sends commands to the field to control the operation of the valvesand pumps. Manual intervention is frequently needed to modify the automatic

operation, as when different batches of fuels are directed to different temporarystorage tanks, or when the system must be shut down or restarted.

The pipeline will be fitted with some type of leak detection system, to allow for arapid response should the pipeline fail. There are various types of system:

i. Simple Systems (Seeing or Smelling) - The simple systems involveflying, driving, walking along or surveying a pipeline and looking forevidence of discoloured vegetation around the pipeline, or hearing orsmelling (if the fluid is odorized) a discharge. Unofficial pipeline leakdetection is performed by members of staff working near a pipeline(e.g. on an offshore platform) or members of the public living near, or

passing, pipelines.ii. Flow Balance (What goes in, must come out) - Simple line flow

balances can be used to detect leakages. This involves measuring

inputs and outputs of a pipeline. A loss of product is determined as thedifference between the steady state inventory of the system and the

instantaneous inlet and outlet flows.iii. Acoustic Methods (Leaks are noisy) - Noise associated with a leak

can be detected. These frequencies, caused by vibration, can havefrequencies in excess of 20 kHz. Transducers can be clamped to a

pipeline, and by noting signal strength, the source of the leak can bepinpointed.

iv. Pipeline Modelling (Theory versus Operation) - Real time pipelinemodelling, which simulates the operation of the pipeline and

continually compares the expected with the actual, can offer bothdetection and location of leaks. There are commercial packages on the

market that may be appropriate to certain pipeline operations. Themodel is a mathematical representation of the pipeline and will includesuch features as elevation data, valve and pump locations, etc.. Themodel can then calculate the expected pressures, flows etc., andcompare them with what the measurements are showing. Anydiscrepancy may be a leak, and leak alarms can be triggered if this isthe case.

Leaks can be difficult to both detect and locate due to transients in the control systemsand the product flow.

2.5.2 Pipeli ne Protection

Pipelines are designed to be protected from the environment as follows:


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i. EXTERNAL CORROSION - The pipe steel must be separated from thesoil or water environment otherwise it will corrode. Usually, there is nocorrosion allowance (increase thickness of linepipe specifically to allowfor predictable corrosion wastage) for external corrosion in pipelines.Hence the outside surface of the linepipe is protected by using a pipecoating (e.g. coal tar) as the primary protection, and a corrosion protectionsystem is the secondary protection.

ii. INTERNAL CORROSION A corrosion allowance to accommodate in-service, predictable, corrosion can be introduced at the design stage;

however, it is preferable to prevent internal corrosion by: treating theproduct prior to entry into the line, and checking quality, cleaning the line,mixing chemicals to inhibit any corrosion.

iii. EXTERNAL DAMAGE Pipelines can be protected from third partiesby: thicker pipe wall, deeper cover (but beware of overburden), locating inremote regions, regular patrols or surveys of the line, clear markings, goodcommunications with third parties including the general public, protectivemeasures such as concrete casings 5 , and damage detection equipment.

2.5.3 Pipeline Inspection and Maintenance

Pipeline regulations and codes require an operator to maintain and inspect theirpipeline to appropriate standards. Maintenance of a pipeline is an essential part of

maintaining the overall integrity of the entire pipeline system. Therefore, pipelines areroutinely inspected and monitored using many direct and indirect techniques. The

methods aim to ensure that:a) pipelines do not become defective or damaged ('proactive' (P in Table 1 below)

methods),b) damage or defects are detected before they cause serious problems ('reactive' (R

in Table 1 below) methods).

Courtesy of Tuboscope Services UK


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Figure 7. A Pipeline Inspection Tool The Intelligent Pig (Image copyright of

Tuboscope Services, UK).

An operator should assess the greatest damage/defect risk to his /her pipeline, thenselect a monitoring/inspection method to reduce that risk. Hence, pipeline operatorsuse a variety of methods to ensure their pipelines are not damaged, or that damage isdetected before it poses a problem. Some of these methods are now summarised in

Table 1. It should be noted that the methods used are simply to either prevent ordetect damage to the pipeline; examples are given below:

i. Patrols Aircraft, road and walking patrols along pipeline routes can

check for unwanted or unplanned excavations around the pipeline,encroachment of population/buildings. Sub-sea pipelines are regularlysurveyed using a survey boat and associated equipment to check the

pipeline route.ii. Internal Inspection Pipelines can now be inspected from the inside,

without serious disruption to the product flow by intelligent6 pigs, Figure7. The pigs are sophisticated machines that usually travel with the

product and via arrays of sensors record data on the condition of the pipe.

These pigs (named pigs because early pipeline engineers thought thenoise they made as they passed through the pipeline resembled a pigsquealing) can measure metal loss (e.g. corrosion), and geometry

abnormalities (e.g. dents). More specialised pigs can map the pipeline, andothers can detect cracks.

iii. Above Ground Inspection The condition of the pipelines corrosionprotection system, and its coating can be determined remotely using aboveground measurements. Sub-sea pipelines can have similar surveysconducted using remotely operated vehicles (ROVs).

iv. Leak Surveys Leaks in pipelines can be detected by on-line systems (seeabove), and also by patrols that may see discoloured vegetation (in onshorelines), or traces of product (in sub-sea lines).

v. Specialised Surveys Pipelines can be subjected to detailed geo-technical

surveys to detect subsidence, etc., and can be fitted with strain gauges todetect excessive stressing.

vi. On-line Quality Monitoring Product quality control, and on-linemeasurement of product properties can help control internal corrosion anderosion.

vii. Hydrotesting - Some pipelines are periodically hydrotested in-service toprove integrity (see Section 2.4.2).

viii. Public Awareness Pipeline operators will liaise with farmers, fishingorganisations, etc., to ensure that organisations that may be workingaround their pipelines, are aware of the location of the lines, and do not

damage them. There is an increased use in one call systems in onshorepipelines where contractors and utilities call a telephone help line before

5 Sub-sea pipelines are often encased in concrete. This concrete coating is primarily a weight coating it prevents the pipeline floating; however, it additionally offers protection against impact from, e.g.anchors.6 Intelligent pigs are known as smart pigs in the USA. Pigs have been used for over 100 years in thepipeline business, primarily to clean a line, or prove its shape. However, when a pig collects data on-board, it is classed as intell igent.


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they carry out excavations. This call allows a central organisation to checkfor the presence of sub-surface utilities such as pipelines, and either

prevent the excavation, or supervise it.

