The failure of a corroded pipe is generally controlled by the depth and the longitudinal extent of the metal loss area subjected to hoop stress. However, the failure of metal loss due to its circumferential extent under longitudinal stress is possible if significant longitudinal stress exists in the pipe or the metal loss has considerable circumferential extent and depth. If such circumstances exist, it is prudent to conduct a complementary analysis of pipe integrity to assess the potential for circumferential as well longitudinal failure. Most existing approaches for assessing circumferential metal loss, such as Miller’s equations, were derived by assuming the metal loss to be centered at the extreme stress position around the pipe circumference, i.e., the center of the metal loss is centered at the location of the maximum bending stress in the pipe. The assessment may be over-conservative if the metal loss area deviates from the extreme position related to the bending plane. Described in this paper is a new approach to assess the potential for circumferential failure of metal loss centered at an arbitrary angle from the location of maximum bending stress. The approach results in the same failure stress as existing models when the metal loss is centered at the location of maximum bending stress. The failure stress increases when the metal loss deviates from the location of maximum bending stress and reaches the maximum value when the metal loss is centered at the neutral axis. The equations of the model developed in this paper can be easily implemented into a spreadsheet tool for routine integrity assessment. Other considerations related to the assessment of circumferential metal loss are also discussed, including non-uniform corrosion, negligible corrosion, and the interaction of multiple corrosion areas in the same pipe cross section. The model developed in this paper can also be used to determine the cutoff line for plastic collapse in a failure assessment diagram (FAD) based approach for assessing circumferential cracks, such as API 1104 Appendix A and API 579.

Natural gas exploitation has been increasing progressively and the pipeline community are facing more challenging demands to ensure safe and reliable operations. In that direction, gas fields in very harsh environments are demanding material and welding procedure selections to comply with a combination of important requirements such as toughness at low temperature, sour environment, very low hardness, manual ultrasonic inspection (for UOE longitudinal weld soundness assurance) and others. Looking forwarding big challenges, Tenaris Confab has been successfully working to continue improving the know how regarding plate to pipe mechanical properties behavior, through steel selection using TMCP plates, welding consumables definition and process control to assure material performance. Considering this scenario, the main challenge is to comply with a combination of toughness and hardness requirements, assuring the material soundness through manual ultrasonic testing after 48h. These combination lead to a careful selection of welding consumable to add the right content of alloy element at the welding pool aiming a specific weld metal chemical composition after dilution. The alloy element selection has to be considered due to the aimed final microstructure at the weld metal, i.e. increases acicular ferrite, in order to achieve the toughness, hardness and manual ultrasonic performance for delayed hydrogen cracking (DHC); it is important to avoid grain boundary ferrite (GBF) nucleation. High wall thickness and high heat input increases residual stress after pipe welding, high residual stress combined to poor microstructure and hydrogen, is a perfect scenario for DHC. To avoid hydrogen cracks, a robust pipe forming process and welding concept is needed to give enough energy to diffuse hydrogen out from weld metal. Quality controls were applied to strict hydrogen content such as welding consumable specifications, evaluating the correlation curve between flux moisture and diffusible hydrogen, flux temperature control and others. As a result of those actions, good mechanical properties were achieved and overcoming the hydrogen cracking performance during automatic and manual ultrasonic testing confirm a robust pipe forming and welding procedure for demanding projects.

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.

