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New approaches to assuring the integrity of pipelines and risers

Geoff Booth, Henryk Pisarski, Channa Nageswaran and Peter Mudge

TWI Ltd Cambridge, UK

Paper presented at IIW International Conference on Global Trends in Joining, Cutting and Surfacing Technology, Chennai, 17-22 July 2011


Successful commercial exploitation of oil and gas reserves clearly depends on the safe and reliable operation of the required infrastructure. The present paper describes new approaches to assuring the integrity of pipelines and risers, recognising the challenges faced by the operating environment.

Pipelines may experience high strains during a reeling operation or due to landslip or earthquakes whilst in service, but the current methods of assuring the significance of weld flaws are stress based and not intended for application of high strain conditions. Recent work has been concerned with the development of a strain based failure assessment diagram to enable appropriate weld flaw tolerance levels to be set for strains approaching 3%.

Ensuring riser girth welds are able to withstand fatigue loading is vital. TWI’s extensive fatigue database of tests on full-scale joints has provided a unique opportunity to correlate fatigue performance with manufacturing parameters.

Finally, information is required about the condition of the pipeline in service, particularly in respect to corrosion attack. Long range ultrasonic techniques have been used to develop equipment capable of inspecting pipelines whilst requiring minimum removal of lagging material or excavation of buried pipelines.

1. Introduction

Towards the end of the eighteenth century a truly disruptive technology emerged that formed the basis of the industrial revolution. Steam power, generated by the burning of coal to boil water, enabled rapid advances to be made in manufacturing, transport and general engineering. Indeed, coal remained the dominant primary fuel until the middle of the twentieth century, although a second disruptive technology, electricity, had by then supplemented some of the uses of steam. Now oil is the predominant fuel used for transport of people and goods. The generation of electricity is still principally achieved by burning coal, but this is being replaced by technologies based on nuclear fission, gas and renewable sources.

In the next twenty years, the world population is expected to grow by about 1.6 billion people. Energy usage per head is also expected to increase, and a typical forecast is for primary energy consumption to grow by around 1.7% per year. This corresponds to an increase in annual energy demand of about 40% by 2030 [1]. Providing this energy remains a major challenge.

Of the fossil fuels, it is expected that growth in the production and consumption of natural gas will be the most rapid, whereas oil usage will grow more slowly. It is clear, therefore, that the production of oil and gas and the transport of these fuels from their reserves to both mature and emerging markets will be essential for at least the next few decades.

At the time of the industrial revolution, society was relatively tolerant of accidents that caused loss of life and environmental damage. This, quite rightly, is no longer the case and the engineering community has the responsibility for ensuring oil and gas resources are exploited safely and with little or no environmental impact. The engineering technology being employed is continuously being improved, and this paper highlights aspects of welded steel pipelines and risers where advances are being made.

2. Strain based design of pipelines

2.1 Background

Fracture mechanics based assessment procedures are commonly used to define flaw acceptance criteria for girth welds in both onshore and offshore pipelines. These provide an alternative to the so-called ‘workmanship based’ criteria described in pipeline welding codes such as API 1104 and DNV OS F101. Often, use of workmanship based flaw acceptance criteria can require a higher rate of repair and increased costs, mainly arising from the delay to installation, but without any significant benefit to the integrity of the girth welds. Indeed, there have been instances where an improperly executed repair has initiated failure. The fracture mechanics based procedures such as those described in BS 7910 provide a quantitative means for deciding which welding flaws, identified by non-destructive testing, potentially compromise weld integrity with respect to defined failure criteria and require repair and those that do not. Although more effort and expenditure is required to carry out the necessary testing and fracture mechanics analyses, prior to installation, this is far out-weighed by the benefits in reducing repair costs and delays during pipe-lay operations.