DEFECT/DAMAGE

SURVEILLANCE/INSPECTION METHOD

AERIAL/GROUNDPATROLS7

INTELLIGENTPIGS

PRODUCTQUAL ITY

LEAK

SURVEYSGEOTECH

SURVEYS

& STRAIN

GAUGES

CP &

COATING

SURVEYS

HYDRO-TEST

3rd Party D amage P R RExt. Corr osion R P RI nt. Corr osion R P R

Fatigue/Cracks R RCoatings P

Materi als/ConstructDefects

R R

Ground Movement R R

Leakage R P R R

Sabotage/Pilfering P

(Visual examinations and public awareness are not included)

Table 1. Some Examples of Pipeline Inspection and Monitoring Methods2.6 Why Do Pipelines Fail?

Pipelines are a very safe form of energy transportation; however, like any otherstructure they do fail. The major causes of failure, in both onshore and offshore

pipelines are:

outside force (sometimes called third party damage, mechanical damage orexternal interference), such as caused by a farmer ploughing a drainage ditch,

or a supply boat dragging its anchor around an offshore platform, corrosion of the pipe wall, either internally by the product or externally by the

surrounding environment.

Figure 8 shows the main causes of pipeline failures in the USA. Outside force andcorrosion are the major failure causes, followed by construction/material defects,equipment/operator error, and other failure causes (e.g. leaking valves).

These failures can cause casualties; and there have been some tragic pipeline incidentsin recent years on both oil and gas lines [Anon., 2002a].

7 Sub-sea pipelines are surveyed by a variety of means. The pipeline will often be flown using aremotely operated vehicle (ROV) which can be equipped with a variety of tools to visually inspect thepipeline and also check i ts condit ion.


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Figure 8. Onshore Pipeline Data from Office of Pipeline Safety, USA, 2000

[Anon., 2002a].

Some benchmark figures for the frequency of pipeline incidents are:

INCIDENT Frequency (incidents/1000km year)

Incident Requiring Repair 4Failure (loss of product) 0.6

Failure (casualties and/or high costs) 0.16

Table 2. Benchmark Incident Rates for Western World Pipelines [Hopkins,

1994]

2.7Ageing Pipeline Assets

One of the biggest problems facing the pipeline industry is the fact that the worldspipeline infrastructure is ageing. For example:

i. over 50% of the 1,000,000 km USA oil and gas pipeline system is over 40 yearsold,

ii. 20% of Russias oil and gas system is nearing the end of its design life. In 15years time, 50% will be at the end of its design life.

This is a real problem when one considers that there is 50 years of proven oil & gassupplies in the world, and the existing pipeline infrastructure will be expected to carry

much of this.

Therefore, care for our ageing assets is a major engineering challenge facing us, andstructural integrity assessments will be a key tool we will use.

Corrosion

23%

Outside Force25%

Failed

pipe/weld

Other

30%

Op./Equip.Error

10%

Corrosion

39%

Outside Force

Const/Mat

Defect

9%

Other

27%

LIQUID

GAS

25%


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3. PIPELINE INTEGRITY AND RISKMANAGEMENT

Most industries have methods available for the assessment of structural integrity.These methods vary from previous good practices to sophisticated analytical methods,

but to understand what is required in a pipeline integrity assessment, an appreciationof what we mean by integrity is first needed.

3.1 Pipeline Integrity

A structural integrity assessment (see Section 4.2) of a pipeline defect will not, on itsown, ensure continuing pipeline integrity. This is because pipeline integrity isensuring a pipeline is safe and secure. It involves all aspects of a pipelines design,operation, inspection, management and maintenance. This presents an operator with acomplex jigsaw to solve if they are to maintain high integrity, Figure 9.

Figure 9. Key Elements of Pipeline Integrity [Hopkins, 2001a].

The key elements include [Hopkins 2001a, Hopkins 2001b]:

a highly trained workforce, good engineering, design, operation, inspection and maintenance, fitness for purpose assessment, and an appreciation of the risks associated with a pipeline, particularly as it ages.

These key elements are all contained and controlled via a formal pipelinemanagement system [Hopkins, 2001b].

Finally, pipeline failures are usually related to a breakdown in a system, e.g. the

corrosion protection system has become faulty, and a combination of ageingcoating, aggressive environment, and rapid corrosion growth may lead to a corrosion


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failure. This type of failure is not simply a corrosion failure, but a corrosioncontrol system failure. Therefore, an holistic approach to pipeline integrity isneeded, where an engineer must appreciate the system in order to prevent failure;understanding the equation that quantifies failure pressure is just one aspect.

3.2 Integrity Management and the Movement to Standardise

Pipeline integrity management is the management of all the elements of this complexjigsaw; the management brings all these pieces of the jigsaw together. This is now an

essential part of pipeline management.

3.2.1 Legislation on Pipeline Integri ty Management

Recent major and tragic pipeline failures in the USA (see Section 5) has resulted inpipeline integrity management legislation in the USA. In 2000, the U.S. Departmentof Transportation (DOT) proposed regulations that will require the integrity validationof liquid pipelines that run through or near high consequence areas (HCAs)8, throughformalised inspection, testing, and analysis [Anon., 2002a]. Similar legislation for gaslines is expected.

3.2.2 Response to Legislat ion by Codes and Standards

The American Petroleum Institute (API) has responded to this legislation anddeveloped an industry consensus standard that gives guidance on developing Integrity

Management Programmes [Anon., 2001] for pipelines carrying liquids. Additionally,ASME will publish an appendix with similar guidance for its gas pipeline design code(ASME B31.8) in 2002 [Leewis, 2001].

3.2.3 Intent of L egislation and Code

The legislation in the USA has created formalized pipeline integrity management. Ithas the intention of [Anon., 2002a]:

accelerating the integrity assessment of pipelines in areas where failures wouldhave a high consequence,

improving operator integrity management systems, improving government's role in reviewing the adequacy of integrity programs

and plans, and, and

providing increased public assurance in pipeline safety.

The operators of pipelines in the USA carrying hazardous liquids now have todevelop and implement a written integrity management plan. This plan must:

i. identify all pipeline segments that might affect a high consequence area,

should there be a failure,ii. plan to perform a baseline assessment9 of pipeline system,

8High consequence areas are high population areas, busy commercial navigable waterways, and environmentally-sensitiveareas.9

This assessment includes conducting internal inspections or hydrostatic tests to determine the condition of the line.


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by specified dates.

3.3 Risk Management

The publication of API 1160 [Anon., 2001] is part of a continuing process to movepipeline safety and management away from prescriptive codes and guidelines to riskmanagement, where clear safety goals are set, and must be met by pipeline operators

and owners. This involves the operator identifying all pipeline hazards and assessingtheir associated risk. Then the operator must put in place measures to both control and

mitigate these risks.

3.3.1 Risk Management in Law

In law, engineers must be aware of two fundamental principles [Wong, 2002]:

1. The concept of a general duty of care for all persons, i.e. workers, operators,customers, users, etc.,

2. Goods and services must be fit for purpose and not result in any danger tohealth and safety when used for the purpose intended.

