For a safe operation of gas pipelines, the prevention of propagating brittle facture is one of the most important requirements. To evaluate the transition temperature of a propagating fracture, the Drop Weight Tear (DWT) Test was developed in the 60s. Fracture surfaces of DWT specimens have been shown to correspond well to the fracture surface of a pipe exposed to a propagating fracture at a certain temperature. Historically, there have always been observations of the fracture initiating in a ductile manner in the DWT test. Nevertheless, the most widely used test standard rules out such behavior, known as inverse or abnormal fracture. As an option to prevent ductile initiation, an alternative notch is proposed. While this might have served in the earlier days, high toughness steels of today are known to provide a high resistance against crack initiation and are therefore prone to inverse fracture, even when making use of the suggested alternative notch. Other, non-standard notch types have been investigated and discussed in literature, amongst these the static pre-crack and brittle weld notch. Observations of the DWT test, especially comparing material showing non-inverse and inverse behaviour, show delayed crack initiation resulting in large deflection when the specimens are inverse. This high degree of pre-deformation of the material will have an adverse influence on the material performance by the time the crack propagates into it. This implies that the appearance of inverse fracture is a test effect in the laboratory test, and not an inherent material property, leading to the question if such DWT test results still correspond to the behavior of pipes. If the correlation is shown to be valid, the brittle initiation requirement as such becomes questionable. This study summarises investigations of different notch types in DWT tests. West Jefferson tests that have been conducted to verify the correlation to shear area fraction in DWT tests. The investigation revealed that ductile initiation could not be reliably suppressed. While neither Chevron nor static pre-crack specimen lead to any reduction of the occurrence of inverse fracture, test series of brittle weld specimens did have a higher number of valid specimens. Interestingly, the results of valid, non-inverse specimens and invalid, inverse specimens showed no shift in transitional behavior. Correspondingly, both valid and invalid specimens showed a good representation of the pipe behaviour in the upper transition region.

Welds that are made onto an operating pipeline cool at an accelerated rate as a result of the flowing pipeline contents cooling the weld region. The accelerated cooling rates increase the probability of forming a crack-susceptible microstructure in the heat-affected zone (HAZ) of in-service welds. The increased risk of forming such microstructures makes in-service welds more susceptible to hydrogen cracking compared to welds that do not experience accelerated cooling. It is understood within the pipeline industry that hydrogen cracking is a time-dependent failure mechanism. Due to the time-dependent nature and susceptibility of in-service welds to hydrogen cracking, it is common to delay the final inspection of in-service welds. The intent of the delayed inspection is to allow hydrogen cracks, if they were going to occur, to form so that the inspection method could detect them and the cracks could repaired. Many industry codes provide a single inspection delay time. By providing a single inspection delay time it is implied that the inspection delay time should be applied for all situations independent of the welding conditions or any other preventative measures the company may employee. There are many aspects that should be addressed when determining what should be considered an appropriate inspection delay time and these aspects can vary the inspection delay time considerably. Such factors include the cooling characteristics of the operating pipeline, the welding procedure that is being followed, the chemical composition of the material being welded and if any preventative measures such as post-weld heating are applied. The objective of this work was to provide an engineering justification for realistic minimum inspection delay times for different in-service welding scenarios. The minimum inspection delay time that was determined was based on modelling results from a previously developed two-dimensional hydrogen diffusion model that predicts the time to peak hydrogen concentration at any location within a weld HAZ. The time to peak hydrogen concentration was considered equal to the minimum inspection delay time since the model uses the assumption that if a weld was to crack the cracking would occur prior to or at the time of peak hydrogen concentration. Several factors were varied during the computer model runs to determine the effect they had on the time to peak hydrogen concentration. These factors included different welding procedures, different material thicknesses and different post-weld heating temperatures. The post-weld heating temperatures were varied between 40 F (4 C) and 300 F (149 C). The results of the analysis did provide justification for reducing the inspection delay time to 30 minutes or less depending on the post-weld heating temperature and pipeline wall thickness. This reduction in inspection delay time has the potential to significantly increase productivity and reduce associated costs without increasing the associated risk to pipeline integrity or public safety.

