The fracture mechanics based engineering critical assessment (ECA) method has been accepted as a fitness for service (FFS) approach to defining weld flaw acceptance criteria for pipeline girth welds. Mechanized gas metal arc welding (GMAW) processes are commonly used in cross country pipeline girth weld welding because of the advantages in good quality and high productivity. With the technical advancements of non-destructive testing (NDT) techniques, automated ultrasonic testing (AUT) has greatly improved flaw characterization, sizing and probability of detection during weld inspection. Alternative weld flaw acceptance criteria are permitted in pipeline construction code to assess the acceptability of mechanized girth welds using an ECA. The use of an ECA based weld flaw acceptance criteria can significantly reduce the construction cost. Mechanized girth weld acceptance criteria have been progressively transitioned from workmanship standards into using fitness for service based ECAs. To successfully deliver an ECA on a pipeline project, a multidisciplinary approach must be taken during the welding design and construction stages. Welding, NDT, mechanical testing and field control are all integral elements of pipeline construction. All these four elements have to be fully integrated in order to implement the ECA and achieve the overall integrity of a pipeline. The purpose of this paper is to discuss the importance of the integration of these four elements necessary for proper implementation of the ECA weld flaw acceptance criteria.

Pipe ovalization, a deviation from the circular nominal cross section, is a common occurrence during the manufacturing of pipe sections. Additionally, ovalization can also occur in pipelines during and after installation and construction. CSA Z662-11 [1] provides an acceptance criteria of 5% for pipeline ovality in bends, however there is a variation in acceptance criteria for pipe ovality occurring in straight pipe sections. An industry review of pipeline design, operation, and maintenance codes was conducted to determine the industry acceptance for ovality limits in straight pipe sections. Based upon this industry review, the ovality limits were evaluated against constructability limits, limitations for passage of in-line-inspection (ILI) tools, as well as evaluating the stress in an ovalized pipe section compared to the maximum allowable stress of the pipe. During this review, it was revealed that allowable stress was the limiting factor for pipeline ovality, compared to constructability and ILI tool passage, thus this paper primarily discusses limitations related to remaining strength for ovalized pipe sections. The API 579 Fitness-for-Service assessment was used to evaluate varying levels of ovality to determine acceptability criteria for ovalization in straight pipe. The criteria was first established using a level 2 Fitness-for-Service assessment, which was then evaluated with a level 3 assessment using finite element analysis. This criterion was evaluated using multiple pipeline diameters and wall thickness in order to determine scalability.

Ground movements, such as landslides and subsidence/settlement, can pose serious threats to pipeline integrity. The consequence of these incidents can be severe. In the absence of systematic integrity management, preventing and predicting incidents related to ground movements can be difficult. A ground movement management program can reduce the potential of those incidents. Some basic concepts and terms relevant to the management of ground movement hazards are introduced first. A ground movement management program may involve a long segment of a pipeline that may have a threat of failure in unknown locations. Identifying such locations and understanding the potential magnitude of the ground movement is often the starting point of a management program. In other cases, management activities may start after an event is known to have occurred. A sample response process is shown to illustrate key considerations and decision points after the evidence of an event is discovered. Such a process can involve fitness-for-service (FFS) assessment when appropriate information is available. The framework and key elements of FFS assessment are explained, including safety factors on strain capacity. The use of FFS assessment is illustrated through the assessment of tensile failure mode. Assessment models are introduced, including key factors affecting the outcome of an assessment. The unique features of girth welds in vintage pipelines are highlighted because the management of such pipelines is a high priority in North America and perhaps in other parts of the worlds. Common practice and appropriate considerations in a pipeline replacement program in areas of potential ground movement are highlighted. It is advisable to replace pipes with pipes of similar strength and stiffness so the strains can be distributed as broadly as possible. The chemical composition of pipe steels and the mechanical properties of the pipes should be such that the possibility of HAZ softening and weld strength undermatching is minimized. In addition, the benefits and cost of using the workmanship flaw acceptance criteria of API 1104 or equivalent standards in making repair and cutout decisions of vintage pipelines should be evaluated against the possible use of FFS assessment procedures. FFS assessment provides a quantifiable performance target which is not available through the workmanship criteria. However, necessary inputs to perform FFS assessment may not be readily available. Ongoing work intended to address some of the gaps is briefly described.

