TEST SUBMISSION
BEN STROMAN CLARION TECHNICAL CONFERENCES, LLC, HOUSTON, USA
larion is a provider of training courses, technical conferences, and publications for engineers and technical management within the oil and gas production and pipeline transportation industries, both on- and offshore. Today, managers at all levels must have a solid understanding of technical operations and a firm grasp of management imperatives – in particular, the technologies available to achieve and maintain top operational performance, safety, reliability and compliance with regulations. Clarion's products provide this knowledge and expertise on a continuous worldwide basis through the Clarion Technical Conferences group and its affiliate, Clarion Technical Publishers.
Risk-Informed Evaluation of Gas Pipeline Assessment Options: Hydrostatic Test, Direct Assessment, and In-Line Inspection
Matthew Fowler, Isabel Chairez Enbridge Gas Transmission and Midstream, Edmonton, Canada
Recent regulatory changes introduced under the PHMSA Gas Mega Rule have significantly broadened the scope of integrity management requirements for gas transmission pipelines. These changes extend assessment obligations beyond traditional high consequence areas (HCAs) to include moderate consequence areas (MCAs) and other previously exempt segments. As a result, pipeline operators face the challenge of implementing an expanded assessment program that balances regulatory compliance, operational feasibility, and cost efficiency while maintaining safety performance.The PHMSA Gas Mega Rule explicitly identifies a non-limiting list of three primary assessment methodologies: Direct Assessment (DA), Hydrostatic Testing, and In-Line Inspection (ILI). Each assessment method presents unique advantages and limitations related to risk reduction potential, cost implications, and applicability to existing pipeline configurations. Selecting the most suitable approach for a given pipeline segment requires a structured, transparent, and defensible decision-making process that accounts for compliance, engineering best-practices, and economic considerations.This paper introduces a risk-informed, cost-benefit framework grounded in the principle of “As Low As Reasonably Practicable” (ALARP). The framework enables operators to evaluate the feasibility of different assessment methods and prioritize pipeline segments for conversion to piggable status where appropriate. Using integrity threat risk modeling approaches, the risk profile of pipeline routes are quantified and compared against projected post-assessment risks following DA, hydrostatic testing, and ILI. These risk reductions are then analyzed alongside estimated implementation costs to determine the ALARP level and overall cost-effectiveness of each option.The proposed approach provides a systematic, transparent method for comparing assessment strategies, supporting defensible decision-making and optimized resource allocation. By integrating regulatory requirements with quantitative risk and cost analysis, this framework helps operators achieve compliance while maintaining safety and operational efficiency. Ultimately, the methodology offers a practical tool for navigating the complexities of the PHMSA Gas Mega Rule, enabling operators to make more informed choices about prospective assessment methods.Keywords: PHMSA, HCA, MCA, Mega Rule, Gas, Transmission, In-Line Inspection, Direct Assessment, Hydrostatic Testing, ALARP, Risk Informed, Cost Benefit
A Tiered Screening Framework for Dent Engineering Critical Assessment
Forrest Gu TC Energy, Calgary, Canada
Dents are among the most frequently reported anomalies in pipeline integrity programs, and operators managing large in-line inspection (ILI) datasets often face high volumes of dent indications requiring engineering critical assessment (ECA). Industry guidance including API RP 1183, API 579, and 49 CFR 192.712 permits the use of analytical and finite element analysis (FEA) to quantify dent severity through damage-based metrics. For FEA methodology, three-dimensional (3D) solid-element models are typically preferred for their ability to resolve through-thickness stress gradients, but the associated computational cost limits their practical use for large populations, creating a bottleneck for timely integrity decisions.This paper presents a comparative evaluation of conventional shell-element and 3D solid-element FEA approaches for dent ECA, based on real-world dents derived from ILI caliper data across a range of pipe conditions. Damage indicators were evaluated over the full loading history, and modeling assumptions were held consistent between formulations to isolate the effect of element type.The results characterize the relative response of shell and solid models across the evaluated dataset and identify the conditions under which each formulation is most applicable for dent ECA. Based on these findings, a tiered screening workflow is proposed in which shell models serve as an efficient primary assessment tool, with escalation to 3D solid analysis triggered by defined criteria — offering pipeline operators a practical path to reduce ECA turnaround time and computational cost while preserving a defensible margin of safety. Limitations and applicability of each type of analysis are also discussed in the paper.Keywords: Fitness-for-service; pipeline dents; finite element analysis; shell elements; solid elements; screening workflow; integrity assessment.
The unexpected complexity of seam peaking
Michael Rosenfeld, Benjamin Zand RSI Pipeline Solutions LLC, New Albany, USA
Longitudinal seam peaking has draw interest from recent pipeline failures. A prior review showed that past failures have been limited to crude oil pipelines, and that peaking is unlikely to be an integrity concern in most natural gas service. Prior evaluations have suggested that susceptibility to cracking is in proportion to the peaking angle. This study digs deeper into the mechanics of peaking to better understand how this seam geometry influences stress distributions during and after a pressure test, and at typical operating pressures. These stress distributions influence crack growth over time in unusual ways. This study also examines the potential for hydrostatic testing of peaked seams to cause more damage than benefit.
Industry Incidents on Natural Gas Transmission Pipelines Resulting from Rupture Failures
Gary Krichau1, David Futch2 1Northern Natural Gas Company, Omaha, USA. 2ADV, Houston, USA
This paper is a review of incident data available from the Pipeline and Hazardous Materials Safety Administration. From 2010 through 2025, there have been 1,984 incidents on natural gas transmission pipelines. Of these incidents, 256 were classified as ruptures. totaling 53,491 feet or 10.1 miles of pipe. These 256 rupture incidents were analyzed by considering the rupture length as a measure of severity. The lengths of the ruptures were compared to the typical pipe attributes such as decade of installation, operating stress, outside diameter, pipe grade, failure root cause, manufacturer, seam type, etc. An unexpected finding was that 189 of these 256 ruptures originated in the pipe body – not the longitudinal seam. This contrasts with what is commonly expected based on research prior to 2010. This paper is intended to bring this to the attention of the industry and ensure that we are not imposing a bias and using current data.
Normalization of Deviance as a Threat to Pipeline Integrity
Michael Rosenfeld, Stephanie Flamberg RSI Pipeline Solutions LLC, New Albany, USA
Normalization of deviance refers to the acceptance of not adhering to procedures, specifications, protocols, or behaviors necessary to maintain safety or reliability in a technical system. It occurs through repeated observation or experience of successful deviance without adverse consequence, such that individuals or organizations become desensitized to the risk of incorrect actions. Deviance can be inadvertent, deliberate, or learned; it is often rewarded by saving time or money, preserving organizational harmony, or meeting other immediate performance goals. Normalization of deviance has been identified as causal to many accidents in safety-sensitive industries including aviation and health care. The authors have observed normalization of deviance to be significant contributors to pipeline incidents and near-miss events as well. This paper describes how normalization of deviance has contributed to pipeline incidents, how it may manifest itself, and how it can be recognized.
An Adaptable Phased Array Approach to Integrity Challenges: The Rooftopping Example
Katja Taeumner¹, Thomas Hennig¹, Alessandro Morandini¹, Brett Conrad²
¹NDT Global, Stutensee, Germany. ²South Bow, Calgary, Canada
Phased arrays have become a standard platform in non-destructive testing, particularly for in-the-ditch verification. Common modalities include FMC, TFM, adaptive methods, and conventional sector scans as those allow for highly optimized data gathering depending on boundary conditions and threat. These capabilities are increasingly being applied to inline inspection, where they offer the same core advantage as handheld systems: depending on the boundary conditions and threat of interest, the inspection setup can be optimized to acquire the most relevant data and provide deeper insight into asset conditions. Given the use of multiple inspection angles and the retrieval of complementary information from the inspection, increased coverage of pipeline conditions and defect types is guaranteed. This presents a clear advantage with respect to monolithic element inspection tools, where a change of boundary conditions commonly implies the deployment of a different tool.
Roof topping has recently gained attention among pipeline operators. Out-of-roundness near the long seam changes the local stress regime and can reduce the detection and sizing performance of conventional ILI crack detection systems. In severe peaking conditions, cracks may become difficult or even impossible for standard ILI systems to detect. This collaborative project addressed two objectives: developing a tool and methodology to locate and size peaking, and optimizing ILI crack detection performance to identify cracks even under severe peaking conditions.
The objective of this work is not to promote a particular tool, but to demonstrate the current state of the art and a pathway for ILI vendors and operators to leverage phased array systems to solve different challenges. The phased array technology can be applied across the ILI industry and is not limited to any specific vendor. The paper presents a structured development path from problem definition through simulations, small-scale testing, system validation, field application, and operational feedback. Relying on a known technology and tool allowed rapid delivery of a field-proven phased array ILI configuration that can characterize and size peaking, while also detecting cracks within peaked areas. As operators continue to seek answers to new integrity challenges, similar extensions of phased array tool functionality can be achieved with significantly less effort than would be required for the development of entirely new inspection tools.
Closing the Gap Between Geotechnical Engineering and Pipeline Integrity: A Case Study-Led Geohazard Toolbox
Rebecca Senior ROSEN, Calgary, Canada
Geohazards pose an evolving threat to pipeline integrity, particularly in regions with complex or unstable terrain. Key hazards include landslides, subsidence, erosion, river scour, and seismic-induced ground deformation, often driven by intense weather events, elevated groundwater levels, soil weakening, and anthropogenic land-use changes.Pipeline failures in these environments are typically the consequence of gaps in geohazard management practice – most often the failure to identify the presence of a hazard interacting with the pipeline, or the failure to detect and interpret externally induced pipeline movement before critical strain develops.Although geohazards have long been recognized as an integrity threat, practical guidance for their management during pipeline operation has become more clearly defined only in recent years. ISO 20074, API RP 1187, and the INGAA Geohazard Framework provide structured guidance for identifying, assessing, monitoring, and mitigating geohazard threats affecting pipelines. In practice, however, there remains a gap between geotechnical assessment and integrity decision-making.This paper presents a practical, case study-led application of the geohazard toolbox for piggable pipelines. The approach combines geotechnical and geomorphological understanding with pipeline integrity data, including in-line inspection outputs such as bending strain, pipeline movement, and caliper measurements. These datasets are supplemented, where appropriate, by terrain mapping, LiDAR, InSAR, geotechnical investigation, and targeted field observations. The objective is not simply to identify where geohazards are present, but to determine whether they are loading the pipeline, how significant that loading is, and what level of action is required.A series of case studies is presented to demonstrate how the toolbox is applied in practice. The examples show how integrated interpretation can distinguish between ground movement and other sources of pipeline deformation, improve prioritization of sites for further assessment, and support decisions on monitoring, mitigation, or continued surveillance. The case studies also demonstrate how the outputs can be incorporated into Integrity Management Plans, providing a clearer link between geohazard assessment, pipeline response, and operational decision-making.The paper demonstrates that closing the gap between geotechnical engineering and integrity does not require a single new technology or standalone assessment method. Rather, it requires a structured process for combining existing datasets, interpreting them in the context of the hazard mechanism, and translating the results into defensible integrity actions for operating pipelines.
Pipe Toughness Determination by Planing-Induced Microfracture: Third-Party Validation, Case Studies, and New Developments for TVC Records
Darrell Thompson1, Simon Bellemare2, Joshua James3, Taylor Shie4 1MMT, Houston, USA. 2MMT, Natick, USA. 3Edison Welding Institute, Columbus, USA. 4Shell Pipeline Company, Houston, USA
Obtaining Traceable, Verifiable, and Complete (TVC) records of the toughness of vintage pipelines is becoming a valuable asset for operators implementing Engineering Critical Assessment (ECA) under new regulatory expectations for combining safety excellence and cost reduction — expectations reinforced by PHMSA's recent Notice of Proposed Rulemaking (NPRM) of July 8, 2026. The industry has already begun collecting toughness data opportunistically, both through cutouts for laboratory testing and through nondestructive testing (NDT) within dig programs. Several operators have amassed thousands of data points on their vintage assets and leveraged them for decision-making. However, the majority of vintage assets have toughness data gaps because most Material Test Reports (MTRs) do not include toughness test results, tests which were not required by the manufacturing specification API 5L for line pipes. Prior papers have described most of the available nondestructive techniques to mechanically probe the pipe surface via indentation, frictional sliding, and planing-induced microfracture.This paper contributes quantitative, third-party accuracy validation data for nondestructive testing of pipe toughness by planing-induced microfracture — not previously reported — together with a case study in which those data were leveraged for integrity management and further recent developments related to seam toughness properties. The third-party validation comprised more than 25 pipe samples blind-tested with the Blade Toughness Meter (BTM), with the predictive models statistically analyzed against laboratory J-R fracture mechanics testing of compact tension (CT) specimens. A case study is presented in which data from opportunistic digs on a pipe population is used to establish a TVC toughness record, with conservative properties set after accounting for sample size, variability among results, and individual measurement accuracy. The statistical treatment draws on other recent publications on population sampling. As a new development, accuracy performance data from a recent PHMSA project will be presented, in which advanced machine learning combined frictional sliding data with planing-induced microfracture data to accurately quantify the toughness of ERW longitudinal seams.Readers and attendees will receive quantitative data on the current state of the art of the technologies, gain insight into approaches for combining data from multiple sources or test locations to reach TVC, and see how operators are prioritizing excavations and repairs based on the actual cracking resistance of specific pipe populations.Keywords: Material Fracture Toughness; Pipe Toughness Determination; Traceable, Verifiable, and Complete (TVC) Records; Direct Assessment; Engineering Critical Assessment (ECA); Integrity Management
ILI Run-to-Run Comparisons – Spreadsheet Comparisons Are Not Good Enough
Tom Bubenik1, Matt Ellinger1, Stacy Hickey1, Adriana Nenciu1, Bill Harper1, Pam Moreno2 1DNV, Dublin, USA. 2DNV, Katy, USA
In-line inspections (ILIs) are a preferred methodology for assessing and managing the threat of metal loss (corrosion) in pipelines. The results from a metal loss ILI survey can be utilized to evaluate the current integrity state of the pipeline with respect to the threat. When subsequent metal loss ILI survey data are available, the combined results can be used to assess the possible future state of the pipeline. This can be accomplished by performing an ILI run-to-run comparison between the subsequent inspections. The final output of a fundamentally sound ILI run-to-run comparison analysis entails establishing final corrosion growth rates (CGRs) along the length of the pipeline, applying the CGRs to the ILI-reported metal loss anomalies, calculating time to criticality, optimizing field inspection programs, and establishing reassessment intervals.ILI vendors typically provide a final report, a spreadsheet listing, and signal data files (and accompanying viewing software) as a part of the ILI project deliverables. The pipeline industry often utilizes software solutions (i.e., spreadsheet-based solutions) to perform comparisons between subsequent ILI surveys. This typically includes performing pit-to-pit (i.e., box-to-box) comparisons from which CGRs are established based on the differences in reported depths divided by the time between the subsequent ILI surveys. These CGRs may be established on a per-anomaly basis or on a larger scale, such as an average or 95th percentile CGR within a segmented portion of the pipeline.However, software solutions based on spreadsheet listings are severely limited by the accuracy of the ILI detection and sizing results. Even if the ILI system meets the stated performance specification (i.e., ±10% 80% of the time), the resulting software solutions can lead to an inaccurate depiction of the true CGRs along the pipeline. For example, spreadsheet-based analyses will inevitably result in negative CGRs (self-healing pipe) and extremely high CGRs (unrealistic except in extraordinary circumstances). Frankly stated, spreadsheet-based CGRs are misleading, inaccurate, and inappropriate to use in integrity-related decision making.ILI signal review analyses (signal-to-signal comparisons) are a necessary part of sound ILI run-to-run comparison programs. If implemented correctly, an ILI run-to-run comparison program that includes ILI signal review analyses will result in more accurate corrosion growth rates that are agnostic to ILI reporting accuracies. This paper describes (1) why spreadsheet-based CGRs are so often wrong and (2) the practical differences between ILI run-to-run comparison programs that do and do not include ILI signal review analyses. The results provide the basis for establishing defensible and accurate ILI run-to-run comparison programs that can be utilized to manage the integrity of their pipeline assets.
