This paper evaluates field ovalization measurements of NPS 24 pipe using 3D continuum finite element analyses. The combination of the soil backfill weight and loose bedding material beneath the pipe near a tie-in concentrates stresses at the location where native undisturbed soil transitions to loose backfill along the trench bottom, which increases the ovality in the pipe cross section. The analysis indicated that at burial depth, transient surface loading temporarily increases the ovality in unpressurized pipe but the ovality is reduced to near normal levels when the transient surface loading is removed. The internal pressure reduces the elastic pipe ovality. This analysis method can be useful for a cost benefit analysis between using thicker pipe, versus the additional costs, such as intervention and/or padding/compacting of soil around the pipe (with inspections).

Stress Corrosion Cracking (SCC) is a time dependent mechanism. Three conditions are required at the same location for the formation of SCC namely, susceptible material, susceptible environment and sufficient stress. Pipe age, operating stress level and coating type are significant parameters in determining the susceptibility to near-neutral pH SCC; whereas, additional parameters such as operating temperature and distance from compressor station are considered for high pH SCC. Environmental conditions such as soil type, topography and drainage have also shown correlation to SCC susceptibility. Several integrity assessment methods can be used to identify SCC on pipeline including hydrostatic testing, in-line inspection (ILI), and direct assessment (DA). Because the occurrence of SCC is a complex phenomenon and it depends on many parameters, it is important to develop a risk assessment model that can systematically incorporate all relevant evidences of SCC in a sensible way. This paper presents a robust risk assessment model for SCC, which uses evidence from failure histories, observation from assessments (i.e., digs, pressure tests, and ILIs), and mechanistic understanding of SCC (i.e. susceptible coating, pipe material, stress level, soil properties, etc.). This risk model is transparent and updateable, which allows incorporation of new scientific learnings and findings of SCC.

In the last 10 years, technical and economical efforts have been made to improve pipeline integrity management. Those efforts focus on developing “searching tools”, capable of identifying pipe mechanical damage due to slow landslides. We identified two main tools: geohazard mapping and inline inspection (OCP is using caliper with inertial navigation system INS). The INS system generates a substantial amount of information about pipe’s geometry and deformation, reported as pitch, yaw and distance cover for each run. Since the caliper has been used for years, the pipeline’s path of evolution over the years is already available. The INS data was merged with pipeline field inspections to develop an assessment tool based on Machine Learning Technology. This tool was applied to the complete path of the pipeline, analyzing each girth weld, thus obtaining a so called “criticality level” for each weld. Two models were evaluated, which differ on the size of the vicinity considered for each girth weld: 250m and 500m. The highest precision model was found with 250m, which already has allowed improvements in field inspections. This paper will describe this technique, capable of improving OCP’s pipeline integrity management.

At the forefront of the effort to understand and mitigate pipeline corrosion is the prediction of corrosion growth rates. It is important to understand the effect of corrosion growth estimates on integrity management decisions. An overly conservative approach results in unnecessary digs, while removing conservatism increases the potential for a missed feature to grow to a threatening size. While approaches to feature depth growth have been well-established, there has been less investigation into the growth of feature lengths. A literature review was performed on the methodologies applicable to length growth, and their performance was compared to those that only account for depth growth using a sample analysis. For pipelines with multiple in-line inspection (ILI) runs, feature or signal matching can be used to estimate the change in feature size. These rates can be used directly on individual features, averaged across pipe joints, or compiled into a statistical distribution. Alternatively, only one ILI measurement can be used and an assumption made on the age of the defect. These approaches are more commonly applied to depth growth but could be used to predict length growth as well. To compare the growth methodologies, the study used historical ILI measurements of a liquid pipeline to predict feature sizes and estimated burst pressures determined at the time of the latest ILI. The number of defects correctly predicted to have an insufficient burst pressure safety factor for safe operation was compared to the number of defects that were erroneously predicted to not meet this criterion, and those that were predicted to be safe but later found to not meet the safety factor requirement. The number of erroneously flagged defects was found to vary the most between methodologies. For the assessed data set, using the joint average rate based on feature box-matching was non-conservative on average. It was also found that incorporating length growth did not significantly affect the accuracy of the burst pressure predictions.