In the European Union, reasonable care (see also Kardon, 2002) can bedemonstrated when the following actions have been carried out:

i. Risk assessment to identify hazards and risks to health and safety,

ii. Reducing the risk to as low as reasonably practicable,iii. Maintenance to ensure safety in operation and the provision of information,iv. Action to measure, monitor and control.

Fitness for Service is a contractual issue (see also Section 4.3.3), and subject to civilproceedings. However, if the goods or services affect the health and safety, criminallaw may apply. For example, a valve that breaks down and causes injury may besubject to both criminal and civil proceedings.

3.3.2 Corporate Responsibil ity

Risk should be identified and managed at all levels in a company, but it should be apartnership [Wong, 2002]:

i. Risk management starts with corporate management, as the senior executivesenable policies and projects, control finance, and set objectives and assign

responsibilities,ii. Designers will conceive ideas and turn them into either concepts or detailed

drawings and specifications,iii. Engineers turn these detailed drawings and specifications into plant and

equipment,iv. Operators and users put the plant and equipment to useful purpose.

Therefore, risk management starts at the top, with corporate management. Howeverthis is not straightforward; risk can only be managed if they are recognised as a threatand there is a fear of their consequences. Unfortunately, many boards and senior


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management lack the imagination or experience to recognise risk. Engineers andoperators are closer to the risks, and they need to have processes in place and a culturethat allows them to learn to educate management in these risks

3.3.3 The Move to Risk Management

The move to risk management is international [Hopkins, 1998]:

- In the USA, the Office of Pipeline Safety has a risk demonstration programme,

and sees risk management as a potential method of producing equal or greaterlevels of safety in a more cost effective manner that the current regulatoryregime.

- In the UK, the Pipelines Safety Regulations issued in 1996 are goal setting,not prescriptive. Their starting point for a good pipeline design and operationis a recognised design code, and good, proven operational practices, butoperators are not limited to these. The Regulations require a major accident

prevention document, where all risks are identified, and also require a safetymanagement system.

- The European Commission is reviewing major accident pipelines, and

by about 2007 is likely to enforce legislation requiring operators to have amajor accident prevention policy and a pipeline management system thatensures the policy is applied.

3.3.4 Structural I ntegri ty in Risk M anagement

Risk is calculated by combining the likelihood of a hazardous event, with itsconsequences (Risk = a function of (Probability, Consequence)). Structuralassessments are usually aimed at reducing the probability of failure, but it isimpossible to reduce this probability to zero. Therefore, the consequences of failureshould also be considered in structural assessments, as there is always a chance of awrong answer.

3.3.5 Risk and Gain

In risk management it is important to balance risk with any accrued gain. Forexample, if risk analysis/management shows that a reduction in maintenance costs is

justifiable, with only a slight increase in risk, then the operator gains by decreasedmaintenance budgets, but it is the public who must carry the increased risk.

3.3.6 Risk Management and Risk Analysis

Finally, risk management should not be confused with risk analysis. Risk assessment

is an analytical process to identify all potential hazards to a pipeline and consequencesof any adverse effect caused by these hazards. It helps in decision-making, but risk

analysis should not be relied on solely to assess the overall integrity and safety of apipeline. Risk management should be used as this is an overall programme thatincludes risk assessment but also includes mitigation methods, measuring the

performance of the mitigation methods, organisation of risk controls, etc..


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4. STRUCTURAL INTEGRITY OF OIL AND GAS PIPELINES

4.1 How a Pipeline Fails

A transmission pipeline can fail in a variety of ways: by internal pressure bursting thepipe, by axial overload caused by earthquake, etc.. However, the most common

failure (Figure 8) is by internal pressure loading on a part wall defect or pipe damage.

4.1.1 Mode of Failure

Most pipelines are made from linepipe steel that is purchased to a specification thatensures it is ductile. This inherent ductility ensures a defect in the pipeline will not fail

by brittle fracture; it has sufficient toughness to ensure that the failure of a defect inthe linepipe will be governed primarily its tensile properties rather than toughness.

The linepipe material has its toughness (resistance to the presence of cracks) tested atthe pipe mill to ensure ductile behaviour. This is necessary, as some materials such aslinepipe steel undergo a transit ion from ductile to brittle behaviour, under conditions

of decreasing temperature, or increasing loading rate. Three basic factors contributeto brittle fracture: triaxial state of stress (e.g. a notch), low temperature (i.e. below thetransition temperature), and a high strain rate. Therefore, impact tests on a specimen

containing a notch, over a range of temperatures, is a good method of measuringtoughness.

4.1.2 Runni ng Fractures

Historically, two tests have been conducted on linepipe steel to give a measure of ittoughness [Maxey et al, 1972; Kiefner et al, 1973; Anon., 1965]:

i. The Drop Weight Tear Test (DWTT10), to ensure the pipe material is notbrittle,

ii. The Charpy V Test (Cv11), to ensure the pipe material has sufficientductility.

These tests are simple specimens containing notches, made from the linepipe steel,and hit by a pendulum. The energy absorbed by the specimen is a measure of thematerials toughness, and the percentage shear area on the fracture faces is a measureof ductility.

These tests were originally implemented to prevent long running fractures in thepipeline (see Section 4.5.10.1, later), known as propagating fractures, Figure 10, and

to ensure the linepipe toughness was sufficient to stop (arrest ) these fractures.

10 A plate specimen using the linepipe thickness and a length of 305mm and depth 76mm, containing a5mm deep pressed notch.11 A full size Charpy V-notch impact test specimen has a square cross-section with 10 mm sides, and a

length of 55 mm, with a 2 mm deep machined V-notch . Sub-size specimens are used for thin walllinepipe.


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Brittle fracture propagation was prevented by specifying a minimum toughness toensure that the line pipe steel is on the upper shelf of the transition curve at theminimum operating temperature, i.e. the fracture propagation transition temperature(FPTT) of the steel was less than the minimum operating temperature.

Figure 10. Long Propagating Fracture12 in a Methane Gas Pipeline with

Preceding Fireball inset (Images courtesy of and copyright of Advantica, UK).

A large amount of correlation with full-scale behaviour concluded that the FPTTcould be taken to correspond to the temperature at which a DWTT specimen exhibits

an 85% shear area fracture, Figure 11. This requirement ensured that the line pipesteel would not sustain a propagating brittle fracture.

The correlation with full-scale behaviour was necessary, as small-scale specimens donot accurately model full-scale behaviour, and non-conservative predictions can beobtained, Figure 11.