In the Groove: Direct Imaging ILI of Selective Seam Weld Corrosion Defects
Greer Simpson1, Corey Richards1, Marshall Lu1, Aaron Schwing2, Jason Moritz2 1DarkVision, North Vancouver, Canada. 2Flint Hills Resources, Wichita, USA
This paper presents lab and field-validated methods for pipeline operators to accurately detect, size, and subsequently prioritize digs for Selective Seam Weld Corrosion (SSWC) defects with direct imaging ILI technology. Building on the complex crack and corrosion morphologies mapping capabilities of direct imaging ILI technology introduced by Simpson et al. at PPIM 2025 and 2026, the technology is further advanced and applied to SSWC features. The increased resolution and combined direct metal loss and crack inspection abilities are shown to be particularly advantageous in differentiating SSWC anomalies from generalized corrosion interacting with the long seam.The unified multimodal inspection capabilities of direct imaging ILI technology presented in this paper accurately measure both the general wall loss over long seam welds and the characteristic sharp, narrow grooving feature along the weld. This single-run method overcomes the limitations of inferred or amplitude-based methods and data registration challenges used in legacy ILI tools. Detailed in this paper is a comprehensive method to evaluate SSWC across its full range of morphological components, from general corrosion and preferential weld-seam grooving to coincident cracking. Lab validation and field in-ditch NDE dig results across a wide range of groove widths, depths, aspect ratios, and sharpness are presented. Direct imaging ILI is applied to:- Clearly differentiate general corrosion occurring on or near a long seam from true preferential corrosion along the weld bondline.- Accurately size grooving in the weld seam and simultaneously evaluate for crack-like features extending beneath it. – Identify locations with high potential for future SSWC growth by resolving shallow corrosion from coating failure and water ingress.A variety of field digs and NDE results are compared to direct imaging ILI findings and presented as case studies supporting the methodology derived in the lab validation phase. Recommendations are presented to further improve the evaluation and prioritization of SSWC features through ILI inspection methods.Keywords for subject area: ILI Application, Selective Seam Weld Corrosion, SSWC, Crack, Metal Loss, Direct Imaging
From Qualification Testing to Field Application: Understanding the Performance Envelope of Compression Sleeve Repairs
PUSHPENDRA TOMAR1, Diana Zapata2, Chris Vrolyk3 1T.D Williamson, Grapevine, USA. 2Williams, Houston, USA. 3T.D Williamson, Edmonton, Canada
To ensure upmost safety standards, pipeline integrity regulations require performance-based evaluation of repair technologies, and the qualification procedure should demonstrate that the repair methods can maintain pipeline integrity under representative loading conditions and integrity threats. Establishing the appropriate performance envelope of repair technologies is therefore needed for defining defect applicability, identifying limitations, and supporting defensible integrity management decisions.Compression sleeve repairs are manufactured from low-carbon steel materials comparable to those used in line pipe and function by inducing compressive stress in the carrier pipe through controlled sleeve installation and thermal expansion effects. The resulting compression reduces stress at the repair location while the sleeve provides additional structural reinforcement. This paper reviews the technical basis for the performance-based qualification of compression steel sleeve repairs by examining the results of multiple laboratory, full-scale, and field validation programs conducted over several decades. The focus is to define acceptability limits or performance envelopes of compression sleeve repairs. The paper evaluates the engineering evidence or where applicable, lack thereof, to demonstrate the repair can achieve its intended performance. Using technical evidence, the paper translates testing results into practical repair selection guidance. The paper also evaluates the field performance of the compression repairs over the last 30 years. Industry operating experience reviewed by the authors includes thousands of compression sleeve installations across transmission pipeline systems, providing a substantial body of service history for comparison with controlled testing programs. The paper also discusses experience from one early adopter of compression sleeve repair technology, including how field experience and engineering evaluations have informed repair applicability for selected defect types and operating conditions. Finally, the paper identifies integrity threats and operating conditions where additional qualification testing may be warranted, including cases where the use of compression sleeve repairs should be supported by further engineering evaluation or additional performance data before application.Keywords for subject area = Qualification Testing
One Dent, Many Views: Leveraging Multi-ILI Insights to Improve Dent Prioritization
Dane Burden1, Karim Kabbara2 1T.D. Williamson, Salt Lake City, USA. 2Marathon Petroleum Corporation, Los Angeles, USA
One Dent, Many Views: Leveraging Multi-ILI Insights to Improve Dent PrioritizationDane Burden, Principal Software Engineer – Data Science, T.D. Williamson, USAKarim Kabbara, Program Manager – Marathon Petroleum CorporationEffective management of dent-related integrity threats continues to be a challenge for pipeline operators, particularly as inspection technologies advance and the volume of available data grows. Standards such as American Petroleum Institute Recommended Practice 1183 (API RP 1183) provide a strong foundation for dent assessment and prioritization. However, operators still face difficulty in consistently distinguishing benign deformations from those that pose a credible threat to pipeline integrity. This paper presents a practical, data-driven approach to prioritizing dents based on integrity threat level, using raw signal data from multiple in-line inspection (ILI) technologies. The approach combines geometric characterization, strain-based indicators, and feature interaction assessment using aligned datasets from high-resolution deformation and magnetic flux leakage (MFL) tools. By analyzing multiple datasets collected during the same inspection, the methodology improves visibility into dent state, interaction with pipeline system components, and the presence of coincident features such as corrosion, gouging, or crack-like anomalies. This type of integrated assessment complements the screening guidance in API RP 1183 and is particularly valuable for more complex dent conditions where raw signal data provides additional context. Several case studies are included to demonstrate how the methodology has been applied across different pipeline systems. These examples show improved differentiation between low-risk dents and features requiring immediate action. Results indicate that incorporating multiple ILI datasets leads to more reliable integrity assessments, reduces unnecessary conservatism, and helps operators better focus resources on the features that matter most. Overall, this work provides a practical path for incorporating advanced dent assessment techniques into existing integrity management programs while remaining aligned with current industry standards.Keywords: Dent prioritization Multi-ILI data integration, In-line inspection (ILI) analytics, Dent integrity assessment, Feature interaction, API RP 1183, Dent Management, Data-driven integrity management
Old Pipe, New Fuel: Defects Found by Low‑Field MFL ILI ahead of Hydrogen Conversion
Mike Kirkwood1, Paul Roovers2 1T.D. Williamson, Swindon, United Kingdom. 2Fluxys, Brussels, Belgium
As transmission operators evaluate the conversion of existing natural gas infrastructure for hydrogen service, understanding the condition of legacy pipeline assets has become increasingly important. While many threats are well understood for natural gas transmission, features such as localized hard spots, gouges, arc strikes, mechanical damage, and crack-like indications may present elevated risks in hydrogen environments due to the potential for hydrogen-assisted cracking and embrittlement.To support its hydrogen transition strategy, Fluxys, the Belgian gas transmission system operator (TSO), conducted a pre-conversion inline inspection (ILI) assessment on a 15.09 km, 12.75-inch natural gas pipeline. The inspection utilized a combination ILI platform incorporating conventional sensors together with a Low-Field Magnetic Flux Leakage (LFM) module designed to identify metallurgical and mechanical anomalies that are often difficult to detect using traditional inspection technologies alone.In addition to identifying typical metal loss features, the inspection detected a number of atypical indications including areas suggestive of increased hardness, gouging, re-rounded dents, arc strikes, and crack-like features. Although these anomalies did not represent immediate integrity concerns under existing natural gas operation, they were considered potential candidates for further investigation before hydrogen conversion.Targeted excavations and non-destructive examinations (NDE) were subsequently performed to validate the ILI findings and assess their significance relative to future hydrogen transport. The results provide valuable insight into the types of latent pipeline features that may exist within ageing gas transmission systems and demonstrate how enhanced inspection technologies can support integrity decision-making during hydrogen conversion projects.This paper presents the inspection results, excavation findings, technology performance, and key lessons learned from applying Low-Field Magnetic Flux Leakage technology as part of a pre-hydrogen pipeline assessment program.Keywords: Hydrogen, pipeline conversion, hydrogen readiness, inline inspection (ILI), low-field magnetic flux leakage (LFM), hard spots, gouging, re-rounded dents, arc strikes, crack-like indications.
The Long‑Seam Challenge: EMAT Detection and Sizing of Seam‑Aligned SCC
Matthew Romney1, Sean Moran2, Chelsea Gibbs1, David Sunwall1, Taylor Tribe1 1T.D. Williamson, Salt Lake City, USA. 2Williams, Salt Lake City, USA
Stress corrosion cracking (SCC) is a critical feature for in-line inspection (ILI) electromagnetic acoustic transducer (EMAT) to properly detect and characterize but can be challenging when coincident with long seam. In these cases, weld geometry can upset transmitter and receiver assemblies, mask the crack signals, complicate sizing accuracy, and lead to false indications or missed defects. As a result, distinguishing true seam SCC from benign long-seam features remains a persistent industry challenge. This paper presents an EMAT approach applied in a challenging long-seam inspection scenario. The EMAT system utilizes a pitch-catch configuration with a guided shear horizontal (SH) wave that propagates circumferentially around the pipe wall. In the inspection campaign described in this paper, this wave mode provided a response mechanism for axial crack colonies by intersecting those features at a near-perpendicular angle, including SCC located within or near the seam. The EMAT system incorporates multiple transmitter and receiver arrays distributed circumferentially around the inspection platform, providing overlapping 360° coverage of the pipe circumference. In the case study, this architecture helped provide alternate signal perspectives where localized effects such as sensor lift-off or elevated weld noise were present. To further support interpretation, a multiple-technology ILI system complemented the EMAT system by providing additional context for defect detection, classification, and sizing evaluation during the inspection campaign. A recent inspection campaign with a major gas transmission operator is presented as a case study evaluating EMAT response to seam-aligned SCC. The observed results provided useful evidence of detection and characterization capability for the pipeline conditions inspected. Quantitative outcomes, supported by analyst review, showed opportunities to distinguish crack-like responses from weld-related artifacts in the inspected segments. The findings highlight how key design elements, including SH-wave propagation, circumferential sensor coverage, robust mechanical design, and complimentary ILI technologies contributed to the inspection results observed in this case study. The paper will focus on what was learned from this inspection campaign and the opportunity these results may represent for future seam SCC integrity programs. Keywords: electromagnetic acoustic transducer, EMAT, long seam, inline inspection, ILI, stress corrosion cracking, SCC
Integrated IMU Run-to-Run Alignment and Machine Learning Workflow for Automated Detection of Landslide-Pipeline Interactions
Devin Frioud1, Doug Dewar2, Sarah Newton3, Andrew Johnson4, Aron Zahradka5 1BGC Engineering, Victoria, BC, Canada. 2Pembina, Calgary, AB, Canada. 3Cambio Earth, Calgary, AB, Canada. 4Cambio Earth, Vancouver, BC, Canada. 5Cambio Earth, Victoria, BC, Canada
Inertial Measurement Unit (IMU) bending-strain data collected during in line inspections (ILI) are widely used to monitor external force related and specifically landslide induced deformations. Previous work demonstrated that machine learning (ML) can effectively prioritize individual bending-strain features associated with landslide interactions from a single inspection. However, identifying movements between inspections remains a significant challenge, as accurate run-to-run comparison requires precise alignment of ILI datasets. Chainage misalignment, odometer drift, wheel slip, and differences in vendor processing can introduce sufficient misalignment to obscure or falsely indicate pipeline movement. This study describes an integrated workflow combining automated run-to-run alignment with ML-based strain feature classification to enable source-attributed detection of pipeline movement between inspections.The workflow first aligns ILI datasets in a multi-stage framework that estimates a smooth warping compensating for both systematic chainage drift and localized distortions, while preserving genuine pipeline deformation. This allows subtle changes in bending strain to be distinguished from alignment errors. Once aligned, bending-strain signals from successive runs are differenced to isolate candidate pipeline movement features, which are screened using a convolutional neural network (CNN) classifier to identify changes associated with landslide-related deformation.By combining signal alignment with automated ML-based screening, the workflow enables efficient comparisons between inspections acquired under different conditions, including direct comparison of inspections processed by different vendors. The approach extends previous ML-based strain feature classification into a complete run-to-run change detection framework, providing pipeline operators with an automated method to identify, prioritize, and monitor new or evolving geohazard-related deformation. This workflow will reduce manual review effort and support earlier identification and enhanced monitoring of landslides.
ILI Validation Spools: A Methodology for Improved Performance Assessment
Ahmed Hassanin1, Gary Winfrey2, Tim Mally3 1Acuren Inspections, Magnolia, USA. 2Enbridge, Houston, USA. 3Henkel, Houston, USA
In-line inspection (ILI) validation programs commonly rely on comparisons of reported indications against field measurements obtained during verification excavations. While excavation remains an important component of integrity management, validation programs based primarily on field digs can be constrained by cost, feature distribution, accessibility, and limited control over anomaly geometry. These limitations can make it difficult to obtain validation datasets that are sufficiently broad, repeatable, and traceable for evaluating ILI tool performance.This paper presents an engineered validation spool methodology intended to supplement excavation-based validation programs and improve the quality of inputs used in API 1163 validation. Since federal regulations for required ILI assessments on both gas and hazardous liquid pipelines reference API 1163, improved validation inputs can support both integrity management and regulatory compliance objectives. The methodology uses fabricated pipe spools containing designed and intentionally introduced features, with independent dimensional characterization to establish truth data for evaluating ILI-reported results. Feature populations are selected based on the validation objectives, including depth, length, width, spacing, interaction, and reporting threshold considerations. The process includes spool design, feature fabrication, dimensional characterization, NDE, QA/QC documentation, and structured assessment of ILI-reported results using applicable validation methods.A metal-loss validation spool case study will be used to demonstrate the application and outcomes of the methodology. The validation spool includes a controlled feature matrix with varying metal-loss aspect ratios and severity levels to evaluate ILI performance across a representative range of feature geometries. The spool was reinforced with composite material overwrap to restore fitness for service while preserving the controlled feature set for ILI validation. This approach provides operators with a practical means to increase confidence in ILI performance assessments, strengthen the technical basis for integrity decisions, and reduce the cost and scope of traditional validation programs.
Transforming Pipeline Integrity NDE data collection
Samuel Kindel1, Wendy Aucoin2 1Enbridge, Houston, USA. 2Cenozon, Calgary, Canada
Transforming Pipeline Integrity NDE Data Collection: Standardizing Field Data Capture to Improve Integrity Data QualityAuthors: Samuel Kindel, Sr. Specialist Inspection and Monitoring IRM Planning Corrosion and Metallurgy – EnbridgeWendy Aucoin, Business Analyst/Customer Experience & Solutions Lead – CenozonPresenter: Samuel KindelTechnical Category: Data Management/Digital TransformationAs pipeline integrity programs continue to generate increasing volumes of Non-Destructive Examination (NDE) field data, operators face ongoing challenges in maintaining data quality, consistency, traceability, and timely access to inspection information. Paper-based processes, disconnected field applications, and inconsistent data capture practices can lead to additional quality assurance effort, reporting delays, and variability in the completeness and reliability of inspection records.This paper describes the collaborative effort between Enbridge and Cenozon to redesign the NDE field data collection process through the implementation of a standardized digital workflow. The objective was not simply to replace paper forms, but to establish a consistent approach to collecting, validating, and managing inspection data across multiple integrity programs while improving data quality at the point of capture.The project focused on developing standardized digital forms, embedded validation rules, quality control checkpoints, photo documentation, digital approvals, and a complete audit trail to support the collection of accurate and consistent inspection data. Particular attention was given to reducing manual data verification, improving the completeness of field records, and creating a repeatable process that could be adapted to different inspection activities and evolving business requirements.The paper also examines the importance of data governance within field operations, including standardized workflows, consistent data structures, and improved traceability from field collection through engineering review. Lessons learned throughout the design and implementation process—including stakeholder engagement, change management, and configuration decisions—will be discussed, along with the operational and cost impacts observed following deployment.Attendees will gain practical insight into the challenges of modernizing NDE field data collection, the considerations involved in implementing standardized digital workflows, and the value of improving data quality and consistency at the source to support more efficient integrity management.
Overcoming data quality challenges during in-situ material nondestructive testing
Emily Brady1, Janille Maragh2, Pooya Delshad3 1Exponent, Inc., Houston, TX, USA. 2Exponent, Inc., Menlo Park, CA, USA. 3PG&E Applied Technology Services, San Ramon, CA, USA
Under 49 CFR § 192.607, operators lacking traceable, verifiable, and complete (TVC) records may use nondestructive testing (NDT) for materials verification, provided the NDT methods are validated by a subject matter expert against destructive test results on material of comparable grade and vintage. Historically PG&E has used real-time SME review to ensure the quality and reliability of in-situ NDT data, namely instrumented indentation testing (IIT) and chemical composition measurements (i.e., XRF, LIBS). This introduces logistical challenges, such as coordination of SME availability, especially where rapid turnaround time is necessary. To address this, targeted quality-checking tools have been developed to systematically evaluate IIT and chemical composition data at the point of collection, applying automated rules to flag potential anomalies. Some of these checks performed by the tools include validation of tools at the beginning and end of work shifts on verification blocks, assessment of consistency of results between test locations on the same pipe joint, and evaluation of measurement scatter at each test location.These tools were designed to improve data reliability and enable faster feedback loops, allowing technicians to collect additional data in a timelier manner when needed. Importantly, the tools are designed to integrate seamlessly into technician workflows, emphasizing ease of use and minimal disruption to workflow. By embedding these data validation capabilities directly into the data acquisition process, this approach supports a transition toward reducing reliance on real-time SME review while maintaining compliance and data integrity.
Are Detailed Crack Profiles Producing Less Accurate Assessment Results?
Ben Hanna, Michael Rosenfeld, Adam Steiner RSI Pipeline Solutions, New Albany, OH, USA
It has been historically presented that the size of a crack in a pipeline is the primary factor that controls the results of fitness-for-service assessments. The common practice for these assessments is to use the overall depth and length of the crack and approximate its shape as that of an idealized semi-ellipse, rectangle, or canoe. This can overestimate the area of the actual flaw and greatly overestimate the area that leads to failure, thus producing very conservative burst pressures and remaining lives. As inspection techniques improve, it is becoming more common for pipeline operators to have information on the detailed crack profile. A better assessment method is required to account for the increased fidelity of reported crack shapes.Some fracture mechanics models use an effective area approach (e.g., RSTRENG) where all contiguous combinations of the crack dimensions that make up the profile are evaluated. It is assumed that the area of the pipe wall removed by the crack dictates failure and an effective idealized shape can represent the failure. As such, either the length is established and an effective depth is calculated, or the depth is established and an effective length is calculated. The representative crack shape is the size that produces a limiting factor in the failure analysis. Usually, the minimum burst pressure is used to define the shape. A maximum stress intensity factor also has been employed recently.This paper investigates the use of an effective area approach on detailed crack profiles when calculating burst pressures and remaining lives. Specifically, the study addresses how the method breaks down when profiles become less ideal (i.e., more realistic). Both methods of calculating effective sizes were included, as well as both limiting factors. The investigation was performed considering four commonly used fracture mechanics methods (RSIM-3-04, MAT-8, Modified Ln-Sec, and Raju-Newman). The methods can produce vastly different effective shapes for the same crack depending on the detailed profile and analysis parameters. This paper identifies the boundary conditions for when each method is appropriate to use.Key words: crack management, fracture mechanics, burst pressure, effective area, crack profiles, remaining life
Assessment of Scour Calculations Using Desktop vs. Field Data and Implications for Integrity Management Decisions
Jeffrey Schneider1, Bailey Theriault2, Muhammed Mustafa3 1Geosyntec Consultants, Inc., Milwaukee, USA. 2Geosyntec Consultants, Inc., Bedford, USA. 3Geosyntec Consultants, Inc., Los Angeles, USA
Scour at river crossings presents a potential integrity concern for pipelines because it may result in the temporary or long-term exposure or suspension of a pipeline intended to be buried. Once exposed, the pipeline is potentially subject to excessive bending stress, vortex-induced vibration (VIV), or debris impact. A common approach that Operators implement in a systemwide prioritization of hydrotechnical hazards is to conduct preliminary scour evaluations at crossings to identify crossings that have a high scour potential compared to the relative pipeline depth of cover at a crossing. A given system may have tens of thousands of watercourse crossings, which makes detailed scour evaluations at each crossing time consuming and costly. Therefore, a screening level scour evaluation approach, where publicly available site data is utilized, is one method to relatively rank the scour-related risks at crossings across a pipeline system, allowing Operators to prioritize sites that may warrant gathering of site-specific data and a more detailed scour evaluation. However, there is limited published data on the relative accuracy of the preliminary desktop scour assessments based on publicly available data compared to the detailed assessments that may require significant resources to obtain higher resolution or more accurate site-specific data.This paper will provide a comparison of scour evaluation results for 27 pipeline watercourse crossings utilizing publicly available data compared to site-specific data. For each site, preliminary scour estimates were completed using publicly available digital elevation models (DEMs) for site topography, USGS StreamStats for flow rates, and estimated bed material grainsize and channel roughness based on assumed channel characteristics visible in aerial imagery. Preliminary hazard classifications were assigned to each site based on the scour results and assumed pipeline depth of cover. Scour assessments for each site were then updated based on field-collected topography and bathymetry, flow rates, samples of channel bed material, and field observations of channel roughness. Hazard classifications were updated based on new results and field verified pipeline depth of cover. The comparison of the two approaches provides insight into the overall effectiveness of screening level scour assessments using easily accessible public data versus the relative cost-benefit value of obtaining site-specific information and associated changes in site hazard classification.