With the increased number of In-Line Inspections (ILI) on pipelines, it is important to evaluate ILI tool performance to support making rational integrity decisions. API 1163 “In-Line inspection systems qualification” outlines an ILI data set validation process which is mainly based on comparing ILI data with field measurements. The concept of comparing ILI results with previous ILI data is briefly mentioned in API 1163 Level 1 validation and discussed in detail in CEPA metal Loss ILI tool validation guidance document. However, a different approach from API 1163 is recommended in the CEPA document. Although the methodologies of validating an ILI performance are available, other than determining whether an inspection data set is acceptable, the role of ILI validation in integrity management decision making is not well defined in these documents. Enbridge has reviewed API 1163 and CEPA methodologies and developed a process to validate metal loss ILI results. This process uses API 1163 as tool performance acceptance criteria while CEPA method is used to provide additional information such as depth over-call or under-call. The process captures the main concepts of both API 1163 and CEPA methodologies. It adds a new dimension to the validation procedure by evaluating different corrosion morphologies, depth ranges, and proximity to long seam and girth weld. The process also checks ILI results against previous ILI data sets and combines the results of several inspections. The validation results of one inspection provide information on whether the inspection data set is acceptable based on the ILI specification. This information is useful for excavation selection. Tool performance review based on several inspection data sets identifies the strength and weakness of an inspection tool; this information will be used to ensure the tool selection is appropriate for the expected feature types on the pipeline. Applications of the validation process are provided to demonstrate how the process can aid in making integrity decisions and managing metal loss threats.

For cross country pipeline welding in Canada, welding procedures shall be qualified in accordance with the requirements of CSA Z662 Oil and Gas Pipeline Systems . For pipeline facility and fabrication welding on systems designed in accordance with CSA Z662 or ASME B31.4, welding procedures qualified in accordance with the requirements of ASME Boiler & Pressure Vessel Code Section IX are permitted and generally preferred. Welding procedures qualified in accordance with ASME IX provide advantages for pipeline facility and fabrication applications as a result of the flexibility achieved through the larger essential variable ranges. The resulting welding procedures have broader coverage on material thickness, diameter, joint configuration and welding positions. Similarly, ASME IX is more flexible on welder performance qualification requirements and accordingly a welder will have wider range of performance qualifications. When applied correctly, the use of ASME IX welding procedures often means significantly fewer welding procedures and welder performance qualifications are required for a given scope of work. Even though ASME IX qualified welding procedures have been widely used in pipeline facility and fabrication welding, it is not well understood on how to qualify the welding procedures in accordance with ASME IX and meet the additional requirements of the governing code or standard such as CSA Z662 in Canada. One significant consideration is that ASME IX refers to the construction code for the applicability of notch toughness requirements for welding procedure qualification, yet CSA Z662 and ASME B31.4 are both silent on notch toughness requirements for welding procedure qualification. This paper explains one preferred method to establish and develop an effective ASME IX welding procedure qualification program for pipeline facility and fabrication welding while ensuring suitability for use and appropriate notch toughness requirements. The paper discusses topics such as base material selection, welding process, welding consumable consideration and weld test acceptance criteria.

Pipeline defects such as cracks, dents and corrosion often require permanent pressure retaining repairs. Full encirclement metallic repair sleeves with fillet-welded end connections to the pipeline are often used for this purpose. In-service failures have occurred at pressure retaining sleeves as a result of defects associated with the sleeve welds, such as hydrogen-induced cracks, undercut at the fillet welds and inadequate weld size. At present, accurate quantitative fitness for service assessments for circumferential defects in a sleeve fillet welds are difficult to carry out due to a lack of detailed stress intensity factor (SIF) solutions for finite length cracks. The primary objective of the project presented in this paper [1] was to develop flaw acceptance criteria which will fill gaps in the available Engineering Critical Assessment procedures for metallic sleeve repairs on all grades of pipelines. SIF solutions for finite length sleeve-end fillet weld toe and root cracks were generated and used to develop parametric equations suitable for carrying out defect assessments. These equations can be used in the assessment of fatigue crack growth and/or fracture using failure assessment diagram (FAD) methods at sleeve end fillets alongside the results developed for other structural geometries in national standards. The equations were developed based on detailed finite element (FE) analyses of a wide range of sleeve end fillet weld cracking scenarios to estimate the SIFs at both the deepest point and the surface breaking point along the crack front.

