The Structural Integrity of Oil and Gas Transmission Pipelinesdocshare01.docshare.tips/files/15478/154783658.pdfTHE STRUCTURAL INTEGRITY OF OIL AND GAS TRANSMISSION PIPELINES 1. INTRODUCTION

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 Transmission Pipelines’

by Phil Hopkins, Penspen Ltd., UK.



CONTENTS

1. INTRODUCTION 2. PIPELINES

2.1 Pipelines – A Brief History 2.2 Pipelines – Types 2.3 Pipeline Design, Regulation and Materials 2.4 Design Stresses, Hydrotesting, and Location

2.4.1 Design Stresses 2.4.2 Hydrotesting Pipelines 2.4.3 Location of Pipelines

2.5 Pipeline Operation, Inspection and Maintenance 2.5.1 Operation and Leak Detection 2.5.2 Pipeline Protection 2.5.3 Pipeline Inspection and Maintenance

2.6 Why Do Pipelines Fail? 2.7 Ageing Pipeline Assets

3. PIPELINE INTEGRITY AND RISK MANAGEMENT 3.1 Pipeline Integrity and Integrity 3.2 Integrity Management and the Movement to Standardise

3.2.1 Legislation on Pipeline Integrity Management 3.2.2 Response to Legislation by Codes and Standards 3.2.3 Intent of Legislation and Code

3.3 Risk Management 3.3.1 Risk Management in Law 3.3.2 Corporate Responsibility 3.3.3 The Move to Risk Management 3.3.4 Structural Integrity in Risk Management 3.3.5 Risk and Gain 3.3.6 Risk Management and Risk Analysis

4. STRUCTURAL INTEGRITY OF OIL AND GAS PIPELINES 4.1 How a Pipeline Fails

4.1.1 Mode of Failure 4.1.2 Running Fractures 4.1.3 Ductile Fracture

4.2 Failure Process 4.3 Fitness For Purpose (FFP)

4.3.1 Generic FFP 4.3.2 Pipeline-Specific FFP 4.3.3 Legal Note

4.4 History of Pipeline Defect Assessment Methods. 4.4.1 The Very Early Days… 4.4.2 The Pioneers 4.4.3 The Basic Equations 4.4.4 Summary Curves

4.5 Structural Assessment of Defects in Pipelines 4.5.1 Safety Factors 4.5.2 Defect-Free Pipe under Internal Pressure 4.5.3 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 Defects 4.5.8 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 Rehabilitation 4.5.13. Other Components of a Pipeline System

5. THE ROLE AND IMPORTANCE OF STRUCTURAL INTEGRITY ASSESSMENTS OF PIPELINES

6. CONCLUDING COMMENTS Acknowledgements References



THE STRUCTURAL INTEGRITY OF OIL AND GAS TRANSMISSION

PIPELINES

1. INTRODUCTION

Oil and gas provide 60% of the world’s primary fuel. Therefore, it is not surprising to discover that there are over 1 million tonnes of oil and 250 million cu metres of gas consumed every hour around the world. Most of this oil and gas is transported in pipelines. The larger of these pipelines are called ‘transmission’ pipelines (Figure 1); the general public will not normally see these lines as they are either under the sea, or buried on land, but they are the main arteries 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-established standards and laws, because the products they carry can pose a significant hazard to the 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 surrounding population,



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

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

iv. Cost Effectiveness - the system must deliver the product at an attractive market 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 and construction practices, which will eliminate most of the above potential failure modes, but as pipelines can operate in hostile environments (underground or subsea) they are constantly threatened by defects and damage that occur in-service. These in-service defects are the major cause of pipeline failures; therefore to understand and control structural integrity, in -service defects must be understood and controlled. The occurrence and behaviour of defects in pipelines has been the subject of extensive research and development for over 35 years, and this chapter presents an overview of this work, detailing the current ‘best practices’ in their structural assessment. The chapter also covers some of the key design aspects of a pipeline that affect structural integrity.



2. PIPELINES

2.1 Pipelines – A Brief History

Our ancestors used wood and clay pipes many centuries ago; the Chinese used bamboo 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 in highly developed towns in 500 BC, and the use of steel or iron pipelines started in the UK in 1820 when cast iron musket barrels left over from wars were used to transport gas made from coal. At the same time (1821), hollowed out logs were used in the USA to transport natural gas used for lighting, but it was not until 1843 that iron pipe was used to reduce the obvious 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. The railway relieved this, but the oil was now controlled by the rail bosses and their ‘teamsters’. In 1879 a 173km (108 mile), 152mm (6in) diameter line was built in Pennsylvania to transport crude oil, to tank cars for the New York market and 12 years later the first high pressure, long distance pipeline was built. The pipeline reduced the transport cost of oil from $3 to $1 per mile.

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



Initially, all steel pipes used to construct the pipeline had to be threaded together. This was 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 to construct 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 a transmission 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 has over 500,000 km of natural gas transmission pipelines). Figure 2 shows a modern transmission pipeline under construction. 2.2 Pipelines - Types There are many types of oil and gas pipelines:

i. FLOWLINES & GATHERING LINES – These short distance lines gather 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 USA’s liquid pipeline system is over 250,000 km in length). Natural gas transmission lines will usually deliver to industry or a ‘distribution’ system, whereas crude oil transmission lines carry different types of product, to refineries or storage facilities.

iv. PRODUCT LINES - Pipelines carrying refined petroleum products from refineries 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, but most 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 ‘system’ that 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 designed to the American Society of Mechanical Engineers (ASME) standards (ASME B31.8 for gas lines and ASME B31.4 for oil lines) or standards based on these. The design and operation of pipelines is usually regulated or subject to local laws. In the UK,



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 longitudinally welded, spiral welded, or seamless), and ‘grade’; grade X60 has a minimum specified yield strength of 60,000 lbf/in2 (414N/mm2). Figure 4 gives some typical yield strengths 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.



Figure 4. Variations in Yield Strength and Impact Toughness of Older Linepipe Steels 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 loads they 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 use the following equation for calculating the hoop stress: Hoop stress = σh = PD/2t =φσy = φSMYS (1) P = pipeline pressure, D = outside pipe diameter, t = pipe wall thickness, φ = design factor (see below),

1 These are approximate values. See Eiber et al, 2000 for details. This figure shows his torical data, and therefore 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/m2 = 6.89N/mm2 . 2 Pressure 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 or ‘absolute’ 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 atmospheric pressure 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 in ‘Atmospheres’ are usually taken to be absolute. Pressure gauge (Pg) (denoted by ‘psig’ in imperial units) is the pressure above atmospheric pressure. Gauge pressures below atmospheric pressure are called vacuum. In the pipeline industry, gauge pressure is in common use.

0

10

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90S

tre

ng

th (

lbf/

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)

30 3 5 42 52 60 70Grade

Min Ave Max

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ug

hn

ess

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lb

)

35 42 5 2 60 70Grade

Min Ave Max

axial

hoop



σy = the yield strength of our linepipe (the linepipe is purchased to the manufacturers’ ‘specified minimum yield strength (SMYS)’).

Most pipeline design codes use outside diameter in the hoop stress formula. This gives 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 above simple 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 elongate the pipeline. This can be visualised by a long thin balloon being inflated - its diameter and length expands. The magnitude of this axial stress is:

- 0.3xhoop stress if expansion of the pipe is restricted, e.g. it is buried and restrained 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 pipelines operating 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 this maximum stress; therefore, a pipeline at 72% SMYS can experience an overpressure to 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 Pipelines When the as-built condition of a structure cannot be ‘proven’ it will have a low design factor (e.g. bridges, ships cannot be proof tested, so their design factor is ~0.6. If the structure 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 the structure, 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 send the fat kid onto the thin ice first. If the ice holds, we go skating, if the ice fails, we lose the fat kid…. In the middle ages, civil engineers would build bridges, but would not be able to calculate their true strengths. Therefore, they would invite the local army battalion to ‘open’ the bridge by mar ching across it with its horses, cannons, etc.. The army thought they were part of a celebration – in fact they were the proof load.



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 hydrostatic test prior to service, to a high stress levels (e.g. 100% SMYS for gas lines in the USA). 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 the early 1950s when Texas Eastern Transmission Company in the USA wanted to rehabilitate their War Emergency Pipelines and convert them to gas [Kiefner and Maxey, 2000]. Before any testing, these lines failed frequently in -service because of original 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 the maximum 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 low

temperature properties.

3 Failure stress of defect-free linepipe is at least 1.25xSMYS but cannot exceed UTS [Leis and Thomas, 2001]. 4 It 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 Failure0

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Safety Factorbased on

failure

Actual failure stress of defect free

linepipe is UTS or >1.25xSMYS



The hydrotest was originally used to detect (by failing) original manufacturing linepipe defects, but modern linepipe is usually free from these older type defects, and linepipe is now highly quality assured before delivery to site. Therefore, the prime role 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 hazardous products 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 the consequences 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 (Figure 6) :

- 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 following section gives some key elements that relate to pipeline integrity.