Validating Composite Repairs for Axial Reinforcement of Pipe to Mitigate Circumferential SCC (CSCC)
Braden Spitzmacher1, Atul Ganpatye2, Elvis SanJuan Riverol1, Tim Mally3, Casey Whalen3, Travis Greenstreet4 1TC Energy, Calgary, Canada. 2TC Energy, Houston, USA. 3Henkel, Houston, USA. 4Acuren, Magnolia, USA
THIS SUBMISSION WILL BE COMBINED WITH SUBMISSION #139. THIS IS APPROVED BY THE PRESENTING AUTHOR.This paper presents a study undertaken to evaluate the effectiveness of carbon-fiber/epoxy composite repair systems for reinforcing pipelines containing severe circumferential crack-like defects, including circumferential stress corrosion cracking (CSCC). Circumferential flaws can pose a significant threat to pipeline integrity when subjected to axial loading caused by bending, thermal expansion and contraction, or longitudinal soil movement. Unlike axial cracking, where repair strategies have traditionally focused on reducing hoop stresses, circumferential cracking requires mitigation of axial loads that promote Mode I crack opening. The objective of this work was to assess whether properly engineered composite repair systems can restore axial load-carrying capacity and maintain structural integrity in pipelines containing significant circumferential defects.The study specifically examined the design, installation, and performance characteristics that govern the effectiveness of composite repair systems for CSCC applications. Particular attention was given to composite-specific variables such as repair thickness, repair length, material stiffness (and therefore composite layer construction and count), load-transfer mechanisms, and installation conditions. Additionally, effect of internal pressure during repair application was addressed. Full-scale testing was combined with analytical development to improve understanding of how these variables influence repair performance under axial loading and to establish a framework for predicting the behavior of repaired circumferential flaws.The experimental program included full-scale tests on both repaired and unrepaired pipe samples containing severe CSCC-type defects. The results demonstrated that the composite repair system substantially increased the axial load resistance of the damaged pipe, maintained reinforcement beyond the onset of yielding in the adjacent unreinforced material, and delivered significant improvements compared to the unrepaired condition. The findings provide practical guidance on the essential variables that must be considered when designing and applying composite repair systems for the mitigation of CSCC and other circumferential crack-like defects, supporting their use as a viable approach for restoring structural capacity under pipeline axial loading conditions.
Seeing Below the Slide – Validating Slipstik as a Rapidly Deployed Landslide Monitoring Technology
Brett Dugan1, Clayton Johnson2, Taylor Arens3, Justin Taylor4, Jeff Lloyd5, Steve Ladavat6, Dennis Fela7 1Pillar Innovations, Morgantown, USA. 2TC Energy, Washington, USA. 3TC Energy, Sugar Grove, USA. 4TC Energy, Elmira, USA. 5WSP, Eliot, USA. 6WSP, Wexford, USA. 7WSP, WExford, USA
This paper presents the field validation and performance of SlipStik, an innovative subsurface monitoring technology designed to detect and characterize shallow landslide movement that may threaten pipeline integrity. Shallow landslides can pose significant risks to buried pipelines, and pipeline operators require reliable monitoring technologies to support safe operation where known landslide threats exist. Many current subsurface monitoring solutions rely on drill rigs and heavy equipment, resulting in high costs and lengthy installation timelines that limit the practicality for rapid response monitoring. The purpose of SlipStik is to address these limitations by providing an agile, casingless subsurface monitoring solution for shallow landslides. SlipStik supports early warning of landslide movement by providing near real time alerts through telemetry, quantifying both magnitude and depth of soil movement. While SlipStik has been previously validated through laboratory testing and full-scale simulations, its performance in active landslide conditions had not been demonstrated prior to this work. This paper examines SlipStik performance through multiple field installations in active landslides. In each case study, SlipStik assemblies were installed on or in close proximity to established industry monitoring instruments, including shape acceleration arrays, inclinometers, and geodetic monuments, enabling direct comparison of SlipStik performance. The paper details the installation process and demonstrates that rapid, hand-installed deployment is feasible and operationally efficient. Results from SlipStik show strong agreement between conventional monitoring technologies for both identified landslide failure planes at depth and measured displacement. In one case study, significant shallow soil movement occurred, ultimately leading to instrumentation failure. Subsequent excavation and inspection of the failed assemblies provided valuable insight into SlipStik’s mechanical response and demonstrated its ability to accommodate large magnitudes of displacement concentrated along discrete failure planes. These findings highlight the robustness of the technology under severe deformation conditions. In addition, SlipStik has been adapted for deep borehole installations of thirty meters or greater, with one successful field installation completed in 2025. This paper also discusses the development of the deep installation approach, associated challenges, and preliminary performance results. Overall, the field case studies demonstrate that SlipStik is a viable, rapidly deployed, and effective subsurface monitoring technology that can enhance pipeline operators’ ability to assess and manage landslide-related threats to pipeline infrastructure
Misaligned by Design? A Data-Driven Look at Pipeline Weld Misalignment
Rhett Dotson1, Kyle Platt2, Grant Myers2, Cassie Ruminski3, Justin Healy1 1D2 Integrity, LLC, Houston, USA. 2Marathon, Cannonsburg, USA. 3D2 Integrity, LLC, Boise, USA
This publication presents a case study on using inertial measurement unit (IMU) data to identify and characterize weld misalignment in pipelines. The investigation was initiated after a weld failure occurred in a 20-inch gas gathering line constructed in 2013. Metallurgical analysis of the failed girth weld found no evidence that weld quality or manufacturing practices caused the failure; instead, field data suggested that the rupture resulted from a combination of weld misalignment and external loads. To evaluate whether IMU data could identify and size weld misalignments, a candidate line from the same construction period was selected for analysis. This paper describes the IMU-based approach, reports the observed weld misalignment distributions from the candidate line, compares those distributions with pipeline construction requirements and ASME B31.8 alignment limits, and presents a field validation of one reported angular misalignment. The results provide a first-of-its-kind view of weld misalignment distributions derived from IMU data and offer operators practical context for interpreting weld misalignment in bending strain analyses, planning validation work, and understanding expected measurement accuracy.
Enhanced Survey Analysis (ESA): Benefits and Methodologies
Grady Smith Enbridge GTM, Houston, USA
Inline Inspection (ILI) data is a foundational component of modern pipeline integrity management programs, supporting regulatory compliance, defect characterization, growth assessments, and repair decision-making. Integrity management practices are typically based on vendor-reported ILI anomaly datasets, which provide a practical and standardized framework for evaluating pipeline condition. However, industry experience has demonstrated that additional insights may sometimes be obtained through detailed review of raw ILI signal data and historical inspection records beyond conventional reporting outputs.Following lessons learned from a prior pipeline failure, Enbridge developed and implemented an internal analytical process known as Enhanced Survey Analysis (ESA). ESA was established as a voluntary enhancement to existing integrity management practices to address opportunities identified during incident investigations and subsequent program reviews. The process is not intended to replace regulatory requirements or standard integrity assessments, but rather to supplement existing workflows through additional analytical rigor where warranted.ESA utilizes a structured and repeatable methodology that includes detailed review of raw ILI signals, joint-by-joint evaluations, signal-to-signal comparisons, and multi-run historical analysis. The objective is to identify corrosion growth trends, non-corrosion anomalies, atypical signal behavior, and data quality concerns that may not be fully characterized or prioritized within standard ILI reporting frameworks. Findings support a range of integrity responses, including targeted excavations, above-ground surveys, enhanced monitoring, engineering assessments, or documented deferral until future inspections, depending on the nature and significance of the indication.An additional application of ESA has been the retrospective evaluation of selected excavations that produced unexpected, inconclusive, or non-matching results. In these situations, signal-level analysis has improved technical understanding of inspection data and, where appropriate, supported discussions with ILI vendors regarding data interpretation and correction. Over time, this feedback process has contributed to improved confidence in inspection results and more effective prioritization of integrity resources.The ESA process is implemented within a documented governance framework to promote consistency, traceability, and auditability while maintaining alignment with applicable regulations and industry standards. Although ESA requires additional analytical effort and resources, Enbridge has elected to continue its application based on observed operational benefits within its integrity management program.Drawing on more than a decade of experience across a large North American natural gas transmission system, this paper presents the motivation for developing ESA, describes the underlying methodology, and discusses key lessons learned, outcomes, and practical considerations. The intent is to share operational experience and provide insights for operators seeking to further enhance ILI-based integrity management processes.
Leak Clamp Qualification Testing
Parth Patel1, David Futch1, Kimber Burt2, Micah Andrejczak1 1Acuren, Houston, USA. 2Southern Star Central Gas Pipeline, Owensboro, USA
Leak repair solutions are implemented as both temporary measures and permanent repairs. While permanent repair methods such as composite wraps have been extensively validated, temporary fixes such as mechanical leak clamps have undergone comparatively limited testing. These weld-free clamps offer a means of suppressing through-wall leaks on in-service gas and liquid pipelines, providing operators a quick, temporary fix enabling more time to coordinate permanent repairs. However, their performance remains largely uncharacterized across the extensive range of field conditions. This study presents a full-scale test program qualifying a bolted clamp that seats a rubber cone plug over a leak origin, with no welding to the pipe required. Six assemblies were tested across nominal 6-inch and 24-inch diameters under simulated active-leak conditions across three phases: (1) baseline static pressurization to failure, (2) cyclic stability, and (3) failure with a simulated corrosion defect coincident at the leak. This paper explores the findings, examining how clamp performance varies with pipe geometry, pressurization conditions, and defect presence. Collectively, the findings support the use of these clamps as temporary repairs on pipelines operating at reduced pressure.
A Risk Framework for Pipeline Integrity Management and Enterprise Decision-Making
Jason Skow1, Alex Tomic1, Chance Wright2, Smitha Koduru3, Graham Goodfellow4 1Integral Engineering, Edmonton, Canada. 2TC Energy, Calgary, Canada. 3Element Resilence & Risk, Calgary, Canada. 4Goodfellow Risk Management, Newcastle, United Kingdom
In 2024, the Pipeline Research Council International (PRCI) developed a strategic research program (SRP) for Pipeline Risk Management. The 5-year plan includes seven projects; this paper summarizes the work completed in the first SRP project, focused on a Risk Framework and Fundamentals Guidelines. Risk management provides a comprehensive and well accepted process to identify, assess, and mitigate potential threats to pipeline systems, preventing failures that could compromise safety, environmental protection, and operational reliability. It is an effective tool that enables data-driven decision optimization and provides a platform for industry collaboration. The SRP’s goals are to assist the industry in addressing significant gaps that remain within current risk management practices including: a consistent risk framework for the context of pipeline integrity management, guidelines applicable to a broad range of threats, understanding of capabilities of various risk models and guidance on risk tolerance and evaluation. Despite its many benefits, implementing a risk management framework is challenging. Operator capabilities vary, and the resources available within each company for managing and communicating risk factors differ significantly. It is essential to gain leadership support, align goals with decisions, and clearly define roles within the company. The guidelines developed in this project address these challenges and support sound decision-making. The framework bridges the gap between field-level engineering and corporate governance by providing guidance on the level of analysis, the maturity of the models and data used to estimate risk, and the effects of aggregation to solve problems at different levels for the organization. The principles of Enterprise Risk Management (ERM) and Decision Optimization are built into the framework.A key element of the framework is the classification of risk models into categories, each with unique data and model requirements. The model types defined in the project extend the PHMSA classification (qualitative, relative index, quantitative, and probabilistic) by incorporating different levels of data maturity and model maturity, the effects of uncertainty when risks are aggregated, and the appropriate level of decision-making that each can support. A survey of the project team members summarizes the key decisions that are supported by risk assessments in our industry. The Framework and Fundamentals project is a first step toward providing pipeline operators with objective decision-support tools to achieve their goals and improve the efficiency of risk reduction across operational layers, from risk engineers to company executives.
The Cost of a Coarse Mesh: Impacts on SCF and PEEQ Predictions in Dent ECA
Robert Greene, Rhett Dotson, Alec Bagby D2 Integrity, Houston, USA
The use of finite element analysis (FEA) in dent engineering critical assessments only continues to grow as additional natural gas operators receive approval for the Dent Engineering Critical Assessment (ECA) process. The 2026 IPC paper “The Hidden Variable: How Mesh Refinement Shapes Dent Assessments” concluded the importance of mesh refinement during level 3 finite element analyses, and potential limitations if an analyst or engineer fails to perform mesh refinement. This follow-up paper will investigate the effect of fine mesh resolution on Stress Concentration Factor (SCF) and Equivalent Plastic Strain (PEEQ) in focused set of over 20,000 level 3 first order shell models in NPS 32, 0.375” NWT pipe in over 3,000 unique indenter parameters. These indenters contain a mix of reentrant, non-reentrant, shallow (<0.5%) and deep (>9%) reductions, and narrow and broad radii with asymmetric aspect ratios, in restrained and unrestrained scenarios. Performance curves will be generated to show how resulting factors such as SCF and PEEQ change as fine mesh resolution is increased or decreased for each indenter. This paper will help identify factors that may indicate to the analyst or engineer that a selected fine mesh resolution is appropriately sized for the given indenter and restraint condition.
From Noise to Insight: Assessing Small Dents and Geometric Anomalies
Rhett Dotson1, Nima Parsibenehkohal2, Rachel Brossman2, Rob Greene1 1D2 Integrity, LLC, Houston, USA. 2PBF Energy, Los Angeles, USA
Historically, most operators evaluated dents only when they met in-line inspection reporting requirements or regulatory response criteria. These thresholds typically identified dents with depths of 2% of pipe diameter or greater. However, after several incidents involving dents less than 1% deep led to a published advisory in Canada, many operators began examining shallower dents. Because limited research has investigated minimum evaluation thresholds for pipeline deformations, there is no industry agreement on a reasonable minimum depth for evaluating pipeline dents. This issue may be compounded by the performance of in-line inspection tools on shallow features. This publication examines in-line inspection tool repeatability and dent severity for small dents and geometric magnetic anomalies in liquid pipelines with diameters between 8 and 12 inches. It also examines caliper-noise challenges in small dents from repeat in-line inspections and provides guidance on evaluation thresholds for dents ranging from 0.5% to 1% deep. The outcomes identify practical evaluation thresholds and highlight opportunities for future research into shallow-dent assessment.
Program to Assess Existing Pipelines for Reuse in Hydrogen Service
Taylor Shie1, Christopher Stolte1, Wim Guijt2, Huub Hillen3 1Shell, Houston, TX, USA. 2Shell, The Hague, Netherlands. 3Shell, Amsterdam, Netherlands
Safely reusing pipeline assets for hydrogen service is a critical need for the energy transition. In order to do this, companies must have structured programs to perform integrity assessments and materials testing to ensure the existing pipeline is compatible with the new service in hydrogen. This paper will outline the program that Shell undertook to consider repurposing two existing pipelines for hydrogen service. One pipeline was constructed in the 1960s with primarily seamless pipe. The other pipeline was constructed in the 2010s with sour service rated materials. The goal of the program was to repurpose these assets with the intent of operating in accordance with a high stress design (ASME B31.8) which was formerly referred to as Option B (ASME B31.12)This paper will outline the five phases of the project and discuss the results of three of the phases. Phase one was data collection from existing pipeline records and performing in-line inspection of the existing assets. Multiple technologies were run in this phase to assess for metal loss, deformations, and to perform material verification. Phase two was correlating the collected inspection data with pipeline records to determine the locations to collect pipe samples for material testing. Phase three was the performance of the material testing. Phase four was the performance of a complete feasibility assessment. Phase five is the planned assessment and remediation work prior to converting service. Note, the details of phase three and four are the subject of another paper.The collaboration of the Shell Hydrogen Technology pipeline research program with the Shell Hydrogen Business development team will also be discussed. A unique relationship was formed to be able to execute cutting edge research while meeting the business development needs.There will be a complementary paper to this one presented at the 2027 Pipeline Research Council International (PRCI) Research Exchange (REX) that focuses on feasibility assessment.Keywords: Hydrogen, Conversion of service, emerging fuels
Accurate Location of Offshore Pipeline Obstructions Using Dynamic Pressure Wave Reflection Analysis: Chevron Angola Field Experience
Stuart Mitchell1, Nikolaos Salmatanis2 1PipeSense, Houston, USA. 2Chevron, Houston, USA
AbstractLocating obstructions in offshore pipelines presents a significant operational challenge, particularly when access is limited and conventional methods such as rescue pigs, electromagnetic tracking, or excavation are impractical or costly. Whether caused by stuck pigs, hydrate plugs, debris, or other restrictions, accurately identifying the location of an obstruction is critical to minimizing downtime, reducing operational risk, and planning effective remediation.This paper presents Chevron's operational experience evaluating pressure wave reflection technology to locate pipeline obstructions on two offshore pipelines in Angola. The work demonstrates how induced pressure pulse testing, high-speed pressure acquisition, and dynamic pressure wave reflection analysis can be used to accurately determine the linear location of an obstruction without interrupting normal pipeline operations or requiring specialized tracking tools.The first case study involved a 20-inch natural gas pipeline approximately 35 km in length where only a single field processing unit could be deployed. Because the pipeline was fully obstructed, the speed of sound could not be directly measured and was instead calculated from the pipeline operating conditions and gas composition. Despite these constraints, repeated pressure pulse testing produced consistent reflection signatures that identified the obstruction approximately 11.3 km downstream of the launch facility.The second case study involved a 16-inch offshore crude/multiphase pipeline flooded with seawater. Unlike the first deployment, instrumentation was installed at both ends of the pipeline, allowing the speed of sound to be directly measured from end-to-end pressure wave propagation. Controlled pressure releases from both locations generated repeatable reflection signatures that independently identified the obstruction within approximately 690–733 m of the launcher. The dual-ended configuration improved confidence in the calculated location and demonstrated an obstruction location accuracy of approximately ±30 m under field conditions.Beyond presenting the testing methodology, this paper discusses the practical considerations that influence measurement quality, including sensor placement, release energy, pipeline fluid properties, obstruction proximity to the release location, and the importance of accurately determining wave propagation velocity. Lessons learned from both deployments are compared to illustrate the differences between single-ended and dual-ended testing configurations and the resulting impact on confidence and accuracy.The authors conclude by discussing how dynamic pressure wave reflection analysis provides operators with a rapid, non-intrusive method for locating offshore pipeline obstructions while reducing uncertainty, avoiding unnecessary intervention activities, and improving planning for remediation. The Chevron field experience demonstrates that this approach can provide a practical addition to the pipeline integrity toolkit for locating stuck pigs, hydrate plugs, debris, and other flow restrictions across a wide range of offshore pipeline applications.Keywords – Non-intrusive obstruction detection
PIPELINE OPERATORS FORUM – 2026 UPDATES OF GUIDELINES AND SPECIFICATIONS
Sieger Koops1,2, Peter van de Camp1,3, Stefan Klein1,4 1Pipeline Operators Forum, Hilversum, Netherlands. 2Gasunie, Groningen, Netherlands. 3Shell, Amsterdam, Netherlands. 4GASCADE, Kassel, Germany
The Pipeline Operators Forum (POF) is a non-profit organization of 32 pipeline operators dedicated to sharing best practices in pipeline inspection and integrity management. Its goal is to improve pipeline safety, environmental protection, and operational reliability worldwide. POF publishes publicly available specifications, recommended practices, and guidelines that are regularly reviewed and updated.This paper highlights the 2026 editions of POF 100 (Specifications and Requirements for In-Line Inspection of Pipelines) and POF 300 (Achieving Successful In-Line Inspection), which provide practical guidance for pipeline operators and contractors. The 2026 revision of POF 100 enhances understanding of ILI performance, data quality, and decision-making, strengthening its role as a practical framework for interpreting inspection data and results.The updated POF 300 extends guidance on successful ILI programs with new approaches to baseline inspection planning, technology selection, acceptance criteria, and risk management. It also includes updated industry statistics and dedicated guidance for CO2 and hydrogen pipelines.