In-line inspection (ILI) data is commonly used in corrosion growth models (CGMs) to predict the corrosion growth in energy pipelines. A hierarchical stochastic corrosion growth model is considered in this paper which considers the variations in the corrosion growth, both spatially and temporally, the inherent measurement error of the ILI tools as well as the model uncertainties. These uncertainties are represented as unknown model variables and are often inferred using a Bayesian method [1], [2] and samples of the unknown parameters’ posterior probability density functions (PDFs) are obtained using Markov Chain Monte Carlo (MCMC) sampling techniques [3]. ILIs can result in massive data sets. In order for MCMC-based inference techniques to yield reasonably accurate results, many samples (approaching infinity) are required. This fact in addition to the massive data sets exponentially increases the scale of the inference problem from an attainable solution to a potentially impossible one that is limited by today’s computing power. For this reason, MCMC-based inference techniques can become inefficient in the cases where ILI datasets are large. The objective is to propose variational inference (VI) as an alternative to MCMC to determine a Bayesian solution for the unknown parameters in complex stochastic CGMs. VI produces approximations of the posterior PDFs by treating the inference as an optimization problem. Variational inference emerged from machine learning for Bayesian inference of large data sets; therefore, it is an appropriate tool to use in the analysis of mass pipeline inspection data[4]–[7]. This paper introduces VI to solve the inference problem and provide a solution for a hierarchical stochastic CGM to describe the defect-specific corrosion growth experienced in pipelines based on excessively large ILI datasets. To gauge the accuracy of the VI implementation in the model, the results are compared to a set of values generated using a stochastic gamma process that represents the corrosion growth process experienced by the pipe.

Mechanical dents often occur in transmission pipelines, and are recognized as one of major threats to pipeline integrity because of the potential fatigue failure due to cyclic pressures. With matured in-line-inspection (ILI) technology, mechanical dents can be identified from the ILI runs. Based on ILI measured dent profiles, finite element analysis (FEA) is commonly used to simulate stresses and strains in a dent, and to predict fatigue life of the dented pipeline. However, the dent profile defined by ILI data is a purely geometric shape without residual stresses nor plastic deformation history, and is different from its actual dent that contains residual stresses/strains due to dent creation and re-rounding. As a result, the FEA results of an ILI dent may not represent those of the actual dent, and may lead to inaccurate or incorrect results. To investigate the effect of residual stress or plastic deformation history on mechanics responses and fatigue life of an actual dent, three dent models are considered in this paper: (a) a true dent with residual stresses and dent formation history, (b) a purely geometric dent having the true dent profile with all stress/strain history removed from it, and (c) a purely geometric dent having an ILI defined dent profile with all stress/strain history removed from it. Using a three-dimensional FEA model, those three dents are simulated in the elastic-plastic conditions. The FEA results showed that the two geometric dents determine significantly different stresses and strains in comparison to those in the true dent, and overpredict the fatigue life or burst pressure of the true dent. On this basis, suggestions are made on how to use the ILI data to predict the dent fatigue life.

Ovality in a pipe results in a stress concentration and may present a pipeline integrity concern. If ovalization is generated during manufacturing or transportation and found during the girth welding process before the pipe is buried, replacement of the oval segment is usually the solution. However, ovalization is sometimes also found in buried pipelines via in-line-inspection (ILI) either before the pipeline is put into service or during regular pipeline maintenance. The mitigation and/or replacement of oval pipes after burial can be expensive. It is vital to identify what constitutes an unacceptable ovality level and to remediate only those that pose a threat of failure during the service life of the pipeline. The existing assessment approaches for oval pipes, such as that in API 579, generally require knowledge of the amount of ovality at zero pressure. However, the ovality of buried pipes usually is only available from ILI runs carried out at a non-zero internal pressure. The internal pressure tends to push the pipe back toward a circular shape, a phenomenon known as re-rounding. As a result, the ILI-reported ovality is smaller than that under zero pressure. Described in this paper is a new approach which can be used to assess the integrity of oval pipe segments based on ovality either as measured with no pressure in the pipe or as reported by ILI conducted at an elevated level of pressure. The approach considers both burst failure and fatigue damage. The accuracy of the approach was verified by finite element analysis (FEA). With the help of this new approach, a general discussion about the threat of ovalization to the integrity of a pipeline is provided. The analysis indicates that ovalization in amounts usually observed does not reduce the burst pressure in most pipelines, but fatigue damage could be a concern. The fatigue damage due to ovalization is sensitive to pipe geometry, amplitude of pressure variation, and the minimum pressure level within the pressure cycles.