In addition, most workmanship based flaw acceptance criteria are based on the assumption that weld inspection is carried out using radiography, which generally only provides quantitative information about flaw length and lateral position across the weld. It does not provide critical information about flaw height which primarily governs the stability of the flaw. Furthermore, unless favourably orientated, tight crack-like flaws can be missed. However, ultrasonic based inspection methods such as AUT are increasingly being used to inspect pipeline girth welds and these provide more information about the flaw, especially flaw height and through wall position; these dimensions have a significantly greater effect on integrity than flaw length alone. Fracture mechanics methods are necessary to interpret such data in order to sensibly sentence welding flaws.

Currently, the fracture mechanics codes that are applied to assessment of pipeline girth welds are essentially stress-based. This means that they are not strictly applicable when the applied longitudinal stress exceeds the actual yield strength of the pipe. For many pipeline installation methods and operating conditions, the applied longitudinal stress is below yield. However, there are a number of installation methods, such as pipe reeling which is used for offshore pipelines, where the welded pipeline is subjected to plastic straining often involving more than one cycle. The strains developed during installation depend on the pipe and reel diameters but are typically in the range of 1-3%. During service, both offshore and onshore pipelines can be subjected to ground movement (eg seismic loading, landslip) or temperature changes (lateral buckling) which can also result in longitudinal plastic straining in addition to internal pressure. Under these extreme loading conditions it is essential that any flaws in the girth weld do not extend sufficiently to cause a leak of pipe contents or initiate an unstable fracture.

Strain-based fracture mechanics assessment procedures are significantly more complex than stress-based methods; they require more input data in terms of material properties and loading conditions. Also, codified strain-based methods are yet to be published. Use of 3-D elastic-plastic finite element analysis is sometimes employed for critical projects, but often the timeframe imposed by pipeline projects prevents extensive use to be made of such techniques. Furthermore, there is always the question of validation and whether flaw sizes derived from such analyses are fully supported by full-scale tests. Since it is usual to analyse a large number of pipe conditions and flaw cases, code based, closed form solutions are desirable in preference to running a large number of finite element analyses. The derivation of such closed form solutions is not straight forward owing to the large number of variables that need to be considered when plasticity takes place. However, progress is being made in this area but a complete solution is not yet available. In the following paragraphs techniques that are currently being used are summarised.

2.2 Assessment of girth welds involving plastic strain during installation

One assessment method which is commonly applied to define flaw acceptance criteria for girth welds employed in reeled pipeline is an extension of the stress-based method described in BS 7910. It was developed by a team [2] involving DNV, TWI and SINTEF and is now codified in Recommended Practice, DNV RP F108. The procedure is also referred to in DNV OS F101 which describes offshore pipeline design in general. The novel features of the method are that the parent pipe, stress-strain curve is used to derive the stress from the maximum reeling strain for each stage in the reeling process (reeling-on, reeling-off and including straightening). Based on numerical analyses and experiment, all positive strain increments are considered to contribute to crack extension, even when the pipe is nominally in compression at that stage during installation. In practice this means the maximum strain achieved during reeling on and the pipe bending over the aligner need to be assessed separately for possible crack extension from a hypothetical flaw. The stress derived in this way is used to determine stress intensity factor a reference stress using the so-called Kastner equation in BS 7910. The Level 3B failure analysis diagram (FAD) described in BS 7910 is used to assess the stability of a hypothetical flaw with respect to fracture and plastic collapse. The procedure permits stable ductile crack extension to take place, provided that the total extension does not exceed 1mm maximum. The procedure accommodates misalignment at the girth weld, which can locally increase strain, using a combination of the elastic stress concentration factor and the Neuber method to transform stress into strain.

The other novel feature concerns fracture mechanics testing. Fracture toughness is determined using surface notched, single edge notch tension (SENT) specimens. These have been found to be more representative of pipe fracture behaviour than the more conventional and standardised, deeply notched, single edge bend specimens (SENB). This is because the crack-tip stress-strain field in the specimen (or crack-tip constraint) replicates better that at a circumferential crack in a pipe than a standard, deeply notched SENB specimen which provides significantly higher crack tip constraint. A consequence is that higher fractured toughness is determined using SENT compared with SENB specimens.