Hard Spot Inspections in Multi-Diameter Low-Pressure Gas Pipelines
Lance Wethey1, Dominik Nieberg2, Stefan Vages1, Peter Clyde3 1ROSEN USA, Houston, USA. 2ROSEN GMBH, Lingen, Germany. 3Louisville Gas & Electric, Louisville, USA
Hard Spot Inspections in Multi-Diameter Low-Pressure Gas Pipelines In response to PHMSA’s RIN-2 regulations and advisory bulletin 2024-26725, pipeline operators such as Louisville Gas and Electric (LG&E) have incorporated hard-spot in-line inspections into their integrity management programs. LG&E operates numerous natural gas transmission pipelines in the greater Louisville, Kentucky area, many of which were constructed in the 1950s and present significant challenges for in-line inspection (ILI). Multi-diameter configurations and transient operating conditions create an environment that complicates the reliable passage and performance of ILI tools. LG&E currently employs high-resolution geometry and metal-loss technologies optimized for low-pressure, multi-diameter systems and has partnered with ROSEN to develop MFL-C and EMAT inspection solutions for these assets. To address the emerging hard-spot inspection requirement, ROSEN proposed its ROMAT DMG technology. However, this solution had not yet been adapted for low-pressure, multi-diameter pipelines. The dual-magnetizer MFL-A configuration used for hard-spot detection is longer and generates more friction than standard MFL-A tools, increasing the difficulty of navigating tight-radius bends and closely spaced fittings under minimal differential pressure—conditions necessary for stable run behavior and high-quality data collection. As a result, customized inspection solutions were defined and developed through a phased process encompassing conceptual design, detailed design, manufacturing, assembly, and full-scale testing. This paper describes the development program, including key design considerations, testing observations, and lessons learned. It further discusses the unique challenges of hard-spot inspections in low-pressure, multi-diameter environments and presents operational insights and results from LG&E’s completed inspections.
How Five Years of Safety Case Assessments Reveal System-Wide Integrity Opportunities
Caitlin Garcia, Niharika Burla Enbridge Gas Transmission & Midstream, Houston, USA
Safety Case approaches have long been required for high-hazard industries in the United Kingdom, Australia, Norway, and other regions that oversee offshore petroleum, nuclear, aviation, and dam safety infrastructure. While Safety Case is not mandated for United States gas transmission pipeline systems, the core principles of structured hazard identification, defensible assurance, and transparent risk-informed decision-making align closely with North American frameworks such as OSHA Process Safety Management, PHMSA’s Mega Rule requirements for traceable, verifiable, and complete data, BSEE’s SEMS requirements, and Canada’s Safety Management Systems. This paper summarizes insights from five years of voluntarily implemented Safety Case assessments and conducted across multiple assets operating under diverse regulatory, geographic, and operating conditions. These assessments were performed as independent, structured evaluations of integrity threats, preventive and mitigative controls, and assurance activities, and were repeated over multiple cycles to capture both point-in-time findings and longer-term trends. While individual assessments generated numerous findings, their greatest value emerged from the recurring themes consistently observed across systems, threat types, and integrity programs. Common themes included data quality gaps, modeling inconsistencies, validation challenges, and governance interfaces that may have impacted the clarity and defensibility of integrity decisions. By examining multiple Safety Case cycles, the paper illustrates how independent, structured reviews help operators move beyond isolated issues to recognize broader systemic patterns, strengthen risk management practices, and mature their internal assurance frameworks. This case study demonstrates how Safety Case principles can function not only as independent assurance, but also as a repeatable framework to drive continuous improvement, enhance cross-functional alignment, and clarify accountability across engineering, operations, and integrity functions. Practical examples demonstrate how Safety Case recommendations have enhanced existing integrity management programs by improving data confidence, increasing transparency, and supporting more defensible risk-informed decisions. The lessons learned provide a pathway for operators seeking to leverage Safety Case principles as a complementary assurance tool within the North American regulatory environment.
Operator’s Experience on ILI Crack Detection Tools – Case Studies from History to Recent Implementation
Lewis Li, Amal Elsisi, Katherine Gao, Andrew Greig Trans Mountain, Calgary, Canada
Cracking remains a critical threat to pipeline integrity. Without effective management strategies, crack-related defects can lead to leaks and ruptures, resulting in significant environmental, safety and societal consequences. In-Line Inspection (ILI) technologies play a vital role in the detection and characterization of crack-like features without disrupting normal pipeline operations. Over the past several decades, continuous innovation in crack detection technologies provided improved detection capability with enhanced accuracy and reliability, thereby increasing the confidence in pipeline integrity management. Key developments include Magnetic Flux Leakage-Circumferential (MFL-C), Electro‑Magnetic Acoustic Transducer (EMAT), Ultrasonic Crack Detection (UTCD), and multi‑angle Phased Array Ultrasonic Testing (PAUT) technologies, each offering unique capabilities and advantages for specific pipeline conditions and crack morphologies.Within the operator’s large-diameter liquid transmission system, these technologies have been progressively implemented as they became available. This evolution reflects a transition from the earlier detection that primarily focused on open crack tip morphology to more advanced, dedicated tools featuring tight crack detection in both pipe body and weld zones. Through selected case studies, this paper highlights several key aspects of this technological progression through, including ILI tools performance and sizing tolerances, classification of detected features in-ditch nondestructive examination (NDE), and the correlation between ILI results and NDE findings.Although the use of multiple ILI technologies enables a more comprehensive evaluation of pipeline condition, it also introduces challenges with data interpretation and integration. This study discusses a practical approach for reconciling differences between datasets and improving confidence in integrity assessments. The findings demonstrate the value of combining multiple ILI technologies to enhance defect detection and characterization, and highlight the importance of close collaboration with ILI vendors for signal interpretation, tool validation, and technical support, enabling more informed decision-making for Pipeline Integrity Management Programs (IMP).
Evolution of Geohazard Management at Government Knob Through Repeat IMU Assessment and Field Validation
Alex Brown1, Nicholas Berkholz2, Evan Kostelka3, Casey Dowling1 1BGC Engineering, Golden, USA. 2Energy Transfer, Pittsburgh, USA. 3Energy Transfer, Shreveport, USA
Bending strain derived from Inertial Measurement Unit (IMU) data has been demonstrated to be a useful tool in identifying landslide impact to pipeline infrastructure. At a site in northwest Arkansas, IMU data was used to not only identify impact but was a critical component of the landslide characterization and management strategy. Since installation of line OM-1, a 20-inch natural gas transmission pipeline, in 1968, repeated impact from landslide activity to the pipeline has been recorded. Since 2015, geotechnical investigations, instrumentation, LiDAR, and IMU bending strain analyses have been applied to the site, demonstrating how these data sets can improve understanding of pipeline-ground interaction and can evolve over time.Initial geotechnical investigations and ground inspections identified active, visually apparent landslide movement at a site called Government Knob, but this provided limited insight into the extent of deeper-seated ground movement and its impact on the pipeline. While LiDAR proved valuable for identifying the presence of geomorphic features, the slow rate of movement and subtle nature of the larger landslide complexes limited the effectiveness of LiDAR change detection (LCD) to detect slope movement. Run-to-run IMU bending strain analysis provided the critical link between observed ground movement and pipeline impact, identifying distinct, changing strain signatures associated with multiple bedrock-controlled landslides. Repeated IMU assessments, combined with subsequent field investigations, excavations, and instrumentation readings, refined the geologic model, improved confidence in the interpreted landslide mechanisms, and enabled targeted placement of geotechnical instrumentation. These learnings formed the foundation of a pro-active site monitoring and management program, extent of the planned pipeline replacement, and guided future approaches to similar geohazard sites along Line OM-1.This paper presents the evolution of site understanding, over more than a decade of investigation, and highlights how field observations, excavations, instrumentation, and repeat IMU assessments were used to progressively refine the geologic model and pipeline loading mechanisms. The Government Knob case history demonstrates the value of repeat IMU analysis not only as a screening tool for identifying geohazard impacts, but also as a long-term asset management tool capable of guiding monitoring strategies, supporting mitigation decisions, and improving understanding of complex pipeline-ground interactions in challenging geohazard environments.
Advancements in Dent Strain Assessment: Benchmarking Alternative Methods to ASME B31.8 for Realistic Dent Morphologies
Ahmed Abdelmoety1, Ayman Abbas1, Thomas Dessein1, Taylor Snider2, Jason Moritz2 1Integral Engineering, Edmonton, Canada. 2Flint Hills Resources, Wichita, USA
The current guidance in API 1183: 2020 directs analysts to estimate dent indentation formation strains using Appendix R of ASME B31.8, relying on the local radii of curvature extracted from the surface contours of measured dents, once signal noise has been removed using smoothing techniques. Since the publication of the current recommended practice, several alternative strain estimation methods have been proposed in IPC2022-87168, PRCI MD-5-2, and IPC2024-133905 to address the limitations in the B31.8 equations.These alternative methodologies improve upon the B31.8 approach using some combination of advanced techniques: incorporating the circumferential membrane strain for a more complete characterization of the effective strain; focusing on the deeper portions of the dent (ex. below 85% depth) to define reference undeformed lengths; using a higher-order function to characterise the local dent curvature or deformed lengths while reducing sensitivity to in-line inspection (ILI) tool resolution; and incorporating regression models fit to data generated from finite element analysis (FEA) that account for the change in profile geometry of unrestrained dents due to re-rounding from internal pressure.Although these methods have individually demonstrated improvement over ASME B31.8, they have not been benchmarked against each other. In addition, the vast majority of the FEA cases used by the original authors to validate these models are limited to idealized single-apex, symmetrical dents.In this paper, we evaluate the accuracy of each proposed method against a comprehensive set of FEA cases that feature a range of realistic geometries, including asymmetric single-apex and multi-apex dents. We propose guidance on the application of these models for both restrained and unrestrained dents. Ultimately, this guidance supports more reliable and conservative screening of dents to limit the number of dents that require costly and time-consuming assessment using FEA.
Demonstrating Enhanced Remaining Life Prediction Using Data Fusion and Existing CGA methodologies.
Andres Gonzalez, Pedro Guillen, Alberto Zepeda, Tuan-Anh Pham ROSEN, Houston, USA
Traditional remaining life estimates based on anomaly “box” dimensions introduce significant uncertainty, particularly in pipelines with complex corrosion morphologies, often leading to conservative or inefficient repair prioritization. These challenges are further amplified when integrating multi-vendor and multi-technology ILI datasets. Reliable remaining life prediction in pipeline integrity management depends on two key factors: (i) accurate in-line inspection (ILI) sizing and (ii) representative corrosion growth rates. Novel machine learning-based Data Fusion (DF) process has demonstrated improved metal loss characterization by integrating axial and circumferential magnetic flux leakage (MFL) data. Leveraging DF outputs, which provide profile-based anomaly characterization, reduces the uncertainty inherent in conventional ILI box-based approaches. By combining axial and circumferential MFL data, a 3D metal loss depth map is obtained, enabling improved assessment when used with established profile-based assessment methods such as Remaining Strength (RSTRENG) and Plausible Profiles (Psqr).This paper presents a case study applying existing corrosion growth assessment (CGA) methodologies to a pipeline containing complex corrosion morphology. Signal-level analysis and box-to-box comparisons were performed to quantify the improvement in remaining life estimates obtained through profile-based corrosion characterization. The results demonstrate that DF is compatible with existing CGA methods and can be seamlessly integrated into integrity management frameworks. The combined application of DF and appropriate CGA enhances reliability in anomaly sizing and remaining life prediction, enabling more informed and optimized integrity decisions.
No Hay, All Needles: Rethinking Run Comparison with Statistical Crack Depth Profiling
Jason Fischer1, Dan Seman1, Jordi Aymerich2, Alessandro Morandini3, Steven Renaud2, Katherine Hartl4, Lamar Frisby5 1Marathon Pipeline, Findlay, USA. 2NDT Global, Calargy, Canada. 3NDT Global, Barcelona, Spain. 4NDT Global, Stutensee, Germany. 5NDT Global, Houston, USA
As an operator's pipeline integrity program matures, additional analysis and services beyond the standard conventional integrity assessments become increasingly effective at managing known threats. Accomplishing this requires advanced ILI technologies combined with sophisticated data analytics that extend beyond traditional engineering assessments.One such approach is the use of ILI reinspection data, Run Comparison (RunCom) analysis, and crack growth profile comparisons. By comparing inspection data on a signal-to-signal and feature-to-feature basis, operators can identify anomalies exhibiting behavior that differs from the surrounding population or from previous inspections. These analyses are specifically intended to highlight features that may warrant additional review, even when they do not exceed conventional fracture mechanics or fatigue criteria.While every ILI inspection is subject to tool-specific sizing tolerances and performance specifications, RunCom analysis provides valuable insight into relative changes between inspections. Features exhibiting growth patterns, profile shape changes, unexpected signal responses, or behavior inconsistent with historical trends can be identified and prioritized for engineering review. This allows operators to investigate potential threats that may not be apparent through standard severity calculations alone.The absence of statistically significant depth growth does not necessarily indicate that a feature is not growing. Rather, it may reflect the limitations of measurement uncertainty associated with the inspection technology. For this reason, crack growth profile comparisons and RunCom analyses are used in conjunction with traditional integrity assessments to identify anomalies that demonstrate unusual behavior and could represent an elevated risk to the pipeline, even when conventional fracture and fatigue analyses indicate acceptable remaining life.This paper outlines an advanced crack depth profile comparison methodology, developed by NDT Global to identify cracks with depth profile changes that otherwise have depth differences within-tool-tolerance. In partnership with Marathon Pipe Line LLC, this comparison was used to identify upcoming digs in advance of when an industry-standard methodology would indicate repair. This study highlights the successful partnership between NDT Global and Marathon Pipe Line LLC in advancing pipeline integrity management, offering valuable insights for the future of pipeline safety and reliability.
Integrating Pipe Manufacturer Hard Spot Classification with High and Low Field Magnetization for Improved Hardness Prediction
Adrian Belanger1, Jing Wang2, Sean Moran3 1TDW, Houston, USA. 2TCE, Calgary, Canada. 3Williams, Salt Lake City, USA
Due to recent failures in non A.O. Smith manufactured pipe, PHMSA released an advisory bulletin (ADB-2024-01 and Federal Register: 2024-2672) that pipeline owners and operators should consider expanding their hard spot threat evaluation to all pipe manufactured prior to 1970. Even before the PHMSA bulletin, industry has been responding to the threat by initiating research projects through the Pipeline Research Council International (PRCI). These projects focused on two objectives, the susceptibility of manufactured pipe to hard spots (PR727-234502) and the performance of ILI tools in characterizing hard spots (PR335-233813). T. D. Williamson has been conducting hard spot inline inspection (ILI) surveys using the high and low magnetization fields on its multiple data set tools for over ten years. With more recent inspections of pipeline manufacturers other than A.O. Smith and a growing body of dig feedback, a classification scheme has been developed to distinguish between the A.O. Smith hard spots that have been the known integrity threat since 1950’s and the hard spots resulting in the more recent failures from other pipe manufacturers. The analysis process is currently in a continual process of refinement as detailed information from the nondestructive examination (NDE) in validation digs has shed new light on the signals measured by the multiple data set tools with high and low magnetization fields. Sufficient data has been collected to incorporate pipe manufacturer as a predictor in the hardness prediction model. Results indicate that hard spots of the same classification can exhibit distinct signal responses between pipe manufacturers, leading to measurable differences in the predicted hardness.This paper describes how the hard spot classification system for different pipe manufacturers was developed through an extensive excavation feedback program conducted by one pipeline operator, and how the resulting insights have been used to refine and validate the analysis for another operator. The findings demonstrate that ongoing collaboration among pipeline operators, ILI providers, and NDE specialists drives continuous improvements in analytical methods. These improvements are transferable across pipeline systems, enhancing both industry research efforts and the overall integrity management of pipeline assets.Keywords: hard spots, low field magnetization, LFM, NDE, A.O. Smith, inline inspection, ILI, pipe manufacturer
Engineering-Driven Standardization and Automated Validation of Inline Inspection Deliverables: An Enbridge Case Study
Brandon Bandoni1, Sheri Baucom2 1Enbridge GTM, Houston, USA. 2Irth, Colorado, USA
A cross-company collaborationInline Inspection (ILI) data is essential for pipeline integrity engineering, enabling defect characterization, growth modeling, regulatory compliance, and informed repair decisions. However, inconsistencies in vendor deliverables, such as variations in templates, terminology, completeness, and calculation logic, can degrade data quality, increase engineering effort, and reduce confidence in the data provided. Addressing these inconsistencies at the source, within the vendor workflow itself, offers a path to both higher data quality and faster delivery.This case study describes how Enbridge and Irth addressed these challenges by designing and implementing an automated, engineering-driven vendor validation framework that applies validation before data ingestion and gives vendors direct visibility into results. The solution centers on the Universal Feature Listing (UFL), a standardized deliverable supported by a formal reporting guide and clearly defined vocabulary. This standardization enabled advanced automated checks for data consistency and integrity across all vendors.Prior to implementation, Enbridge’s ILI data ingestion process relied on manual quality assurance and quality control (QA/QC) reviews performed after vendor delivery. These reviews were limited in scope and capability, focusing primarily on basic formatting and obvious errors rather than comprehensive validation. Because these checks depended heavily on the variable knowledge level of individual analysts, they were prone to error and lacked consistent in-depth validation. This led to delayed downstream engineering analysis and additional cost during times of higher report volume when contracted support was required.With the new approach, automated validation rules are applied before data ingestion to evaluate template conformity, data formatting, permissible values, completeness of required feature attributes (such as length, width, and depth), and calculation logic (such as pressure assessments and interacting defects). The validation logic distinguishes between critical errors that prevent ingestion and non-blocking warnings that inform engineering reviews. Vendors receive direct access to validation results, allowing them to correct issues iteratively before final submission, which significantly reduces the need for back-and-forth communication.Implementation shifted validation from a post-delivery quality review activity to an upstream vendor-facing control point. This change allowed Enbridge and Irth to identify deliverable issues earlier, standardize how vendors interpreted reporting requirements, and reduce the amount of engineering effort required to prepare ILI data for downstream integrity analysis.Quantitative results demonstrate substantial engineering and operational benefits: the average number of revision cycles per inspection decreased from approximately three to one, processing time per inspection dropped from 2.5 days to 0.5 days, and on-time delivery of inspection data improved from 76% to 98% in the three years following implementation. These improvements reduced manual validation effort and expenditure on contracted QA/QC services, while enhancing consistency across multiple ILI vendors.From an engineering perspective, the standardized and validated datasets increased confidence in automated defect sentencing, reduced variability in integrity assessments, and improved traceability of inspection data. This case study demonstrates that embedding engineering validation logic directly into vendor workflows, supported by standardized vocabulary and reporting formats, can materially improve data quality and efficiency. The approach provides a scalable model for operators seeking to strengthen ILI data governance, integrity decision-making, and regulatory compliance.