This paper describes a novel technique for the detection of cracks in pipelines. The proposed in-line inspection technique has the ability to detect crack features at random angles in the pipeline, such as axial, circumferential, and any angle in between. This ability is novel to the current ILI technology offering and will also add value by detecting cracks in deformed pipes (i.e. in dents), and cracks associated with the girth weld (mid weld cracks, rapid cooling cracks and cracks parallel to the weld). Furthermore, the technology is suitable for detection of cracks in spiral welded pipes, both parallel to the spiral weld as well as perpendicular to the weld. Integrity issues around most features described above are not addressed with ILI tools, often forcing operators to perform hydrostatic tests to ensure pipeline safety. The technology described here is based on the use of wideband ultrasound inline inspection tools that are already in operation. They are designed for the inspection of structures operating in challenging environments such as offshore pipelines. Adjustments to the front-end analog system and data collection from a grid of transducers allow the tools to detect cracks in any orientation in the line. Description of changes to the test set-up are presented as well as the theoretical background behind crack detection. Historical development of the technology will be presented, such as early laboratory testing and proof of concept. The proof of concept data will be compared to the theoretical predictions. A detailed set of results are presented. These are from tests that were performed on samples sourced from North America and Europe which contain SCC features. Results from ongoing testing will be presented, which involved large-scale testing on SCC features in gas-filled pipe spools.

Pipeline risk models are used to prioritize integrity assessments and mitigative actions to achieve acceptable levels of risk. Some of these models rely on scores associated with parameters known or thought to contribute to a particular threat. For pipelines without in-line inspection (ILI) or direct assessment data, scores are often estimated by subject matter experts and as a result, are highly subjective. This paper describes a methodology for reducing the subjectivity of risk model scores by quantitatively deriving the scores based on ILI and failure data. This method is applied to determine pipeline coating and soil interaction scores in an external corrosion likelihood model for uninspected pipelines. Insights are drawn from the new scores as well as from a comparison with scores developed by subject matter experts.

Gas pipelines and networks are subject to multiple regulatory governance arrangements. One regime is economic regulation which is designed to ensure fair access to gas markets and emulate the price pressures of competition in a sector dominated by a few companies. Another regime is technical regulation which is designed to ensure pipeline system integrity is sufficient for the purposes of public safety, environmental protection and physical security of supply. As was highlighted in analysis of the San Bruno pipeline failure, these two regulatory regimes have substantially different orientations towards expenditure on things such as maintenance and inspection which ultimately impact public safety. Drawing on more than 50 interviews, document review and case studies of specific price determinations, we have investigated the extent to which these two regulatory regimes as enacted in Australia may conflict, and particularly whether economic regulation influences long-term public safety outcomes. We also draw on a comparison with how similar regulatory requirements are enacted in the United Kingdom (UK). Analysis shows that the overall orientation towards risk varies between the two regimes. The technical regulatory regime is a typical goal-setting style of risk governance with an overarching requirement that ‘reasonably practicable’ measures are put in place to minimize risk to the public. In contrast, the incentive-based economic regulatory regime requires that expenditure should be ‘efficient’ to warrant inclusion in the determination of acceptable charges to customers. How safety is considered within this remains an open question. Best practice in performance-based safety regimes such as those used in the UK and Australia require that regulators adopt an attitude towards companies based on the principle of ‘trust but verify’ as, generally speaking, all parties aim for the common goal of no accidents. Equally, in jurisdictions that favor prescriptive safety requirements such as the United States (US) the common goal remains. In contrast, stakeholders in the economic regulatory regime have significantly diverse interests; companies seek to maximize their individual financial returns and regulators seek to exert downward price pressures. We argue that these differences in the two regulatory regimes are significant for the management of public safety risk and conclude that minimizing risk to the public from a major pipeline failure would be better served by the economic regulatory regime’s separate consideration of safety-related from other expenditure and informed by the technical regulator’s view of safety.