Finally, the procedure requires segment specimens (taken from the girth weld and containing an artificial crack) to be tested in order to validate the assessment procedure. Once validated for one flaw size, a range of flaw sizes can be determined which will not compromise the integrity of the girth weld during installation.

The procedure is intended to be applicable to ductile materials (it is not generally applicable to situations which the SENT specimen fail by cleavage), and to girth welds which have a higher yield strength (ie overmatch) than the parent pipe. The procedure has been used successfully in many offshore pipeline projects including plastic straining during installation and service acceptance criteria.

Although the procedure was validated by full-scale testing of pipe subjected to repeated plastic straining simulating reeling, subsequent numerical analyses studies have shown that it can be potentially non-conservative if all the criteria defined in DNV RP F108 are not adhered to. However work [3] has shown that conservatism is maintained if weld metal yield strength overmatching is achieved and welding residual stresses are not ignored but treated in accordance with BS 7910 recommendations, this is illustrated in Figure 1.

[ Zoom ]
Fig.1 3x50mm surface flaw at weld root fusion boundary. Homogeneous material (parent pipe) was employed in the reeling procedure (DNV-RP-F108) and both homogeneous and weld strength mismatched materials employed in the numerical (FE) analyses [3].
Fig.1 3x50mm surface flaw at weld root fusion boundary. Homogeneous material (parent pipe) was employed in the reeling procedure (DNV-RP-F108) and both homogeneous and weld strength mismatched materials employed in the numerical (FE) analyses [3].

2.3 Strain-based assessment

A number of research workers in UK, Norway [4] and North America have been developing specific strain-based assessment methods for pipeline girths welds. In the case of North America developments, the emphasis has been on predicting strain capacity of the pipeline when the girth weld contains welding flaws. In Europe the emphasis has been more on defining flaw acceptance criteria which are used to define inspection regimes. In North America there are two programmes examining strain-based of pipelines; a PRCI sponsored project [5] and [6] which is on-going and another run by ExxonMobil which has published initial recommendations. Exxon [7] have carried out extensive numerical analysis and full-scale pipe tests to derive parametric equations to define strain-capacity. The procedure is CTOD (crack tip opening displacement) based and three levels of assessment are proposed, with each higher level requiring more sophisticated information about material properties. Their work has shown that strain capacity is dependent on the following factors: crack size (height and length), misalignment at the girth weld, weld metal strength overmatch, pipe wall thickness, strain hardening (defined in terms of yield to tensile ratio), uniform elongation of the pipe material, fracture toughness (in terms of a CTOD resistance curve) and internal pressure.

To date, only Level 1, the most basic level, has been published. Here, strain capacity is defined as a function of crack size, pipe wall thickness and weld strength overmatch (in terms of tensile strength). Fracture toughness is not required since a lower bound resistance curve is assumed which is based on experimental data derived from X65-X80 steels. Interestingly, CTOD fracture toughness is determined using SENT specimens. The comparison between predicted and experimentally measured strain capacity is conservative (for the range of pipeline girth welds tested), as illustrated in Figure 2. As currently formulated, the Exxon-Mobil approach is  limited to certain materials and loading conditions.