Unpiggable No More: Successful Inline Inspection in Challenging Gas Gathering Systems
Mukund Belavadi, Adam Pipe, Boyd Abshire Phillips 66, Houston, USA
Inline inspection (ILI) is not mandated by US and many federal regulations for gas gathering systems; however, many operators and producers deploy ILI on selected critical gathering lines to support integrity management programs, improve system reliability, and enable proactive maintenance. Successful ILI execution requires specific operating conditions, including controllable flow rates, appropriate pressures, adequate line cleanliness, and passable pipeline geometry. Achieving these conditions in gas gathering systems is often difficult due to non‑standard designs and normal operating constraints.Both operational and commercial challenges can prevent typical operating conditions from meeting ILI requirements. Operational challenges include excessive or insufficient flow rates, multiple inlets and outlets that create complex and fluctuating flow regimes, extreme operating pressures, and difficulties associated with pre‑inspection line cleaning. Commercial challenges include contractual commitments and producer reluctance to curtail production, reroute gas volumes, or remove lines from service to support ILI operations, whether conducted with natural gas or offline media such as water or nitrogen.Accordingly, successful ILI deployment in gas gathering lines—particularly for first‑time inspections—requires treating each line as a standalone project. Customized planning, preparation, and execution tailored to the specific operating characteristics of the line are essential. Early stakeholder engagement, coordination among operator’s teams, support and inspection vendors, a “thinking outside of the box” approach to solutions and flexibility during execution are critical elements in overcoming both operational and commercial constraints.This paper presents two case studies in which customized planning and coordinated execution enabled successful ILI runs in gas gathering lines that were previously deemed almost unpiggable. The first case study involves an ILI run in a system with multiple inlets and outlets that produced varying flow regimes along the pipeline. The second case study addresses a more challenging scenario involving multiple inlets and outlets combined with flow rates and pressures that exceeded conventional limits for controllable ILI tool speeds. Together, these case studies demonstrate practical approaches, lessons learned, and operational strategies applicable to integrity management of gas gathering systems.
Optimizing Pipeline Burst Pressure Calculations Using 3-D Crack Meshes of EMAT Detected Crack-Like Features
Ryan Holloman1, Miguel Martinez1, Michael Turnquist1, Jane Dawson2 1Quest Integrity, Boulder, USA. 2Quest Integrity, Cramlington, United Kingdom
Accurate assessment of crack-like defects is critical for ensuring pipeline integrity and optimizing dig programs to avoid unnecessary excavations and repairs. Electromagnetic Acoustic Transducer (EMAT) in-line inspection (ILI) tools provide operators with characterization of potential axial crack-like features such as stress corrosion cracking, crack colonies, and seam weld anomalies. Conventional closed form pipeline assessment models such as API 579 Part 9 Level 2 and PRCI MAT-8 are commonly used to evaluate these features; however, it has been observed that these fracture models can introduce significant conservatism, particularly when idealizing crack fields in the pipe body where more favorable toughness properties are more likely to result in a plastic collapse failure condition. Here, an advanced engineering methodology that applies three-dimensional finite element analysis (FEA) specifically to EMAT-reported anomalies is presented. Using FEACrack™, detailed 3D crack meshes were generated directly from ILI-reported feature dimensions and used to perform fracture mechanics calculations to determine burst pressure. The resulting burst pressures were compared against results from conventional methods, including API 579 Part 9 Level 2 and PRCI MAT-8.Comparative analysis demonstrates that FEA-based assessments can produce substantially higher burst pressure predictions compared to traditional closed form solutions when idealizing crack colonies. The flaw geometries evaluated in this work were represented using the same commonly-used semi-elliptical, axially oriented surface crack assumptions. The primary distinction is that the FEA methodology presented herein directly evaluates the local stress and strain response that develops near the crack front under increasing load, including the effects of nonlinear material behavior and yielding for a feature’s unique dimensions and pipe geometry. This effect is amplified in pipe materials with relatively high fracture toughness, as is typically exhibited by flaws in the pipe body.Advances in computational performance and automated mesh generation have made high fidelity fracture mechanics practical for evaluating a large population of features. The results indicate that incorporating FEA into crack assessment workflows can significantly increase predicted burst pressures relative to traditional assessment methods. Furthermore, this approach can provide a practical alternative to conventional assessments that enable operators to better differentiate feature severity, rank anomalies more consistently, and prioritize dig programs toward locations that present the greatest integrity concern, while reducing unnecessary excavations and repairs.
Active Magnetometry for Unpiggable Pipelines: Validation Against In-Line Inspection
Keng Yap1, Mark Glinka2, David Xu3 1EMPIT USA, Pearland, USA. 2EMPIT GmbH, Berlin, Germany. 3Pacific Gas and Electric Company (PG&E), San Ramon, USA
In-line inspection (ILI) remains the benchmark for assessing external corrosion, one of the most pervasive threats to transmission pipelines; however, many pipelines are unpiggable due to operational or geometric constraints, limiting the applicability of conventional ILI-based integrity assessment. As a result, operators rely on above-ground inspection technologies, though independent validation against ILI benchmark data remains limited. This paper presents a field validation of an active magnetometry technology using ILI data as the reference benchmark. The technology, Current Magnetometry Inspection (CMI), is developed primarily for above-ground integrity assessment of unpiggable pipelines. It employs multi-frequency electromagnetic excitation and magnetic field measurements to assess external corrosion associated with coating damage without requiring excavation or interruption of pipeline operation. Unlike ILI, which establishes corrosion severity by quantifying the wall-loss, CMI evaluates the electrochemical condition at coating defects that manifest as magnetic field responses, indicating whether corrosion is active, transitional, or passivated.The study uses two natural gas transmission pipeline segments for which corresponding ILI datasets were available. Across both segments, 269 coating defects were identified and characterized by CMI. Comparison with ILI data showed strong spatial correlation in reported feature locations. The majority of CMI identified features were characterized as passivated, while a subset was identified as transitional, and no locations exhibiting active external corrosion were observed at the time of inspection.The results highlight that coating damage alone is not a reliable indicator of active corrosion and demonstrate the importance of incorporating corrosion activity information into excavation prioritization. The findings support the use of CMI as a decision tool to improve ECDA effectiveness where in-line inspection is not feasible, with significant implications for integrity management of unpiggable pipelines.
Establishing Ground Truth for ILI Strain Measurement: Lessons Learned from Laboratory and Field Validation Programs
Sylvain Cornu1, Mark Olson2 1NDT Global, Stutensee, Germany. 2Entegra, Indianapolis, USA
Geohazards such as landslides, subsidence, river scouring, or riverbank erosion can impose complex loading conditions that threaten pipeline integrity. While IMU-based bending strain assessment is a mature industry standard, it is fundamentally incapable of measuring axial strain resulting from pipeline elongation or contraction, which can be a primary driver of girth weld failure or interact with other pipeline anomalies. To address this gap, novel electromagnetic technologies based on the magneto-elastic effect are been developed to provide high-resolution, direct measurements of absolute longitudinal (axial and bending) strain. Although ILI validation methodologies are well established through industry standards such as API 1163 and decades of operational experience, strain measurement presents a unique challenge: establishing reliable ground truth. Unlike metal loss, crack, or geometry validation programs where hundreds or thousands of representative features can be manufactured/encountered and independently verified using NDE techniques, geohazard induced strain events are rare and difficult to assess. Field verification often requires extensive excavation in unstable terrain and installation of supplemental monitoring systems, including strain gauges. As a result, generating statistically meaningful validation datasets can require multi-year, multidisciplinary programs. A validation of a high-resolution ILI strain technology, primarily focused on axial strain, was conducted through a multi-tiered program progressing from controlled full-scale laboratory testing to deployment on several thousand kilometers of operating pipelines. Field validation incorporated multiple scenarios, including known strain events, correlations with finite element analysis (FEA), comparison with IMU-derived bending strain, repeat inspections to quantify strain evolution, and assessments performed before and after strain mitigation activities. Validation results demonstrated strong correlation and repeatability with instrumented field measurements and engineering assessments, supporting the technology's use for geohazard integrity management. The work demonstrates a practical framework for establishing defensible performance specifications for emerging strain measurement technologies and provides guidance for operators seeking to incorporate strain-based assessment into geohazard integrity management programs and/or to employ a total stress approach to pipeline integrity management.
Beyond the Spec: Validating an in-line inspection tool for metal loss with low expected probability of detection
Fraser Gray, Susannah Turner, Aaron Lockey, Tim Turner Highgrade Associates, Newcastle upon Tyne, United Kingdom
This paper discusses in detail the methods used to validate an ILI tool beyond its original specification and the improved understanding of integrity that follows. This demonstrates the strength of tool validation, particularly when incomplete ILI datasets are expected (i.e. many anomalies are unreported), and when confidence in sizing certainty is low.A case study is considered for a production pipeline transporting gas from offshore to an onshore terminal where In-line inspection (ILI) identified deep internal corrosion along the entirety of the route. Integrity assessment based on the findings of the ILI resulted in restriction of the maximum allowable operating pressure (MAOP). However, field validation of a small number of accessible anomalies in the onshore section identified that the metal loss was on average 40% shallower than reported by the ILI, indicating that the ILI may have significantly oversized the anomalies. Further information was therefore required to understand whether the condition was as severe as indicated by the ILI. It was identified that ILI using an alternative tool would be the most appropriate method to better understand the internal condition of the pipeline. However, due to operational and practical limitations, the choice of ILI technology was restricted.It was a key requirement that the new ILI should provide information to confirm the pipeline’s condition with confidence. Specifically, that the information should be sufficient to reject the conclusion from the original ILI regarding the presence of multiple, deep internal corrosion anomalies. In addition, a significant proportion of the population of anomalies reported by the original ILI had diameters below the thresholds for the stated probability of detection (POD) and sizing specifications of the new ILI. Given this, the POD and sizing performance of the ILI tool needed to be tested, quantified and validated, including for anomalies outside the stated limits. To achieve this, a pull-through test spool was used. This was designed considering the potential nature of anomalies in the pipeline. It was expected that the new ILI tool would have a low POD for small diameter metal loss and a large number of these smaller anomalies were therefore introduced into the test spool. This ensured that sufficient anomalies were detected by the pull through test to allow a statistically confident sizing model to be developed for metal loss, beyond the tool’s stated specification. On successful completion of the pipeline ILI run, the findings were analysed accounting for the sizing performance developed from the test spool, review of correlations between the original and new ILIs, and the available field validation data. Integrity assessment considered both the anomalies reported by the new ILI and the potential population of unreported anomalies. Ultimately, it was concluded that the original MAOP could be reinstated.
Advancing ILI-Based Characterization of Circumferential and Off-Axis SCC: An Operator’s Evaluation of Non-Ultrasonic Technologies for Integrity Management
Zaida Rojas1, Jade Horton2, Asim Khan1, STEPHEN WESTWOOD3 1Pembina, Calgary, Canada. 2Novitech, Toronto, Canada. 3Novitech, Calgary, Canada
Axial stress corrosion cracking (SCC) has long been recognized as a significant pipeline integrity threat, and extensive industry research has advanced the understanding of its causes, mitigation measures, and growth behavior. By comparison, circumferential SCC (CSCC) and off-axis SCC represent less prevalent but increasingly important cracking threats, particularly where complex loading conditions influence crack orientation and severity. Although in-line inspection (ILI) technologies have matured considerably for axial SCC applications, reliable detection, characterization, and sizing of circumferential and off-axis cracking remain comparatively less established.Pembina’s operating experience has demonstrated that CSCC can often be identified through ILI; however, consistent and accurate sizing has proven more challenging. Instances of both over-call and under-call have introduced uncertainty in integrity assessments, influencing excavation prioritization, repair planning, and overall confidence in remaining-life decisions.In response, Pembina undertook an evaluation of non-ultrasonic ILI technologies to assess their capability to detect, discriminate, and characterize circumferential and off-axis SCC. This paper presents the results of that evaluation and discusses the practical implications for integrity management. In doing so, it highlights a broader evolution in ILI application: from a primarily detection-based approach toward a more integrated strategy that uses multi-sensor data to support threat characterization, risk-informed prioritization, and defensible integrity management decisions.The findings provide a practical operator perspective on the role of emerging ILI technologies in addressing cracking threats that are not fully characterized by traditional inspection approaches. By comparing field experience with technology capability, the paper identifies opportunities to improve confidence in CSCC and off-axis SCC assessment, reduce uncertainty in integrity decision-making, and support more targeted, risk-based responses to complex cracking threats.
Scaling Pipeline Integrity Across 30 Divisions Through Unified Data and Standardized Analytics: An Energy Transfer Case Study
Sheri Baucom1, Trang Pham2 1Irth, Durango, USA. 2Energy Transfer, Houston, USA
Large pipeline operators managing geographically diverse assets face ongoing challenges in maintaining consistent integrity analyses, regulatory compliance, and defensible decision-making, particularly when integrity data is fragmented across spreadsheets, inspection vendors, and localized workflows. This paper presents a case study of Energy Transfer’s implementation of a unified integrity data framework across 30 operating divisions. It demonstrates how enterprise-scale data unification enables a qualitatively different class of corrosion growth analysis that is not achievable under fragmented workflows, regardless of individual engineer capability.Prior to implementation, integrity data was maintained in disconnected tools and spreadsheet-driven processes. Corrosion growth rate (CGR) evaluations relied on manual two-point pit-to-pit minimum matching, a method structurally prone to over-projection when applied to anomaly populations where measured depth differences between inspection runs fall within tool tolerance bands. Conservative fixed-rate assumptions were applied broadly rather than selectively, introducing systematic bias into excavation planning and reassessment interval determination.Energy Transfer deployed a centralized integrity data environment integrating ILI data, GIS data, internal corrosion data, and repair records, enabling joint-level data control, automated anomaly alignment, and standardized analytical workflows across all 30 divisions within approximately nine months. Centralized governance of corrosion growth methodology enabled the transition from two-point pit-to-pit minimum evaluation to full-history linear regression modeling. This change produced a materially different and more accurate characterization of the corrosion anomaly population.A representative pipeline segment evaluation demonstrated an approximately 79 percent reduction in projected CGR conditions, from 42 to 9, with field excavations confirming that prior projections were systematically over-conservative. The revised methodology distinguished between individually characterized anomalies supported by multi-run depth histories and statistically modeled unmatched features. This change directly improves dig selection confidence and long-range planning accuracy.Outcomes included improved integrity evaluation accuracy, reduced systematic bias in corrosion growth projections, enhanced dig selection confidence, and stronger compliance defensibility across the enterprise. This case demonstrates that the primary value of enterprise data unification in pipeline integrity is not administrative efficiency; it's the capacity to make technically superior integrity decisions at scale.
Overcoming the Challenges with Adopting a Dent ECA Procedure in Compliance with CFR 192.712(c)
Michael Turnquist1, David Classen2 1Quest Integrity, Boulder, USA. 2Baker Hughes, Houston, USA
Effective dent management is a critical component of any holistic pipeline integrity management plan. Recent focus on this threat has improved the pipeline industry’s understanding of what makes a dent injurious to a pipeline segment. These advancements have largely manifested as guidance contained in API 1183 Assessment and Management of Pipeline Dents, a recommended practice document published in the fall of 2020. Furthermore, the recent adoption of new regulatory language contained in CFR 192.712(c) specify the requirements for engineering critical assessment (ECA) of pipeline dents, giving U.S. gas pipeline operators the option to adopt such an assessment process in lieu of the historical prescriptive requirements for investigation and remediation of pipelines in high consequence areas (HCAs).While the development of API 1183 and the adoption of CFR 192.712(c) represented significant steps forward for the pipeline industry, operators are still experiencing challenges with their practical application. This is especially true for U.S. gas pipeline operators tasked with adopting the best practices contained in API 1183 while maintaining compliance with applicable Federal regulations.As stated in CFR 192.712(c)(11), pipeline operators must submit advance notification of the adoption of a dent ECA procedure to the Pipeline and Hazardous Materials Safety Administration (PHMSA) prior to implementation. PHMSA has now begun approving these procedures, with the clear stipulation that advanced engineering analysis reliant on the execution of detailed elastic-plastic finite element analysis (FEA) is required in order for such a procedure to be deemed compliant. This in turn has raised concerns among pipeline operators about the practicality of adopting such an approach on a large scale given the complexity of the analysis that is required.Baker Hughes has supported the development and implementation of a procedure for executing dent ECA that has officially been granted acceptance from PHMSA as being fully compliant with the requirements listed in 192.712(c). To date, this procedure has been used to perform ECA for over 1,000 dents that would traditionally require response based on historical prescriptive conditions. This paper will present a general overview of the ECA process, discuss the perceived challenges associated with executing this process at scale, and highlight the successes that have been observed from its initial adoption in terms of improving the safety and reliability of the overall pipeline network.