Strain based design concepts have been extensively used for subsea pipelines for both installation and service. However, most onshore transmission pipelines are designed assuming a maximum longitudinal stress, typically 90% SMYS. Some onshore pipelines have been designed for a limiting axial strain generated by causes such as seismic activity, frost heave, discontinuous permafrost or landslides. Models have been developed to predict the axial strain capacity in both tension (usually limited by the girth welds) and compression (where the limit is local buckling of the pipe wall). In service monitoring of a pipeline initially designed on a stress basis may reveal that strains approaching or exceeding the design level are occurring, or are predicted to occur in the future. In these cases the pipeline operator will have to assess if the pipeline is fit for continued service. In principle strain based design approaches could be adapted for such an assessment. Strain based design approaches place more onerous demands on the linepipe and the girth welds, but for a new pipeline these requirements can be addressed during design, material specification, procurement and weld procedure qualification. However, for an existing pipeline the data required to use strain based approaches may not be readily available. Some strain capacity models are only valid over a restricted range of inputs and so cannot be used in all cases. Hence there is a need to develop guidance for assessing the fitness for purpose of a stress based design pipeline that is found to be experiencing high axial strains. The European Pipeline Research Group (EPRG) has initiated a program to develop such guidance. This paper presents the results of the first stage of this program. The requirements for data such as inspection records, weld metal fracture toughness and parent pipe mechanical properties are considered. A flow chart has been developed to guide operators when assessing an existing pipeline found to be subject to high strains, and a gap analysis identifies areas where additional work is required.

The Wapiti River South Slope is located 25 km southwest of Grande Prairie, AB. The slope is 500 m long and consists of a steep lower slope and a shallower upper slope, both of which are located within a landslide complex with ground movements of varying magnitudes and depths. The Alliance Pipelines Ltd. (Alliance) NPS 42 Mainline (the pipeline) was installed in the winter of 2000 using conventional trenching techniques at an angle of approximately 8° to the slope fall line. Evidence of slope instability was observed in the slope since the first ground inspection in 2007. Review of the available geotechnical data indicates two different slide mechanisms. In the lower slope, there is a shallow translational slide within a colluvium layer that is draped over a stable bedrock formation. In the upper slope, there is a deep-seated translational slide within glaciolacustrine and glacial till deposits that are underlain by pre-glacial fluvial deposits. Both the upper and lower slope landslide mechanisms have been confirmed to be active in the past decade. Large ground displacements in the order of several meters between 2012 and 2014 in the lower slope led to a partial stress relief and subsequent slope mitigation measures in the spring and summer of 2014, which significantly reduced the rate of ground movement in the lower slope. Surveying of the pipeline before and after stress relief indicated an increase in lateral pipeline deformation (in the direction of ground movement) following the stress relief. This observation was counter-intuitive and raised questions regarding the effectiveness of partial stress relief to reduce stresses and strains associated with ground movements. Finite element analysis (FEA) was conducted in 2017 to aid in assessing the condition of the pipeline after being subject to the aforementioned activities, and subsequent ground displacement from July 2014 to December 2016. This paper presents the assumptions and results of the FEA model and discusses the effect of large ground displacement, subsequent stress relief and continued ground displacement on pipeline behaviour. The results and findings of the FEA reasonably match the observed pipeline behaviour before and after stress relief. The FEA results showed that while the lateral displacement of the pipeline that was caused by ground movement actually increased following the removal of the soil loading, the maximum pipeline strain was reduced in the excavated portion. The results also indicated that ground displacement in the upper slope following the stress relief had minimal effect on pipe stresses and strains in the lower slope.

The pipeline sector is facing a multi-faceted challenge regarding its workforce. Valuable knowledge is being lost as increasing numbers of technical experts and long-term employees exit the industry (due to retirement). Concurrently, the public spotlight is focused on the environmental impact of the pipeline industry. Therefore, robust construction of new pipelines and effective maintenance of aging infrastructure is increasingly important. Herein lies the challenge — How does the industry transfer the knowledge required to ensure that personnel have suitable competency to maintain the integrity of the pipeline system? A scenario where new personnel efficiently gain knowledge through experience is critical. An important aspect of achieving this is a more systematic and thoughtful approach to knowledge transfer. As part of its fundamental methodology for developing training and alternate methods for knowledge transfer, the team launched an initiative to review the literature and current industry approaches. This was done as a key input to developing a “Knowledge Taxonomy.” This tool simplifies the process for selecting the optimal method for effectively transferring key technical knowledge based on the desired level of competency (e.g., awareness building vs. mastery). Specifically, the team identified a number of consistent themes and combined them with both sound educational theory and industry experience to develop a tool in the form of a practical framework. This Knowledge Transfer Taxonomy was then applied to a specific knowledge gap in industry as a case study. This paper will 1. Summarize, at a high level, the results of the literature review and current approaches; 2. Describe the framework (i.e., Knowledge Taxonomy) developed by the team; 3. Discuss a case study involving the application of this framework to a specific and real challenge; and Through this work, the team identified and developed specific strategies and tactics to effectively overcome some of the barriers to knowledge transfer. These experiences will be shared in the context of a specific situation that typifies the current challenges industry is facing in effective knowledge transfer.