Meeting this DWTT requirement will ensure no propagating brittle fractures, but it

will not necessarily prevent a propagating ductile fracture. The Charpy V-Notchimpact energy is related to the ductile toughness of a pipeline, and following moreresearch work and full scale test validation, a number of empirical and semi-empiricalcriteria were developed to estimate the minimum required arrest toughness (see

Section 4.4.10.1, later).

12 These are photographs of a full scale test on a pipeline, conducted at Advanticas Spadeadam TestSite in the UK.


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Figure 11. Ductile Brittle Behaviour of Pipeline Steels

4.1.3 Ductile Fracture

The above DWTT and Cv requirements will ensure propagating fractures arrest

quickly. But we also need to ensure that any defect failure will initiate in a ductilemode, and its failure stress will be primarily governed by the tensile properties of the

linepipe rather than the toughness.

4.1.3.1 Ductile Initiation

Empirical research work [Eiber et al, 1993] has indicated that for most pipelines thetemperature for 85% shear area on a DWTT specimen corresponds to a fractureinitiation transition temperature (FITT), where the fracture initiation mode changesfrom ductile to brittle as the temperature decreases below the FITT, Figure 12a. Itshould be noted that the FITT, and its empirical base, depends on many parameters,

including:

- type of defect (Figure 12b),- thickness of the structure (Figure 12c),

- loading rate on the defect (Figure 12d).

Therefore, this correlation with DWTT may not be valid for newer materials (e.g.high grade steels), thicker linepipe, or lower temperature operation.

4.1.3.2 Ductile Failure (governed by UTS)

Finally, work by Battelle [Leis and Thomas, 2001] has shown that to ensure failure ofa defect is governed by the ultimate tensile strength (UTS) of the material, a typicaltoughness (full size Charpy) of 80-100J (60-75 ft lb) is needed. Note that these levelsneed to be calculated, and that they will ensure collapse at the UTS (which is higherthan the conventional flow stress that is used in the equations that follow).

Energy

Absorbed

Temperature

DWTT or

Charpy

Specimen

Structure

The specimen may behave ina ductile manner (i.e. 0

percent cleavage area), butthe structure could behave in

a brittle manner at the sametemperature.

Hence we need toCALIBRATE our small DWTT

or Charpytests with full scalebehaviour

Energy Absorbed or

% Shear

Temperature

Ductile

85%

Brittle

OperatePipelineabove

thisFPTT


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EnergyAbsorbed

TemperatureEnergy

Absorbed

Temperature

EnergyAbsorbed

Temperature

Dynamic Loading

Static Loading

Part wall defect

Thro-wall defect

Decreasing thickness

in Charpy or

DWTT specimen

%o

fductilefailurepressure

TemperatureFITT

%o

fductilefailurepressure

TemperatureFITT

a. b.

c.d.

Figure 12. Fracture Initiation Transition Temperature and Influencing

Parameters

4.2 Failure Process

A part wall defect in ductile linepipe fails as follows:

PART WALL DEFECT:o The defect bulges as the pressure in the pipeline is increased.o The ligament below the defect plastically deforms.o Stable crack growth may start, as the pressure continues to increase.

o Unstable crack growth, through the wall, leads to the creation of athrough wall defect.

o THROUGH-WALL DEFECT: This through-wall defect can fail either as a:

LEAK (its length does not increase) or RUPTURE13 (its length does increase), depending on its

initial length and the pipeline pressure (see Figure 17,later).

o The rupturing defect can either: ARREST (the rupturing defect quickly

stops increasing in length). PROPAGATE (the rupturing defect

continues to increase in length to create apropagating fracture).

Figure 13 presents a schematic of the above failure process.

13 Sometimes called a break.

Comment: leads


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Figure 13. Ductile Failure of a Defect in a Pipeline under Pressure Loading.

4.3 Fitness For Purpose (FFP)

During the fabrication of a pipeline, recognised and proven quality control (orworkmanship) limits will ensure that only innocuous defects remain in the pipeline atthe start of its life. These control limits are somewhat arbitrary, but they have been

proven over time. However, a pipeline will invariably contain larger defects at somestage during its life, and they will require an engineering assessment to determine

whether or not to repair the pipeline. This assessment can be based on fitness forpurpose (see 4.3.3), i.e. a failure condition will not be reached during the operationlife of the pipeline.

Engineers have always used fitness for purpose in the early days an engineersintuition or direct experience could help when a defect was discovered in a structure,

and there were many rules of thumb developed. We are now better positioned instructural analysis, and we have many tools available that can help us progress fromthese early days. And remember that rule of thumb was derived from a very oldEnglish law that stated that you could not beat your wife with anything wider thanyour thumb.

The fitness for purpose of a pipeline containing a defect may be determined by a

variety of methods ranging from previous relevant experience, to model testing, toengineering critical assessments, where a defect is appraised analytically, takinginto account its environment and loadings [Anon., 1999a; Anon., 2000]. It should benoted that fitness for purpose is not intended as a single substitute for goodengineering judgement; it is an aid.

4.3.1 Generic FFP

There are various technical procedures available for assessing the significance ofdefects in a range of structures. These methods use fracture mechanics; for example,

the British Standard BS 7910 [Anon., 1999a] contains detailed engineering criticalassessment methods, and can be applied to defects in pipelines. Also, there is API

l

dt

b. If the stress in the Pipeline is above a critical value,then the remaining ligament below the Part Wall Defect

fails and produces a Through-Wall Defect

a. Pipeline contains a Part Wall Defect

g. The Through Wall Defect ruptures, and Propagatesif the pressure is high, and/or if the pipe has a LowToughness.

d. The through Wall Defect causes a Leakif the defect is Short, or if the pressure is Low .

c. A Through Wall Defect in aPipeline.

e. The Through Wall Defect causes a Ruptureif the defect is Long, or if the pressure is High.

f. The Through Wall Defect ruptures, but

Arrests if pressure is low, and/or pipe isHigh Toughness, or if product is a liquid.


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579 [Anon., 2000] which has similar methods, but with a bias towards their use inprocess plant.

4.3.2 Pipeline-Specifi c FFP

The above standards (API 579 and BS 7910) are generic; they can be conservativewhen applied to specific structures such as pipelines. Therefore, the pipeline industry

has developed its own fitness for purpose methods over the past 35 years. However,it should be noted that they are usually based on experiments, with limited theoretical

validation (i.e. semi-empirical). This means that the methods may become invalidor unreliable if they are applied outside these empirical limits.

The pipeline industry has used their fitness for purpose methods to produce genericguidelines for the assessment of defects in pipelines. These methods and guidelinesare based on pioneering work at Battelle Memorial Institute in the USA on behalf ofthe Pipeline Research Council International[Anon., 1965; Maxey et al, 1972; Kiefneret al, 1973], with the more recent additions of ad hoc guidelines for the assessment ofgirth weld defects, mechanical damage and ductile fracture propagation produced bythe European Pipeline Research Group [Re et al, 1993; Knauf & Hopkins, 1996; Bood

et al, 1999].