Advances in micro-electronics and machine learning open the door to a new method of in-line pipe inspection: small free-floating smart sensors moving in the flow, capturing critical data and enabling operators to optimize pipeline performance, detect anomalies, and flag changes in pipeline condition. The free-floating nature of these smart sensors allows for full length pipeline inspection without interrupting the operation. This makes frequent inspection possible turning it into a cost-efficient data driven solution. The alternative requires significant capital to modify the pipeline system to accommodate traditional ILI. Furthermore, traditional ILI methods are a one off costly and labor extensive measurement executed once every 5 to 10 years, where these free-floating sensors allow for high frequency, low cost measurements. Frequent inspection allows for early detection of changes in the pipeline condition such as deposit formation and metal loss as well as timely detection and localization of leaks or similar hazardous conditions. The free-floating nature, combined with the capability to detect pipeline elements such as flanges and welds, permits accurate localization without the need for external markers. An alternative to the free-floating deployment, the sensor device can also be attached to an off-the-shelf cleaning pig. This solution is especially suited for gas lines and allows for screening of the pipeline condition while cleaning the pipeline with limited extra effort from the operator. The paper will demonstrate the outcome of over ten validation projects that have been conducted during the course of 2017 using an implementation of this technology in a golf ball-sized (1.5 inch diameter), robust and chemically inert integrated sensor system called Piper™. The Piper™ is equipped with a comprehensive set of sensors, consisting of a 3-axial accelerometer, gyroscope and magnetometer, a combined pressure and temperature sensor, and an advanced system for acoustic leak detection. Topics that will be addressed include the advantage of using a free-floating integrated device, the capability of reconstructing positioning, the ability to locate and quantify leaks, and the ability to locate pipeline elements such as welds and flanges, and changes in wall thickness. In the Piper™ pig combination, the detectability of bends including the angle and radius of curvature will also be demonstrated.

When faced with an opportunity to install a branch connection using the “hot tapping” technique, pipeline operating companies have a wide variety of choices when it comes to branch connection design and installation practices (e.g., welding procedure options) depending on the application. The objective of a recently-completed joint industry project (JIP) was to develop industry best practices for hot tap branch connections, including a compendium of properly qualified procedures, guidance pertaining to specification of branch connection design for specific applications, and guidance pertaining to related areas of concern for which there was not widespread agreement. The core group of welding procedures that was developed and qualified for branch groove welds and sleeve fillet welds all involve the use of shielded metal arc welding (SMAW) and conventional low-hydrogen electrodes. There are applications for which other welding processes and consumables have advantages, so procedures for a broader range of applications were also developed and qualified. All of the procedures were qualified in accordance with the requirements of a range of relevant industry codes, including the Twenty-first Edition of API Standard 1104. The various options for branch connection design include integrally-reinforced fittings (e.g., Weldolets ® ), fabricated branch connections, and full-encirclement pressurized tees (e.g., Stopple ® fittings). Some designs are better suited to some applications than to others. The guidance for specifying branch connection designs focused on geometric parameters, such as branch diameter, header diameter, and branch-to-header diameter ratio. Several antiquated branch connection designs that should no longer be used were also identified. The related areas of concern for which guidance was developed included the need for sleeve end fillet welds, burnthrough prediction for in-service welding on thin-wall pipelines, pressure limits/pressure reduction requirements, flow rate limits, heat-affected zone (HAZ) hardness limits, welder qualification requirements, branch connection location and fit-up, pipeline support requirements, branch connection welding sequence, preheating for in-service welds, fillet weld size requirements, extent of welding required for integrally-reinforced fittings, inspection/non-destructive testing (NDT) requirements, delay time prior to inspection for hydrogen cracking, pressure testing prior to tapping, and grouting of larger diameter, larger diameter-ratio branch connections. This guidance, along with the branch connection design guidance, was used to develop a generic company specification for installing hot tap branch connections in the field. The use of this guidance and the compendium of properly qualified welding procedures that was developed during the JIP will reduce the cost of installing hot tap branch connections, increase safety during installation, and increase the reliability of completed connections.

Double submerged arc welding is an efficient process used during the production of longitudinally-welded large-diameter pipes. It is well known that the associated high heat input has a negative influence on the toughness of the heat-affected zone (HAZ). The toughness drop is related to changes in the HAZ microstructure compared to the base metal. The austenite grain size increases significantly and larger carbon-rich martensite/austenite particles (M/A-particles) are formed within a coarse bainitic matrix during the phase transformation compared to the as-rolled base material. The exact relationship between the microstructure, the processing conditions, base metal composition and the weld metal are at the focus of attention of materials development efforts at EUROPIPE and Salzgitter Mannesmann Forschung GmbH (SZMF). In the present study, scanning electron microscopy (SEM) and electron backscatter diffraction (EBSD) were used to investigate the HAZ of X70 large-diameter pipe material as well as tested Charpy specimens from the same material. Secondary cracks in the direct vicinity of the primary fracture surface of tested Charpy specimens from the HAZ were analyzed by EBSD and SEM to investigate the damage mechanism in detail. It was found that these cracks originate at M/A-particles and that the dominant crack path depends on the crystallographic orientation of the surrounding matrix. The analysis of several EBSD measurements and a 3D-analysis of the propagation direction of the crack showed that secondary cracks frequently propagate parallel to {100} and rarely along {110}-planes. It is known from literature that these are preferred cleavage planes in ferritic steels. The SEM analysis performed in the HAZ of the investigated steel showed that the volume fraction of elongated M/A-particles is elevated close to the fusion line and decreases within the first few hundred micrometers distance from the fusion line. The EBSD measurements illustrate that the geometrically necessary dislocation density is significantly increased in the neighborhood of M/A-particles. This indicates that the bainitic matrix is work-hardened around the M/A-particles during testing and is therefore more prone to the formation of microcracks than other surrounding regions.