Cor

ridor

Wid

th Proximity

No restriction in this zone

Prevent, or severely limit, building in this zone

Prevent, or severely limit, building in this zone

Limit buildingin this zone

Limit buildingin this zone

No restriction in this zone



2.5.1 Operation and Leak Detection Modern long-distance pipelines are operated mainly automatically by a computer at the headquarters of the pipeline company. The computer monitors the pressure, flow rates, and other parameters at various locations along the pipe, performs many on-line computations, and sends commands to the field to control the operation of the valves and pumps. Manual intervention is frequently needed to modify the automatic operation, as when different batches of fuels are directed to different temporary storage 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 a rapid response should the pipeline fail. There are various types of system:

i. Simple Systems (‘Seeing or Smelling’) - The simple systems involve flying, driving, walking along or surveying a pipeline and looking for evidence of discoloured vegetation around the pipeline, or hearing or smelling (if the fluid is odorized) a discharge. ‘Unofficial’ pipeline leak detection 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 the difference 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 have frequencies in excess of 20 kHz. Transducers can be clamped to a pipeline, and by noting signal strength, the source of the leak can be pinpointed.

iv. Pipeline Modelling (‘Theory versus Operation’) - Real time pipeline modelling, which simulates the operation of the pipeline and continually compares the expected with the actual, can offer both detection and location of leaks. There are commercial packages on the market that may be appropriate to certain pipeline operations. The model is a mathematical representation of the pipeline and will include such features as elevation data, valve and pump locations, etc.. The model can then calculate the expected pressures, flows etc., and compare them with what the measurements are showing. Any discrepancy may be a leak, and leak alarms can be triggered if this is the case.

Leaks can be difficult to both detect and locate due to transients in the control systems and the product flow. 2.5.2 Pipeline Protection Pipelines are designed to be protected from the environment as follows:



i. EXTERNAL CORROSION - The pipe steel must be separated from the soil or water environment otherwise it will corrode. Usually, there is no ‘corrosion allowance’ (increase thickness of linepipe specifically to allow for predictable corrosion wastage) for external corrosion in pipelines. Hence the outside surface of the linepipe is protected by using a pipe coating (e.g. coal tar) as the primary protection, and a corrosion protection system 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 the product 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 parties by: thicker pipe wall, deeper cover (but beware of overburden), locating in remote regions, regular patrols or surveys of the line, clear markings, good communications with third parties including the general public, protective measures 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 their pipeline to appropriate standards. Maintenance of a pipeline is an essential part of maintaining the overall integrity of the entire pipeline system. Therefore, pipelines are routinely 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



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, then select a monitoring/inspection method to reduce that risk. Hence, pipeline operators use a variety of methods to ensure their pipelines are not damaged, or that damage is detected 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 or detect 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 regularly surveyed 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’, Figure 7. 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 the noise they made as they passed through the pipeline resembled a pig squealing) can measure metal loss (e.g. corrosion), and geometry abnormalities (e.g. dents). More specialised pigs can map the pipeline, and others can detect cracks.

iii. Above Ground Inspection – The condition of the pipeline’s corrosion protection system, and its coating can be determined remotely using above ground measurements. Sub-sea pipelines can have similar surveys conducted using ‘remotely oper ated vehicles’ (ROVs).

iv. Leak Surveys – Leaks in pipelines can be detected by on-line systems (see above), and also by patrols that may see discoloured vegetation (in onshore lines), 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 to detect excessive stressing.

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

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

viii. Public Awareness – Pipeline operators will liaise with farmers, fishing organisations, etc., to ensure that organisations that may be working around 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 onshore pipelines 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 the pipeline business, primarily to clean a line, or prove its shape. However, when a pig collects data on-board, it is classed as ‘intelligent’.



they carry out excavations. This call allows a central organisation to check for the presence of sub-surface utilities such as pipelines, and either prevent the excavation, or supervise it.

DEFECT/DAMAGE

SURVEILLANCE/INSPECTION METHOD

AERIAL/ GROUND

PATROLS7

INTELLIGENT PIGS

PRODUCT QUALITY

LEAK SURVEYS

GEOTECH SURVEYS & STRAIN GAUGES

CP & COATING SURVEYS

HYDRO - TEST

3rd Party Damage P R R Ext. Corrosion R P R Int. Corrosion R P R

Fatigue/Cracks R R Coatings P

Materials/Construct Defects

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 Methods 2.6 Why Do Pipelines Fail? Pipelines are a very safe form of energy transportation; however, like any other structure they do fail. The major causes of failure, in both onshore and offshore pipelines are:

• outside force (sometimes called third party damage, mechanical damage or external 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 and corrosion 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 incidents in recent years on both oil and gas lines [Anon., 2002a].

7 Sub-sea pipelin es are surveyed by a variety of means. The pipeline will often be ‘flown’ using a remotely operated vehicle (ROV) which can be equipped with a variety of tools to visually inspect the pipeline and also check its condition.



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 4 Failure (loss of product) 0.6 Failure (casualties and/or high costs) 0.16

Table 2. Benchmark Incident Rates for Western World Pipelines [Hopkins, 1994] 2.7 Ageing Pipeline Assets One of the biggest problems facing the pipeline industry is the fact that the world’s pipeline infrastructure is ageing. For example: i. over 50% of the 1,000,000 km USA oil and gas pipeline system is over 40 years

old, ii. 20% of Russia’s oil and gas system is nearing the end of its design life. In 15

years 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 & gas supplies 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, and structural integrity assessments will be a key tool we will use.

Corrosion23%

Outside Force25%

Failed pipe/weld

12%

Other30%

Op./Equip. Error10%

Corrosion39%

Outside Force25%

Const/Mat Defect

9%

Other27%

LIQUID

GAS

25%



3. PIPELINE INTEGRITY AND RISK MANAGEMENT

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 appreciation of 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 its own, ensure continuing pipeline integrity. This is because pipeline integrity is ensuring a pipeline is safe and secure. It involves all aspects of a pipeline’s design, operation, inspection, management and maintenance. This presents an operator with a complex ‘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 pipeline management 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 ageing coating, aggressive environment, and rapid corrosion growth may lead to a corrosion



failure. This type of failure is not simply a ‘corrosion’ failure, but a ‘corrosion control system’ failure. Therefore, an ‘holistic’ approach to pipeline integrity is needed, 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 complex jigsaw; 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 Integrity Management Recent major and tragic pipeline failures in the USA (see Section 5) has resulted in pipeline integrity management legislation in the USA. In 2000, the U.S. Department of Transportatio n (DOT) proposed regulations that will require the integrity validation of liquid pipelines that run through or near high consequence areas (HCAs)8, through formalised inspection, testing, and analysis [Anon., 2002a]. Similar legislation for gas lines is expected. 3.2.2 Response to Legislation by Codes and Standards The American Petroleum Institute (API) has responded to this legislation and developed 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 Legislation and Code The legislation in the USA has created formalized pipeline integrity management. It has the intention of [Anon., 2002a]:

• accelerating the integrity assessment of pipelines in areas where failures would have 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 to develop 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 assessment’9 of pipeline system, 8 ‘High consequence areas’ are high population areas, ‘busy’ commercial navigable waterways, and environmentally-sensitive areas. 9 This assessment includes conducting internal inspections or hydrostatic tests to determine the condition of the line.



by specified dates. 3.3 Risk Management The publication of API 1160 [Anon., 2001] is part of a continuing process to move pipeline safety and management away from prescriptive codes and guidelines to ‘risk management’, where clear safety goals are set, and must be met by pipeline operators and owners. This involves the operator identifying all pipeline hazards and assessing their 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 fundam ental 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 to health and safety when used for the purpose intended.

In the European Union, ‘reasonable care’ (see also Kardon, 2002) can be demonstrated 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 civil proceedings. However, if the goods or services affect the health and safety, criminal law may apply. For example, a valve that breaks down and causes injury may be subject to both criminal and civil proceedings. 3.3.2 Corporate Responsibility Risk should be identified and managed at all levels in a company, but it should be a partnership [Wong, 2002]:

i. Risk management starts with corporate management, as the senior executives enable 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. However this is not straightforward; risk can only be managed if they are recognised as a threat and there is a fear of their consequences. Unfortunately, many boards and senior



management lack the imagination or experience to recognise risk. Engineers and operators are closer to the risks, and they need to have processes in place and a culture that 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 greater levels of safety in a more cost effective manner that the current regulatory regime.