Best practices in structural assessments of defects in pipelines are now emerging

(e.g. Hopkins and Cosham, 1997; Cosham and Kirkwood; Cosham and Hopkins,2001; Cosham and Hopkins, 2002), and a Joint Industry Project sponsored by 14

major oil and gas companies will produce a state-of-the-art Pipeline DefectAssessment Manual in 2002 [Cosham and Hopkins, 2001; Cosham and Hopkins,2002].

4.3.3 Legal Note

It is important to note that in structural assessments of defective structures, FFP isdefined as when a particular structure is considered to be adequate for its purpose,

provided the conditions to reach failure are not reached (see BS 7910). This is atechnical definition, but fitness for purpose may have a legal and contractual

meaning in certain countries.

For example, in the UK, a consultant engineer is expected to exercise reasonable skilland care in his/her work; however, a contractor carrying out a construction has afundamentally different obligation he/she is obliged by law to warrant that thecompleted works will be fit for their intended purpose. This will be implied in his/hercontract it does not have to be stated explicitly.

Therefore, if a consultant gives a warranty (guarantee) for fitness for purpose (on thecompleted works) and they are not, he/she will be liable even if he/she has used all

reasonable skill and care. The damages awarded following a breach of warranty aredifferent from those of negligence:

i. Warranty costs of making the works fit for purpose, i.e. the work has tobe perfect.

ii. Negligence you pay for anything that could have reasonably beenforeseeable, i.e. the work does not have to be perfect.


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Engineers should check with their professional indemnity insurance what is coveredas a company/professional? Usually, professionals/consultants are not covered forwarranties.

4.4 History of Pipeline Defect Assessment Methods.

4.4.1 The Very Ear ly Days

Fracture mechanics provides the scientific understanding of the behaviour of defects

in structures. The effect of defects on structures was studied as long ago as the 15thcentury by Leonardo da Vinci, but prior to 1950, failure reports of engineeringstructures did not usually consider the presence of cracks; cracks were consideredunacceptable in terms of quality, and there seemed little purpose in emphasising this.Additionally, it was not possible to apply the early fracture mechanics work of

pioneers such as Griffith to engineering materials since it was only applicable toperfectly elast ic materials, i.e. it was not directly applicable to engineering materialssuch as linepipe, which exhibit plasticity.

The 1950s and 1960s was a period where the safety of transmission pipelines was of

interest, primarily in the USA. Early workers on pipeline defects were faced withproblems; pipelines were thin walled, increasingly made of tough materials, andexhibited extensive plasticity before failure. The fracture mechanics methods (using

stress intensity factor, K) at that time used linear elastic theories that could notreliably be applied to the failure of defective pipelines as they would have needed:

- quantitative fracture toughness data, including measures of initiation andtearing (only simple impact energy (e.g. Charpy V-notch) values wereavailable),

- a measure of constraint (this concept was not quantifiable in the 1960s, otherthan by testing),

- a predictive model for both the fracture and the plastic collapse of a defect in athin-walled pipe.

4.4.2 The Pioneers

Workers [Anon., 1965; Maxe y et al, 1972; Kiefner et al, 1973] at the BattelleMemorial Institute in Columbus, Ohio decided to develop methods based on existingfracture mechanics models, but they overcame the above deficiencies in fracturemechanics knowledge by a combination of expert engineering assumptions andcalibrating their methods against the results of full-scale tests.

Over a 12-year period, up to 1973, over 300 full-scale tests were completed, but the

main focus was on:- 92 tests on artificial through wall defects, and

- 48 tests on artificial part wall defects (machined V-shaped notches)


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Figure 1414 . Summary [Cosham and Hopkins, 2001] of the early work at Battelle,

USA.

The workers noted that linepipe containing defects tended to fail in a ductile manner,

and final failure was by collapse, although very low toughness linepipe could fail in abrittle manner, Figure 14 (inset). The Battelle workers concluded that two basic

distinctions could be made, Figure 14:

i. Toughness dependent these tests failed at lower stresses (pressures).To predict the failure stress of these tests a measure of the material

toughness was required (e.g. critical stress intensity factor, Kc, or anempirical correlation based on upper shelf Charpy impact energy).ii. Strength dependent these tests failed at higher stresses. To predict the

failure stress of these tests only a measure of the materials tensile

properties was needed.

4.4.3 The Basic Equations

The work at Battelle led to the development of a strength (flow stress, see Figure15)dependent and the toughness dependent, through-wall and part-wall NG-18 equations.

Figure 14 presents a summary of the early test data and the Battelle failure criteria 15for axially-orientated defects in linepipe:

14Predicted failure stress is that predicted using Equations 2 and 5. Normalised flaw size is

2sc8

EpA

12v

C

.

15 Toughness dependent Equations (2) and (5) are for imperial units, and these units are retained in thissection of the Chapter as they are historical equations. Note that a variety of Folias factors (Equation(3)) are used. See original references [Anon., 1965; Maxey et al, 1973; Kiefner et al, 1973].

0 2 4 6 8 10 12

Normalised flaw size

0.4

0.6

0.8

1.0

1.2

1.4

Actualfailurestress/predictedfailurestress

Through-wall Defect, Eq. 2

Part-wall Defect, Eq. 5

DEFORMATION

BRITTLE

FAILURES

xx

COLLAPSEFAILURES

St ra in

Stress

xx

x


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Through-wall defect:

==

2secln

8

12

8 22

2 M

c

EA

C

c

K vc toughness dependent (2)

222

80.012

40.01 +=+= Dtc

Rt

cM (3)

1=M strength dependent (4)

For part wall defects:

==

2secln

8

12

8 22

2P

vc M

c

EA

C

c

Ktoughness dependent (5)

=

t

d

Mt

d

MP1

11

(6)

=

Mt

d

t

d

11

1

strength dependent (7)

D Outside diameter of pipe (R=D/2=radius)t pipe wall thickness

E elastic modulusM Folias factorR radius of pipe

d part wall defect depth hoop (circumferential) stress at failure (or f)

2c defect axial lengthCv Upper shelf Charpy V-notch impact energy

A Area of Charpy specimen fracture surface flow stress (function of U(ultimate tensile strength) and Y(yield strength))

Flow stress was a concept introduced by Battelle to help model the complex plastic

flow and work hardening associated with structural collapse. Flow strength is anotional material property with a value between yield strength and ultimate tensilestrength, Figure 15.