Many pipe mills may not be familiar with a Crack Tip Opening Displacement (CTOD) requirement on the pipe seam weld, nor will they find easily relevant information in open literature. Influencing — and certainly not independent — factors are: welding parameters, base material and consumable selection. Out of these, the welding parameters such as heat input and cooling rate cannot be varied over a wide range during the pipe production, which means that the leverage is rather limited at the given welding process. The properties of the heat affected zone will be mainly affected by the base material, while the properties of the weld metal will be affected by both, base material and filler wire selection. In particular with respect to the weld metal properties it will be difficult to obtain general quantitative information. For example, a welding consumable supplier will readily provide the properties of the filler wires but would be unable to predict the changes caused by the dilution from any base material in the weld pool and specific welding procedures that may have been used. To support the pipe mills in the selection of the consumables for submerged arc welding, an experimental program was launched with the aim to provide recommendations on how to optimize CTOD toughness of the spiral weld seam. For this, a large number of welds were produced on 20 mm thick X70 coil samples, with eight different filler wire combinations, using a 2-wire (tandem) set-up for both the inside and outside weld. Welding parameters were kept constant. The welding program was applied to two different X70 steels to determine a potential influence of the micro-alloying elements, particularly Nb. The results show clearly that a careful consumable selection is required for obtaining acceptable CTOD toughness in the weld metal. Ni-Mo and Ti-B additions to the weld metal are found to be beneficial with both steel concepts. Mo addition alone both to the ID and OD welds was clearly not a suitable selection.

This work proposes an assessment procedure for the determination of the remaining strength in pressure vessels with pitting type metal loss, trough the developed of integrity diagrams according to the pitting density, pitting depths and the internal pressure of the component using Finite Element Analysis simulations. The simulations results indicate that the pitting density and depths according to the Gumbel Max Distribution, are the main factors that determine the mechanical integrity of the component; where 45% damaged area by pitting generates a stress concentration that multiplies at least ten times the stress compared with components without defects, since these variables present a synergistic behavior in the stress state. The proposed assessment procedure facilitates the evaluation of the components that present pitting corrosion damage, due to the geometric and population effect of the pitting is considered in the finite element simulation.

Accurate defect sizing is crucial for maintaining effective pipeline safety and operation. Under growing pressure from local, national and world organizations, pipeline operators demand improved magnetic flux leakage (MFL) metal-loss sizing accuracy and classification from in-line inspection (ILI) tools. The axial MFL field response in pipeline steel near a metal-loss defect is a very complex phenomenon. Although critical for proper sizing model development, the effects of tool speed due to product flow is very difficult to model during finite element analysis (FEA) and therefore is often overlooked. However, understanding the dynamic MFL response is crucial for proper ILI tool design and the development of accurate defect sizing algorithms. T.D. Williamson (TDW) utilizes dynamic computer simulation modeling, paired with laboratory testing, to develop the complex parametric relationships between metal loss geometry, pipeline material and ILI tool speed. The blend of simulation and physical test results allow for TDW to iterate more quickly across multiple physics variables with simulation models, while maintaining a firm footing in reality with physical test validation. Accurately simulating magnetic field responses of metal loss under dynamic conditions produces the data necessary to identify optimal magnetizer design, including optimizing sensor spacing and placement for metal-loss defect sizing and characterization. This paper will provide an overview of advances in the use of computer simulation modeling for predicting dynamic flux leakage field response. Besides increasing accuracy, results from this work will extend specifications beyond optimal speed ranges and provide the basis for general corrosion profilometry predictions from decomposition of the full MFL signal.