For more than two decades, CSA Z662 Annex K has provided a method for developing alternative acceptance criteria for weld flaws in mechanized welded pipelines. Increasingly, over the years, fracture mechanics practitioners have found the method overly conservative and restrictive with respect to brittle fracture criteria when compared to other accepted fracture mechanics-based engineering critical assessment ECA codes and methods. These limitations rendered the CSA Annex K method difficult to implement on pipelines constructed with materials not possessing optimal toughness and in cases requiring consideration of fracture toughness at temperatures lower than the typical minimum design metal temperature (MDMT) of −5°C. This paper presents experiences implementing CSA Z662-15 Annex K Option 2 methodology on a 610 mm diameter liquids pipeline and compares and contrasts the utility and benefits of the code revision. This pipeline required consideration for installation during winter months, necessitating installation temperatures as low as −30°C. In addition to evaluation of actual ECA results, analytical evaluations of the Option 2 methodology were also conducted considering parameters outside those used on the project. The new Annex K Option 2 method was found to be of considerable benefit in preparation of a practical ECA. Since fracture toughness testing was conducted at the anticipated lowest installation temperature, the flaw criteria were, as expected, principally controlled by elastic/plastic crack growth consideration. The failure assessment diagram implemented into the CSA Z662-15 Annex K Option 2 provided tolerance for both longer and deeper flaws than that afforded by Option 1 (which resorts to the former 2011 Annex K method). Furthermore, the reduced restriction to the surface interaction ligament (p distance) offers additional advantages including increased flexibility in weld profile design and weld pass sequencing. Fracture toughness (CTOD) testing of TMP pipeline steels used in the project at −30°C often produced transitional fracture toughness results. It was found that the particular project materials were quite sensitive to the level of test specimen pre-compression (an acceptable plastic straining method to reduce residual stress gradients) applied to the CTOD specimens to enhance fatigue crack-front straightness. It was found that optimizing the level of pre-compression (to achieve acceptable pre-crack straightness while minimizing plastic pre-strain) achieved a balance between fully satisfying testing requirements, providing a conservative assessment of CTOD, and facilitating a functional Annex K ECA.

As an alternative to radiography, a field-proven mechanized ultrasonic inspection system is discussed. Called Rotoscan , this system has been developed for inspection of girth welds during construction of long-distance pipelines, both on- and offshore. It is characterized by high inspection speed and instant recording of results. Unlike prevailing radiography, it provides immediate feedback to the welders. Recent technical improvements in flaw sizing and recording have allowed the application of rejection/acceptance criteria for weld defects based on fracture mechanics principles. The development and actual use of such modern acceptance criteria, particularly in Canada, supported the introduction of mechanised ultrasonic inspection. World wide applications proved that, contrary to expectations, ultrasonic inspection does not lead to higher weld repair rates than radiography does. Between early 1989 and now, over 5.000 km of pipeline (300.000 welds) were inspected with Rotoscan and its reliability proven. The introduction of colour enhanced transit distance “C-scan mapping”, producing a coherent picture based on the signal’s transit distance, enabled the system to cope with most existing ultrasonic procedures and acceptance criteria, because of its capability to detect and quantify volumetric defects. Moreover, the integrated simultaneous Time Of Flight Diffraction (TOFD) function enables through-thickness sizing of defect. The present system is capable of achieving a high Probability Of Detection (POD) together with a low False Call Rate (FCR) . In the meantime, Rotoscan has been qualified in various countries, for different customers and for a variety of weld processes, pipe diameters and wall thicknesses. Because of its features, the now mature system has demonstrated its capabilities also for use on lay barges as an alternative to high-speed radiography.