- In the UK, the Pipelines Safety Regulations issued in 1996 are goal setting, not prescriptive. Their starting point for a ‘good’ pipeline design and operation is a recognised design code, and good, proven operational practices, but operators are not limited to these. The Regulations require a ‘major accident prevention document’, where all risks are identified, and also require a safety management system.

- The European Commission is reviewing ‘major accident’ pipelines, and by about 2007 is likely to enforce legislation requiring operators to have a ‘major accident prevention policy’ and a pipeline management system that ensures the policy is applied.

3.3.4 Structural Integrity in Risk Management Risk is calculated by combining the likelihood of a hazardous event, with its consequences (Risk = a function of (Probability, Consequence)). Structural assessments are usually aimed at reducing the probability of failure, but it is impossible to reduce this probability to zero. Therefore, the consequences of failure should also be considered in structural assessments, as there is always a chance of a wrong answer. 3.3.5 Risk and Gain In risk management it is important to balance risk with any accrued gain. For example, 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 decreased maintenance 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 consequences of 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 a pipeline. Risk management should be used as this is an overall programme that includes risk assessment but also includes mitigation methods, measuring the performance of the mitigation methods, organisation of risk controls, etc..



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 the pipe, 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 that ensures 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 in the linepipe will be governed primarily its tensile properties rather than toughness. The linepipe material has its toughness (resistance to the presence of cracks) tested at the pipe mill to ensure ductile behaviour. This is necessary, as some materials such as linepipe steel undergo a transit ion from ductile to brittle behaviour, under conditions of decreasing temperature, or increasing loading rate. Three basic factors contribute to brittle fracture: triaxial state of stress (e.g. a notch), low temperature (i.e. below the transition 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 measuring toughness. 4.1.2 Running Fractures Historically, two tests have been conducted on linepipe steel to give a measure of it toughness [Maxey et al, 1972; Kiefner et al, 1973; Anon., 1965]:

i. The Drop Weight Tear Test (DWTT10), to ensure the pipe material is not brittle,

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

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 the material’s toughness, and the percentage shear area on the fracture faces is a measure of ductility. These tests were originally implemented to prevent long running fractures in the pipeline (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 a 5mm 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 wall linepipe.



Brittle fracture propagation was prevented by specifying a minimum toughness to ensure that the line pipe steel is on the upper shelf of the transition curve at the minimum 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 FPTT could 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 pipe steel would not sustain a propagating brittle fracture. The correlation with full-scale behaviour was necessary, as small-scale specimens do not accurately model full-scale behaviour, and non-conservative predictions can be obtained, 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-Notch impact energy is related to the ductile toughness of a pipeline, and following more research work and full scale test validation, a number of empirical and semi-empirical criteria 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 Advantica’s Spadeadam Test Site in the UK.



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 ductile mode, 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 the temperature for 85% shear area on a DWTT specimen corresponds to a ‘fracture initiation transition temperature’ (FITT), where the fracture initiation mode changes from ductile to brittle as the temperature decreases below the FITT, Figure 12a. It should 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 of a defect is governed by the ultimate tensile strength (UTS) of the material, a typical toughness (full size Charpy) of 80-100J (60-75 ft lb) is needed. Note that these levels need to be calculated, and that they will ensure collapse at the UTS (which is higher than the conventional ‘flow stress’ that is used in the equations that follow).

Energy Absorbed

Temperature

DWTT orCharpy

Specimen

Structure

The specimen may behave in a ductile manner (i.e. 0 percent cleavage area), but the structure could behave in a brittle manner at the same temperature.Hence we need to CALIBRATE our small DWTT or Charpy tests with full scale behaviour

Energy Absorbed or % Shear

Temperature

Ductile

85%

Brittle

Operate Pipeline above this ‘FPTT’



Energy Absorbed

TemperatureEnergy

Absorbed

Temperature

Energy Absorbed

Temperature

Dynamic Loading

Static Loading

Part wall defect

Thro-wall defect

Decreasing thicknessin Charpy orDWTT specimen

% o

f duc

tile

failu

re p

ress

ure

TemperatureFITT

% o

f duc

tile

failu

re p

ress

ure

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 a

through 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 a propagating fracture).

Figure 13 presents a schematic of the above failure process.

13 Sometimes called a ‘break’.

Comment: leads



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 (or workmanship) limits will ensure that only innocuous defects remain in the pipeline at the 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 some stage 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 for purpose’ (see 4.3.3), i.e. a failure condition will not be reached during the operation life of the pipeline. Engineers have always used fitness for purpose – in the early days an engineer’s intuition 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 in structural analysis, and we have many tools available that can help us progress from these early days. And remember that ‘rule of thumb’ was derived from a very old English law that stated that you could not beat your wife with anything wider than your 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, to ‘engineering critical assessments’, where a defect is appraised analytically, taking into account its environment and loadings [Anon., 1999a; Anon., 2000]. It should be noted that fitness for purpose is not intended as a single substitute for good engineering judgement; it is an aid. 4.3.1 Generic FFP There are various technical procedures available for assessing the significance of defects in a range of structures. These methods use fracture mechanics; for example, the British Standard BS 7910 [Anon., 1999a] contains detailed engineering critical assessment 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 Low Toughness.

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

c. A Through Wall Defect in a Pipeline.

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

f. The Through Wall Defect ruptures, butArrests if pressure is low, and/or pipe is High Toughness, or if product is a liquid.



579 [Anon., 2000] which has similar methods, but with a bias towards their use in process plant. 4.3.2 Pipeline-Specific FFP The above standards (API 579 and BS 7910) are generic; they can be conservative when 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 invalid or unreliable if they are applied outside these empirical limits. The pipeline industry has used their fitness for purpose methods to produce generic guidelines for the assessment of defects in pipelines. These methods and guidelines are based on pioneering work at Battelle Memorial Institute in the USA on behalf of the Pipeline Research Council International [Anon., 1965; Maxey et al, 1972; Kiefner et al, 1973], with the more recent additions of ad hoc guidelines for the assessment of girth weld defects, mechanical damage and ductile fracture propagation produced by the 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 Defect Assessment 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 is defined 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 a technical 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 skill and care’ in his/her work; however, a contractor carrying out a construction has a fundamentally different obligation – he/she is obliged by law to warrant that the completed works will be fit for their intended purpose. This will be implied in his/her contract – it does not have to be stated explicitly. Therefore, if a consultant gives a warranty (guarantee) for fitness for purpose (on the completed 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 are different from those of negligence:

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

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



Engineers should check with their professional indemnity insurance – what is covered as a company/professional? Usually, professionals/consultants are not covered for warranties. 4.4 History of Pipeline Defect Assessment Methods. 4.4.1 The Very Early 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 15th century by Leonardo da Vinci, but prior to 1950, failure reports of engineering structures did not usually consider the presence of cracks; cracks were considered unacceptable 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 to perfectly elastic materials, i.e. it was not directly applicable to engineering materials such 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 with problems; pipelines were thin walled, increasingly made of tough materials, and exhibited extensive plasticity before failure. The fracture mechanics methods (using stress intensity factor, K) at that time used linear elastic theories that could not reliably be applied to the failure of defective pipelines as they would have needed:

- quantitative fracture toughness data, including measures of initiation and tearing (only simple impact energy (e.g. Charpy V-notch) values were available),

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

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

4.4.2 The Pioneers Workers [Anon., 1965; Maxe y et al, 1972; Kiefner et al, 1973] at the Battelle Memorial Institute in Columbus, Ohio decided to develop methods based on existing fracture mechanics models, but they overcame the above deficiencies in fracture mechanics’ knowledge by a combination of expert engineering assumptions and calibrating 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)



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 a brittle 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 an empirical 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 material’s 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 criteria15 for axially-orientated defects in linepipe:

14 ‘Predicted’ failure stress is that predicted using Equations 2 and 5. ‘Normalised’ flaw size is 2sc8

EpA12

vC.

15 Toughness dependent Equations (2) and (5) are for imperial units, and these units are retained in this section 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

Act

ual f

ailu

re s

tres

s/pr

edic

ted

failu

re s

tres

sThrough-wall Defect, Eq. 2Part-wall Defect, Eq. 5

DEFORMATION

BRITTLEFAILURES

xx

COLLAPSEFAILURES

Strain

Stress

xx

x



Through-wall defect:

==

σσπ

σ

π

σπ θ

2secln

8

12

8 22

2 Mc

EA

C

cK v

c toughness dependent (2)

222

80.012

40.01

+=

+=

Dt

c

Rt

cM (3)

σσ θ1−= M strength dependent (4)

For part wall defects:

==

σσπ

σ

π

σπ θ

2secln

8

12

8 22

2P

vc M

c

EA

C

cK

toughness dependent (5)

−

−

=

tdMt

d

M P

1

11

(6)

−

−=

Mtd

td

11

1σσ θ strength dependent (7)

D Outside diameter of pipe (R=D/2=radius) t pipe wall thickness E elastic modulus M Folias factor R radius of pipe d part wall defect depth σθ hoop (circumferential) stress at failure (or σf) 2c defect axial length Cv Upper shelf Charpy V-notch impact energy A Area of Charpy specimen fracture surface σ flow stress (function of σU (ultimate tensile strength) and σY (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 a notional material property with a value between yield strength and ultimate tensile strength, Figure 15.