It is generally accepted that hot induction bending (HIB) results in a decrease in strength and an increase in fracture toughness in bend area, heat affected zone (HAZ) and weld metal (WM). As the result, Post bend heat treatment (PBHT) is not considered to be a requirement and could be waived for saving money and time. This research work raises the concern that factual verification of proper microstructure and no localized brittle zone is vitally necessary prior to waving PBHT. Evaluation of the steel microstructure and mechanical properties as the result of various pipe chemistries during pipe bending has been verified in this experimental work. It is emphasized that knowledge and control of prior steel pipe chemistry, control of temperature, cooling rate and bending speed assures the reliability and repeatability of induction bends, especially in critical environments such as low temperature application. In the present work, qualitative and quantitative microstructural analysis, hardness and impact test performed and evaluated on samples from X70 line pipe with 3 different steel chemistries. The samples prepared from different locations on body, weld and HAZ in the as received and as bent condition. It was found that the final microstructure and mechanical properties in the as bent condition is dependent on the chemistry, steel cleanliness and microstructural uniformity. It was observed that small localized brittle zone with traces of upper Bainite and Martensite islands could be transformed in the microstructure with rich chemistry containing non-homogenous central segregation. It is concluded that factual verification of proper microstructure with no localized hard zone is required prior to waving PBHT.

Pipeline in-line-inspections (ILI) are used to assess and track the integrity of pipelines, aiding in identifying a variety of features such as: metal loss, dents, out-of-roundness, cracks, etc. The presence of these features can negatively affect the operation, integrity, and remaining life of a pipeline. Proper interpretation of the impacts these features may have on a pipeline are crucial to maintaining the integrity of a pipeline. Several codes and publications exist to assess the severity of these features under known operating conditions, either through empirical formulations or more detailed analysis, in order to aid the operator in determining a corrective action plan. These empirical formulations are generally applicable to assess a singular defect but require a more detailed assessment to evaluate combined defects (i.e. dent in a bend). These detailed assessments typically require a higher level numerical simulation, such as Finite Element Analysis (FEA). This detailed FEA can be quite costly and time consuming to evaluate each set of combined features in a given ILI run. Thus, engineering judgement is critical in determining a worst-case scenario of a given feature set in order to prioritize assessment and corrective action. This study aims to assess dent features (many associated with metal loss) occurring in a pipe bend to determine a worst-case scenario for prioritization of a given feature listing. FEA was used to simulate a field bend of a given radius and angle in order to account for residual stresses in the pipe bend. A rigid indenter was used to form a dent of the approximate length, width, and depth from the ILI data. Separate models were evaluated considering the dent occurring in the intrados, extrados, and neutral axis of the pipe bend to evaluate the worst-case scenario for further assessment. The resulting stresses in the pipe bend-dent geometry, under proper loading were compared to the same dent scenario in a straight pipe segment to develop a stress concentration factor (SCF). This SCF was used in the API 579-1/ASME FFS-1 Fitness for Service (API 579) [1] methodology to determine the impact on the remaining life of the combined features.

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.

While In-line Inspection Magnetic Flux Leakage (MFL) tools have been used for many years to successfully manage corrosion related threats, small pinhole-sized metal-loss anomalies remain a significant concern to pipeline operators. These anomalies can grow undetected to develop leaks and cause significant consequences. The physical dimensions of these anomalies, their proximity to and/or interaction with other nearby anomalies can challenge MFL’s detection and sizing capabilities. Other factors such as tool speed, cleanliness of the line and incorrect assumptions have an impact as well. For pipeline operators to develop effective and efficient mitigation programs and to estimate risks to an asset, the underlying uncertainties in detection and sizing of pinholes need to be well understood. By using magnetic modeling software, the MFL response of metal-loss anomalies can be determined, and the effect of a number of factors such as radial position, wall thickness, depth profile, pipe cleanliness and tool speed on MFL response and reporting accuracy can be determined. This paper investigates these factors to determine the leading causes of uncertainties involved in the detection and sizing of pinhole corrosion. The understanding of these uncertainties should lead to improvements in integrity management of pinhole for pipeline operators. This paper first investigates the physical measurement methodology of MFL tools to understand the limitations of MFL technology. Then, comparisons of actual MFL data with field excavation results were studied, to understand the limitations of specific MFL technologies. Finally, recommendations are made on how to better use and assess MFL results.