Grade 550 (X80) pipeline steels are now the basis of a standard platform for the design and construction of large-diameter pipeline projects at NOVA Gas Transmission (NGT). Their introduction in 1995 and further application in 1997 have provided material savings, provided greater gas flow capacity and fuel gas savings and, once again, shown NGT to be an industry leader in successfully developing and applying new technology in response to business needs. The paper will outline the development of a Canadian capability to supply these steels, discuss design aspects including fracture initiation and arrest and weld/pipe strength mismatch, the overall cost efficient approach to material and weld requirements, and pipeline construction using mechanized welding with mechanized ultrasonic inspection and alternative weld acceptance standards. Future directions at NGT with respect to higher strength steels will also be described.

In recent years significant changes have taken place in the Mexican gas industry. Activities related to gas transmission, distribution and storage are no longer the exclusive privilege of PEMEX Gas & Petroquimica Basica (PGPB), a traditionally state-owned company. The first priority of PGPB is to ensure a safe, efficient and reliable pipeline network. Several projects have been established to guarantee a smooth transition from a monopoly to open market competition. Among these projects is a pipeline risk assessment and management programme (RAMP), to provide feedback on all safety related conditions of PGPB’s pipeline facilities. This project is planned to have a permanent application within PGPB, although a risk acceptance criteria based upon experience gained through the different project stages has yet to be established. This paper provides an approach adopted to assessing risk in more than 13,000 kilometres of pipeline, regardless of the transported fluid. Risk management is considered to be the step following the risk factors evaluation. However, PGPB is aware of the importance of calculating realistic indexes, so that management policies may be defined according to a well known risk magnitude.

An integrated approach for the development of welding, inspection, and alternative weld flaw acceptance criteria, as used for girth welds during pipeline construction is presented. Welding is typically the pace limiting step during pipeline construction and is critical element of pipeline integrity. As such it is vital that it be completed efficiently and with high quality. Each of these three elements is vitally important to welding productivity and quality. At the core of the approach is the coordination of the three elements such that they are developed in concert. By this coordinated effort, all design options are considered leading to optimization of the final outcome. The approach is described by providing an example alternative weld flaw acceptance criteria, and giving the logic pertaining to choices of welding setup, AUT setup, the standard used for design and construction, and the impact of choices within these three elements on the final outcome. The paper illustrates the importance of a unified approach on weld productivity and quality.

For typical cross-country pipelines not expected to experience ground movement hazards, the longitudinal stresses experienced during lifting and lowering-in are typically the highest that they experience in their entire service life. Vertical bending stresses are produced by the curvature created from the upward lifting forces of the sidebooms and the downward force of the pipe weight. Horizontal bending stresses are produced due to the lateral movement of the pipe when the pipe string is moved from its support position on the side of trench to the center of the trench. It is critical to limit the stresses during lifting and lowering-in so that potential damage to the pipeline is avoided. For pipelines constructed using an engineering critical assessment (ECA) based flaw acceptance criteria, stresses must be controlled below the limit established during the development of the flaw acceptance criteria. However, there is little in the way of formal guidance in current codes and standards for controlling stresses during the lifting and lowering-in process. This paper is part of a long-term effort being sponsored primarily by Pipeline Research Council International (PRCI) to develop general construction guidelines that can be used to manage lifting and lowering-in stresses during pipeline construction. In this paper, the stresses during lifting and lowering-in on normally flat terrain were studied. The component of stress due to bending in the horizontal plane was determined through an analytical method. The component of stress due to the bending in the vertical plane was studied by finite element analysis (FEA). The FEA determined the stresses under various profiles. Recommended lifting profiles in the format of lifting height ranges were developed. The combined stress was then determined from the two components. In addition, FEA was used to simulate the lifting and lowering-in process of a pipe string including a field side bend. The results show that the side bend produces a very slight increase in the stress level. More work is being performed to investigate various other scenarios of field and pipe string conditions.