Figure 15. ‘Flow Stress’ Modelling of Stress -Strain Behaviour in Pipe lines It is important to note that:

i. The original work and models accommodated the very complex failure process of a defect in a pipeline, involving bulging of the pipe wall, plastic flow, crack initiation and ductile tearing. These pioneering models were safe 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), and

ii. 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 linepipe has a 2/3 Charpy toughness of 21 J (16 ftlbf).

This work has formed the basis for the development of many current pipeline defect assessment 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 to still be applicable to many newer pipeline applications, but it is unreasonable (and dangerous) to expect that 30 year old methods will be applicable to newer (e.g. X100 grade) 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 greater than 1 percent strains). 4.4.4 Summary 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 assessment curves for part wall defects in ductile linepipe. These curves assume strength

typical engineering stress-engineering strain curve for

linepipe steel

yield strength

ultimate tensile

strength

engineering strain (ε)

engineering stress (σ)

flow stress (σ)



dependent behaviour, and can be considered ‘universal’ assessment curves; a defect of depth (1-(d/t)) and length (2c/(Rt)0.5) will fail if the pipeline hoop stress falls above the 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 above Equations ((2)-(4)) allow the hoop stress (σf) 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

Failu

re S

tres

s/Y

ield

Str

engt

h

RUPTURE

LEAK

2c

σσ

fM= −1

This boundary is not sensitive to pressurising medium2c 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

Fai

lure

Str

ess/

Yie

ld S

tren

gth

1 - (d/t) = 0.6

0.5

0.3

0.2

0.10.05

0.4

1 - (d/t) = 0.6

2c (l )d

t

2240.01

+=RtcM

Flow strength = 1.15σy



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 assess the 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 external pressure (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 following Sections. 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 tole rances, v. time dependent effects (defects can grow to failure at constant

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

vi. overpressures in the pipeline (pipeline pressures are never constant - pipelines are typically allowed a 10% (of maximum allowable operating pressure ((MAOP)) overpressure during operation – therefore the maximum 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 defect’s failure.

It is the responsibility of the engineer conducting the assessment to derive a safety factor. It is becoming customary in the pipeline business to only allow defects to remain in a pipeline if they can withstand a hoop stress to the stated pre-service hydrotest 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 assessment of the failure stress of a defect-free pipe. This gives a ‘benchmark’ failure stress for any pipeline. 4.5.2 Defect-Free Pipe under Internal Pressure 4.5.2.1 Static Failure Most grades of steel (<X80) will deform (strain) a large amount before reaching UTS and failing (e.g. strain at failure > 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



significant if you are basing your pipeline design on strain rather than stress, as your margin of safety on strain will decrease with increasing grade of linepipe. However, most pipelines are still designed on stress In general, the simplest and most conservative formula for the range of transmission pipeline D/ t ratios is given by using σU and the mean pipeline diameter (D-t) in the simple Barlow equation (although it becomes increasingly conservative for thicker walled pipe):

( )tDt

P Uf −

=σ2 (8)

Pf = failure pressure There are more accurate analytical methods [Stewart et al, 1994] incorporating material work hardening and large displacement theory, and they are accurate over a wide range of D/t ratios. 4.5.2.2 Cyclic Failure The fatigue strength of (notionally defect-free) welded linepipe subject to cyclic internal pressure will be governed by the fatigue strength of the weld, and the fatigue strength 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 Axially-Orientated Gouges or Similar Metal Loss Defects1 7 4.5.3.1 Basic Equations External interference during operation, or damage during construction, can cause gouges or scratches on the pipe’s surface, Figure 18. These metal loss defects may be accompanied by local plastic deformation. If this deformation caused a dent, then the gouge 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 Transportation Safety Board website: www.ntsb.gov

Comment: delete



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

2c

R

d

t

Defect Dimensions

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

2UY σσσ += (9)

222

52.012

26.01

+=

+=

Dtc

Rtc

M (10)

for use in Equation 7, and D = outside diameter to be used in the equations. Note that these equations are only validated for pipewall thicknesses up to 22mm and toughnesses of 21J (2/3 Charpy) [Cosham and Hopkins, 2001]. Figure 191 8, shows the accuracy of using Equations 7, 9 and 10 to assess gouge or gouge-like defects in linepipe. 4.5.3.2 Note 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 be indicative 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 a toughness >20J [Cosham and Kirkwood, 2000; Cosham and Hopkins, 2002]. Note that 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.



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

Figure 19. Predicted Failure Stresses of Full Scale Burst Tests on Vessels containing 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 damage should be inspected closely before assessment, and appropriate safety factors included in the assessment. 4.5.4 Dents 4.5.4.1 Burst Strength of Plain Dents Dents 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 coincide with 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 by the 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

Pre

dic

ted

Fai

lure

Str

ess/

Yie

ld S

tren

gth

, per

cen

t

CONSERVATIVE

UNCONSERVATIVESee original referencefor test details



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. a gouge 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 been derived 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], a variety 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 an API publication [Kiefner and Alexander, 1997; Anon 1997] specifically on the assessment of dents caused by rocks in pipelines. The reader is directed to these references for more detailed information. In full scale tests on plain dents on welds very low burst pressures have been recorded. Therefore, the burst strength (and the fatigue strength) of dents containing welds 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 both product 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 reduced significantly if the pipeline is subjected to cyclic loading (see next). 4.5.4.2. Fatigue Life of Plain Dents Large 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 the stress concentration changes as dents can ‘reround’ under cyclic internal pressure loading. 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 life compared 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 to fatigue cycling, because the dent was permanently pushed out (rerounded), reducing the 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.



74.3

6

114001

100.2−

∆

∆∆

×= pp

Nσ

(11)

where: N number of cycles to failure

∆∆

pσ 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-linear elastic-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 the various 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 a geometrically 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:

( )90300 6.0−

=Qf

σ

σ …... (12) e

( )

=

td

cR

HC

Q v

22

…..(13) (13)

10000+= Yσσ 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 into unpressurised pipe; therefore, the dent depth measured at zero pressure must be used

H

R

D

t

d



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 above empirical relationship of Battelle. The model is defined as follows (in SI units):

−

+

−−=

−

−

2

1

2

2121 )738.0ln(

exp2.108.115.1

113expcos2

KKC

DH

tR

YDH

YAdE voo

σπ

πσσθ

(14)

where

−=

td

Y 115.1 σσ (15)

432

1 4.307.216.1023.012.1

+

−

+

−=td

td

td

td

Y (16)

432

2 0.141.1332.739.112.1

+

−

+

−=td

td

td

td

Y (17)

9.11 =K

57.02 =K

ro HH 43.1= (18)

The flow stress (Equation (15)) assumed in the dent-gouge fracture model is not appropriate 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 parameter K2 non-linear regression parameter This failure criterion for a dent containing a metal loss defect does not give a lower bound 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 to high 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 of between ten and one hundred times less than the fatigue life of an equivalent plain dent [Hopkins et al, 1989]. In some cases even shorter fatigue lives have been observed during testing. 4.5.4.4 Note on the Assessment of ‘Mechanical Damage’



Dents and/or gouges in a pipeline are indicative of impact damage. When a dent or a gouge is suspected in a pipeline, they should be carefully investigated to determine if they are co-incidental, as the combined dent and gouge is a very severe defect, and usually requires rapid repair. 4.5.5 Corrosion20 There are several approaches that have been used to characterise the behaviour of both 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 most accurate (DNV RP 101) is covered last. 4.5.5.1 ANSI/ASME B31G The most popular document for the assessment of the remaining strength of pipelines with 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 early 1970s [Kiefner and Duffy, 1973], although it has since been updated [Kiefner and Vieth, 1989; Anon., 1991]. It is based on an empirical fit to an extensive series of full scale tests on vessels with narrow machined slots. The basis of the equation used in B31G is relatively simple and involves: • assuming the maximum pipe hoop stress is equal to the pipe material's yield

strength, and, • characterising the corrosion geometry by a projected parabolic shape for relatively

short corrosion, and a rectangular shape for long corrosion. The equation used in B31G is a derivative of Equation (7):

σ σfo

o

A AA A M

=−−

−

11 1

( / )( /

(19)

where A=cross sectional area of defect in pipewall (for a rectangular, flat bottomed defect this is 2c.d), and Ao=pipe wall area occupied by defect (for a rectangular flat bottomed defect this is 2c.t). In the B31G code, a simplified equation is provided which represents the defect as a parabolic shape:

σ σf

dt

dt M

=−

−

123

123

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, where the defect must be assessed over its ‘whole life’, and its size at the end of the pipeline’s design life needs to be used in the calculations.