Beyond the Niche: Closing the Gap in Circumferential Crack Detection in Gas Pipelines with EMAT ILI
Thomas Beuker, Can Gromoll, Joerg Grillenberger ROSEN, Lingen, Germany
Circumferential crack detection is well established in liquid pipelines; however, its application in gas pipelines remains limited. Conventional ultrasonic inspection methods require liquid batching, resulting in operational disruption, increased cost, and potential risks during drying. Consequently, circumferential crack inspection in gas pipelines is often considered a niche application, a view increasingly challenged by evolving integrity demands.Gas pipelines are exposed to rising geotechnical loading conditions, including ground movement, soil instability, and strain-based operation. In combination with internal pressure, these factors generate complex stress states that increase susceptibility to circumferential and off-axis cracking. Such defects are particularly critical in girth welds and areas with geometric deformation, where failure may occur with limited stable crack growth.Electromagnetic Acoustic Transducer (EMAT) technology, widely applied for axial crack detection, allows ultrasonic inspection without liquid coupling and is therefore well suited to gas pipeline environments. Building on this capability, EMAT-A in-line inspection (ILI) technology has been developed for the detection and sizing of circumferential cracks and has been validated through full-scale testing in accordance with API 1163.This paper presents an integrated inspection approach combining EMAT-A with high-resolution eddy current-based geometry measurement and magnetic flux leakage (MFL) metal loss inspection. The combined dataset enables improved identification and characterization of interacting threats, including the relationship between circumferential cracking, geometric features, and metal loss, particularly at girth welds.The results demonstrate enhanced detection reliability and provide a more complete basis for integrity assessment in gas pipelines under increasingly complex operating conditions.Keywords for subject area:Crack Management and Assessment, EMAT Technology, Geohazards, ILI Application, SCC Assessment and Management,
Closed-Loop Active Velocity Control for Inline Inspection: Field Application on a 12-Inch Natural Gas Pipeline
Andrew McNiel1, Makund Belavadi2, Adam Pipe2 1Expro, Houston, USA. 2Phillips66, Houston, USA
Inline inspection (ILI) tool performance is highly dependent on maintaining tool velocity within a defined operating window. However, many pipeline systems lack the control resolution required to consistently meet these constraints under live operating conditions. This limitation is particularly pronounced in high-flow transmission pipelines, where nominal conditions may exceed ILI velocity limits as well as gas gathering lines that have multiple intakes and outlets resulting in multiple flow regimes along the length of the line. In both cases conventional control methods are unable to achieve or maintain the required reductions in velocity in a consistent manner.A field application was executed by Expro in collaboration with Phillips 66 on a 12-inch natural gas gathering pipeline to evaluate a new closed-loop velocity management system, Velonix™, which is designed to regulate pipeline flow velocity in real time. Under nominal operating conditions, the pipeline flowed at approximately 499 psig and 37 MMSCFD, resulting in a measured velocity of 11.1 mph, exceeding the ILI tool’s maximum allowable velocity of 9 mph. The applied system utilized a non-intrusive velocity meter and a digitally actuated control valve to increase nominal pipeline pressure, thereby increasing fluid density and reducing velocity to within the required operating range without affecting the mass or volumetric flowrate of the pipeline system. This approach prevented the pipeline operator from having to make any flow changes to their system during pigging operations.The system was deployed during both cleaning pig and ILI tool runs, with velocity setpoints established and adjusted in coordination with the operator during execution. Controlled operation resulted in an average pipeline velocity of 5.7 mph, consistent with third-party pig tracking measurements of 5.6 mph and onboard ILI tool measurements of 5.0 mph, 51.4% less than the nominal flow velocity resulting in velocity conditions suitable for ILI integrity data acquisition. During active closed-loop control, the standard deviation of recorded velocity was calculated at 1.9%, demonstrating stable velocity regulation within ILI requirements.Real-time system response enabled setpoint changes during the run, with measured velocity setpoint adjustments occurring within approximately three minutes across a 9.4-mile segment. In addition to velocity control performance, it was observed that during active manipulation of pipeline operating conditions, the system operated within a transient state that resulted in lower peak pressures than those predicted under steady-state assumptions. This behavior enabled successful completion of the pig run without exceeding anticipated pressure constraints and informed subsequent methods for pre-calculating transient pressure response during operations.The results demonstrate that closed-loop control of pipeline velocity can reliably maintain ILI tool speeds within specified limits under live operating conditions, improving inspection data quality and operational predictability. The integration of real-time measurement with automated control provides a repeatable method for managing velocity in systems where traditional approaches are either insufficient or inconvenient, with demonstrated benefits in both high-flow and dynamically varying pipeline environments.Keywords: pipeline pig velocity speed control inline inspection ili unpiggable difficult to inspect meter pigging optimization automation flow assurance performance integrity
Robotic MLF Inspection Comparison to Wireline MFL in Out of Service Pipelines
Brady Blake1, Dale Simpson2, Jerry Toth3 1Colonial Pipeline, Alpharetta, USA. 2Intero Integrity, Calgary, Canada. 3Intero Integrity, Houston, USA
Robotic magnetic flux leakage (MFL) inspection and tethered wireline MFL have emerged as effective solutions for evaluating pipelines that are unsuitable for conventional in-line inspection (ILI). Operational constraints such as the absence of launcher and receiver facilities, low-flow or stagnant conditions, tight-radius bends, and significant geometric restrictions (e.g., dents) often limit the applicability of traditional pigging technologies. In these scenarios, both robotic and tethered MFL systems provide viable alternatives for integrity assessment.This paper presents a comparative evaluation of robotic and tethered wireline MFL technologies based on their application in out-of-service tank lines within the Colonial Pipeline system. By deploying both methods on similar assets, a direct side-by-side comparison is conducted to assess performance, data quality, operational considerations, and deployment efficiency. The findings highlight the respective strengths of each approach and provide guidance on technology selection for challenging pipeline inspection scenarios.
Technical Knowledge Management as a Critical Human Factor in Pipeline Integrity Management
Adrian Destefano, Pedro Hryciuk
Transportadora de Gas del Norte S.A. (TGN), Buenos Aires, Argentina
Pipeline integrity management has traditionally focused on identifying and mitigating threats to physical assets through inspections, monitoring, fitness-for-service assessments, and maintenance programs. However, operational experience has demonstrated that the integrity of a pipeline system depends not only on the condition of the assets themselves, but also on the ability of people to interpret information, assess risks, and make consistent technical decisions over time.
In mature pipeline systems, where aging infrastructure coexists with evolving regulatory, technological, environmental, and social conditions, integrity management becomes increasingly complex. When technical capabilities do not evolve at the same pace as the systems they are intended to manage, a capability gap emerges that can itself become a source of organizational risk. In this context, technical knowledge management and stewardship become strategic elements of pipeline integrity management.
This paper presents the framework implemented by Transportadora de Gas del Norte (TGN) to develop, manage, and preserve the technical knowledge associated with pipeline integrity.
The framework is based on building an organizational ecosystem supported by technical leadership, organizational culture, cross-functional capabilities, technical competencies, and an organizational structure that promotes professional development. In alignment with the principles of API RP 1173, the approach integrates people, processes, and technology as key enablers of operational excellence.
Implementation included a structured international competency certification program, specialized technical certifications, professionalization of critical tasks, active participation in technical organizations and international knowledge-sharing forums, and the development of a formal technical career path aimed at transforming individual expertise into sustainable organizational capabilities. These initiatives strengthened the consistency of technical decisions, reduced dependence on external specialists, and established formal mechanisms for knowledge transfer and preservation.
The results achieved have translated into measurable improvements across several integrity management processes and favorable trends in technical performance indicators, including reduced failure frequency, lower repair rates per pipeline length, and significant improvements in the management of complex threats such as cracking.
The experience presented demonstrates that technical knowledge management and stewardship are not merely professional development tools, but essential components of pipeline integrity management in mature transmission systems. The ability of organizations to develop, preserve, and continuously enhance technical knowledge is as critical to long-term integrity sustainability as the physical condition of the assets themselves.
Integrity Management of Manufacturing Threats in Spiral-Welded Pipelines
Jing Ma1, Joe Bratton2, Vitaly Vorontsov3, Lyndon Lamborn3, Nauman Tehsin4 1DNV, Houston, USA. 2DNV, Dublin, USA. 3Enbridge, Edmonton, Canada. 4Aramco, Dammam, Saudi Arabia
Spiral‑welded pipelines continue to play a significant role in oil and gas transportation systems worldwide; however, manufacturing‑related threats associated with spiral seam welds remain an integrity concern with a lack of adequate understanding. Historical and recent industry findings have reinforced the need for improved assessment methodologies and more robust integrity management practices.This paper provides a comprehensive review of the current state of industry and academia studies on spiral‑welded seam performance. It synthesizes takeaways from spiral welded pipe manufacturing history, full‑scale fatigue and burst testing programs, evaluates the applicability and limitations of existing fitness‑for‑service (FFS) frameworks for spiral seam anomalies, and explores risk‑based approaches benchmarked against historical failure statistics from regulatory databases and industry‑wide incident records.Key technical challenges are identified as well as critical gaps that warrant further development. These insights aim to support the advancement of more reliable and defensible integrity management strategies for spiral‑welded pipelines.
Validation of the EMAT-C Ultra System for Advanced Crack Detection in Natural Gas Pipelines
Matthias Hilvert1, Lukas Paschke2, Ernesto Rodrigo Miranda Waldo1, Thomas Beuker1 1ROSEN Group, Lingen, Germany. 2ROSEN Group, Dresden, Germany
Electromagnetic Acoustic Transducer (EMAT) technology has become an established approach for advanced In-Line Inspection (ILI), particularly in the detection and characterization of stress corrosion cracking (SCC) and other crack-like defects in pipelines. EMAT sensors operate in direct contact with the pipe wall and generate ultrasonic waves without requiring a liquid coupling medium, making the technology especially suitable for gas pipeline inspections.The EMAT-C Ultra Service features a dual sound-path design (clockwise and counterclockwise ultrasound propagation), providing up to 200% circumferential coverage. This redundancy significantly enhances sensitivity to small cracks, while improving detection reliability and sizing accuracy compared to earlier EMAT systems.An extensive verification and validation program, including full-scale testing on pipe samples with artificial and representative crack morphologies, demonstrated strong detection and sizing performance under controlled conditions. Building on this, multiple inspection projects were conducted with corresponding field and in-ditch activities. These structured field tests included post-inspection reviews, data correlation, and detailed analysis of detected features to evaluate real-world performance.The results confirmed the reliability of the technology, showing consistent identification of relevant crack indications and actionable sizing information. This paper presents a comprehensive assessment of the field validation work, including methodology, data evaluation, and key performance indicators. The findings demonstrate enhanced crack detection confidence and improved integrity assessment through more accurate and reproducible characterization of crack-like anomalies, reinforcing EMAT as an essential technology for proactive pipeline integrity management and risk mitigation.
Enabling Safe Hydrogen Pipeline Modification: Integrated Deployment of Grouted Tees and Double Block-and-Bleed Isolation in SGN’s LTS Futures Trial
Kalen Jensen1, Gemma Simpson2, Lee Steele3 1DNV, Calgary, Canada. 2Southern Gas Network, Edinburgh, United Kingdom. 3Stats Group, Aberdeenshire, United Kingdom
The safe execution of inspection, maintenance, and modification activities on in-service pipelines is a critical barrier to hydrogen network conversion. As part of SGN’s LTS Futures program, a world-first live trial was performed to validate an integrated approach enabling safe intervention on high-pressure hydrogen pipelines while maintaining system integrity.The methodology combined DNV-approved grouted tees with STATS Group’s BISEP® double block-and-bleed isolation technology. Grouted tees, a proven weld-free connection system with over 1,400 installations and zero recorded failures, eliminate in-service welding risks and provide a structurally bonded interface capable of transferring operational loads while preserving pipeline integrity. This approach supports safe access for inspection and maintenance without process interruption or thermal degradation concerns.Following installation, hot tapping and line stopping were executed using the BISEP tool, which achieved 100% leak-tight isolation under high-pressure hydrogen conditions. This zero-leakage capability directly enhances maintenance safety, reduces emissions, and enables controlled inspection and modification activities not achievable with conventional technologies.The integrated solution was demonstrated on an 18-inch pipeline within a representative transmission system, overcoming key operational challenges including swarf management and hydrogen-specific process validation.From an operator perspective, this trial establishes a repeatable framework for maintaining pipeline integrity during hydrogen conversion, enabling safe inspection access, planned maintenance, and future interventions. The results provide a scalable, field-proven approach to support long-term asset reliability and integrity management within evolving hydrogen networks.
A Practical Framework for API 1163 Validation: Improving Confidence Through Data-Driven Methods
Simon Slater, Austin Guerrero ROSEN, Houston, USA
Across the pipeline industry, expectations for rigorous and defensible In-Line Inspection (ILI) validation programs have increased significantly. However, implementing API 1163 continues to present challenges to both operators and ILI vendors. This is true for Level 1 and Level 2 assessments, which are expected to be more straightforward compared to the level 3 approach. Level 1 assessments are challenging due to ambiguous guidance regarding pipeline applicability, evaluation methodologies, required input parameters, and the definition of an “acceptable” validation. Level 2 assessments offer a more structured framework, yet variability persists in determining appropriate dataset size, establishing dataset selection criteria, understanding how anomaly type influences tool performance, and interpreting performance specifications.Opportunities exist to make both assessment levels more efficient. Level 1 assessments can be improved through a structured, data‑driven framework that leverages repeat ILI to evaluate consistency against defined change thresholds, supplemented by pre‑validation using historical excavation data. Level 2 assessments can be enhanced through standardized verification protocols, improved interpretation of NDE measurements, and advanced alignment tools that better correlate ILI and NDE datasets. A critical but often overlooked step is determining which data should be included in the validation process to avoid misinterpretation. Additionally, system‑wide data integration can expand available datasets, increase statistical confidence, and support more robust performance evaluations. Looking ahead, centralized databases capable of storing comparative analyses will enable systematic performance tracking, trend identification, and more effective management of change.This paper presents recent experience from multiple validation programs performed in collaboration with operators, highlighting key lessons learned from both operator and ILI vendor perspectives. The intent is to demonstrate how more consistent, transparent, and statistically robust validation procedures can be developed to improve confidence, meet regulatory expectations, and support the continued advancement of ILI and NDE technologies.
First-Year Deployment of Non-Intrusive Pipeline Assessment (NIPA) in North America: Assessing the Good, the Bad, and the Ugly
Arash Ilbagi1, Lewis Barton2, Edmund Bennett2, Arvind Chhabra3 1ROSEN Group, Houston, USA. 2ROSEN Group, Newcastle, United Kingdom. 3Enbridge Gas Inc., Toronto, Canada
At the 2025 Pipeline Pigging and Integrity Management (PPIM) Conference, a paper was presented describing a Non-Intrusive Pipeline Assessment (NIPA) approach for the integrity assessment of conventionally unpiggable and operationally constrained pipelines, integrating Large Standoff Magnetometry (LSM) into the External Corrosion Direct Assessment (ECDA) process. This paper presents the review and lessons learned from the first year of North American NIPA deployments. NIPA combines Close Interval Survey (CIS), Direct Current Voltage Gradient (DCVG), and LSM with AI-driven predictive analytics derived from a global integrity data warehouse comprising tens of thousands of ROSEN In-line Inspection (ILI) datasets, enriched with pipeline and environmental data. The approach enhances ECDA by improving pre-assessment, indirect inspection, and data integration. Outputs are expressed probabilistically as likelihoods of corrosion exceeding defined wall-thickness thresholds, enabling risk-informed prioritization across large asset bases, supported by ILI data.Field applications from multiple North American systems across unpiggable and piggable pipelines are presented. Integrated analysis of CIS-derived under-/over-protection, DCVG coating defects, LSM stress concentration zones, and AI corrosion predictions were used to rank and prioritize anomalies for excavation. Where available, results were compared against ILI data to assess spatial alignment and severity trends.Results show individual methods often provide incomplete indications, while integrated analysis improves anomaly discrimination and excavation targeting. Limitations include interpretation of stress response relative to metal loss, data alignment sensitivity, and reliance on validation through excavation or ILI.Key learnings indicate that combining AI analytics, physics-based inspection, and operator validation provides a robust quantitative framework, improving excavation efficiency and reducing non-productive digs. This would also improve pipeline condition and risk assessments especially where only above-ground survey is feasible.
Integrated ECA-Based MAOP Reconfirmation Across Diverse Pipeline Systems Using Advanced ILI, Material Verification, and Threat Assessment
Arash Ilbagi1, Simon Slater1, Sean Moran2 1ROSEN Group, Houston, USA. 2Williams, Salt Lake City, USA
Although Engineering Critical Assessment (ECA) is increasingly used to support Maximum Allowable Operating Pressure (MAOP) reconfirmation under 49 CFR §192.624, implementation across diverse pipeline systems remains challenging. This paper presents operator-led experience applying ECA (Method 3, §192.632) across multiple natural gas transmission segments within a large interstate pipeline network, including legacy and modern assets operating from 676 to 1,200 psi.The approach integrates multi-technology inline inspection (ILI), including magnetic flux leakage (MFL), electromagnetic acoustic transducer (EMAT) crack detection, geometry, and inertial technologies, augmented by advanced material property characterization methods capable of estimating pipe grade and hardness. These datasets are combined with targeted excavation and validation to establish traceable, verifiable, and complete (TVC) material records and confirm critical properties across diverse pipe populations.A structured threat assessment aligned with an integrity management program (IMP) evaluates corrosion, stress corrosion cracking (SCC), manufacturing, and strain-related threats. Results show that while susceptibility conditions may exist (e.g., SCC or external corrosion), combined ILI data, gas quality, and cathodic protection performance indicate low threat levels within MAOP reconfirmation segments.Key lessons highlight the importance of integrating complementary ILI technologies to achieve full threat coverage and reduce uncertainty in ECA-based MAOP reconfirmation. Material property verification (MPV) enabled closure of TVC gaps and reduced conservatism. Results also emphasize the distinction between susceptibility and active threats, demonstrating low integrity risk despite theoretical susceptibility. Practical experience managing non-contiguous segments underscores the need for data integration, conservative buffering, and consistent engineering application, supporting a repeatable, technically robust framework for ECA implementation.
Breaking the UT Barrier: Field-Proven High-Pressure Deployment of Liquid Self-Contained UT ILI (LS-C UT) in Gas Pipelines
Raymond Lam Choong Meng1, GEERT BONTEKOE2 1PETRONAS TAG IVA-ASG, Kuala Lumpur, Malaysia. 2Quest Integrity, Stafford, USA
High-pressure upstream gas pipelines have traditionally been inspected in-service using Magnetic Flux Leakage (MFL) In-Line Inspection (ILI) tools. While effective for general corrosion detection, MFL tools exhibit limitations in accurately sizing defects in heavy wall sections, Heat-Affected Zones (HAZ), and areas with external attachments such as clamps, supports, and casings. For aging assets, data accuracy is critical to enable defensible integrity assessments, reliable remaining life calculations, and to prevent unnecessary derating, costly repairs, or premature pipeline replacement.Ultrasonic Testing (UT) technology provides superior accuracy and repeatability for wall thickness measurement and defect characterization. However, UT inspection requires a liquid medium for acoustic coupling, traditionally necessitating pipeline shutdown or liquid batching. These approaches result in production deferment, increased operational complexity, and significant inspection costs.To address these limitations, PETRONAS, in collaboration with Quest Integrity, developed the Liquid Self-Contained Ultrasonic ILI (LS-C UT) system. The system enables high-resolution UT inspection in gas and multiphase pipelines by integrating a self-contained liquid coupling mechanism, allowing the tool to be propelled by in-service flow with minimal production interruption. Initially designed for low-pressure applications, the system operates at pressures as low as 4 bar. An offshore PETRONAS asset subsequently successfully deployed the LS-C UT system on a 6-inch, 130 bar gas injection pipeline in service for over 25 years. The objective was to obtain high-reliability inspection data, including critical riser sections, to support accurate integrity assessment and life extension strategies.This paper presents the engineering challenges of adapting the LS-C UT system for high-pressure service and its successful field execution. The inspection delivered high-accuracy data that reduced uncertainty in defect sizing, enabling optimized integrity decisions. The approach avoided lengthy production downtime, minimized inspection spread requirements, and mitigated the risk of unnecessary repairs or replacement, resulting in significant cost avoidance while enhancing asset safety and operational reliability.