[ Zoom ]
Fig. 2 Comparison of full-scale test capacity with predicted strain capacity using Level 1 strain capacity equation
Fig. 2 Comparison of full-scale test capacity with predicted strain capacity using Level 1 strain capacity equation

A more general strain-based assessment framework has been proposed by others [8] and [9]. This is set within the failure analysis diagram approach described in the R6 integrity assessment procedure which is extensively used in the electricity generating industry. Although R6 is stress-based, a new section is being prepared which essentially replaces the stress-based plastic collapse axis (Lr) of the FAD with ratio of the reference strain to the yield of the material (Dr). The Kr axis is relatively unchanged and fracture toughness is defined in terms of J-integral. The procedure has been found to be applicable to thick section components, but can be potentially non-conservative for thin walled component such as pipes where the flaw height is a significant proportion of the wall thickness. This is thought to arise from the assumption that the reference strain is equal to the applied strain. TWI [10] has been developing a strain-based procedure, similar to the one proposed by Budden, but significantly, is developing specific reference strain solutions for flaws in pipeline girth welds. The approach is promising and is able to deal with misalignment, axial straining plus internal pressure. The strength of the approach is that it is set within the flaw assessment framework of BS 7910. The procedure uses the existing elastic solutions for stress intensity factor to generate the Kr axis on the FAD and fracture toughness is defined in terms of J-integral. Furthermore, it is not restricted by material type or loading condition. So within the limits of the reference strain solutions, the approach will be applicable to a wide range of pipeline loading conditions. Validation of these procedures is on-going at TWI through full-scale pipe girth welds subjected to a combination of internal pressure and axial straining.

In summary, the current situation is that a number of strain-based approaches are being developed. A universally accepted approach is not yet here. It is generally agreed that extensive experimental validation is necessary, especially when the methods are applied to large pipeline projects, where a failure or even a leak could have significant consequences to the environment, loss of production and adversely affect the reputation of the owner/operator.

3. Fatigue performance of riser girth welds

A steel catenary riser is an extension of a subsea pipeline that enables the fluid to be transported from the sea bed to a floating production structure. As the riser generally is unsupported it takes a catenary shape due to the action of gravity. Risers are typically around 300mm and upwards in diameter and fabricated from steel complying with the American Petroleum Institute pipeline grades. Steel catenary risers experience fatigue loading due to vortex shedding, platform movement and sea currents. Failure by fatigue of a steel catenary riser therefore would be catastrophic.

Girth welds are the fatigue critical features of risers and validation testing of girth welds fabricated using representative welding procedures is essential to ensure that adequate fatigue strength is achieved. The most appropriate method of validation testing is to excite a full-scale riser in resonance, in a controlled manner, such that the riser vibrates in a circular fashion and the whole circumference of the girth weld experiences an identical fatigue cycle. In its laboratory, Figure 3. TWI has performed several thousand full scale tests over the last decade or so. Analysis of the database [11] has provided a unique opportunity to establish correlations between fatigue performance and manufacturing parameters, including pipe dimensions, welding process and position, joint alignment and surface mismatch (hi-lo).

[ Zoom ]
Fig. 3 TWI designed resonance test machines.
Fig. 3 TWI designed resonance test machines.

Girth welds made from one side, as is the case in risers, are currently considered under the UK fatigue design rules (BS 7608) as Class F2. This classification, however, is based on the assumption that single sided girth welds may have poor root profiles that could give rise to poor fatigue performance. If it can be demonstrated that good control of the root profile can be achieved, then the database of fatigue results indicates that better fatigue performance can be achieved.

[ Zoom ]
Fig. 4 Fatigue test results for single-sided girth weld showing performance is independent of diameter.
Fig. 4 Fatigue test results for single-sided girth weld showing performance is independent of diameter.

As an example of the analysis carried out [11] Figure 4 shows resonance fatigue data for single sided girth welds fabricated from risers of different diameters. It is clear fromFigure 4 that when expressed in terms of local stress range at the weld toe, fatigue life is largely independent of riser diameter. Furthermore, all the results correspond to lines greater than the BS 7608 Class E design life, suggesting that Class E could be considered as an appropriate class for these joints.

After extensive analysis it was concluded [11] that none of the variables analysed reduced the scatter to a level at which specific design curves could universally be recommended, reflecting the fact that many factors influence fatigue strength. The need remains for validation fatigue testing for girth welds made using new welding procedures, but the data as a whole indicate that BS 7608 Class E performance can be achieved.