The benefits of mechanized welding for pipeline construction are well known, as reflected by the high industrial acceptance and usage of its variations. However, the engineering and qualification costs associated with the preparation of alternative acceptance criteria for typical pulsed and short-circuit MIG (GMAW-P and GMAW-S) girth welds can make the implementation of mechanization too costly and/or time consuming for small projects. A multi-wire welding technology, employing a high-deposition consumable that possesses excellent positional capability, along with paired digitally controlled asynchronous inverter power sources, is presented. Trials were performed on CSA Z245.1 914 mm (NPS 36) OD × 20.4 mm WT Grade 483 heavy wall high strength line pipe. One variant used an 8-head internal welding machine for the root pass, and a conventional single torch short-circuit GMAW hot pass in a compound narrow-groove configuration. A second variant utilized an externally applied controlled short-circuit GMAW-S process for the root pass in a factory-style pipe bevel configuration. Both variants employed fill and cap passes using tandem pulsed gas-shielded flux-cored arc welding (T-FCAW-G/P), using rutile consumables, with the “bug and band” MOW II mechanized welding system. Basic mechanical testing was performed on the first weld variant, along with single-edge notched bend (SENB) crack tip opening displacement (CTOD) tests, and results are presented. A productivity comparison is then shown, using weld data from the second weld variant against alternative processes, showing considerably lower fill and cap pass arc time using the T-FCAW-G/P process. Given the process’s low tendency for the formation of planar discontinuities, the process is appealing for the use of “workmanship” acceptance criteria. With further procedure development and fine-tuning of the process, tandem flux-cored arc welding may prove viable, particularly for “short” pipelines, where the costs of comprehensive engineering critical assessment/fitness-for-purpose weld procedure qualification and associated engineering work aren’t justified; as a higher productivity alternative to single wire flux-cored arc welding for mechanized tie-in welding; as a much higher productivity alternative to SMAW for tie-ins; or with a narrow groove design, mainline applications for longer-distance projects.

The most critical component of external corrosion prevention on pipeline is the protective coating system. The coating selection process can be extremely challenging due to the sheer number of manufacturers and products/options that are offered — often with limited performance data available. Relying solely on manufacturer’s recommendations or information can be problematic when the anticipated service environment has not been adequately characterized, application parameters not completely understood, and/or when there is a misunderstanding of the product’s capabilities. Although there are many test methods for evaluation of pipe coatings, there are no commonly accepted test protocols or acceptance criteria for selecting coatings. Moreover, laboratory based testing is often complicated, expensive, and rarely provides an accurate simulation of field conditions. Although in-house subject matter experts (SMEs) and/or independent coating specialists provide some confidence in coating selection, the diversity of background and experience between these experts frequently creates inconsistency in coating evaluations and can produce divergent or conflicting recommendations. In this paper, an innovative approach is proposed to address these coating selection process challenges. The proposed approach incorporates a systematic analysis of critical material attributes within an expert environment, and applies established decision making techniques to the evaluation. Priorities are developed by structuring a hierarchy of criteria and eliciting technical judgment of company’s SMEs, stakeholders, and unbiased industry specialists. The Deterministic Analytic Hierarchy Process (d-AHP) is applied using pairwise comparisons for prioritizing coating products/options and achieving an optimal selection. The experts’ opinions can then be updated by technical lab-based results for a smaller selection of top ranked products. Laboratory tests would be expected to be completed annually based on smart selection of certain products and to ensure year-over-year consistency. This paper also presents a probabilistic approach that improves d-AHP in order to capture uncertainties in experts’ opinions and/or lab results through probabilistic AHP (p-AHP). Although this approach is not widely used within the pipeline industry, there is a potential opportunity to improve conventional approaches for selecting and approving coatings for pipelines based on a systematic/quantitative approach.

Demand for natural gas using LNG and pipelines to supply the world’s gas markets is increasing. Under the large demand for high-strength linepipe, crack arrestability is one of the most important properties. DWTT (Drop Weight Tear Test) is the major test method for evaluating crack arrestability. Generally, a DWTT shear area of 85% or higher is required as the acceptance criteria, such as those of the API (American Petroleum Institute). In high-toughness linepipe steels, the abnormal fracture frequently occurs in DWTT. Abnormal fracture is defined as a cleavage fracture on the hammer side. However, the mechanism for occurrence of the abnormal fracture during DWTT has not been fully clarified. This paper describes the effect of plastic deformation on occurrence of abnormal fracture during DWTT using various steels with different microstructures. Each DWTT was carried out at the same test temperature using 20 mm plates with approximately the same tensile strength. This paper describes the deformation during DWTT, which consists of deformation caused by hammer impact, bending compression, and bending tension. The deformation due to the impact of the hammer during DWTT on a 20 mm plate was limited, and the location affected by the hammer impact did not correspond to that where abnormal fracture occurred. Moreover, the equivalent plastic strain from bending deformation was dominant as compared with that of hammer impact regardless of the microstructure. This suggests that abnormal fracture occurred by exceeding the critical equivalent plastic strain due to the bending deformation.