Carbon steel piping can be exposed to environments that contain various chemical and organic elements that induce corrosion and cracking events. This can lead to the loss of fluid into surrounding sensitive and remote environments. To minimize this inherent risk, various coating technologies have been utilized over the years in industry. These coatings typically suffer from complex application methods, high application cost, and vulnerabilities to environmental effects such as mechanical damage and cathodic disbondment. To overcome these challenges, a novel epoxy based composite coating that utilizes the properties of various nano-particulates such as graphene nanoplatelets (GnP), multi-walled carbon nanotubes (MWCNTs), chitosan, and hBN (Hexagonal boron nitride) is developed. These nanoparticles create a nano-scale “brick and mortar” type effect that is analogous to various natural structures such as the abalone shell (nacre). These nano-structures also enhance coating performance by increasing mechanical strength and anti-bacterial properties while simultaneously decreasing gas permeability. This performance enhancement serves to reduce overall corrosion-induced disbondment area. The dispersion of nanoparticles is verified using various microscopy methods such as scanning election microscopy and an optical 3D profilometer. To confirm the role of nanoparticles in the epoxy composite, the samples undergo rigorous testing to determine both mechanical properties as well as the feasibility of coating application, in particular, for use on girth welds. Using a dynamic mechanical analysis (DMA), the material strength of each combination of nanocomposites is tested and used to determine the glass transition temperature. The testing also includes abrasion, and both long-term mechanical and thermal behaviors of the coating. To test the feasibility of the coating, cathodic protection tests in an accelerated corrosive environment, and gas permeability tests are carried out. The results show that the composite coating made from these nanomaterials had a decrease in cathodic disbondment area and gas permeability and an increase the glass transition temperature and scratch resistance. Therefore, the nanocomposite coatings are found to be a significant improvement over standard epoxy-based coating.

Various numerical approaches have been developed in the last years aimed to simulate the ductile fracture propagation in pipelines transporting CO 2 or natural gas. However, a reliable quantification of the influence of material plasticity on the fracture resistance is still missing. Therefore, more accurate description of the material plasticity on the ductile fracture propagation is required based on a suitable numerical methodology. In this study, different plasticity and fracture models are compared regarding the ductile fracture propagation in X100 pipeline steel with the objective to quantify the influence of plasticity parameters on the fracture resistance. The plastic behavior of the investigated material is considered by the quadratic yield surface in conjunction with a non-associated quadratic plastic flow potential. The strain hardening can be appropriately described by the mixed Swift-Voce law. The simulations of ductile fracture are conducted by an uncoupled, modified Mohr-Coulomb (MMC) and the micromechanically based Gurson-Tvergaard-Needleman (GTN) models. In contract to the original GTN model, the MMC model is capable of describing ductile failure over wide range of stress states. Thus, ductile fracture resistance can be estimated for various load and fracture scenarios. Both models are used for the simulation of fracture propagation in DWTT and 3D pressurized pipe sections. The results from the present work can serve as a basis for establishing the correlation between plasticity parameters and ductile fracture propagation.

Hydrogen-assisted cracking in welds, which is also referred to as ‘hydrogen cracking’ or ‘delayed cracking,’ often requires time to occur. The reason for this is that time is required for the hydrogen to diffuse to areas with crack susceptible microstructures. Prior to inspection for hydrogen cracking, general good practice indicates that a sufficient delay time should be allowed to elapse — to allow any cracks that are going to form to do so and for the cracks to grow to a detectable size. What is a ‘sufficient’ delay time? Why does a delay time tend to be required for some applications (e.g., installation of a hot tap branch connection) and not for others (e.g., construction of an offshore pipeline from a lay barge)? This paper will address these and other related questions and present the results of recent experimental work on this subject. When determining appropriate delay times prior to inspection, it is important to consider not only the time-dependent nature of hydrogen cracking, but also the expected susceptibility of the weld to cracking. From a time-dependent nature standpoint, longer delay times decrease the chance that cracking can occur after inspection has been completed. From a probability standpoint, if measures can be taken to assure that the probability of cracking is extremely low, then determining an appropriate delay time becomes a moot point. In other words, if the weld is never going to crack, it does not matter when you inspect it. The probability of cracking can be minimized by using more conservative welding procedures (i.e., by designing out the risk of hydrogen cracking during procedure qualification). For example, if hydrogen levels are closely controlled by using low-hydrogen electrodes or a low-hydrogen welding process, or if the hydrogen in a weld made using cellulosic-coated electrodes is allowed to diffuse away after welding by careful application of preheating and slow cooling, or the use of post-weld preheat maintenance (i.e., post-heating), the probability of cracking is significantly reduced, and immediate inspection may be justified. This alternative approach to time delay prior to inspection for hydrogen cracking, which can allow for immediate inspection, will be presented.