4. Inspection technology for pipes and pipelines

4.1 Background

Developments in inspection technology for pipes and pipelines have, in recent years, been driven by a number of factors:

  • The growth of arduous applications, for example the use of steel catenary risers for deep water oil and gas production and, more recently, pipes for CO2 capture and storage service,
  • Changes in materials in use, in particular the increase in the use of pipes clad with corrosion resistant alloys,
  • Legislation. In 2002 the US Congress passed the ‘Pipeline Safety and Improvement Act’, which states, among other things, that all gas transmission pipelines located in High Consequence Areas (ie close to populated areas) must have an integrity management program [12]. Many HCAs include cased road and rail crossings, for which assessment of the internal carrier pipe is difficult,
  • Economic factors. As plant and pipeline operators seek to reduce operating costs, there is a need to apply more cost-effective global examination methods for pipes, to enable more of the piping systems to be covered and the areas requiring more detailed action to be identified.

Recent developments in non-destructive testing (NDT) to address these issues are highlighted. The two technologies presented are the improvements to phased array ultrasonic testing (PAUT) for the examination of girth welds in pipes internally clad with corrosion resistant alloy (CRA) and long range ultrasonic testing (LRUT) using low frequency guided waves for the examination of cased crossings and offshore risers.

4.2 Phased array ultrasonic testing for clad pipes

Ultrasonic testing using phased array transducers has become a widely accepted method for the examination of girth welds in carbon steel pipelines after manufacture, replacing radiography as now allowed by ASME Section V. The method is rapid, as the phased array transducers allow a range of beam angles to be used, and the ability of the approach to produce a cross-sectional image of the weld region permits efficient interpretation of the results.

The use of pipes internally clad with a CRA, for use in sour service, in carbon capture projects and to reduce the total thickness of carbon steel substrate required (for cost reasons), presents a number of challenges for PAUT. The CRA layer, typically a few millimetres thick, has different ultrasonic properties from the carbon steel. The ultrasonic velocity is different in the two materials, so that the beam angle changes on entering the CRA and the simple ray-tracing approach for reconstruction of the image of the weld is not sufficient. Errors may be introduced into the positioning of responses from the clad region and, as the condition of the root area is vital to the continuity of corrosion resistant properties in the pipeline, this is a significant issue for determining weld quality. Further, depending on the method of deposition of the clad layer there may be coarse grained, directional solidification structures in the cladding, which lead to ultrasonic beam deviation, attenuation and scattering. In any case, the welds need to be made of a similar corrosion resistant material to avoid dilution in the root area, with consequent loss of corrosion resistance. These materials have a coarse-grained and directional solidification structure, which also leads to the attenuation and scattering effects which limit test sensitivity. These factors may also distort the image produced and limit the sensitivity which can be achieved.

TWI has investigated the factors influencing the performance of PAUT for clad pipe and has developed improved procedures. This has involved a combination of theoretical and experimental studies of the microstructure associated with welds in clad material to determine the effect on the image. The details of the solidification structure obtained from this study have enabled the influence of the microstructure on the ultrasonic beam to be determined. The model allows the distortion of the beam to be calculated. Figure 5 shows the computed distortion of the longitudinal and transverse beams from a 15mm diameter 2MHz transducer, designed to produce 45° beams. The refraction at each boundary between the different microstructural zones produces gross deviations of the beams.

[ Zoom ]
Fig. 5. Distortion of 45 degree longitudinal (green) and transverse (red) ultrasonic beams by microstructural features in a CRA weld. The boundaries of the different microstructural regions are shown.
Fig. 5. Distortion of 45 degree longitudinal (green) and transverse (red) ultrasonic beams by microstructural features in a CRA weld. The boundaries of the different microstructural regions are shown.