There are a number of methods that are commonly used for the assessment of a girth weld containing a ‘fabrication’ defect. These range from the more generic workmanship limits through to more complex pipeline specific Engineering Critical Assessment (ECA) methodologies. The workmanship limits stipulated in pipeline design codes can be very conservative, resulting in un-necessary and costly repairs. The ECA approach is being increasingly used to derive girth weld defect acceptance limits specific to a pipeline. These limits have been derived using either semi-analytical methods or from the results of large-scale tests conducted on pipeline girth welds. However, at present there is no one standardized method. The guidance produced by the European Pipeline Research Group (EPRG) is an example of an established methodology based on the results of large-scale tests, while commonly used pipeline specific semi-analytical assessment methods include API 1104 and CSA Z662. Other commonly used analytical methods, which are more generic in application, include BS 7910 and API 579-1/ASME FFS-1. Application of these methods to girth welds in grade X100 pipelines has not yet been validated. The US Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA) commissioned Electricore, Inc and GL Noble Denton to investigate the applicability of these ‘commonly used’ girth weld assessment procedures to grade X100 pipelines. To facilitate this project, BP provided 10 girth welds from a full-scale operational trial of two grade X100 48in diameter pipeline test sections, following completion of the trial at GL Noble Denton’s Spadeadam test facility, Cumbria, UK. The girth welds were selected to enable the effects of material variability between abutting pipes, different heats and different manufacturers (pipe was sourced from two world class pipe mills, with the plate supply for one mill coming from two sources) to be investigated. A substantial test program has been undertaken to fully characterize the mechanical properties of each girth weld, comprising curved wide plate (CWP), tensile, Charpy impact and fracture mechanics tests. The results from the CWP tests have been analyzed using the procedures given in API 1104 (Option 2), EPRG, CSA Z662, BS 7910 and API 579-1/ASME FFS-1. This paper presents an overview of the tests undertaken and a comparison of the actual test results with the predictions from the assessment methods.

Welding onto an in-service pipeline is frequently required to facilitate a repair (Figure 1) or to install a branch connection using the “hot tapping” technique (Figure 2). Welds made in-service cool at an accelerated rate as the result of the ability of the flowing contents to remove heat from the pipe wall. These welds, therefore, are likely to have hard heat-affected zones (HAZs) and a subsequently increased susceptibility to hydrogen-assisted cracking. During the evaluation of procedure qualification welds, HAZ hardness is often used as an indicator of the susceptibility to cracking. A widely used value below which it is generally agreed that hydrogen cracking is not expected to occur is 350 HV. Both the US standard API 1104 Appendix B [1] and the Canadian standard CSA Z662 [2] indicate that procedures for in-service welding that produce HAZ hardness greater than 350 HV should be evaluated with regard to the risk of hydrogen cracking. A previous paper on this topic [3] is referenced in CSA Z662 as guidance for performing this evaluation. The present paper describes the further development of HAZ hardness acceptance criteria that can be used to evaluate welds during the qualification of procedures for welding onto in-service pipelines. [4] This further development involved taking the effect of material thickness (restraint level) into account and further validation.