Inline inspections following new pipeline construction completion as a means of ensuring specific quality requirements are fulfilled poses unique challenges when compared with inline inspections in operating pipelines. Construction contractors are often responsible for conducting a post-construction inline inspection as part of construction quality verification; however, construction contractors often lack expertise in planning and conducting inline inspections. Schedule constraints for conducting inline inspections, often introduced because of other prior construction delays, can contribute to poor planning and execution. The consequent undesirable outcome may be failed inspections further delaying pipeline construction completion, turnover to the Client, and final payments. It is in the interest of all stakeholders to ensure inline inspections be completed in a timely manner and in a way that maximizes the likelihood that the needed pipeline data will be successfully acquired. It is crucial for post-construction inline inspection success, that all stakeholders poses basic knowledge of operational requirements and inspection proceedings. Additionally, adequate planning of the inline inspection proceedings can greatly mitigate the risks associated with the inline inspection. To ensure necessary considerations and the division of responsibilities is clear and understood among all stakeholders; a Post-Construction ILI Execution Plan is prepared. The Inline Inspection Contractor is responsible for completion of the Post-Construction ILI Execution Plan in consultation with other stakeholders. The contents of the Post-Construction ILI Execution Plan include project information, run conditions, and stakeholder contact information. Moreover, it defines the assignment of stakeholder responsibilities and involvement for all inspection planning and execution aspects.

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.

Technology plays a critical role in the oil and gas sector, and the pipeline industry is no exception. Maintaining the integrity of high pressure oil and gas pipeline requires the use of advanced technologies. A challenge that confronts every pipeline operator is the risk posed in the deployment of unproven technologies, especially those associated with the inspection, assessment, monitoring, and rehabilitation of their systems. Use of unproven technologies and concepts puts pipeline operators at risk. The concept of Technology Readiness Levels (TRLs), commonly used in the aerospace and defense industries, provides the pipeline industry with a proven means for evaluating and assessing technologies used to enhance integrity management efforts. This paper presents details on technology readiness levels ranging from Proof of Concept to System Operation . The adoption and implementation of the TRL approach will minimize operator risk and foster the deployment of advanced technologies, thus enhancing the safe operation of high pressure pipelines. Three TRL-oriented case studies will be included evaluating the monitoring of pipelines using fiber optics, inspection using three-dimensional imaging, and reinforcement using optimized composite technologies.

Many different inspections are conducted on gas transmission and gas distribution pipelines — valve inspections, cathodic protection system inspections, in-line inspection, odorant monitoring, etc. — demanding significant resources and operational expenditures from pipeline operators. Risk-based optimization relating to these kinds of operational activities has been applied in analogous industries. The result has been measurable savings consistently ranging at a level between 20–40%. Significantly, this explicitly means that 20–40% of many operational activities have been proven not to bring a benefit. In the pipeline industry, however, there has not been a basis to determine which activities bring no value in terms of risk reduction. In this paper, a detailed example is provided for risk-based optimization of valve inspections and the savings are found to be within these expectations. These savings can be taken in either a risk reduction benefit or completely in cost savings. Through development of a valve failure risk model (which independently considers loss of function and loss of containment failures) and an inspection cost model, a set of the optimum risk-cost combinations is developed and can be presented as an optimized inspection curve. Using the curve to establish inspection frequencies is demonstrated, including the impact on operating expenditures. As demonstrated via the presented case studies, the general framework is suitable for optimization of any gas pipeline inspection or maintenance activity.