Pipeline integrity decisions are highly sensitive to the assessment model. A less accurate and less precise model can conservatively trigger many unnecessary actions such as excavations without providing additional safety. Therefore, a more accurate and precise model will reduce excavations and provide higher assurance of safety. This is akin to using a more precise surgical tool such as a laser for cutting out a brain tumor where you can cut closer to the edge and be assured of cutting out more of the tumor (safer) and yet cut less of the surrounding brain tissue (less conservative). This paper presents a novel model for assessing large metal-loss corrosion based on in-line inspection (ILI) or field measurement. The model described in this paper utilized an unconventional approach, namely multiple plausible profiles (P 2 ), to idealize the shape of the corrosion, and therefore is referred to as P 2 model. In contrast, all existing models use one single profile for characterizing corrosion profile, e.g. RSTRENG utilizes a single worst-case river bottom profile to characterize the shape of corrosion. The P 2 model has been initially validated using fourteen (14) full scale specimen-based hydrostatic tests on pipes containing real large corrosion features. Validation results showed that the P 2 model is safe, but less conservative and more precise than RSTRENG. The magnitude of reduction in conservatism depends on the corrosion morphology. On average, the P 2 model achieves 15% reduction in model bias and 44% reduction in standard deviation of model error. Further validation was provided using the testing data published by PRCI and PETROBRAS. Another set of burst tests are being conducted by TransCanada as part of the continuous validation of P 2 model. The effectiveness of the P 2 model was demonstrated through two case studies (denoted by Case study 1 and 2). Case Study 1 included 170 external metal-loss corrosion features that were excavated from different pipeline sections, and have field-measurements using laser scan tool. Case Study 2 included 154 ILI-reported external metal-loss corrosion features with RSTRENG calculated rupture-pressure-ratio (RPR) of less than or equal to 1.25 (i.e. RPR ≤ 1.25); hence, these features were classified as immediate features. The Case Studies showed that the use of the P 2 model resulted in 80% less number of ILI-reported features requiring immediate action (i.e., RPR ≤ 1.25) and 89% less number of excavated features requiring repair (e.g., sleeve or cut-out) compared to the respective number of features identified by RSTRENG-based assessment. The reduction in the number of features requiring excavation or repair is highly morphology-dependent with the highest reduction achievable for pipeline containing long and wide corrosion clusters (e.g., tape-coated pipeline). However, the P 2 model is applicable to all clusters regardless of the number of individual corrosion anomalies associated with the cluster.

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.

Reliability engineering science is a mature discipline that has been used extensively in industries such as aviation, nuclear energy, automobiles, and structures. The application of reliability principles (especially structural reliability) in oil and gas transmission pipelines is still an active area of development. The advent of high resolution in-line inspections tools (ILI) facilitates a formal application/utilization of reliability methods in pipeline integrity in order to safely manage deformation, metal loss, and crack threats. At the same time, the massive amount of ILI data, their associated uncertainties, and the availability/accuracy of failure prediction models present a challenge for operators to effectively implement the use of reliability analysis to check the safety of integrity programs within available timeframes. On the other hand, approximate reliability techniques may affect the analysis in terms of both accuracy and precision. In this paper, a Pipeline Integrity Reliability Analysis (PIRA) approach is presented where the sophistication of the reliability analysis is staged into three levels: PIRA levels I, II and III. The three PIRA levels correspond to different representations of integrity uncertainties, uses of available validated/calibrated data, uses of statistical models for operating pressure and resistance random variables, implementation of reliability methods, and consideration of failure modes. Moreover, PIRA levels allow for improved integration of reliability analysis with the existing timelines/stages of traditional integrity programs, such that integrity data are updated as the integrity program progresses. The proposed integrity reliability approach allows for the delivery of safety checks leveraging all types of information available at any given point in time. In addition, the approach provides a full understanding of the strengths and weaknesses of each PIRA level. Pipeline corrosion case studies are provided herein to illustrate how the PIRA Levels can be applied to integrity programs.