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Figure 15. Flow Stress Modelling of Stress -Strain Behaviour in Pipelines

It is important to note that:

i. The original work and models accommodated the very complex failureprocess of a defect in a pipeline, involving bulging of the pipe wall, plasticflow, crack initiation and ductile tearing. These pioneering models weresafe due to inherently conservative assumptions and verification via

testing, but they were limited by their experimental validity range(generally, thin walled (plane stress), lower grade, low yield to tensile ratio

line pipe), andii. the strength dependent formulae cannot be applied to low toughness

material; for example, it has been concluded [Cosham and Hopkins, 2001]that Equation 7 cannot be applied to gouges in linepipe unless the linepipehas a 2/3 Charpy toughness of 21 J (16 ftlbf).

This work has formed the basis for the development of many current pipeline defectassessment methods such as those detailed in ASME B31G [Anon., 1984] and DNV

RP 101 [Anon., 1999b].

More recent work (mainly experimental or numerical) has shown these old methods tostill be applicable to many newer pipeline applications, but it is unreasonable (anddangerous) to expect that 30 year old methods will be applicable to newer (e.g. X100grade) steels, thicker wall (e.g. deep water pipelines approaching 50 mm in thickness),and higher applied strains (deep water and arctic conditions will give rise to greaterthan 1 percent strains).

4.4.4 Summar y Curves

The above equations can be summarised easily:

4.4.4.1 Part Wall Defects (Defect fails to become a through-wall defect) Figure 16 (Equations (3) and (7)) can be plotted to give a complete set of assessmentcurves for part wall defects in ductile linepipe. These curves assume strength

typical engineering stress-engineering strain curve for

linepipe steel

yield

strength

ultimatetensile

strength

engineering strain()

engineering stress

()

flow stress ()


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dependent behaviour, and can be considered universal assessment curves; a defect ofdepth (1-(d/t)) and length (2c/(Rt)0.5) will fail if the pipeline hoop stress falls abovethe relevant curve.

Figure 16. Failure Stress of Part Wall Defects in Ductile Linepipe (no safety

factor included).

4.4.4.2 Through-wall Defect (Defect fails to become a leak or a rupture)

Figure 13 shows that a part wall defect can either leak or rupture. The aboveEquations ((2)-(4)) allow the hoop stress (f) at which a through-wall defect will

either leak or rupture to be calculated. Figure 1716 is a simple summary of Equations(3) and (4), showing the leak-rupture boundary.

16 Assuming a flow stress of 1.15x yield strength.

0

0.2

0.4

0.6

0.8

1

1.2

0 1 2 3 4 5 6 7 8

2c/(Rt)^0.5

FailureStress/YieldStrength

RUPTURE

LEAK

2c

f

M= 1This boundary is not sensitive to pressurising medium

2c or l

t

This boundary is not sensitive to pressurising medium2c or l

t

0

0.2

0.4

0.6

0.8

1

1.2

0 1 2 3 4 5 6 7 8

2c/(Rt)^0.5

FailureStress/YieldStrength

1 - (d/t) = 0.6

0.5

0.3

0.2

0.1

0.05

0.4

1 - (d/t) = 0.6

2c (l)d

t

22

40.01

+=Rt

cM

Flow strength = 1.15y


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Figure 17. Leak/Rupture Behaviour of Through- wall Defects in Ductile Linepipe

(no safety factor included).

4.5 Structural Assessment of Defects in Pipelines

This Section gives a summary of the fitness-for-purpose methods available to assessthe variety of defects that may occur in a pipeline. Failure due to internal pressure is

the only failure mode considered, as this is the major cause of in-service failures,Figure 8. If a pipeline is subjected to external loads (e.g. due to landslide), thermal

stressing (e.g. a high temperature, high pressure offshore pipeline) or externalpressure (e.g. deepwater lines), they will require special considerations.

4.5.1 Safety Factors

It should be noted that safety factors are not given or recommended in the followingSections. They will be dependent on:

i. the type of defect,ii. the reliability of the data used in the assessment,

iii. the reliability of assessment method,iv. material and geometry variations and tolerances,v. time dependent effects (defects can grow to failure at constant

stresses/pressures. Historically an allowance of 5% of failure pressure isused for part wall defects),

vi. overpressures in the pipeline (pipeline pressures are never constant -pipelines are typically allowed a 10% (of maximum allowable operatingpressure ((MAOP)) overpressure during operation therefore themaximum pressure a defect might see is 1.1xMAOP),

vii. subsequent growth (e.g. fatigue. corrosion),viii. pipeline operational control (the accuracy and tolerances on pipeline

monitoring and control),ix. the consequences of a defects failure.

It is the responsibility of the engineer conducting the assessment to derive a safetyfactor. It is becoming customary in the pipeline business to only allow defects toremain in a pipeline if they can withstand a hoop stress to the stated pre-servicehydrotest level, e.g. 100%SMYS. This leads to a safety factor of at least 1.39 (100/72)on predicted failure stress on a defect in a pipeline designed to oper ate at 72% SMYS.

When summarising fitness-for-purpose methods, it is best to start with an assessmentof the failure stress of a defect-free pipe. This gives a benchmark failure stress for

any pipeline.

4.5.2 Defect-Free Pipe under I nternal Pressure

4.5.2.1 Static Failure

Most grades of steel ( 10%). However, the newer high grade steels(>X80) will not reach these high strains, and may only reach 3 to 5% at UTS. This is


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significant if you are basing your pipeline design on strain rather than stress, as yourmargin of safety on strain will decrease with increasing grade of linepipe.

However, most pipelines are still designed on stress In general, the simplest and mostconservative formula for the range of transmission pipeline D/ t ratios is given by

using U and the mean pipeline diameter (D-t) in the simple Barlow equation(although it becomes increasingly conservative for thicker walled pipe):

( )tD

tP Uf

=2

(8)

Pf= failure pressure

There are more accurate analytical methods [Stewart et al, 1994] incorporatingmaterial work hardening and large displacement theory, and they are accurate over awide range ofD/tratios.

4.5.2.2 Cyclic Failure

The fatigue strength of (notionally defect-free) welded linepipe subject to cyclicinternal pressure will be governed by the fatigue strength of the weld, and the fatiguestrength of seamless line pipe will be governed by local surface imperfections.Similarly, the fatigue strength of the girth weld will govern under cyclic axial or

bending loads. Fatigue strength curves (S-N curves) are given in BS 7910 [Anon.,1999a] and API 579 [Anon., 2000].

4.5.3 Axial ly-Ori entated Gouges or Simi lar Metal L oss Defects17

4.5.3.1 Basic EquationsExternal interference during operation, or damage during construction, can causegouges or scratches on the pipes surface, Figure 18. These metal loss defects may beaccompanied by local plastic deformation. If this deformation caused a dent, then thegouge must be assessed using sophisticated fracture mechanics methods (see later).