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

McDt

= +

1 0 82 2

. (3)

It is stated in the B31G code that the above equations should only be applied to corrosion 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 relative longitudinal 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 M is 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 equation is replaced by the following equation:

σ σf

dt

= −

1 (22)

4.5.5.2 Modified B31G The B31G criterion has been used successfully in the pipelines industry for many years. The method has been proven, in general, to be conservative and as a result an ‘improved’ method was developed which modified the existing B31G guidance. The modified B31.G method [Kiefner and Vieth, 1989; Anon., 1991] has recently been adopted as the preferred method for the fitness for purpose assessment of corrosion defects in the ANSI/ASME B31 Code. The hoop stress at failure is given by:

−

−=

Mtd

td

185.01

85.01σσ θ (23)

with σ =SMYS + 68.94 MPa (10 ksi)

M = 1 0 62752

0 0033752

2 4

+

−

. .c

Dt

c

Dt for

250

2c

Dt

≤ (24)

M = 0 0322

3 32

. .c

Dt

+ for

250

2c

Dt

> (25)

Equation (23) shows that the representation of the area of metal loss was revised (A=0.85d(2c)). A simple, arbitrary, geometric idealisation was proposed for hand



calculations (a factor of 0.85 rather than the 0.67 in the original ASME B31G was recommended). Additionally, an effective area method using the measured profile of the corroded area (A), was also developed to give more accurate predictions. The effective area method is most commonly known as RSTRENG (‘Remaining STRENgth’), as this is the name of the software that does the assessment of irregular-shaped corrosion defects, using the modified equations above. 4.5.5.3 New Methods New assessment methods are becoming available. These include both in-house methods from leading research departments [Stewart et al, 1994], and the results of a large group sponsored projects [Kirkwood et al, 1996; Bjornoy et al, 1997; Bjornoy et al, 1999; Fu and Batte, 1999; Bjornoy et al, 2000]. The latest corrosion model given in DNV RP 101 [Anon., 1999b] is:

( )

−

−

−=

Qtd

td

tDt

P Uf 11

129.0 σ (26)

where 2

31.01

+=DtlQ (27)

This is the same form as ASME B31G and the modified ASME B31G, but note that the flow stress is related to ultimate tensile strength ( Uσ ), which can be estimated from the materials specified minimum tensile strength (SMTS). The DNV RP 101 methods are considered ‘best practice’ for corrosion assessment in modern linepipe steels [Cosham and Kirkwood, 1999; Cosham and Hopkins, 2000]. 4.5.5.4 Comparison of Corrosion Assessment Methods The above methods for assessing corrosion can be compared, Table 3.

METHOD BASIC EQ. (No)

FLOW STRESS

DEFECT SHAPE

‘FOLIAS FACTOR’

‘Original’ Battelle (19)

SMYS + 69MPa Defect Area 2)/2(8.01 Dtc+

B31.G Battelle (20) 1.1SMYS Parabolic

[2/3(d/t)] 2)/2(8.01 Dtc+

Modified B31.G

Battelle (23)

SMYS + 69MPa

Arbitrary [0.85(d/t)]

422003375.026275.01

−

+Dtc

Dtc

RSTRENG Battelle (23)

SMYS + 69MPa

Defect ‘Profile’

422

003375.02

6275.01

−

+Dtc

Dtc

DNV RP-F101

Battelle (26)

0.9SMTS Rectangular (and Defect ‘Profile’)

2)/2(31.01 Dtc+



Table 3. A Comparison of the Bases of Corrosion Assessment Methods. Clearly, all rely on the original work at Battelle, and the major changes over the past 30 years have centred on the modelling of flow stress, defect shape and the Folias Factor. Figure 20 compares three of the methods in Table 3 (assuming a rectangular shape defect, X52 linepipe, and ignoring the 80% d/t cut-off in ASME), showing that for this grade of linepipe there is little difference between DNV and the modified ASME B31G method. 4.5.5.5 Notes on the Assessment of Corrosion. The ASME methods are proven on older linepipe, and hence these methods should be used on linepipe of circa 60s and 70s vintage. They are also proven on thin walled linepipe with grades less than X70; hence their applicability to high grade, thicker walled linepipe must be proven. The more recent methods have been proven on more modern linepipe. For example, DNV RP 101’s validity range is in linepipe with full size Charpy values above 61J.

Figure 20. Comparison of ASME (B31G and modified B31G) and DNV Methods of Corrosion Assessment. 4.5.6 Environmental Cracking 4.5.6.1 Internal Surface and Pipe Body Cracking

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 1 2 3 4 5 6 7 8

2c/(Rt)^0.5

Def

ect

Dep

th/W

all T

hic

knes

s

B31G

modified B31G

DNV



Not all gas is 100% pure gas – if a gas contains liquids it is termed ‘rich’ or ‘wet’ gas. Dry or lean gas means the opposite. Additionally, some pipelines carry product that is ‘sour’ (high content of hydrogen sulphide). A ‘sweet’ gas or oil is low in hydrogen sulphide. If we have these sour, wet environments we can have: corrosion pitting, sulphide stress cracking and hydrogen induced cracking on the internal surface of the linepipe, Figure 21.

Figure 21. Environmental Cracking in Linepipe carrying Sour Product. Cracking in pipelines is not usually a defect assessment problem; it is usually an indication that operation, product or environment is a major problem. It is a symptom of something wrong – hence the cause needs to be isolated. Therefore this cracking is treated as a material, product, process or environment problem, and the cracking problem is solved by changing or controlling product, environment, etc.. Generally, when designing against stress corrosion cracking, e.g. sulphide stress cracking of carbon steels, three factors contribute to cracking:

• material type and microstructure, • applied stress, and • the environment.

Therefore, avoidance of the problem may be achieved through appropriate material selection or by keeping the stress below the critical level for cracking. Where practicable, the environment may be modified but this is only occasionally possible. Consequently, any crack initiation of environmental cracking, such as sulphide stress cracking of carbon steels, is usually considered unacceptable due to the rapid rate of subsequent propagation (growth). However, there is some fundamental understanding of their growth under static loading

Corrosion of pipewall due toreaction and formation of

iron sulphides and H2

Two types of cracking can occur

Pipeline Carries Wet, Sour Product.

The solution is to select the correct (resistant)pipe materials and control product quality

Sulphide Stress Corrosion Cracking(SSCC)

H2 can enter steel and cause damage and embrittlement.

SSCC usually occurs in welds becauseit needs high stresses and

high yield strengths/hardness

Hydrogen Induced Cracking (HIC)

HIC is stepwise cracking caused by H2diffusing into the steel and entering voids

e.g. around inclusions

HIC

SSCCweld

Comment: full stop spacing

Comment: full stop



Environmental cracks grow due to the environment, but they can reach a size when they can start to grow by a fracture mechanism. The stress intensity (KI) of the crack at this size exceeds a critical stress intensity for crack growth, KIscc. If the Ki value of a crack exceeds KIscc the crack will initiate and grow at a rate dictated by the material, environment, etc.. The rate of growth (da/dt) will dictate how long the crack takes to fail the structure. The structure fails when Ki=K1c (the fracture toughness), assuming that K1c>KIscc. KIscc, K1c and da/dt can be measured in the laboratory (see API 579 and BS 7910). 4.5.6.2 External Surface Cracking21 - Stress Corrosion Cracking Stress corrosion cracking has been well known for many years in pipelines. The older type of stress corrosion cracking (‘high’ pH) was usually found downstream from compressors on poorly coated pipelines, where the high and varying temperatures of the product (after compression) accelerated cracking. In recent years, there have been an increasing number of pipeline failures caused by a different type of stress corrosion cracking [Anon., 2002b]; since 1977, SCC has caused 22 pipeline failures in Canada. These failures include 12 ruptures and 10 leaks on both natural gas and liquids pipeline systems. This is a 'new' type of SCC that attacks the external surface of the pipeline, but it can occur at relatively low temperatures, and in environments with relatively low pH (near neutral) values [Anon., 2002b]. It again requires:

• a potent environment at the pipe surface,

• a susceptible pipe material, and

• a tensile stress.

No reliable fracture mechanics model has yet been developed, but some basic and developing models are in the literature [Leis and Mohan, 1993; Jaske and Beavers, 1999]. Therefore, if SCC is suspected, the best plan of action is to mitigate by:

- improve corrosion protection (CP), temperature control and reduced pressure cycling (this slows down the growth),

- repair and recoat (note that some repair methods such as welded sleeves are considered acceptable, but others (e.g. some composite wraps) are not yet considered proven for cracks),

- retest and repair/recoat (a hydrotest (to 110% SMYS) will fail large defects), - selective replacement (this could be near populated areas, to reduce overall

risk), - replace or loop affected areas, - intelligent (smart) pigs (see Figure 7) and selective replacement.