Figure 6 shows the effect of the anisotropic FCC microstructure of a weld on the profile of the beam for both longitudinal and transverse waves. It may be seen that the longitudinal waves are affected much less than the transverse.

[ Zoom ]
Fig. 6 Predicted beam shapes for: a) longitudinal;
Fig. 6 Predicted beam shapes for: a) longitudinal;
[ Zoom ]
Fig. 6 Predicted beam shapes for: b) transverse beams for isotropic material (above) and for anisotropic microstructure (below).
Fig. 6 Predicted beam shapes for: b) transverse beams for isotropic material (above) and for anisotropic microstructure (below).

By quantifying the influence of the microstructure, TWI is developing better tailored delay laws to overcome the distortion induced by the cladding CRA pipelines.

4.3 Long range ultrasonic testing for cased crossings and risers

Long range ultrasonic testing is particularly useful for detection of time-dependent degradation, such as corrosion, which may occur at unpredictable locations over a large surface area. The benefits are:

  • Reduction in the costs of gaining access to the pipes for inspection,
  • Avoidance of removal and reinstatement of insulation or coatings (where present), except for the area on which the transducers are mounted,
  • The ability to inspect inaccessible areas, such as at clamps and cased or buried pipes,
  • The whole pipe wall is tested, thereby achieving a 100% examination.
[ Zoom ]
Fig. 7 Long range ultrasonic testing tool mounted at one end of a cased crossing, to provide 100% examination of the crossing length.
Fig. 7 Long range ultrasonic testing tool mounted at one end of a cased crossing, to provide 100% examination of the crossing length.

The use of long range UT is particularly important for examination of cased crossings. The PHMSA requirements in the USA (PHMSA 2010) state that if the pipe cannot be examined using an internal inspection (ILI) tool, a key requirement is for ECDA, ie excavation and direct examination of the pipe. If this cannot be done, a hydrotest is required. Pipeline owners are reluctant to perform hydrotests as they have a large impact on the pipeline operation. As a high proportion of gas pipelines (> 70%) are not suitable for an internal inspection, an alternative to either excavation or hydrotest is required. The PHMSA guidelines permit the use of long range ultrasonic testing as an ‘alternative technology’ for the examination which allows the evaluation of these inaccessible areas. TWI has long been in the forefront of the application of LRUT for this application. Figure 7 shows a guided wave tool mounted on a 24” insulated cased crossing. Of particular concern in this location was ‘weld pack’ corrosion, where there is premature breakdown of the insulation/coating applied over the field joint after welding.

[ Zoom ]
Fig. 8 Preferential corrosion resulting from ‘weld pack’ coating degradation in a 10 inch water injection line.
Fig. 8 Preferential corrosion resulting from 'weld pack' coating degradation in a 10 inch water injection line.

Weld pack corrosion also affects pipelines that are buried in the ground. Figure 8 shows a section of pipe cut from a 10 inch buried water injection line where the coating at the weld had degraded causing preferential corrosion at that location. This was detected by LRUT while the line was buried, 25m away from the test position. Excavation at the place identified by the LRUT revealed the damage caused; It would not have been possible to detect this by other methods.

LRUT is also highly applicable for the examination of risers for oil and gas production. There are two strategies that may be applied; testing from the topside and subsea application. Topside testing may be performed from the coffer- or spider deck levels or the sensors may be deployed using rope access. Figure 9 shows examples of these two approaches.

TWI has been extending the range of capabilities of LRUT, with projects aimed at sub-sea deployment of the tools via the Risertest and SubCTest projects [13]. These programmes were designed to provide instrumentation to enable offshore risers and structural members to be monitored for degradation over time. Figure 9 shows the initial offshore trials for the Risertest system, at DNV’s facility in Bergen, Norway. These demonstrated that it is feasible to use long range systems for underwater monitoring and that applications such as the monitoring of SCRs for fatigue are possible.