Figure 18. Damage on a Pipeline Failure in Louisiana, USA (Image courtesy of

National Transportation Safety Board, USA)

17 See Section 4.4.9.2 for methods for assessing the fatigue life of these type of defects.

Image from National TransportationSafety Board website: www.ntsb.gov

Comment: delete


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In ductile linepipe, the failure stress of an axially-orientated gouge subject to internalpressure loading is described by Equation (7):

2c

R

d

t

Defect Dimensions

It has been recommended that [Cosham and Hopkins, 2001]:

2

UY

+= (9)

222

52.012

26.01

+=

+=

Dt

c

Rt

cM (10)

for use in Equation 7, and D = outside diameter to be used in the equations. Note thatthese equations are only validated for pipewall thicknesses up to 22mm andtoughnesses of 21J (2/3 Charpy) [Cosham and Hopkins, 2001].

Figure 1918, shows the accuracy of using Equations 7, 9 and 10 to assess gouge or

gouge-like defects in linepipe.

4.5.3.2Note on Structural Assessment of Gouges

If a gouge is detected in the field, an engineer needs to check:

- FOR SURFACE CRACKING - There may be some crack-like indications(spalling) caused by the damaging object. If the cracking is deep, it may beindicative of a gouge that has cracked due to denting (the denting may not be

visible, as it may have been pushed out [Hopkins et al, 1989; Hopkins et al,1992]. This is severe, and requires repair.

- FOR EVIDENCE OF DENTING - The impact may have also dented the pipe.Residual denting around a gouge is severe see later.

Gouges can be assessed using the above equations, providing your pipeline has atoughness >20J [Cosham and Kirkwood, 2000; Cosham and Hopkins, 2002]. Notethat a gouge needs to be checked for possible fatigue crack growth in some pipelines(e.g. some liquid lines).

18 See Hopkins and Cosham, 2001 for data used in Figure 19.


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Allowance (e.g. adding 0.5mm to defect depth) for the hard layer or sub-surfacecracking is advisable, if they are to be left in the pipeline, but there should be no riskof environmental cracking, and no residual denting, and no problems from cyclicloading.

Figure 19. Predicted Failure Stresses of Full Scale Burst Tests on Vesselscontaining Gouges or Similar Defects.

Finally, an engineer should always think carefully of the consequences of getting

things wrong. If damage is in a pipeline in a high consequence area, the damageshould be inspected closely before assessment, and appropriate safety factors includedin the assessment.

4.5.4 Dents

4.5.4.1 Burst Strength of Plain DentsDents in pipelines are assessed using data derived from full scale tests, and large dents

can be tolerated, although their behaviour under cyclic loads, or when they coincidewith seam welds, remain a problem [ Hopkins et al, 1989; Hopkins et al, 1992; Fowler

et al, 1994; Hope et al, 1995; Kiefner et al, 1996; Kiefner & Alexander, 1997;Bjornoy et al, 2000; Rosenfield, 1998; Roovers et al, 2000].

The effect of a plain dent (i.e. one with no associated loss of wall thickness defect,and of smooth shape) is to introduce high localised stresses and cause yielding in the

pipe material. The high stresses and strains caused by the dent are accommodated bythe ductility of the pipe. Full scale test results have confirmed this by showing that

plain dents do not generally affect the burst strength of the pipeline [Hopkins et al,

1989; Kiefner et al, 1996; Kiefner & Alexander, 1997]. On pressurisation the dent

0 20 40 60 80 100 120 140 160

Failure Stress/Yield Strength, percent

0

20

40

60

80

100

120

140

160

PredictedFailureStress/YieldStrength,perce

nt

CONSERVATIVE

UNCONSERVATIVESee original reference

for test details


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attempts to move outward, allowing the pipe to regain its original circular shape.Provided that nothing restricts the movement or acts as a stress concentration (e.g. agouge or a kink), then the dent will not reduce the burst strength of the pipe.

Empirical limits for plain dents under static internal pressure loading have beenderived from extensive full scale testing. It should be noted that all of the dent depths(usually measured as % pipe diameter) in the full scale tests were measured at zero

pipeline pressure. Based on these full scale tests [Hopkins et al, 1989; Hopkins et al,1992; Fowler et al, 1994; Hope et al, 1995; Kiefner et al, 1996; Kiefner and

Alexander, 1997; Rosenfield, 1998; Roovers et al, 2000; Bjornoy et al, 2000], avariety of dent sizes have been quoted as acceptable dents of depth19 up to 10%

pipe diameter have little effect on the burst strength of pipe. Additionally, there is anAPI publication [Kiefner and Alexander, 1997; Anon 1997] specifically on theassessment of dents caused by rocks in pipelines. The reader is directed to thesereferences for more detailed information.

In full scale tests on plain dents on welds very low burst pressures have beenrecorded. Therefore, the burst strength (and the fatigue strength) of dents containingwelds cannot be reliably predicted, and caution is recommended with this type of

damage.

It should be noted that a dent of depth 10% the pipe diameter might be associated with

surface damage, which makes it a severe defect. Also, this deep dent may restrict bothproduct flow, and the passage of pigs in the pipeline. Finally, this depth may be

acceptable in some pipelines under static pressure loading, but it will be reducedsignificantly if the pipeline is subjected to cyclic loading (see next).

4.5.4.2. Fatigue Life of Plain DentsLarge cyclic stresses and strains are localised in a dent under cyclic pressure loading.The depth of a dent changes with internal pressure, meaning that the magnitude of thestress concentration changes as dents can reround under cyclic internal pressureloading.

Full scale fatigue tests [Eiber et al, 1981; Wang and Smith, 1988; Hopkins et al, 1989;

Hopkins et al, 1992; Fowler et al, 1994; Hope et al, 1995; Kiefner and Alexander,1997; Roovers et al, 2000] on plain dents indicate that they reduce the fatigue lifecompared to plain circular pipe. The greater the dent depth the shorter the fatigue life.

No fatigue failures occurred in those tests where the pipe was hydrotested prior tofatigue cycling, because the dent was permanently pushed out (rerounded), reducingthe stress concentration.

A number of semi-empirical or empirical methods for predicting the fatigue life of a

plain dent subject to cyclic pressure loading have been developed [Fowler et al, 1994;Hope et al, 1995; Kiefner and Alexander, 1997; Rosenfield, 1998; Roovers et al,

2000]. One of the relationships, developed by SES in Houston [Fowler et al, 1994;Kiefner and Alexander, 1997], is:

19 The literature indicated that the key dent parameter is the depth, with length and width secondary.


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74.3

6

11400

1100.2

= pp

N

(11)

where:N number of cycles to failure

p

stress intensification factor (obtained from original references)

p cyclic pressure (psi)

This fatigue model is based on an S-N curve, modified for the stress concentration

due to the dent. The stress intensification factor was derived from non-linearelastic-plastic finite element analyses to account for the stress concentration due to the

dent. The reader is directed towards the original references if they wish to apply thevarious fatigue methods.