Transport of anthropogenic carbon dioxide in pipelines from capture site to storage site forms an important link in the overall Carbon Capture, Transport and Storage (CCTS) scheme. The thermodynamic properties of CO 2 are different from those of other gases such as natural gas that are transported in pipelines. Recent full-scale burst tests from the projects SARCO2 and COOLTRANS indicated significant variations in correction factors necessary to predict the arrest of a running ductile fracture. In addition, CO 2 can be a potential hazard to human and animal life and the environment. While consequence distances of natural gas pipelines are well established and documented in standards, this is not the case with CO 2 . The research focused CO2SAFE-ARREST joint industry project (JIP) aims to (1) investigate the fracture propagation and arrest characteristics of anthropogenic CO 2 carrying high strength steel pipelines, and (2) to investigate the dispersion of CO 2 following its release into the atmosphere. The participants are DNV GL (Norway) and Energy Pipelines CRC (Australia). The project is funded by the Norwegian CLIMIT and the Commonwealth Government of Australia. The joint investigation commenced in 2016 and will continue to 2019. The experimental part of the project involves two full-scale fracture propagation tests using X65, 610mm (24“) pipe and two 6″ shock tube tests, with all tests filled with a dense phase CO 2 /N 2 mixture. The full-scale tests were made up of 8 pipe lengths each, with nominal wall thicknesses of 13.5 mm and 14.5mm. The dispersion of the carbon dioxide from the full-scale test sections was measured through an array of sensors downwind of the test location. The tests were conducted in 2017/2018 at Spadeadam, UK. Following a short review of the background and outcomes of previous CO 2 full-scale burst tests, this paper provides insight on the aims of the overall experimental program along with summary results from the first full-scale fracture propagation test, carried out in September 2017. Two companion papers provide further details on the first test. The first companion paper [IPC2018-78525] discusses the selection of pipe material properties for the test and the detailed fracture propagation test results. The second companion paper [IPC2018-78530] provides information on the dispersion of the CO 2 from the first full-scale test, along with numerical modelling of the dispersion.

Economic and environmental incentives encourage operators to maintain pipeline operation during repair and maintenance procedures including hot-tap branch fitting installation onto pipelines. Welding onto a liquid-filled pipeline induces accelerated cooling of the weld and heat affected zone (HAZ), increasing the propensity for cracking. In-service welding codes and due diligence requires that several key factors be considered during the design of an in-service welding procedure specification for its intended purpose. The level of restraint (LoR) imposed by the geometry, material, or dimensional differences of the branch compared to the run pipe has also been shown to be a significant contributor to cracking. Finite element analysis (FEA) was utilized to investigate the geometric effects of an in-service weld procedure to approximate the LoR of hot-tap branch installation. The LoR was quantified and compared by simulating multi-pass weld sequences on two configurations: a branch-on-pipe (BoP) configuration of various dimensions and a configuration using perpendicular plates (PP) that has been used as an alternative to the branch-on-pipe configuration. The highest LoR, as measured by transverse tensile stress at the fillet weld toe, was the branch-on-pipe configuration with the largest branch wall thickness, the smallest branch diameter, the largest run pipe diameter, and the largest run pipe wall thickness. FEA modeling revealed that the PP configuration has lower LoR, thus it is not recommended to use for simulating in-service branch weld procedures.