4.5.7 Material Defects ‘Material defects’ are defects that are in the body of the linepipe, usually from the manufacturing or rolling processes. These defects will have survived both a pipe mill hydrotest and the pre-service hydrotest, and therefore are unlikely to be a problem in-

21 In the old ‘ town gas’ pipelines, that carried (impure) gas manufactured from coal, there were incidents of SCC on the internal pipe surface.



service. However, they can sometimes be detected and they can sometim es pose risk. The following highlights these problem areas and presents some solutions. Defects in the parent plate of pipe steels (e.g. laps. slivers, laminations, etc.) can be assessed using the methods outlined in Section 4.5.3, if they result in a loss in the cross-sectional area of the pipe. More specific guidance:

i. Inclusions in the pipe body are not considered significant if they have passed a pre-service hydrotest. However, they may be a site for hydrogen cracking in sour service pipelines.

ii. Laminations are not usually a problem as most do not cause a reduction in the cross-sectional area (e.g. a planar, radial-orientated lamination), and hence they will not cause a reduction in the pressure containment of the pipe. However some laminations can caus e structural problems: o Laminations inclined to the plate, or multiple laminations through the

wall thickness may cause a leak path, o Beware welding onto laminations (the lamination can open up and

cause a leak path)’ o Beware of laminations associated/adjacent to weld or other structural

discontinuities - they may lead to failure, o Laminations that are in a hydrogen-charging environment, can attract

hydrogen and lead to cracking and blisters. iii. Blisters can occur in pipelines carrying sour product. Guidance for

hydrogen charged blisters and laminations are given in API 579 [Anon., 2000]. This document gives acceptance limits and conditions to be met for acceptance.

iv. Hard spots (‘dollar spots’) are local hard zones caused by excessive local quenching. They are typically <250mm (10in) diameter, and may cause local out of roundness. The high hardness can lead to cracking if exposed to a hydrogen charged environment. Generally, they are not a problem, but they do increase susceptibility to other types of defects.

4.5.8 Construction Defects Construction defects will generally be gouges, or perhaps dents. The assessment methods detailed in Sections 4.5.3-4.5.4 above can be used to assess these construction defects. Note that API 1156 [Anon., 1997] gives guidance on pipeline dents caused by rocks. However, it should be emphasised that construction defects detected prior to operation can be easily repaired, and may be more of a contractual/legal issue than fitness-for-purpose. 4.5.9 Defects in Linepipe Welds and Pipeline Girth Welds Linepipe is either made by welding plate into a cylinder shape, or by producing a seamless tube, the former being the most popular for larger diameter pipelines. This weld is either longitudinally orientated or is a spiral, depending on the linepipe manufacturing process. These sections of linepipe are welded together to form the pipeline. The circumferentially -orientated welds that join each section are called girth welds.

Comment: Presumably ‘inches’ ? Most have used mm. I’ll check instructions, but use of ‘’ is confusing



i. Linepipe welds - Longitudinal or spiral seam welds in linepipe are made

under controlled, good conditions in a pipe mill, and will have survived the pipe mill test and pre-service hydrotest; therefore, new linepipe should not contain large (pre-service) defects in their welds. Many years ago, when weld quality control was not as good as today, and some of the welding processes in use were relatively new, these welds could be delivered to site with large defects. Additionally, some types of older welds (electric resistance or flash welded seam welds) are susceptible to preferential corrosion (the bond line corrodes preferentially to the surrounding steel) that can produce a ‘sharp’ V-shaped notch along the bondline.

ii. Girth welds - Girth welds are manufactured in the field, under more difficult conditions compared to linepipe welds, and the stresses created by the hydrotest will be <50% of that experienced by the linepipe seam welds. Therefore, there is a chance of large, undetected, weld defects entering service.

4.5.9.1 Pipeline Welding Codes and Defects All welds will contain some defects, so pipeline welding codes allow reasonable levels of defects to remain. These levels are often called ‘workmanship’ levels – those expected when reasonable operators, materials and working practices are followed. The codes allow some ‘planar’ and ‘non planar’ defects. Non planar defects are slag, porosity, etc., and planar defects are lack of side wall fusion, etc.:

i. Non planar defects are not usually a problem, but indicate poor quality, and they could mask the presence of more serious defects.

ii. Planar defects can act like cracks, and hence are limited in extent by the welding codes.

Typically, a surface breaking defect of 25mm (1in) in length22, or a 50 mm (2in) embedded defect is allowed to remain in girth welds by most weld ing codes. Cracks are not usually allowed; cracks can indicate bad welding, poor material, poor quality control, etc., and hence are usually repaired. These codes, and their acceptance levels, have been shown to be effective; pipeline girth welds rarely cause problems during service. However, defects are sometimes detected during service, and they require assessment. Additionally, operators may wish to set different defect acceptance levels (based on fitness-for-purpose, rather than workmanship limits) at the construction stage of their pipeline. 4.5.9.2 New Acceptance Limits for Girth Weld Defects The European Pipeline Research Group, EPRG has published guidelines on the assessment of defects in transmission, and they constitute the state of the art. The reader is directed towards these guidelines and their background literature [Hopkins,

22 Pipeline girth welding codes normally only quote defect length in their acceptance charts. This is because pipeline welds have traditionally been inspected using radiography, which will not give a measure of through-thickness depth.



1993, Knauf & Hopkins, 1996]. They can be used on new pipelines (to set weld defect acceptance levels), but have applicability to existing pipelines. The EPRG guidelines present three ‘tiers’ or levels of defect assessment. The first tier is a simple workmanship level, where short defect lengths are quoted as acceptable. This tier can be used on new pipeline constructions where there is no need for large defects to be either assessed or accepted. The two higher tiers use fracture mechanics, supported by a large experimental programme, to give very generous defect limits for girth welds. These limits are not intended for new constructions; modern girth welds should easily meet current workmanship standards. It is recommended that the new limits in the EPRG guidelines be used for:

- special applications where longer defects are anticipated (e.g. new processes), - as a concession by the pipeline operator to avoid unnecessary repairs, - as an insurance policy for cases where a defect is detected during post-

construction audit or during in -service inspection.

Figure 22 gives the Tier 3 defect limits from the EPRG guidelines. Note that the guidelines do not take account of fatigue loading, or environmental attack.

Figure 22. Defect Limits for Girth Welds in the EPRG Guidelines (note conditions apply) 4.5.9.3 Arc Strikes Welding arc strikes/burns are often found on linepipe. These are areas of localised melting of the linepipe, usually causing:

- a small depression in the pipewall, - an area of local hardness (this hardened layer may increase susceptibility to

environmental cracking and possibly small cracks).

8 10 12 14 16 18 20 22 24MIN. OR MEASURED WALL THICKNESS (mm)

0

10

20

30

40

50

60

DE

FE

CT

LE

NG

TH

(%

pip

e ci

rcum

fere

nce)

Total - All Planar Defects

Interacting Planar Defects

Individual Planar Defects

Total - All Defects



Welding codes require arc burns/strikes to be removed – this is simple and quick when the pipeline is being welded, and crews are on site. They are not considered a problem in service as:

- they are not known to be a cause of in-service failures, - the area hardened/cracked is very small and insignificant, - the arc strike is usually coated after welding, so it is protected from the

environment,

but good practice is to grind them away, ensuring that the local wall thickness is not reduced below the minimum specified or calculated by methods such as those in Section 4.5.3. 4.5.10 Other Fitness-For- Purpose Methods For Transmission Pipelines. 4.5.10.1 Preventing Dynamic Fracture Running fractures - both ductile and brittle - are a risk in gas and multiphase pipelines [Anon., 1965; Maxey et al, 1972], Figures 10 and 13. Consequently, design codes specify toughness requirements, based on impact tests (the drop weight tear test, DWTT and Charpy, Cv ), for the pipeline material. These fractures can run long distances (the longest brittle fracture in history ran for 13 km, and the longest ductile fracture ran for 568m). By ensuring adequate toughness in the linepipe, any fracture that starts to run along the pipeline will quickly be arrested (Figure 13). Brittle fractures propagate at very high speeds, in excess of the speed of the decompression wave of the methane gas (400m/sec (1300ft/sec)). The tip of the running brittle fracture will experience the full pressure existing in the pipeline at the time of the incident that caused its initiation, as the gas cannot ‘exhaust’ from the pipe at speeds higher than the acoustic velocity. The lower the temperature of the pipeline, the faster the fracture speeds, so it is essential that the linepipe is not a brittle material. Ductile fractures run at lower speed; these can be below the speed of the decompression wave. Hence, the first requirement in preventing any running fracture in a pipeline is to ensure that any fracture will be ductile; however, despite travelling at speeds lower than the decompression speed, it is possible for ductile cracks to propagate indefinitely because of the nature of the decompression process. So, it is essential to ensure the ductile pipeline has sufficient toughness to arrest a running ductile fracture

The prevention of propagating fractures in gas/multiphase pipelines is achieved by:

i. specifying a minimum toughness requirement (in terms of DWTT) to ensure that brittle fracture propagation does not occur, and

ii. specifying a minimum toughness requirement (in terms of Charpy) to ensure that ductile fracture propagation does not occur.