4.5.4.3 Plain Dent Containing a Defect

4.5.4.3.1 Burst Strength

The failure behaviour of a dent containing a gouge is complex. A dent and gouge is ageometrically unstable structure. Outward movement of the dent promotes initiation

and growth of cracking in the base of the gouge, changing the compliance of the dent.The failure of a dent and gouge defect involves high plastic strains, wall thinning,

movement of the dent, crack initiation, ductile tearing and plastic flow [Leis et al,2000].

Empirical relationships for predicting the burst strength of a smooth dent (of depth H)containing a gouge have been proposed by British Gas [Hopkins et al, 1989], the

EPRG [Roovers et al, 2000], and Battelle [Mayfield et al, 1979; Maxey, 1986].

The Battelle model is:

( )

90

3006.0

=Qf

... (12) e

( )

=

t

dc

R

H

CQ v

22

..(13) (13)

10000+=Y

psi

A semi-empirical fracture model for assessing the burst strength of a dent-gouge

defect has been developed by British Gas [Hopkins, 1992], and has subsequently been

included in the EPRG recommendations for the assessment of mechanical damage[Bood et al, 1999].

The fracture model is based on tests in which the damage was introduced intounpressurised pipe; therefore, the dent depth measured at zero pressure must be used

H

R

D

t

d


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or corrected for any internal pressure [Hopkins et al, 1992; Roovers et al, 2000;Rosenfield, 1998].

The fracture model gives more accurate and reliable predictions that the aboveempirical relationship of Battelle. The model is defined as follows (in SI units):

+

=

2

1

2

212

1 )738.0ln(

exp2.108.11

5.1

113expcos

2

K

KC

D

H

t

R

YD

H

YAd

Evoo

(14)

where

=

t

dY 115.1 (15)

432

14.307.216.1023.012.1

+

+

=t

d

t

d

t

d

t

dY (16)

432

2 0.141.1332.739.112.1 ++= td

td

td

tdY (17)

9.11

=K

57.02

=K

roHH 43.1= (18)

The flow stress (Equation (15)) assumed in the dent-gouge fracture model is notappropriate for higher grade steels (greater than X65), due to the increasing yield to

tensile ratio with line pipe grade.

Ho dent depth measured at zero pressure (mm)Hr dent depth measured at pressure (mm)K1 non-linear regression parameterK2 non-linear regression parameter

This failure criterion for a dent containing a metal loss defect does not give a lowerbound failure stress. It is a mean predictive model. Additionally, the model is semi-empirical and therefore limited by the bounds of the original test data, and is prone tohigh scatter [Cosham & Hopkins, 2001; Cosham & Hopkins, 2002].

4.5.4.3.2 Fatigue Life

The fatigue life of a dent containing a gouge is difficult to predict. Full scale tests

indicate that the fatigue life of a combined dent and gouge can be of the order ofbetween ten and one hundred times less than the fatigue life of an equivalent plaindent [Hopkins et al, 1989]. In some cases even shorter fatigue lives have been

observed during testing.

4.5.4.4Note on the Assessment of Mechanical Damage


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Dents and/or gouges in a pipeline are indicative of impact damage. When a dent or agouge is suspected in a pipeline, they should be carefully investigated to determine ifthey are co-incidental, as the combined dent and gouge is a very severe defect, andusually requires rapid repair.

4.5.5 Corrosion20

There are several approaches that have been used to characterise the behaviour ofboth through and part wall corrosion defects. The first two methods (approved by

ASME) described below are the oldest and most proven. The most modern and mostaccurate (DNV RP 101) is covered last.

4.5.5.1ANSI/ASME B31GThe most popular document for the assessment of the remaining strength of pipelineswith smooth corrosion has been ANSI/ASME B31.G [Anon., 1984; Anon., 1991].This supplement to B31 was developed over 20 years ago, based on work in the early1970s [Kiefner and Duffy, 1973], although it has since been updated [Kiefner andVieth, 1989; Anon., 1991].

It is based on an empirical fit to an extensive series of full scale tests on vessels withnarrow machined slots. The basis of the equation used in B31G is relatively simpleand involves:

assuming the maximum pipe hoop stress is equal to the pipe material's yieldstrength, and,

characterising the corrosion geometry by a projected parabolic shape for relativelyshort corrosion, and a rectangular shape for long corrosion.

The equation used in B31G is a derivative of Equation (7):

f

o

o

A A

A A M=

1

1 1

( / )

( /(19)

where A=cross sectional area of defect in pipewall (for a rectangular, flat bottomeddefect this is 2c.d),andAo=pipe wallarea occupied by defect (for a rectangular flat bottomed defect thisis 2c.t).

In the B31G code, a simplified equation is provided which represents the defect as aparabolic shape:

f

d

td

t M

=

12

3

1

2

3

1(20)

20 Usually, the most difficult data to obtain when assessing corrosion, is the expected corrosion growth

rate. This is important, because most assessments of corrosion are based on intelligent pig data, wherethe defect must be assessed over its whole life, and its size at the end of the pipelines design lifeneeds to be used in the calculations.


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The flow strength ( ) is defined by 1.1xSMYS. The parabolic shape of the projectedarea is used as an approximation to the actual defect, and the Folias (bulging) factor

is:

Mc

Dt

= +

1 0 82

2

. (3)

It is stated in the B31G code that the above equations should only be applied tocorrosion defects, which have a maximum depth greater than 10% of the nominal wall

thickness, and less than 80% of the nominal wall thickness. Furthermore, the relativelongitudinal extent should satisfy the following equation:

Mc

Dt= +

1 0 8

24 0

2

. . (21)

The above equation limits the use of the parabolic shape formulation because when Mis greater than 4.0 (i.e. long corrosion), the approximation of a parabolic shape is no

longer adequate. Instead a rectangular shape is used. Accordingly, the failure equationis replaced by the following equation:

f

d

t=

1 (22)

4.5.5.2Modified B31GThe B31G criterion has been used successfully in the pipelines industry for manyyears. The method has been proven, in general, to be conservative and as a result animproved method was developed which modified the existing B31G guidance. Themodified B31.G method [Kiefner and Vieth, 1989; Anon., 1991] has recently been

adopted as the preferred method for the fitness for purpose assessment of corrosiondefects in the ANSI/ASME B31 Code.

The hoop stress at failure

120708557 pipeline integrity

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