Environmentally assisted cracking (EAC), more specifically, stress corrosion cracking (SCC) has been a pipeline integrity concern since the 1960s. However, there were not many options for pipeline operators to effectively manage this threat on gas and liquid pipelines. SCC and other crack type defects have become a threat which is more widely understood and can be appropriately managed through in-line inspection (ILI). The two primary technologies for crack detection, developed in the 1990s and early 2000s respectively, are ultrasonic (UT) and electromagnetic acoustic transducer (EMAT). Although EMAT was originally developed to find SCC on gas pipelines, it has proven equally valuable for crack inspections on liquid pipelines. A case study with a gas and natural gas liquid (NGL) operator, ONEOK Inc. (ONEOK) demonstrates the effectiveness of using EMAT ILI to evaluate the potential threat of crack and crack-like defects on a 48 mile (77.2 km), liquid butane pipeline. By utilizing both 10-inch (254 mm) multiple datasets (MDS) technology and 10-inch (254 mm) EMAT ILI tools, ONEOK proved the effectiveness of ILI to identify critical and sub-critical crack and crack-like defects on their pipeline. This paper will present on the findings from the two technologies and illustrate the approaches taken by the operator to mitigate crack type defects on this pipeline.

Ultrasonic crack inspection services have become a standard solution for pipeline integrity programs, especially for liquid pipelines. ILI tools provide reliable and accurate data for assessment of axial and circumferential cracking defects to derive educated decisions on the integrity and maintenance of the asset. This technology inspects common media such as crude and light oils, water, diesel, benzene, or similar. Running tools in mediums used for commercial operations does not affect the throughput of the line. Crude and light oils, water, diesel, benzene etc. have relatively constant ultrasonic characteristics with varying pressures and temperatures and are very suitable for ultrasonic inspections, therefore called common media within the context of this paper. If the medium in the pipeline does not fall within the common media, the situation changes. These media are called challenges media. Especially for liquefied natural gases (LNG) or liquefied petroleum gases (LPG) where temperature and pressure have a significant impact on the ultrasonic characteristics of speed of sound, density, and attenuation. LNGs and LPGs typically contain high amounts of propane, butane, and some other higher order alkanes. Due to the high variability of these components to external boundary conditions, inline inspections in these type of pipelines are usually performed by replacing the medium with a more feasible one, e.g. water or diesel. This causes significant impact to productivity and throughput and increases costs and efforts. The authors will present the work performed to overcome and solve this workaround and run an ultrasonic crack inspection tool in LNG. This paper highlights the challenging aspects considered to successfully perform inline inspections in LNGs. We will present a standardized and systematic approach to overcome limitations of the technology in such media. Starting with the challenges and ideas for enhancement of the service, the paper will discuss the design of the experiment, the experiment itself, the results, and present the conclusions that resulted in the tool development and the analysis procedure. Finally, the authors will present the application of the enhanced service in a customer pipeline, including ILI preparation, execution, analysis, and in-the-ditch verifications. The structured and systematic approach allows the inspection company to perform successful and reliable crack detection inspections in LNG lines. This includes axial and circumferential cracking threats.