Long-term large deformation geohazards can impose excessive deformation on a buried pipeline. The ground displacement field may initiate pipeline deformation mechanisms that exceed design acceptance criteria with respect to serviceability requirements or ultimate limit states. Conventional engineering practice to define the peak moment or compressive strain limits for buried pipelines has been based on the pipeline mechanical response for in-air conditions. This methodology may be conservative as it ignores the soil effect that imposes geotechnical loads and restraint on buried pipelines. The importance of pipeline/soil interaction and load transfer mechanisms that may affect local buckling of buried pipelines is not well understood. The authors previously developed a new criterion for local buckling strain of buried pipelines in stiff clay through response surface methodology (RSM) [1, 2]. In this paper the new criterion was compared with a number of available in-air based criteria to study the effect of soil restraint on local buckling response of buried pipelines. This criterion predicted larger critical strain than selected in-air based criteria which shows the significant influence of soil presence. The supportive soil effect is discussed. The soil restraining effect increases the pipeline bending resistance, when the pipeline is subjected to large displacement-controlled ground deformation. A correlation between Palmer’s et al. (1990) conclusion [3] and current study’s results has been made. The critical strain increases as the ratio between axial thrust and pipeline bending stiffness decreases.

This paper examines the inherent conservatisms of alternative girth weld defect acceptance criteria from the 2007 API 1104 Appendix A, CSA Z662 Appendix K, and the proposed EPRG Tier 2 criteria. The API and CSA codes have the same empirical limit-load criteria, where it has previously been shown that the conservatism on the failure stress is ∼30 to 50 percent compared to pipe test data prior to applying any safety factors. In terms of flaw length, it was found that the API/CSA limit-load equation might allow a flaw of 5% of the pipe circumference, where the properly validated limit-load equation would allow a flaw of 75% of the circumference, i.e., a safety factor of 30 percent on load corresponded to a safety factor of 15 on flaw length for that example case. Similarly there are conservatisms in a proposed EPRG Tier 2 girth weld defect acceptance criterion. This proposed criterion was directly based on curved-wide-plate data to assure that toughness was sufficient to meet limit-load conditions for a curved-wide plate. However, the curved-wide plates are really an intermediate-scale test, and still require proper scaling to pipes of different diameters. The proposed Tier 2 EPRG allowable flaw length is 7T from a large database of curved-wide-plate tests with the a/t value of less than 0.5 (or a < 3mm), and the failure stress being equal to the yield strength of the base metal (also requires the weld metal overmatch the base metal strength, and the Charpy energy at the defect location have a minimum > 30 J and average > 40 J). However, the widths of those curved-wide-plate tests are typically a factor 5 to 12 times less than typical large-diameter pipes. The proper limit-load/fracture mechanics scaling solution would have the flaw length proportioned to the plate width, not the specimen thickness. Additionally, the proper limit-load solution for a pipe in bending gives a much larger tolerable flaw size at the yield stress loading than a plate or pipe under pure tension. Example calculations showed that the EPRG Tier 2 approach is conservative on the flaw lengths by approximately 9 for pure axial tension loading, and between 34 to 79 for a pipe under bending. Suggestions are presented for an improved procedure that accounts for proper limit-load solutions for pipe tests, effects of pipe diameter, effects of internal pressure, and also a much simpler approach to incorporate the material toughness than the 2007 API 1104 Appendix A Option 2 FAD-curve approach. The fracture analyses could evoke SENB, SENT testing, or have relatively simple Charpy test data to assess the transition temperatures to ensure ductile initiation will occur.

It is common practice in the construction of buried pipelines that pipe sections are welded together at surface level and then lowered into a trench. The stresses induced to the pipe during lowering operation are seldom evaluated or considered in the pipeline design. Scarce industry guidelines and procedures are empirical. Simplistic (while not always conservative) calculations typically used to prevent yielding lead to restrictive spacing between lift points. This paper shows that the use of finite element analyses to realistically simulate the pipe lowering operations can significantly increase the distance between side booms (and hence the productivity) while increasing safety. Case study analyses were performed using data from a real pipeline under construction, showing that limiting the pipe span length is not sufficient to prevent yielding, while by adequately studying the lowering procedure, significantly larger spacing between lift points was achieved. The analyses were performed using a commercial software package widely used in offshore pipeline analyses. The effect in terms of induced stresses of additional issues such as route curves, which are difficult to evaluate in simple calculations, was also discussed. Further advantage can be taken from being aware of the actual stresses imposed to the pipe during its construction, for example by using weld defect acceptance criteria based on fracture mechanics rather than workmanship.