Pipeline design codes give these specifications, and the levels quoted in, for example, ASME B31.8 are based on extensive full scale testing in both North America and



Europe. The simple Charpy (Cv) test remains the definitive test for fracture propagation, and it is the Charpy test that linepipe is assessed against for crack arrest. A popular relationship used for calculating the required Charpy value for crack arrest is the Battelle formula: Cv = 1.5x2.382x10-5σh

2(Rt)1/3 (28)

Cv = full size Charpy V-Notch Energy, J σh = hoop stress, Nmm-2 D = pipe diameter, mm R = pipe radius, mm t = pipe wall thickness, mm

These types of formulae are related to confidence levels, and therefore the original publications should be consulted prior to use [Anon., 1965, Maxey et al, 1972]. For modern linepipe toughness requirements the reader should consult the latest EPRG guidelines [Vogt et al, 1995]. Modern linepipe does not have a brittle fracture problem (i.e. the DWTT requirements are easily met), and most modern linepipe can easily meet Charpy requirements to prevent running ductile fractures. However, it should be remembered that equations such as Equation (28) are empirical and they have not been generally validated on the higher grade steels (X80 and above), rich gases, pipelines designed to operate at high stresses and pressures, and the thick walled linepipe (e.g. for use in deepwater). 4.5.10.2 Fatigue Calculations Pipelines experience changes in pressure due to varying customer demand, or differing batch flows. This means the pipeline can experience fatigue cracking. Fatigue cracking is not a major cause of pipeline failure, as pipelines tend not to be subjected to heavy cyclic loading, but there have been recorded incidents in poor seam welds, and at damage locations in linepipe. Additionally, some pipelines can be heavily cycled; liquid pipelines that are carrying batched products, and gas pipelines that are supplying a variable demand profile customer (e.g. domestic) can see large cyclic pressure changes. Offshore, pipelines can be subjected to high cyclic stresses during laying (this will effect the fatigue strength of the girth weld) and thermal loading. Therefore, it has been necessary for the pipeline industry to apply fatigue fracture mechanics [Hopkins and Jones, 1984; Hopkins and Haswell, 1995; Kiefner and Maxey, 2000]. Loss of wall thickness defects or cracks can be assessed for fatigue using classic fracture mechanics calculations [Anon., 1999a; Anon., 2000], whereas damage such as dents has to be assessed using the methods detailed in Section 4.5.4.2. 4.5.11 Sub-sea Pipelines Most transmission pipelines are onshore, buried to about 1m. However, there are many 1000kms of offshore (or ‘sub-sea’) pipelines. They range from pipelines in very



shallow water (a few metres), to very deep: some new pipelines are planned to operate at many 1000kms below the surface. These pipelines use the same linepipe, and carry similar products, but their integrity problems and how we solve them can differ significantly because of their environment:

- there is limited accessibility for inspection and maintenance (e.g. no human intervention is possible at depths >300 m); the cost of inspection can be greater than 10 times the onshore cost,

- the pipeline configuration may prevent external inspection (e.g. pipe-in-pipe systems, riser caisson assemblies, etc.),

- different types of inspection methods and tools are required, - most sub-sea pipelines are ‘producers’ with no redundancy for alternative

route, i.e. potential increased cost of lost production, - there is an increased cost of remedial works, and therefore more frequently it

is cost-effective to conduct analytical assessments, - there can be constraints in schedule by the weather and availability of

equipment (e.g. specialized boats), - other users (fisherman, tankers, etc.) of the sea are continually in the vicinity

of the pipelines creating a high third party damage risk. Sub-sea pipelines can contain all the damage covered by the above assessment methods, but additionally can contain:

- Pipeline spans – these are sections of unsupported pipeline, created by: construction, scour and seabed movement, changes in local soil properties, and pressure and temperature effects, Figure 23. They have a tendency to change year-by-year. The key integrity issues are structural over -stress or fatigue failure.

- Pipeline exposures – these are sections of exposed pipeline found on a trenched or protected pipeline system. They are caused by seabed movement or pipeline movement, and can be the pre-cursor to a pipeline span. The key integrity issues are stability, external damage and possibly thermal performance.

- Buckling - Lateral (horizontal) and upheaval (vertical) buckling are possible in sub sea pipelines. Lateral buckling is usually associated with unburied pipelines at areas where the alignment is curved, whereas upheaval buckling will be on buried pipelines at overbends, where the profile is convex upwards. They are caused by temperature and pressure, combined with construction features or third party interference. They are identified by gross pipeline lateral or upheaval deflection, usually coupled with soil movement, Figure 23. The key integrity issues are structural and fatigue failure, short and long-term.

- Risers – the pipeline section alongside an offshore platform (the ‘riser’) can have collision damage from supply boats, impact damage from anchors and dropped objects from the platform. It will also be subjected to large external loads (wave loading) and corrosion around the splash zone.

The above span and buckling problems can be solved by stress analysis and guidance given in sub-sea pipeline design codes. However, they will require precise inspection data, and additional analyses such as hydraulic and process calculations.



Finally, it should be emphasized that the defect assessment methods given above have been developed primarily for onshore pipelines. This does not invalidate their use in sub-sea pipelines; however, sub-sea pipelines can be subjected to high external loads (additional to internal pressure loading), and can be of geometries (thick wall, or low D/t) that will not have been included in the empirical validation of many of the methods.

Figure 23. Example of a Free-span (top) and Upheaval Buckle in a Sub-sea Pipeline. 4.5.12. Other Components of a Pipeline System There are many other types of plant associated with a pipeline system. This Chapter has focussed on the pipeline, but there are assessment methods for other plant. Much of this associated plant is designed to pressure vessel or pipework standards, and the pipeline industry has applied structural integrity methods to these varied structures [Hopkins and Haswell, 1995]. In general, the methods detailed in BS 7910

Feed-in Free-span Feed-in

Axial Force

Buckled Position

Buckle

Initial Position

Overbend

Direction of Least Resistance

Pipeline

Longitudinal compressive force from temperature and pressure effects

Buckled Position

Buckle

Buckled Position

Buckle

Initial Position

Overbend

Initial Position

Overbend

Direction of Least Resistance

Pipeline

Longitudinal compressive force from temperature and pressure effects



[Anon., 1999a], and API 579 [Anon., 2000] can be used to assess defects in these types of structures. 4.5.13 Repair and Rehabilitation There will be cases where a defect assessment concludes that a repair is necessary. There are various repair methods available, but often the choice of the repair method is a secondary consideration [Hopkins and Bruton, 1999a; Hopkins and Bruton, 1999b]:

i. DRIVERS FOR REPAIR - Many repair or rehabilitation projects are not driven by the choice of repair or rehabilitation method. They are driven by economics, urgency or engineering considerations.

ii. COST – The cost of a repair method may be a minor element; for example, the cost of the repair clamp for a damaged offshore pipeline is negligible compared to the cost of the vessel that has to be hired to install the repair. Also, it may be cost-beneficial to replace, rather than rehabilitate, a pipeline - a new, larger, more efficient pipeline can give lower whole life costs than an ageing, small, inefficient line, albeit rehabilitated.

iii. URGENCY - A catastrophic failure (people or environmental) has such a devastating effect on public relations, etc., that the least of a company’s worries is the type of repair/rehabilitation. Cost to public image, lost revenue and clean up costs are key considerations.

iv. ENGINEERING - The ‘engineering’ associated with any work on a pipeline may be the crucial consideration. For example, an offshore line that has lost its coating, and is floating, or an onshore line that is to be lifted out of a trench and recoated live.

v. APPROACH - Pipeline rehabilitation is similar to pipeline construction/overhaul (i.e. retrieval/trenching, section rehabilitation, backfill, inspection, etc.), and requires the same engineering approach.

There are various repair methods available, including: § Coating Repair, § Grinding, § Weld Metal Deposition, § Full Circumferential Sleeves, § Composite Reinforcement Sleeves, § Patch/Part Sleeve Repairs, § Mechanical Clamps, § Pipe Section or Pipeline Replacement, § External Coatings/Internal Liners, § Combined inspections/repairs/rehabilitation.