In the majority of liquid pipelines, the pump station discharge pressure ranges are much greater than the pressure ranges experienced at the suction end of the downstream pump station. Consequently, the cyclic pressure induced fatigue damage accumulation rate is greater at the discharge end than at the suction end of a given pipeline segment. In completing an integrity assessment of a fatigue susceptible feature, assuming that the pump station discharge cyclic pressure profile applies to all features in the line segment is conservative. This conservative assumption can lead to un-necessary repairs, unintentional damage from over-prescribed maintenance, or inefficient decisions regarding maintenance action prioritization. The following paper presents the results of a Canadian Energy Pipeline Association (CEPA) initiative to develop a simple approach to define the cyclic pressure history at any point in a liquid pipeline segment based on the bounding discharge and suction pump station Supervisory Control and Data Acquisition (SCADA) pressure time history data. The approach was developed based on collected operating pipeline SCADA pressure time history data for line segments with intermediate measurement points which could be used to validate the developed model. The pressure time histories for all the locations were analyzed using a Rainflow cycle counting technique to develop pressure range spectra (i.e. histograms of pressure range events) and the cyclic pressure severity of each of the time histories was characterized by the Spectrum Severity Indicator (SSI). The SSI represents the number of annual 90MPa hoop stress cycles required to accumulate the same fatigue damage as the actual pressure spectrums. The technique presented in this paper illustrates how to infer the pressure range spectra or SSI at intermediate locations. The technique is shown to be a significant improvement (i.e. higher location specific accuracy) than either applying the discharge pressure spectrum or applying a linear interpolation between discharge and suction conditions in fatigue life assessments. The liquid pipeline cyclic pressure characterization technique presented in this paper will permit integrity assessment or severity ranking of features along a pipeline to be based on an accurate local pressure profile rather than an upper bound. This understanding will help to improve the accuracy of defect loading, one of the three main pillars in integrity assessment (i.e., loading, geometry, materials) for defects susceptible to cyclic loading (e.g., cracking, mechanical damage).

The integrity of aging assets like gas pipelines are managed by a variety of inspection and validation methods. In the particular case of gas pipelines and their susceptibility to cracking, an ultrasonic inspection methodology has been introduced over the last decade, which is based on an electromagnetic acoustic transducer (EMAT). Meanwhile, a high resolution implementation of the technology has been utilized on in-line inspection (ILI) tools from 10″ to 48″ in diameter. Williams Gas Pipelines have utilized this inspection technology successfully on several pipelines, therefore an overview will be given about this experience. Secondly a case study will be presented, in which a post hydrostatic test ILI service was used to gain additional relevant safety and integrity information from the ILI inspection and to better understand the actual capabilities of a hydrostatic test. The approach taken is in accordance with API 1163 and in consideration of API 1176. As part of this approach the performance of the ILI tool was confirmed based on a set of full scale tests conducted at the PRCI ILI test facility. The results were used to increase the statistical confidence in the capabilities of the technology.

Pipelines passing through hilly-terrain potentially have numerous rock dents. Some of them require further in-ditch investigation. However, in-ditch experience revealed elastic rebounding and re-rounding due to internal pressure that could cause cracking on dent outside surface when rock is removed even after following the commonly used pressure reduction by industry. Such OD-surface cracking in rock dent could pose safety issues to excavation crew and immediate integrity threat due to gas release. A preliminary research was performed to determine the required safe dig pressure level for rock dent excavation and address if there is a gap between the common industry practice for pressure reduction. This research could assist pipeline operators with setting a safe dig pressure level for rock dent excavation. The research consists of four components. First, detail review of rock dents cracking experience during excavation has been performed and identified relevant parameters that contributed to OD-cracking. Then, performed several rock dent case studies with different dent depths, indenter sizes, internal pressures and developed criterion for OD cracking using Finite Element Analysis. Thirdly, a decision chart was developed for safe rock dent excavation and presented. Finally, full-scale denting tests with internal pressure was conducted to corroborate the safe dig pressure criterion and compared against FEA results. In this paper, all above components are presented with summary of findings and recommendations for future research.

The instrumented indentation technique (IIT) is a novel method for evaluating mechanical properties such as tensile properties, toughness and residual stress by analyzing the indentation load-depth curve measured during indentation. It can be applied directly on small-scale and localized sections in industrial structures and structural components since specimen preparation is very easy and the experimental procedure is nondestructive. We introduce the principles for measuring mechanical properties with IIT: tensile properties by using a representative stress and strain approach, residual stress by analyzing the stress-free and stressed-state indentation curves, and fracture toughness of metals based on a ductile or brittle model according to the fracture behavior of the material. The experimental results from IIT were verified by comparing results from conventional methods such as uniaxial tensile testing for tensile properties, mechanical saw-cutting and hole-drilling methods for residual stress, and CTOD test for fracture toughness.