In order to meet the increasing worldwide energy demand, there is a need to economically develop remote oil and gas resources. Construction of pipelines is required to connect these resource locations to markets. Such pipeline routes may cross areas of large ground motions such as regions of active seismicity, discontinuous permafrost, and offshore ice gouging. All of these features can subject pipelines to significant longitudinal strains. For these conditions a strain-based design (SBD) approach may be required to maintain pipeline integrity. Welding technology is a key component of pipeline construction. Significant pipeline construction cost savings are enabled with the use of higher strength steels (X80+). Higher strengths enable reduced pipe wall thicknesses, which reduces both weight and girth welding time. However, robust welding technology for high strength SBD pipelines remains challenging. Such applications demand welds with both high strength (>120ksi) and low temperature (−15°C) toughness, combinations that are at the limits of, or beyond, existing commercial technology. This paper discusses the development of an enabling welding technology which offers a superior combination of strength and toughness properties. An iron-nickel (FeNi) martensitic weld metal with a refined mixed cellular microstructure has been developed as a promising high strength weld metal that can be applied for field pipeline construction. This paper describes how this technology has been applied to create welds for X80 strain-based pipelines requiring significant weld strength overmatch and superior ductile tearing resistance. The welding technology can also be applied to X70 grade strain-based pipelines where high toughness is required. This approach has been developed for mainline girth, tie-in girth, and girth repair welding scenarios. Welding procedures are discussed and examples of the mechanical properties achieved and calculated strain capacities are described.

Corrosion growth models are used to estimate future metal loss and the safe remaining lifetime of corrosion features in pipelines. Probabilistic models have become increasingly important in practice for reliability and risk-based pipeline assessments. The unknown model variables are usually determined from in-line inspection (ILI) results. Corrosion growth models exhibit various levels of complexity to account for temporal and spatial uncertainties of the actual corrosion growth process, and measurement uncertainties associated with ILIs. Model diversity leads to significant differences in how the models approach the uncertainty of future corrosion growth. This paper builds upon previous work and provides some theoretical background to an application described in [1]. It compares four common probabilistic corrosion growth models with respect to reliability estimates of leak failure. The four models are two uncertain corrosion rate models and two stochastic process models where the features are considered to be either independent or exchangeable. The unknown random variables of each model are updated in a Bayesian manner using the same ILI results. The key findings of this paper are: • Proper truncation at zero of the probability distributions for the unknown random variables is necessary if the measured corrosion growth is near zero or negative. • A stochastic process leads to lower uncertainties when determining future metal loss and, consequently, an increased reliability against leak failure than corrosion rate models. • The assumption of exchangeable features causes a reduction in the probability of leak failure due to the effect of borrowing information compared to independent features. The four corrosion growth models provide similar results with respect to the probability of failure if the measured corrosion growth is large. As the measured corrosion growth decreases in size, the differences between the reliability estimates increase.

There has been increasing interest across the industry to better understand the possible long term risks associated with out of service pipelines. In Canada, the Canadian Energy Pipeline Association (CEPA), Petroleum Technology Alliance of Canada (PTAC), and the National Energy Board (NEB), have undertaken multiple studies to identify and assess the threats related to pipeline abandonment. [1][2][3] The primary hazards typically identified across industry for pipeline abandonment are associated with long term corrosion degradation, potential for creation of water conduits, possible environmental impacts, and potential for pipeline collapse and associated soil subsidence. Unfortunately, little guidance is presently available to the industry for determining remaining structural capacity of a heavily corroded pipeline to establish likelihood, and possible timeline, of collapse, nor for determining possible subsidence magnitudes associated with large diameter transmission lines. This paper presents a technical case study for an assessment approximating the remaining strength of an abandoned pipeline subject to long term corrosion degradation, considering both general metal loss, and randomized pitting and perforation growth. The work presented used a combination of finite element analyses, and existing industry models for determining load bearing capacity of an abandoned pipeline under varying levels of degradation.

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.