Information on these repairs can be found in the technical literature, e.g. Hopkins and Bruton, 1999a or Hopkins and Bruton, 1999b, but can also be found in commercial literature on the internet. Repairs to ‘live’ pipelines can present hazards. Therefore, safe working procedures must be in place before approaching or excavating the pipeline. A reduction in



pressure to a safe level before repair, in essential, and additional pressure reductions may be necessary for the selected repair method:

- If the pipeline is severed, or the defect is leaking, the pipeline and surrounding must be made safe. This will mean immediate pressure or flow reductions (if necessary) to prevent further damage or leakage.

- For pipe wall defects, the operating pressure needs to be lowered to 80% of that at which defect was discovered/inflicted, until the defect has been assessed. This pressure reduction will prevent any time dependent effects causing the defect to fail under constant pressure. For structural defects (e.g. buckling), structural assessments will be needed.

- Future pressure reductions may need to be planned depending on the type of repair or rehabilitation method selected. Some composite repairs require pressure reductions of 50%.

- Recoating a pipeline may require removal of the pipe from the trench, and the pressure may be required to be reduced to zero.



5. THE ROLE AND IMPORTANCE OF STRUCTURAL INTEGRITY

ASSESSMENTS OF PIPELINES

Transmission pipelines are essential for the energy business, but the high energy content of these structures means that they are a hazard to surrounding population and environment. A good pipeline design eliminates most structural problems and we know that it is defects occurring in operation that are our major safety hazards (Section 2.6). There has been a number of very high profile, tragic pipeline accidents recently in the USA. In 1999 an onshore gasolene line (see Figure 24, right) failed and product leaked into a river; a subsequent ignition killed three young people who were playing/fishing in the river.

Figure 24. Recent Pipeline Failures in the USA (Images Courtesy of National Transportation Safety Board, USA) Unfortunately, it does not stop there – another major failure of an onshore gas line in New Mexico in 2000 killed 12 campers (see Figure 24, left), and these failures have made the pipeline industry unpopular in the USA. Our pipelines are growing older, and – as engineers – we know we cannot expect the same/more performance without some intervention. Therefore, continued safety will require management systems that reduce in-service defects either by prevention or detection.

Image from National Transportation Safety Board website: www.ntsb.gov

Image taken from National Transportation Safety Board website: www.ntsb.gov



The risk associated with pipelines can be managed by good operatio nal practices. For example, damage to the pipelines can be prevented by good surveillance, and liaison with those who might damage them. Also, corrosion can be prevented by effective corrosion protection systems, and detected by using intelligent pigs, Figure 7. Indeed, structural integrity assessments are one of the methods we use to control pipeline risk, Figure 25, after commissioning.

Figure 25. Managing Pipeline Integrity and Risk Pipeline risk management (see Section 3) starts with good staff and management, dealing in good quality data, usually accessible from a database. This database can be accessed by ‘applications’ such as Geographic Information Systems (GIS), but structural assessments will also need the data. Overall, these applications and assessments will be managed by some type of pipeline integrity management system (PIMS) [Hopkins, 2001b], and the data and analyses can be used to monitor and control the risk posed by the pipeline to surrounding population and society. Figure 25 shows the position of structural assessments in controlling pipeline risk. The control of pipeline risk is a complex and wide ranging exercise: it is not simply a risk analysis software package. Similarly a structural assessment must always be viewed as a part of the risk control of a pipeline. Obviously, a team of engineers is needed to carry out all this work in Figure 25, and the assessment work that follows. Unfortunately some of our pipeline operators have downsized engineering capabilities and have lost their ‘grey hairs’, and may soon have staffing that is under-strength or under-trained [Hopkins, 2001a] or ‘under-experienced’. It is important to protect both ‘corporate memory’, and engineering objectivity [Hopkins, 2000; Hopkins, 2002] during these changing times.

DATABASEStore all pipeline data

APPLICATIONSUse data for GIS,

structural integrity

assessments, risk analysis, etc.

PIMSManage

your pipeline

RISK

PIPELINE DATA

PROCESSESe.g. Inspection

PEOPLE



6. CONCLUDING COMMENTS

This Chapter will end by listing some wider issues and general advice for engineers to consider when conducting a structural assessment of a pipeline:

1. THINK SAFETY – Pipeline codes are safety standards, and an engineer’s prime role in any industry is to ensure safety. Structural assessments are safety assessments. Always ‘think’ safety.

2. CODES ARE ‘DAY 1’ CODES – Pipeline design codes give us minimum structural integrity requirements – they are the starting point for integrity, not the end point. A pipeline designed and built to code will be very safe on its first day in service. However, after day 1 the pipeline’s management dictates its safety, not the design code. Therefore, good managers and good management systems23 are the key to pipeline structural integrity. This means a continual appraisal of technical issues such as smart pigging, risk management programmes, correct routeing etc., to achieve high integrity. But remember - only good management will guarantee integrity

3. ADOPT AN HOLISTIC APPROACH – Pipelines fail for a reason, and most of these reasons can either be avoided or mitigated by good pipeline management. Structural assessments must address all elements of the problem including consequences of failure, and the management systems that need to be in place to implement any recommendation. Therefore, pipeline integrity management must consider all aspects of our pipeline system, as it is an integrated process, where all elements affect safety. Holistic solutions must be applied [Hopkins, 2001a; Hopkins 2001b]. Pipelines are safe if we adopt an holistic approach.

4. DO NOT DO THE ‘MINIMUM’ - Codes. Regulations, etc., are minimum requirements. Aim to do more than your peers. It makes sense… if you do only one thing more than your peers, his/her pipeline has a higher probability of failing first. You will learn from their experience, and act accordingly, so it does not happen to you. They will then copy your practices, but you will then move one step ahead again… and then their pipeline will again fail before yours!

5. DO NOT AUTOMATICALLY SELECT LOWEST BIDS - Do not automatically select the lowest bid in engineering: a trained monkey can select the smallest of three objects. An engineer can select the safest and best.

6. CHANGE IS DIFFICULT – It is difficult to change pipeline engineering practices in companies, because it is difficult to change people [Hopkins, 2000; Hopkins, 2002]. However, as pipelines age we must continually change our approach to pipeline structural integrity.

7. REGULATIONS AND COMPANY PRIORITY - Your company/work will be limited by both company codes/practices and your national/state legislation/regulation. These may not allow fitness for purpose assessments, or the defects you consider acceptable. You must always check local and national limits and legislation, before applying ‘fitness for purpose’: i) can I apply it, and ii) can I use the results?

8. ORIGINS – Always understand the origin or cause of your structural defect before you assess it. A structural assessment may not be enough; for example,

23 Management Systems are covered in Hopkins, 1998 and Hopkins, 2001b.



defects can be due to bad design (e.g. fatigue cracking), and hence the design will also need changing, and some defects can be due to a hostile environment (e.g. external stress corrosion cracking), and in this case the pipeline coating may need replacing.

9. CONSEQUENCES - Always appreciate the consequences of your assessment. If I have made an error, if the defect measurement is wrong, etc., and the pipeline fails, what are the consequences? Consequences will dictate your safety margin on your calculations.

10. NEVER ASSESS A MESS – There will be some situations where an engineer is asked to assess the structural significance of defects, where the defects are extensive, or the structure itself is in poor condition. Sometimes even the best surgeon has to pronounce the patient dead….

11. CALCULATIONS ARE NOT ENGINEERING [Kardon, 2000] - Calculations convey the thought process and design intent, and are an essential part of any engineering appraisal. The quality, etc. of calculations indicates the level of care and diligence; however, calculations substantiate, but do not substitute, for judgement.

12. ENGINEERING RESPONSIBILITY - It is your responsibility to ensure that any fitness for purpose assessment is correct. Try and use the best possible practices available. Check calculations, inputs and assumptions. Use all available data (historical, current and circumstantial) when you assess a defect – inspection data, operations records, maps, etc., may give you more information about the defect, its cause, etc.. Your appreciation of the wider practical issues, and your understanding of all engineering aspects of the problem, are why you have been hired to conduct the assessment, rather than someone who can simply work out an equation.

13. PROFESSIONAL AND PERSONAL INTEGRITY – Engineers performing structural assessments, where decisions can effect company profits, career progression, environment, etc., must put safety first, and remember that engineers have professional (institutional requirements), legal (‘standard of care’) and ethical (moral) criteria to also satisfy [Anon, 2002a; Hopkins 2002] in all aspects of their work.

Acknowledgements The author would like to thank all his colleagues at Penspen Group UK, in particular, Mr Andrew Cosham, who have contributed to this Chapter.



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The Structural Integrity of Oil and Gas Transmission Pipelinesdocshare01.docshare.tips/files/15478/154783658.pdfTHE STRUCTURAL INTEGRITY OF OIL AND GAS TRANSMISSION PIPELINES 1. INTRODUCTION