The rehabilitation of damaged pipelines plays a critically-important role in maintaining the integrity management of pipeline systems. The repair techniques employed by pipeline operators typically include welded Type A and Type B sleeves, as well as composite repairs. Once repairs are made, operators must trust the integrity and soundness of the repairs based on various monitoring and inspection techniques; however, there are no current widely-accepted techniques for monitoring either the reinforcement or the pipe itself. A research program was conducted that involved the embedding of fiber optics in a steel sleeve and E-glass / epoxy composite repair systems. Measurements from the fiber optic sensors included temperature, hoop strain, and axial strain, which allowed engineers to monitor conditions in both the repair and the pipe sample. The implications of embedded technologies in pipeline repairs are far-reaching, including the ability to monitor not only the reinforcement itself, but also serve as a resource for monitoring pipeline activities including third party damage and land movement. This paper presents results from the test program, but also concepts for continued use of pipeline repair embedded technologies and their impact on the generation of large-scale data and enhancement of integrity management efforts.

The Pipeline Open Data Standard (PODS) Association develops and advances global pipeline data standards and best practices supporting data management and reporting for the oil and gas industry. This presentation provides an overview of the PODS Association and a detailed overview of the transformed PODS Pipeline Data Model resulting from the PODS Next Generation initiative. The PODS Association’s Next Generation, or Next Gen, initiative is focused on a complete re-design and modernization of the PODS Pipeline Data Model. The re-design of the PODS Pipeline Data Model is driven by PODS Association Strategy objectives as defined in its 2016–2019 Strategic Plan and reflects nearly 20 years of PODS Pipeline Data Model implementation experience and lessons learned. The Next Gen Data Model is designed to be the system of record for pipeline centerlines and pressurized containment assets for the safe transport of product, allowing pipeline operators to: • Achieve greater agility to build and extend the data model, • respond to new business requirements, • interoperate through standard data models and consistent application interface, • share data within and between organizations using well defined data exchange specifications, • optimize performance for management of bulk loading, reroute, inspection data and history. The presentation will introduce the Next Gen Data Model design principles, conceptual, logical and physical structures with a focus on transformational changes from prior versions of the Model. Support for multiple platforms including but not limited to Esri ArcGIS, open source GIS and relational database management systems will be described. Alignment with Esri’s ArcGIS Platform and ArcGIS for Pipeline Referencing (APR) will be a main topic of discussion along with how PODS Next Gen can be leveraged to benefit pipeline integrity, risk assessment, reporting and data maintenance. The end goal of a PODS implementation is a realization of data management efficiency, data transfer and exchange, to make the operation of a pipeline safer and most cost effective.

Pipeline integrity has been threatened at the Dead Horse Creek pipeline crossing in southern Manitoba by a slow-moving slope failure with a potential for crest retrogression. The movement zone extends from the slope crest to the bottom of the creek, a vertical distance of about 25 m and is approximately 80 m long from toe to scarp and 100 m wide along the creek. The slope has degraded over time and is controlled by the combination of local geology, which consists of weak colluvium overlying high plastic clay shale, and creek bank erosion and channel degradation. Saturated soil conditions, a function of poor drainage and elevated seasonal precipitation, have exacerbated the problem over the years. The slope movements have been monitored on a regular basis since 2008 and presented an increasing risk to the integrity of multiple pipelines located in two rights-of-way (ROWs) situated within and immediately adjacent to the failing soil mass. The site is surrounded by various infrastructure and recreational areas that are key to the community, and therefore is considered a high consequence area with respect to potential pipeline failures. To manage the risk and protect pipeline integrity, various stress relief and other mitigating measures have been implemented since 2013 [1], culminating in a major slope rehabilitation project undertaken in 2015, which comprised earthworks, drainage and watercourse improvements, and slope stabilization using stone columns. While the use of stone columns to stabilize embankments is not a new technique, it is not commonly used in the pipeline industry and represents another option for geohazard stabilization in the right situations. This paper presents the slope stabilization techniques employed and discusses the challenges of working on an active moving slope confined by a watercourse and live pipeline assets. The positive benefits of the stabilization measures are illustrated through the use of 2D and 3D numerical modelling, and confirmed through an ongoing geohazard management program that includes site inspection and instrumentation monitoring which continues to show improvements in slope performance post construction.