In-line inspection (ILI) systems continue to improve in the detection and characterization of cracks in pipelines, and are relied on substantially by pipeline operators to support Integrity Management Programs for continual assessment of conditions on operating pipelines that are susceptible to cracking as an integrity threat. Recent experience for some forms of cracking have shown that integration of data from multiple ILI systems can improve detection and characterization (depth sizing, crack orientation, and crack feature profile) performance. This paper will describe the approach taken by a liquids pipeline operator to integrate data from multiple ILI systems, namely Ultrasonic axial (UC) and circumferential (UCc) crack detection and Magnetic Flux Leakage (MFL) technologies, to improve detection and characterization of cracks and crack fields on a 42 miles long, 12-inch OD liquid pipeline with a 38-year operating history. ILI data has indicated a large number of crack features, including 4000+ crack features reported by UC, 1000+ crack features by UCc, and 2500+ metal loss features reported by MFL. Initial excavations demonstrated a unique pattern of blended circumferential-, oblique- and axial-orientated cracks along the entire extent of the 42-mile pipeline, requiring advanced methods of data integration and analysis. Applying individual technologies and their analysis approaches showed limitations in performance for identification and characterization of these blended features. The outcome of the study was the development of a feature classification approach to classify the cracks with respect to their orientation, and rank them based on the depth sizing by using multiple datasets. Several sections of the 42-mile pipeline were cut-out and subjected to detailed examination using multiple non-destructive examination (NDE) methods and destructive testing to confirm the crack depths and profiles. These data were used as the basis for confirming the ILI tool performance and providing confirmation on the improvements made to crack detection and sizing through the data integration process.

Improvements in in-line inspection (ILI) technology have led to an increase in the probability of detection and ability to characterize geometric features such as wrinkles, the assessment of which was introduced into CSA Z662, “Oil & Gas Pipeline Systems”, in the 2015 version. The CSA wrinkle acceptance limits are based predominantly on fatigue assessment criteria; part of the assessment procedure is confirmation that wrinkles are free from associated cracking. In practice, this often restricts the assessment to wrinkles that have already been investigated in-field and where the absence of cracking has been confirmed by non-destructive examination (NDE). This paper describes the assessment of a series of wrinkles that exceeded the CSA height criteria, reported by ILI within field bends in an insulated liquid pipeline. Strain-based assessment, supported by in-field investigations, was used to investigate the likelihood of associated cracking. Utilizing the high resolution caliper ILI tool data, three-dimensional profiles of the wrinkles were generated. Previous work that compared “tool-measured” with “field-measured” profiles identified that caliper tool measurements can underestimate the true depth and profile of wrinkles, this effect is more pronounced for particularly sharp wrinkles. The wrinkle profiles were therefore adjusted based on the historical field-tool correlation. Strain profiles were then calculated using the guidance within ASME B31.8 Appendix R. It was identified that the majority of the wrinkles exceeded the 6% strain limit commonly applied to dents. One field bend containing multiple wrinkles was subsequently excavated in order to gather detailed profile information and to inspect for cracking. Upon excavation, the wrinkles were not visually apparent, but their presence was confirmed following removal of the insulating coating. Profile information was subsequently recorded using laser scanning technology. In addition, NDE confirmed the absence of cracking, despite the fact that the majority of wrinkles were associated with strain levels that exceeded the CSA limiting value, 6%. The laser scan data were then compared with the adjusted “tool-measured” profiles. It was observed that the adjusted measurements based on the ILI tool data were conservative, and in some cases excessively so. The caliper measurements were optimized by identifying a factor that could be systematically applied to the “tool-measured” wrinkle profiles, which provided consistency with the profiles measured by the laser scan, thereby improving the accuracy of the dimensions and strain estimation of the remaining (non-excavated) wrinkles. Finally, a S-N based fatigue assessment was performed using operational cyclic pressure data and estimates of the stress concentration factors associated with the wrinkles. The calculated fatigue lives exceeded the expected operational life of the pipeline.