Study of the Operating Range of Vibrating Wire Strain Gauges for Pipeline Geohazard Monitoring
Suraj Khadka1, Juan Holmquist1, Amir Ahmadipur1, Farideh Ehsasi1, Arash Mosaiebian2, Ali Ebrahimi1 1Geosyntec Consultants, Inc., Houston, USA. 2Enbridge, Calgary, Canada
Spot-weldable vibrating wire (VW) strain gauges are widely used for long-term monitoring of pipeline strain associated with geohazard activity. These instruments provide a direct means of measuring pipeline strain and are commonly relied upon by pipeline operators to manage integrity threats and risk-based decision-making. However, accurate interpretation of strain data depends on an understanding of the strain gauge’s performance within the manufacturer-specified operating ranges and response behavior as the strain gauge approaches or exceeds these limits. In practice, pipeline operators may encounter measured strain values that are influenced by environmental factors, instrument malfunctions, erroneous measurements, or threshold exceedances. Under such conditions, uncertainty arises as to whether the reported measurements remain reliable and accurately represent the actual pipeline strain, or whether the observed response is influenced by external factors. This uncertainty is compounded by the fact that VW strain gauges from different vendors have varying operating ranges and internal configurations, which may result in different response characteristics near and beyond the specified limits.To address these limitations, this paper presents a laboratory testing program conducted to assess the operating range and response characteristics of the spot-weldable VW strain gauges commonly used in pipeline monitoring. The primary goal of the laboratory testing program was to characterize the response of these strain gauges within their operating range, evaluate measurement accuracy, and assess their behavior as measured strain approaches or exceeds the manufacturer-specified operating range. Multiple VW strain gauge models with total operating ranges of approximately 2,500, 5,000, and 10,000 microstrain were evaluated using controlled bending plate tests.Keywords: Vibrating Wire Strain Gauge, Instrumentation, Pipeline monitoring technology, Geohazard
Forging a New Path Forward for Managing Selective Seam Weld Corrosion
Greg Riversmith1, Josh Bremner2, David Futch3, Mike Redmond4, Chris Newton2, Geoff Hurd1 1Enduro Pipeline Services, Calgary, Canada. 2Phillips 66, Houston, USA. 3Acuren Inspection Inc., Magnolia, USA. 4Fundamental Management Solutions, Tulsa, USA
Changes to the gas transmission 49 CFR §192.712 regulations in 2020, and a FAQ clarification to the hazardous liquids 49 CFR §195.452(h)(4)(iii)(H) code in 2025 have renewed interest in managing selective seam weld corrosion (SSWC) using engineering assessment (EA) and have triggered a resurgence in research efforts on the topic. This ongoing wave of R&D studies has produced greater clarity into the underlying source mechanism for SSWC – and provided significant new perspective into the threat. It also invited a re-evaluation of the industry’s current best practices for SSWC integrity management (IM). Recent research clearly shows that some industry practices regularly used to evaluate SSWC are subject to considerable challenges that were not previously identified or understood, and that the development of new and better tools would greatly benefit SSWC IM activities moving forward. This is true whether proceeding under the current regulatory framework – or under a future adjusted framework that would optimize efficiency over the long term. This paper reviews the recent R&D developments, and proposes alternate paths forward for assessing SSWC susceptibility, and for overcoming fundamental limitations that are inherent to ILI and NDE calls when it comes to confidently identifying/validating SSWC within a pipeline system. The main goal of this paper is to start a discussion on this topic within the greater industry. One critical aspect of this work is to more concretely define what SSWC is, and what it is not. At present, the industry has quietly (and perhaps unknowingly) lumped multiple threats/anomalies together within a single “SSWC” threat category – despite the source mechanism (and expected integrity ramifications) for each threat being very different. This might explain many disparate observations about “SSWC” from operators who have reported diverging experiences with the threat – and has strained discussions that center on appropriate industry responses to the threat of SSWC. Extraneous complexity has also been introduced into the current SSWC identification definition (as provided in API1160 and the PRCI EC-2-12 report) with the introduction a severity-based consideration that is needed to make SSWC identification calls (grooving ratios of GR > 2). This severity cutoff has been highlighted in API1160 as lacking quantitative evidence and/or fundamental reasoning (that can serve as a logical basis) for delineating SSWC from ordinary corrosion using the severity threshold. Despite the lack of a concrete origin, the SSWC identification metric remains valid in today’s regulatory framework. However, SSWC severity (i.e. GR) fits more naturally into consequence-based conversations, where operator responses become tied to the expected accelerated growth rate for SSWC defects – rather than being awkwardly “shoe-horned” into the definition of SSWC. Topics such as ILI inspection interval adjustments for SSWC affected lines provide a much more natural application for SSWC severity implications. Revising the criteria the industry uses to evaluate SSWC – to better align with the underlying threat source mechanisms and current technology capabilities – should greatly improve the performance and efficiency of future integrity management programs for SSWC.Keywords: Selective Seam Weld Corrosion (SSWC), ERW pipe, Long Seam Welds, Integrity Management Planning, In-Line Inspection (ILI), Destructive Testing, Non-Destructive Evaluation
Advanced Engineering Assessments for Complex Threats and the Role of Inline Inspection
Jeff Sutherland1, Michael Turnquist2 1Baker Hughes, Calgary, Canada. 2Quest Integrity, Boulder, USA
Complex threats have a distinct presence within pipeline integrity practices and require distinct, usually unique assessment solutions. Standard practices and methods for detailed engineering assessments of flaws have been available for many decades, often referred to as Fitness-for-Purpose (FFP) or Fitness-for-Service (FFS) assessment. More advanced FFP/FFS methods typically rely on the use of finite element analysis (FEA) modeling and/or probabilistic analysis via Monte Carlo simulation. These advanced methods are often required in the presence of complex conditions such as the interaction of multiple threats and/or unique loading conditions. From a pipeline inline inspection (ILI) perspective, detection has historically focused on singular threats. While it is common practice to engage in data integration efforts to identify interaction of multiple threats, this process can often become convoluted. As a result, the commonly used empirical assessment methods that have been derived to assess such threats (i.e., ASME B31G, RSTRENG, Modified Ln-Sec, CorLAS, PRCI MAT-8, and the Level 1 and 2 screening methods for dents contained in API 1183) have limitations in their applicability in the presence of complex conditions. From an FFP/FFS perspective, physical coincidence of features on an imperfectly shaped pipe can be directly accounted for. Additionally, complex loading conditions can be evaluated where typical limit states derived from simplified load cases (such as a straight cylinder subject to internal pressure only) are no longer valid. These advanced FFP/FFS approaches therefore enable consideration of a broader perspective of essential variables and influences on pipe conditions, loads, environment, materials, etc. Over the course of the 1990s and early 2000s, advanced FFP/FFS methods utilizing FEA were initially applied to ILI geometry data (caliper) to assess cases of pipeline deformation, particularly for fatigue modeling of dents. At the time, the complexity of the modeling and the computations required, even for singular features, made detailed assessment inefficient, expensive, and an unattractive general option. Hence, the adoption of such methods was usually limited to very specific cases, even though it was understood such an approach would offer the most comprehensive solution. However, recent advancements in ILI detection capabilities for corrosion, cracks, dents, and other features, coupled with the significant improvement in computing capacity to support more rapid computational analysis, have made the concept of executing these advanced analyses on a larger scale much more practical. This increased scale and applicability means that more accurate, justifiable, and comprehensive outcomes are now more readily available and cost-effective within integrity programs. This paper will describe and review the landscape of common best practices used today for advanced engineering assessments, typically as starting from ILI as a source data set. The impact of the accuracies and uncertainties of model variables will be discussed, specifically highlighting the additional value that can be provided from the adoption of these more advanced approaches. While the assessment methods presented herein are not necessarily new or novel practices, the concept of executing these analyses more rapidly and on a larger scale offers a new perspective for the pipeline integrity community. Furthermore, this paper aims to challenge the current convention by justifying the specific intent to further integrate such methods into existing integrity programs.
Risk-Informed Prioritization and Management of Interacting Threats
Brian Wong, Colin Dooley, Greg Van Boven
TC Energy, Calgary, Canada
Threat interaction can be defined as two threats acting on a pipe or pipeline segment that increase the likelihood of failure to a level greater than the effects of the individual threats acting alone. Although industry practices effectively address prevalent and high-severity threat interactions (e.g., dent and metal loss), recent incidents have demonstrated that rare but complex interactions can also drive failure. This paper introduces a structured approach to identify, prioritize, and manage such interactions within an operator's integrity management program.
This paper presents a practical framework for identifying and prioritizing interacting threats within a pipeline integrity program using a risk-informed lens. The framework focuses on how combinations of threats can influence the likelihood of failure through two primary categories: (1) the interaction of two threats that degrades the effectiveness of a barrier used to control one of the singular threats and (2) the interaction of two threats acting on a pipe or pipeline segment reduces the pressure carrying capacity of the pipe to a level greater than the effects of the individual threats acting alone.
Application of this framework across TC Energy's (TCE's) natural gas pipeline system demonstrated that only a limited number of interaction scenarios warrant further evaluation or program enhancements. These higher-priority interactions span multiple integrity disciplines and require coordinated responses across identification, assessment, mitigation, and monitoring processes.
Building on this initial prioritization, several targeted initiatives are underway to further address key threat interactions applicable to TCE's gas pipeline operations:
Deformation and Geohazards: Systematic integration of Deformations In-Line Inspection (ILI) data with Geohazard data to methodically improve the identification of deformations within geohazards.
External Corrosion and Stress Corrosion Cracking (SCC): Understand the existing challenges from this feature interaction (including implications for identification and assessment) and evaluate development of a mechanics-based limit state determination.
External Corrosion and Geohazards: Overlay applicable ILI and geohazard data, systematically identify lines/locations targeting this threat interaction and propose a process for assessment.
Circumferential SCC and Geohazards: Refine assessment models for combined loading response for circumferentially oriented crack-like flaws. Integration of geohazard data with applicable ILI data.
These efforts are supported through formation of cross-functional teams that aim to define and implement practical program enhancements while considering impacts across pipe integrity functions and business processes. The resulting framework and associated work provide a structured and replicable approach for operators to proactively manage threat interactions relevant to their operations while enhancing safety and optimizing integrity program resources.
A Technical Briefing on ASTM E3499-25: The New Standard for In-Situ Material Verification
Jimmy Campbell1, Max Burley2, Olly Morris1 1Plastometrex Ltd, Cambridge, United Kingdom. 2Plastometrex Inc, Houston, USA
Every inspection method used in pipeline integrity programs operates within an ASTM framework: ultrasonic testing, magnetic particle inspection, tensile testing. In-situ material verification now has one too.Published in November 2025, ASTM E3499-25 establishes the first standardized approach for non-destructive material verification under 49 CFR 192.607, bringing traceability, repeatability, and defensibility to a space that has historically lacked it.In this presentation, the team behind ASTM E3499-25 explain what the standard means in practice, how it was developed, and how operators can apply it within their integrity programs today. Topics covered:What ASTM E3499-25 covers and where it fits within material verification requirements What ASTM standardization delivers in practice: traceability, repeatability, and defensible results How the standard was developed: committee process, round robin testing, and balloting How to specify ASTM-standardized tools within your integrity program to reduce technical and regulatory risk
Avoid the Trap: Inline Inspection Through a Valve
Kenneth Maxfield1, Samatha Spellman-Bales2, Jason Weiss3, John Chapman4 1KMAX Inspection, Millcreek, USA. 2Platte River Gathering, Denver, USA. 3Argus, Edmonton, Canada. 4Elevation Midstream, Denver, USA
Pigging valves (pig valves) provide a novel alternative to conventional launcher and receiver trap systems, enabling the insertion and retrieval of cleaning and inline inspection (ILI) tools directly through line-mounted valve bodies. Their adoption offers compelling benefits: simplified operation, improved safety, reduced emissions during tool deployment, a smaller installation footprint, and lower capital costs. These advantages are particularly impactful for smaller-diameter and restricted-access pipeline systems, many of which would otherwise remain unpiggable for routine integrity management.Over the last six years, KMAX Inspection has focused on re-engineering conventional ILI technologies—including Magnetic Flux Leakage (MFL), Deformation sensing (DEF), and Inertial Measurement Unit (IMU) mapping—into modular architectures suitable for valve-based deployment. In collaboration with Argus, a global leader in pig valve manufacturing, KMAX designed and commercialized pig-valve-launchable ILI tools for 4", 6", and 8" pipelines. These systems leverage compact magnetizer assemblies and segmented-tool technologies to overcome the geometric, magnetic, and energy constraints imposed by the valve passage. When coupled with pigging valves, these modular ILI systems enable operators to clean and inspect previously inaccessible pipelines without major facility modifications or outages.A field case study will demonstrate the real-world impact of this approach. A pipeline operator responsible for a four-inch liquid-gathering pipeline required an integrity assessment but lacked space to install a conventional launcher and receiver trap. The line was located within a densely built facility, and surrounding utilities and structures prevented any expansion of the site footprint. Historically, this type of constraint forced operators to abandon the idea of ILI and resort to a hydro-test. Instead, the operator installed Argus pig valves at both ends of the system, allowing direct valve-based launch and retrieval of KMAX’s 4" modular ILI toolset. The inspection was conducted at controlled velocities, with MFL and Deformation data acquired across the full pipeline length. The tool was launched, propelled, and received entirely through pig valves, eliminating the need for trap infrastructure. The successful run not only delivered actionable integrity data but also validated a repeatable deployment methodology that can be integrated into routine operations. These results demonstrate the technical feasibility, practicality, and strategic value of small-diameter, pig-valve-based ILI for compact or previously unpiggable assets, offering operators a cost-effective pathway to modern integrity management.
A General Stress in Buried Pipe during Ground Vibration due to nearby Blasting or Pile Driving
Fan Zhang Phillips 66 Company, Houston, USA
Blasting is commonly used for excavation and mining in rocky terrain. The energy released during an explosion fractures surrounding rock and generates ground vibrations that propagate away from the blast source. When a buried pipeline is located nearby, these vibrations can impose additional stresses on the pipe. Combined with operating stresses such as internal pressure, the added stress may exceed the pipe’s resistance and lead to failure. For this reason, blasting-induced stress should be evaluated before nearby blasting activities are approved.Several experimental and analytical studies have examined this issue; however, their conclusions vary considerably because of differences in explosive energy, site conditions, and analysis methods. Pipeline operators therefore need a screening method that is simple enough for rapid evaluation and conservative enough to be broadly applicable. If a proposed blast does not pass the screening criteria, field mitigation measures may be implemented, or a more detailed engineering assessment may be performed to account for the specific blast characteristics and site conditions.This paper presents a general screening approach recently developed at Phillips 66. The method significantly updates company procedure and reduces the overconservatism of the previous version. Because pile driving also generates ground vibrations, the same framework can be applied to evaluate resulting stresses in nearby buried pipelines.
Risk-Informed Integrity Management of Deepwater Flowlines – an Operator’s Perspective
Jocelyn Nelson1, Wenjun Zeng1, Robil Mittal2, Stefan Kuczera3 1ExxonMobil Upstream Integrated Solutions Company, Spring, USA. 2ExxonMobil Services & Technology Private Limited, Bengaluru, India. 3ExxonMobil Guyana Ltd, Georgetown, Guyana
As oil and gas operators venture into ever deeper waters, the number and mileage of deepwater flowlines continues to increase. At the same time, many of the pioneering deepwater production systems have surpassed 20 years of operation and are undergoing life extension. The first edition of DNV-RP-F116, Integrity Management of Submarine Pipeline Systems, was released in 2009, with the current edition published in 2021. As such, deepwater operators, compared to onshore and shallow water operators, have a relatively small experience base from which to learn. A benchmarking exercise published by PRCI in 2022 found that the design and implementation of integrity management programs for deepwater flowlines varied notably across Operators. This paper will share the authors’ experience developing and implementing a risk-informed integrity management program for deepwater production flowlines. The program addresses a range of threats including organic solids deposition, internal corrosion, lateral buckling, thermal fatigue, end expansion (walking), and free spans. The paper will also discuss the complementary roles of surveillance, inspection, and advanced engineering analysis in integrity management.
Estimating Bending Strain at Geohazard Locations Using Historical Inertial Measurement Unit Data
Abrar Islam1, Mathew Bussiere1, Onyekachi Ndubuaku2, Nader Yoosef-Ghodsi2 1C-FER Technologies (1999) Inc., Edmonton, Canada. 2Enbridge Liquids Pipelines, Edmonton, Canada
Operators receive reports with numerous bending strain features from an IMU inspection run and some of the reported features may be located within flagged geohazard sites. Features reported at these locations must be reviewed to determine whether they may evolve into an integrity concern and whether the features warrant closer examination. For this purpose, operators can use bending strain measurements from IMU inspection logs to estimate strain demand. However, forecasting bending strain using past inspection data involves numerous assumptions, and quantifying the associated uncertainty can be challenging.Enbridge maintains two key datasets: (1) a geohazard database, which catalogs geohazard locations and severity ratings, and (2) a site-wide ILI database containing vendor-reported bending strain features, their associated strain values, and geospatial coordinates. This study leverages data from both mentioned databases to explore a probabilistic data-driven approach for estimating future strain at vendor-reported features. The approach quantitatively accounts for two major sources of uncertainty: variability in reported IMU strain measurements and uncertainty in the strain projection methodology. The first step involved extracting a dataset of reported bending strain features from multiple inspections at flagged geohazard sites by mapping between the two databases. Then future bending strain was predicted using a Monte Carlo simulation framework incorporating simple linear and weighted linear regression. The weighted regression approach used an age-weighted function to increase inspection weight based on recency. Results showed that linear approximations provided reasonably accurate predictions, with the age-weighted approach providing improved accuracy. The results indicate that the strain estimation methodology and the associated data mapping procedure can be included in the operator’s geohazard management workflow as an additional tool to help screen vendor-reported strain features and flagged geohazard sites.