[ Zoom ]
Fig. 9 a) Riser testing from the topside, with associated results;
Fig. 9 a) Riser testing from the topside, with associated results;
[ Zoom ]
Fig. 9 b) Rope access deployment of the transducer tool
Fig. 9 b) Rope access deployment of the transducer tool
[ Zoom ]
Fig. 10. Test pipe being raised after the initial, successful sub-sea test of the Risertest underwater LRUT system at DNV, Bergen
Fig. 10. Test pipe being raised after the initial, successful sub-sea test of the Risertest underwater LRUT system at DNV, Bergen

5. Concluding remarks

The development and exploitation of oil and gas reserves in a safe and environmentally satisfactory manner is essential to satisfy the world’s requirements for energy.

There are many aspects to be considered, but in the field of integrity and inspection improved technological capabilities are being developed to ensure pipelines and risers perform as intended for their entire lifetimes. These developments are a mixture of incremental advances and innovative procedures, particularly in inspection techniques. It is envisaged that there will be commercial and economic pressure to maintain and accelerate the pace of technology development.

6. Acknowledgements

The authors wish to thank their colleagues at TWI, whose experiences have been invaluable in preparing this paper.

7. References

  1. BP ‘Statistical Review of World Energy 2010’ Accessed May 2011.
  2. Wastberg S, Pisarski H G and Nyhus B ‘Guidelines for engineering critical assessment for pipeline installation methods introducing cyclic plastic strain’. Proceedings of 23rd International Conference on Offshore Mechanics and Arctic Engineering, Vancouver, Canada, OMAE 2004-51061, 2004.
  3. Pisarski H G and Cheaitani M J ‘Development of girth weld assessment procedures for pipelines subjected to plastic straining’, Int. Journal of Offshore and Polar Engineering. Vol.18, No.3, 183-187, 2004.
  4. Ostby E Fracture control-offshore pipelines. ‘New strain-based fracture mechanics equations including the effects of axial loading, mismatch and misalignment’. 24th Int. Conf. on Offshore Mechanics and Arctic Engineering. ASME OMAE2005-67518, 2005.
  5. Wang Y-Y, Liu M, Stephens M J and Horsley, ‘Recent developments in strain-based design in North America’. Proc. 19th Int. Offshore and Polar Engineering Conference, ISOPE, Osaka, Japan, 2009.
  6. Stephens M et al, ‘Large-scale experimental data for improved strain-based design models’. Proc. 8th Int. Pipeline Conference, Calgary, Alberta, Canada, ASME 2010, IPC2010-31396.
  7. Kibey et al ‘Tensile capacity equations for strain-based design of welded pipes’. Proc. 8th International Pipeline Conference, Calgary, Alberta, Canada, ASME IPC2010-31661.
  8. Budden P J ‘Failure assessment diagram methods for strain-based fracture’. Engineering Fracture Mechanics, 73, 537-552, 2006.
  9. Budden P J and Smith C S. ‘Numerical validation of a strain-based failure assessment diagram approach to fracture’. Proc. ASME 2009 Pressure Vessels and Piping Conference, Prague, Czech Republic, 2009.
  10. Cheaitani M J and He We, ‘Strain-based driving force estimates for circumferential cracks in pipe girth welds’. TWI Research Report, to be published.
  11. Maddox S J and Johnston C ‘Factors affecting the fatigue strength of girth welds: an evaluation of TWI’s resonance fatigue rest database’. Offshore Mechanics and Arctic Engineering, OMAE 2011 - 49192, Rotterdam, 2011.
  12. PHMSA 2010. ‘Guidelines for Integrity Assessment of Cased Pipe for Gas Transmission Pipelines in HCAs’, Revision 0, March 2010. US Pipeline and Hazardous Materials Safety Administration, Washington DC, 2010.
  13. The Risertest and SubCTest projects were partly funded by the European Commission through the Framework 6 and Framework 7 programmes respectively.