As part of a major pipeline expansion, two deactivated 24″ diameter pipeline segments with a combined length of 192 kilometres will be assessed and upgraded to operational status. These line segments include a 42 kilometre section within the North Thompson valley of British Columbia, and a 150 kilometre segment through the Rocky Mountains of Alberta and British Columbia. Reactivating the lines to operational condition is a multi-staged process, which will be partially guided by a National Energy Board Condition requiring the issuance of a certificate from an independent certifying body that the system is fit for service and meets all applicable requirements of CSA Z662, Oil and Gas Pipeline Systems. This certificate must be unconditional and remain in effect for a period of 5 years. The need for unconditional certification of fitness for service drives the need for a comprehensive assessment of the pipeline condition using a broad slate of inline inspection technologies. Tools were selected for the assessment of deformations, metal loss, manufacturing anomalies and cracking. The lines were maintained with a low pressure nitrogen blanket for between 9 and 13 years prior to the start of the reactivation work and it was therefore not possible to run the tools using service fluid. Several options were considered for propelling the inline inspection tools including nitrogen, compressed air and water slugs in compressed nitrogen or air. Each method has advantages and disadvantages and modelling was carried out to simulate the transport of the tools through each segment. The modelling needed to account for pipe elevation changes, wall thickness changes, valves, tool drive friction, acceptable tool velocity, and the pressure of the drive medium in the pipeline. The modelling focused on the following constraints: i. Ensure ILI data quality ii. Ensure safety considering the potential presence of defects in the lines iii. Minimize risk iv. Minimize overall cost These constraints guided a flow modelling/feasibility study for inspecting the lines with the 4 tools. The objective of the study was to determine the optimum configuration of propellant, inspection tools, and line segmentation while ensuring a safe, economical operation resulting in optimal data collection. The paper will provide some background on the line segments being reactivated and pressure limitations that were adopted for ILI runs. The majority of the content will focus on the determination of tool drive technique, how simulation occurred and how the actual execution of the runs compared. Details regarding the challenges and troubleshooting required to successfully complete the integrity surveys will also be discussed in depth.

The fracture process of energy pipelines can be described in terms of fracture initiation, stable fracture propagation and final fracture or fracture arrest. Each of these stages, and the final fracture mode (leak or rupture), are directly impacted by the tendency towards brittle or ductile behavior that line pipe steels have the capacity to exhibit. Vintage and modern low carbon steels, such as those used to manufacture energy pipelines, exhibit a temperature-dependent transition from ductile-to-brittle behavior that affects the fracture behavior. There are numerous definitions of fracture toughness in common usage, depending on the stage of the fracture process and the behavior or fracture mode being evaluated. The most commonly used definitions in engineering fracture analysis of pipelines with cracks or long-seam weld defects are related to fracture initiation, stable propagation or final fracture. When choosing fracture toughness test data for use in engineering Fracture Mechanics-based assessments of energy pipelines, it is important to identify the stage of the fracture process and the expected fracture behavior in order to appropriately select test data that represent equivalent conditions. A mismatch between the physical fracture event being modeled and the chosen experimental fracture toughness data can result in unreliable predictions or overly conservative results. This paper presents a description of the physical fracture process, behavior and failure modes that pipelines commonly exhibit as they relate to fracture toughness testing, and their implications when evaluating cracks and cracks-like features in pipelines. Because pipeline operators, and practitioners of engineering Fracture Mechanics analyses, are often faced with the challenge of only having Charpy fracture toughness available, this paper also presents a review of the various correlations of Charpy toughness data to fracture toughness data expressed in terms of K IC or J IC . Considerations with the selection of an appropriate correlation for determining the failure pressure of pipelines in the presence of cracks and long-seam weld anomalies will be discussed.