Risk Analysis Methodology for 192.935 RMV Requirements
Oscar Ballesteros1, CHRISTOPHER WALKER2 1Peoples Gas & North Shore Gas, Chicago, USA. 2Pond and Company, Houston, USA
In response to the Gas Mega Rule, 49 CFR §192.935(c) requires operators to evaluate whether rupture mitigation valves (RMVs) would be an efficient means of adding protection to high-consequence areas (HCAs) during a gas release. This determination must be supported by a risk analysis that considers leak detection and shutdown timing, gas type, operating pressure, potential release rate, pipeline profile, ignition potential, and the location of response personnel.This presentation will share the approach used by Peoples Gas and North Shore Gas to evaluate RMV effectiveness and support compliance with 49 CFR §192.935(c). The methodology uses a quantitative, matrix-based process to evaluate the regulatory factors and determine whether additional RMVs are warranted on applicable transmission pipeline segments.The process begins by verifying compliance with valve-spacing requirements under 49 CFR §192.179. Segments that already meet applicable RMV installation or spacing considerations are screened before additional analysis. For segments requiring further evaluation, a GIS-based process divides the pipeline system into valve-to-valve segments, with each segment evaluated independently to account for class location, HCA/MCA exposure, operating conditions, and other segment-specific characteristics.A customized rupture mitigation matrix assigns numerical scores to each regulatory evaluation factor, with lower values representing lower relative risk and higher values representing greater potential consequence or response limitations. The combined score is compared against established thresholds to determine whether an RMV would provide an efficient means of adding protection to an HCA.By combining GIS-enabled segmentation with a quantitative evaluation matrix, Peoples Gas and North Shore Gas have developed a structured approach for meeting 49 CFR §192.935(c). The presentation will discuss the development of the methodology, the translation of regulatory factors into measurable criteria, and lessons learned from applying the process across transmission pipeline assets. The intent is to provide operators with practical insight into one approach for documenting RMV evaluations, improving consistency in decision-making, and supporting pipeline safety objectives under the Mega Rule.
Quantifying Girth Weld Flaws using Triaxial MFL
Anthony Tindall1, Gurwinder Nagra2, Yanping Li2 1Baker Hughes, Cramlington, United Kingdom. 2Enbridge Pipelines, Edmonton, Canada
Girth weld flaws – such as inadequate penetration, incomplete fusion, porosity, slag, and hydrogen assisted cracks (HAC) in the weldment or heat affected zone – can pose threats to pipeline integrity. Although these flaws are often regarded as low risk because typical failure mode is leak, historical failures show they can have serious consequences if the leak happens in locations with water body or environmental sensitive area.Girth welds flaws tend to remain stable in service unless the pipeline is caused to move longitudinally or laterally by settlement, landslides, earthquakes, or other soil-movement phenomena. As environmental conditions become more unpredictable, it is increasingly important for pipeline operators to understand and address girth weld flaws to maintain safety and reliability. This paper explores the use of multi-axis measurement data from the Baker Hughes Triaxial Magnetic Flux Leakage (MFL) fleet, which provides axial, radial, and transverse sensing. This advanced approach enables more accurate detection, classification, and sizing of girth weld flaws compared to traditional Axial-only MFL inspections and other sensing technologies.The collaboration between Enbridge and Baker Hughes has demonstrated the effectiveness of this technology in quantifying girth weld flaws. Real-world case studies are presented to show how the enhanced data from triaxial MFL leads to improved safety protocols and more robust pipeline risk management. By leveraging this technology, operators are better equipped to detect hidden or subtle weld flaws before they develop into significant threats, particularly in the locations with water body environmental sensitive area.In summary, adopting multi-axis measurement inspection methods represents an important step forward in girth weld integrity management. The ability to detect and size flaws more reliably supports proactive maintenance, reduces the likelihood of failure, and ultimately strengthens pipeline safety for operators and the communities they serve.
Thirty years of experience in operators working together and successfully interacting with their regulators – the successes and lessons learned
Gary Senior1,2, Kirsty McDermott3,2, Jane Haswell1, Simon Joyce4,2, Nikki Barker1 1PIE, Newcastle, United Kingdom. 2UKOPA, Warwick, United Kingdom. 3national gas, Warwick, United Kingdom. 4SGN, Edinburgh, United Kingdom
Kirsty McDermott¹, Nikki Barker², Jane Haswell², Gary Senior², Simon Joyce³¹National Gas, Warwick, United Kingdom, ²Pipeline Integrity Engineers, Newcastle upon Tyne, United Kingdom, ³SGN, Edinburgh, United KingdomOver the past 30 years, the United Kingdom Onshore Pipeline Operators’ Association (UKOPA) has played a central role in the development, safety, and governance of the UK’s onshore high-pressure pipeline network.A defining aspect of UKOPA’s work has been its ability to unite operators across the sector and provide a consistent, authoritative voice on safety, operations, and integrity management. Through collaboration with the Health and Safety Executive (HSE), government departments, local planning authorities, and industry stakeholders, UKOPA has contributed to the development of legislation, industry standards, and safe working practices across the UK pipeline sector.UKOPA has also led the development of guidance used by pipeline operators, contractors, developers, planners, and landowners working near pipeline infrastructure. In parallel, the association has promoted a strong culture of shared learning by enabling operators to exchange knowledge from incidents, near misses, operational experience, and technological advancements.This paper will outline UKOPA’s achievements since its formation in 1996, including the structure and function of its technical workgroups, its relationship with regulators, and the key guidance produced for operators of natural gas transmission and distribution systems, petrochemical liquids and gases pipelines, and oil and refined liquids pipelines.The paper will also present key outputs and lessons learned from the following UKOPA workgroups for consideration by the international pipeline community:Emergency Planning Working Group (EPWG)Fault Data and Risk Assessment Working Group (FARWG)Infringement Working Group (IWG)Pipeline Integrity Working Group (PIWG)Process Safety Working Group (PSWG)Corrosion Prevention Working Group (CPWG)UKOPA’s 30 member operators, many of whom operate globally, are keen to share the lessons, practices, and collaborative approaches developed within the UK pipeline sector over the last three decades.
301
Cultivating Tomorrow’s Pipeline Leaders: A Proven Model for Developing Young Professionals
Cassandra Moody, Chelsea Le Salle, Alexandria Pedersen, Nolan Durham, Andrey Fomin
Time For Change, LLC., Houston, USA
As the pipeline industry workforce shifts towards seasoned professionals entering retirement and junior engineers stepping up to the duty of care for the industry, the education, training, and competency assurance of individuals in facilitating the transition to a younger workforce entrusted with ensuring public safety around pipelines becomes increasingly critical. However, the demands of job duties and operational responsibilities often overshadow the development of young and mid-career professionals. This paper examines the current state of the midstream workforce and the challenges it faces within the industry. It presents a case study featuring fifteen years of proven continuous improvement results that have benefited young professionals, employers, the industry, and public safety. An overview of the evolving young professional development framework serves as the starting point, which will be expanded upon by examining the gap between graduates and workplace skills, offering considerations for developing individuals within companies, and providing suggestions for standardization in competency assurance across the industry. The role of companies, industry organizations, and educational facilities will be evaluated. The role of qualification and training, regulatory considerations, and implementation challenges will be highlighted to provide insights into the practical hurdles and opportunities associated with adapting to the evolving workforce and developing new strategies to meet the demands of safe operation.
Correlation of Surface Peak Particle Velocity to Dynamic Stresses in Buried Pipelines Subjected to Vibration
Benjamin Zand RSI Pipeline Solutions, New Albany, USA
The assessment of buried pipeline integrity when subjected to mechanical vibration sources—ranging from heavy construction machinery and pile driving to blasting operations—remains an important question for pipeline operators. Traditional industry guidelines typically rely on seismic wave attenuation models combined with semi-empirical or free-field equations to predict pipeline stresses based on Peak Particle Velocity (PPV) measured at the ground surface. While computationally convenient, these conventional methods frequently overlook the complex mechanics of soil-pipe interaction. This simplification can lead to discrepancies, resulting in either overly conservative exclusion zones that hinder construction progress or, conversely, an underestimation of fatigue-related stress cycles in aging, thin-walled pipelines.This paper presents a comprehensive numerical investigation utilizing explicit dynamic Finite Element Analysis (FEA) to capture the transient structural response of buried pipelines to near-field harmonic excitations. A high-fidelity, three-dimensional model was developed, coupling shell elements for the pipeline with a continuum soil domain to rigorously simulate wave propagation and energy transfer from a point source located at varying offset distances.A systematic parametric study was conducted to quantify the sensitivity of pipe stress to critical variables, including soil shear wave velocity, the pipe diameter-to-wall thickness (OD/t) ratio, and the depth of cover. The analysis specifically examines the correlation between surface-measured PPV and the resultant longitudinal and circumferential stresses within the pipe wall. The results elucidate that while surface PPV serves as a primary indicator of intensity, the stress amplification factors are affected by the acoustic impedance mismatch between the surrounding soil medium and the steel pipe. Furthermore, the FEA predictions are benchmarked against the widely accepted Esparza equation.
301
Cultivating Tomorrow’s Pipeline Leaders: A Proven Model for Developing Young Professionals
Cassandra Moody, Chelsea Le Salle, Alexandria Pedersen, Nolan Durham, Andrey Fomin
Time For Change, LLC., Houston, USA
As the pipeline industry workforce shifts towards seasoned professionals entering retirement and junior engineers stepping up to the duty of care for the industry, the education, training, and competency assurance of individuals in facilitating the transition to a younger workforce entrusted with ensuring public safety around pipelines becomes increasingly critical. However, the demands of job duties and operational responsibilities often overshadow the development of young and mid-career professionals. This paper examines the current state of the midstream workforce and the challenges it faces within the industry. It presents a case study featuring fifteen years of proven continuous improvement results that have benefited young professionals, employers, the industry, and public safety. An overview of the evolving young professional development framework serves as the starting point, which will be expanded upon by examining the gap between graduates and workplace skills, offering considerations for developing individuals within companies, and providing suggestions for standardization in competency assurance across the industry. The role of companies, industry organizations, and educational facilities will be evaluated. The role of qualification and training, regulatory considerations, and implementation challenges will be highlighted to provide insights into the practical hurdles and opportunities associated with adapting to the evolving workforce and developing new strategies to meet the demands of safe operation.
Recordings will be available approximately 2 hours after the presentation.
301
Cultivating Tomorrow’s Pipeline Leaders: A Proven Model for Developing Young Professionals
Cassandra Moody, Chelsea Le Salle, Alexandria Pedersen, Nolan Durham, Andrey Fomin
Time For Change, LLC., Houston, USA
As the pipeline industry workforce shifts towards seasoned professionals entering retirement and junior engineers stepping up to the duty of care for the industry, the education, training, and competency assurance of individuals in facilitating the transition to a younger workforce entrusted with ensuring public safety around pipelines becomes increasingly critical. However, the demands of job duties and operational responsibilities often overshadow the development of young and mid-career professionals. This paper examines the current state of the midstream workforce and the challenges it faces within the industry. It presents a case study featuring fifteen years of proven continuous improvement results that have benefited young professionals, employers, the industry, and public safety. An overview of the evolving young professional development framework serves as the starting point, which will be expanded upon by examining the gap between graduates and workplace skills, offering considerations for developing individuals within companies, and providing suggestions for standardization in competency assurance across the industry. The role of companies, industry organizations, and educational facilities will be evaluated. The role of qualification and training, regulatory considerations, and implementation challenges will be highlighted to provide insights into the practical hurdles and opportunities associated with adapting to the evolving workforce and developing new strategies to meet the demands of safe operation.
Mehdi Laichoubi is Chief Technology Officer at Skipper NDT, where he leads the development of innovative pipeline integrity technologies using unmanned and non-contact inspection methods. His work focuses on applying magnetic measurement, advanced data interpretation, and geolocation algorithms to improve the safety and reliability of buried pipeline networks and facilities. Mehdi has played a key role in bringing field-validated drone-based inspection solutions from concept to operational deployment, helping operators improve data quality and reduce risk in complex environments. An inventor with patents related to Skipper NDT’s technology, Mehdi is also the author of multiple technical papers, among which is the 2025 PPIM Innovation Award paper published with Enbridge on geohazard management. He actively contributes to industry conferences and collaborations with major operators. Mehdi holds a Master’s degree in Aerospace Engineering from Pennsylvania State University and a Master of Engineering in Energy from École Centrale (France).
Ian Kornfeld is the Regional Engineering Manager for National Grids Downstate NY Gas Transmission Engineering and Design team. He has over 10 years of industry experience leading a team through a large-scale capital engineering and construction portfolio and has worked on some of the largest natural gas infrastructure projects the company has seen in the territory. Projects have included over five miles of 30-inch steel high-pressure main, gate stations, heaters, and other complex installs throughout the region.
Ian has also led many company efforts for standardization and improvement of processes, standards and engineering knowledge transfer, including setting up events for such knowledge transfer. He has a bachelor’s degree in mechanical engineering, is a licensed Professional Engineer in NY, MA, NC, RI and ME and holds certifications including the Project Management Professional, Certified Construction Manager, Institute of Asset Management and API 1169 Pipeline Construction Inspector. Ian is a passionate advocate for the future of energy and the role that natural gas plays, and he actively contributes to industry advancement through his leadership roles in various organizations including the American Gas Association and The Young Pipeline Professionals USA organization, where he has served as secretary for the last three years. He brings a collaborative spirit, technical depth and strategic vision to every engagement.
319
Management and Validation of CSCC Using Multiple ILI Technologies
Rick Gonzales¹, Katrina Dwyer¹, Sergio Limon²
¹Xcel Energy, Denver, USA, ²Blade Energy Partners, Salt Lake City, USA
Xcel Energy operates ~2,128 miles of natural gas transmission pipeline, ~80% of which is piggable, with significant legacy segments in challenging terrain. Since the initial discovery of circumferential stress corrosion cracking (CSCC) threats in 2015, Xcel’s integrity program has evolved through investigative digs, ILI pull testing, and successive in-line inspections using AMFL/CMFL/DEF/XYZ tools—culminating in reliable detection and sizing, and field validation/repairs across >450 miles of susceptible lines in the 6”–12″ diameter range.
This paper documents system conditions, baseline CSCC tool runs, CSCC signal characteristics, susceptibility drivers (coating condition, bending/strain, slope), and results from a case study on a 1960’s vintage pipeline system. Results include reassessment, excavation, and repairs. Xcel will discuss tool performance, depth accuracy (±15–20%), operational constraints (seasonal access, pressure cuts), and mitigation methods. The findings highlight the success of using ILI based assessments to supplement susceptibility or risk-based models in order to more reliably identify and address CSCC threats. Last, the paper will provide recommendations for NDE sizing, repair practices, and reinspection logic for CSCC.
320
A Comparative Study of ICDA and ILI in Subsea Pipelines
Pedro Rincon¹, Yougui Zheng¹, Adam Maggio², Ryan Meyer², Eric Pierce² LeeAnn Escobar²
¹Shell Global Solutions (US) Inc, Houston, USA, ²Shell Exploration & Production Company, New Orleans, USA
This study provides a comparative analysis of Internal Corrosion Direct Assessment (ICDA) and In-Line Inspection (ILI) methodologies for subsea pipelines. It reveals that while ICDA is effective in predicting corrosion depth during its Pre-assessment and Indirect Inspection stages, it struggles with accurately locating specific damage points. This difficulty arises because internal corrosion is often localized and influenced by factors like severe corrosion at joints, making it challenging to identify critical defects even when predictive models highlight vulnerable areas. Moreover, there is a notable difference in the effectiveness of inspection and defect detection when conducted onshore compared to offshore environments.
The study also explores the impact of corrosion inhibitors on inspection processes. These inhibitors are generally effective against widespread corrosion but are less effective at preventing localized pitting. This variability introduces randomness on predicting defect location, which challenges the standard inspection approach outlined by NACE SP-0116. This standard assumes a pattern of widespread corrosion for detailed examinations, but it is inadequate for pipelines with inhibitors where pitting is unpredictable.
To address these issues, the study recommends enhanced inspection strategies. For pipelines that cannot be inspected using traditional pigging methods, it suggests increasing inspection frequency beyond the ICDA guidelines. These adjustments aim to improve defect detection accuracy and better manage the complexities introduced by corrosion inhibitors, ultimately ensuring more reliable pipeline integrity.
151
Learnings from Seven Successful Years of Phased Array Inline Inspections
Thomas Hennig¹, Gerhard Kopp¹, Alessandro Morandini¹, Peter Haberl¹
¹NDT Global GmbH, Stutensee, Germany
Phased array ultrasonic testing (PAUT) has emerged as a transformative technology in the field of non-destructive testing (NDT), offering unparalleled flexibility, precision, and adaptability across a wide range of applications—from medical diagnostics to the inspection of critical infrastructure in the energy and transportation sectors. Over the past two decades, the evolution of phased array systems has been marked by significant advancements in hardware miniaturization, computational capabilities, and software-driven imaging techniques. These developments have enabled not only real-time visualization in clinical environments but also high-fidelity structural assessments in industrial contexts, where accurate flaw detection and characterization are paramount.
One of the most impactful features of PAUT in industrial NDT is its ability to perform absolute depth sizing of cracks using tip diffraction echoes. This technique, unlike amplitude-based methods, is inherently less sensitive to surface conditions and coupling inconsistencies, making it a robust solution for geometry-independent flaw evaluation. As a result, tip echo-based sizing has become a widely accepted standard in sectors such as oil and gas, nuclear power, and aerospace.
Despite these advantages, deploying phased array systems in autonomous or resource-constrained environments presents unique challenges. Inline inspection tools, for instance, must operate within strict temporal and energy budgets while maintaining high data quality. The need to perform multiple measurements using varied aperture configurations and delay laws—often at medium inspection speeds—can introduce acoustic clutter and increase data processing demands.
This paper presents a structured approach to optimizing phased array measurement strategies under such constraints. By systematically analyzing the trade-offs between acquisition complexity, signal-to-noise ratio, and inspection throughput, the authors propose a methodology for selecting measurement configurations that maximize data utility while minimizing operational overhead. Furthermore, the study explores how multi-configuration datasets can be leveraged to construct high-resolution digital twins of inspected components. These digital models capture critical geometric features such as weld seams, wall thickness variations, and cross-sectional profiles, offering valuable input for integrity management programs (IMPs) and long-term asset monitoring.
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Low-Pressure High-Speed Gas: Adaptive Speed Control Outside of Traditional Use Cases
James Barlow1, Mukund Belavadi2, Simon Crompton2, William Deschamps-Robertson1, McKenzie Kissel1, Mark Ryan2
1Onstream Pipeline Inspection, Calgary, Canada
2Phillips 66, Houston, USA
1Onstream Pipeline Inspection, Calgary, Canada
2Phillips 66, Houston, USA
In todays economic environment, Operators are reluctant to reduce the throughput in their pipelines. This can be at odds with the Inspection technology ideal performance window. With this in mind, adaptive speed control systems were developed in the mid 1990’s to allow the MFL tool to operate at its ideal velocity in gas transmission bullet lines (~2000 psig at 10 m/s). This paper outlines the development of an adaptive speed control system that is capable of operating at both extremes of pressure. This system has proven itself at high pressure high flow gas lines and more recently on low pressure high flow lines an area traditionally ignored by ILI vendors for these systems.
A case study will be shared showing how operators with gas gathering systems consisting of low-pressure lines and tight fittings, that generally result in poor ILI tool dynamics, can be overcome with the use of a speed control system. This allows high quality integrity decisions to be made without restricting product throughput.