Integrity reliability science plays a major role in the integrity management of transmission piping, which is piping that traverses long distances across the continent, at high pressures, and can experience high pressure cycling. This science can be applied to non-transmission piping such as lateral piping, which traverses between a transmission line and a facility, or between two facilities, at lower pressures and with lower pressure cycling. Laterals are susceptible to the same threats as transmission lines (internal corrosion, external corrosion, cracking, geotechnical hazards, etc.). However, due to their operation, laterals are only highly susceptible to internal and external corrosion. While site specific conditions may result in a high susceptibility of a geotechnical hazard, this threat is outside of the scope of this paper. On transmission piping, corrosion is generally managed with In-Line Inspection (ILI), Non-Destructive Examination (NDE), and corresponding repairs (e.g. sleeving) to assess and mitigate. With laterals, there can be limited ILI and NDE data. As such, the data used in the quantitative reliability framework for these threats is not available and this creates a gap in the process. This paper addresses this gap through the application of semi-quantitative reliability analysis for internal and external corrosion on laterals along with a risk-based integrity decision making framework. The proposed approach is designed to enable pipeline and facility operators to make effective decisions around lateral integrity programs given the available data, and to better understand the limitations of integrity decision making. Moreover, the paper expands the discussion around the difference between risk-informed and risk-based integrity decision making in order to provide a guideline for optimal and safe integrity management programs considering different criteria. Case studies that include limited or no ILI or NDE information are used to demonstrate the application of semi-quantitative and quantitative reliability assessment of laterals along with the exploration of challenges in calibrating the two assessment methods to provide an example of how reliability science can be applied to laterals and how this can be used in effective decision making given such limitations.

Since the late 1980’s Ultrasonic tools have been used for the detection and sizing of crack like indications. ILI service providers developed inspection technologies for liquid and gas lines that are widely used nowadays. In comparison to axial cracking, circumferential cracking is not a prevalent risk to most pipelines and therefore is not as well understood. Nevertheless, pipeline Operators observe from time to time circumferentially oriented defects, often in combination with circumferential welds or local stress/strain accumulations. These are often caused by pipeline movement, which may especially occur in mountain areas. With the introduction of Ultrasonic circumferential crack inspection tools in the late 2000’s the knowledge has steadily increased over time. Extensive data collected from in-ditch NDE validations has provided NDT Global with an increased knowledge of the morphology of single cracking and stress corrosion cracking defects both in the axial and circumferential orientations. Field verifications have shown that not all features have the same morphology. Some of the challenges with circumferential cracking are for features that fall outside of the industry standard specifications. These types of features can exhibit characteristics such as being sloped, skewed or tilted. In 2016 NDT Global was approached by Plains Midstream Canada to complete inspections utilizing the 10″ Ultrasonic Circumferential crack inspection technology. The pipeline system spans 188km within Canada and consists of 2 segments. The pipeline traverses several elevation changes and crosses several creeks and roads. Circumferential cracking was identified during dig campaigns performed for other threats, therefore the need to inspect each pipeline segment with the Ultrasonic circumferential technology was identified. Plains Midstream Canada and NDT Global formed a close collaboration to assess the severity of circumferential crack features in this line. This paper will discuss integrity aspects from an Operator and Vendor perspective. Challenges identified due to the morphology of the circumferential crack like indications and derived analysis rules and interpretation methodologies to optimize characterization and sizing are presented. Finally, potential opportunities to maintain the integrity of similar assets by applying some of the findings and enhance the management and decision making process are suggested.

A pipeline operator set out to assess the risk of circumferential stress corrosion cracking and to develop a proactive management program, which included an in-line inspection and repair program. The first step was to screen the total pipeline inventory based on pipe properties and environmental factors to develop a susceptibility assessment. When a pipeline was found to be susceptible, an inspection plan was developed which often included ultrasonic circumferential crack detection in-line inspection and geotechnical analysis of slopes. Next, a methodology was developed to prioritize the anomalies for investigation based on the likelihood of failure using the provided in-line inspection sizing data, crack severity analysis, and correlation to potential causes of axial or bending stress, combined with a consequence assessment. Excavation programs were then developed to target the anomalies that posed the greatest threat to the pipeline system or environment. This paper summarizes the experiences to date from the operator’s circumferential stress corrosion cracking program and describes how the pipeline properties, geotechnical program, and/or in-line inspection programs were combined to determine the susceptibility of each pipeline and develop excavation programs. In-line inspection reported crack types and sizes compared to field inspection data will be summarized, as well as how the population and severity of circumferential stress corrosion cracking found compares to the susceptible slopes found in the geotechnical program completed. Finally, how the circumferential SCC time-average growth rate distributions were calculated and were used to set future geohazard inspections, in-line inspections, or repair dates will be discussed.