| Name | Authors | Pages | Abstract | Price | Buy |
|---|---|---|---|---|---|
| Evaluating the Suitability of the US Pipeline Network for Hydrogen Service | Simon Slater, Neil Gallon, Ryan Sager, Richard Ingolia, Sebastiaan Schuite | 26 | Abstract | $30.00 | |
| Making Hard Decisions | Khanh Tran, Simon Slater, Jason Edwards, Sean Moran, Ann Reo, David Futch | 24 | Abstract | $30.00 |
Kelly Thompson¹
¹Williams, Tulsa, USA
Hard spots are a pipeline defect created during original manufacturing. These are typically considered stable unless acted upon by coincident environmental factors including coating degradation, atomic hydrogen, and stress. As a result of industry lessons learned and recent hard spot related failures on its system, Williams is executing a hard spot mitigation program that encompasses improvements to our risk assessment model to account for hard spot defects. In this presentation, we will share how we are incorporating this risk into our modeling approach and how those results influence the mitigation effort. Additionally, this presentation will discuss the benefits that can be realized through broader industry collaboration, current collaborative studies underway, and key metrics to advance industry understanding of the hard spot risk that ultimately will improve overall pipeline safety.
Scott Olson¹, Andy Studman², Jim Evans³, Aidan O’Donoghue⁴
¹Shell Trading & Supply Operations, Trinidad & Tobago, ²Shell International Ltd, Aberdeen, UK, ³Pigtek Limited, Temple Normanton, UK, ⁴Pipeline Research Limited, Glasgow, UK
Abstract
A routine sphering operation to control liquid hold up on a 30-inch trunk pipeline transporting wet gas was interrupted when a sphere became damaged and stalled in the pipeline following interaction with a subsea isolation valve inadvertently stuck in the partially closed position. Rectifying the valve to the fully open position followed by rescue pigging was selected as the remediation strategy. The offshore platform topsides facilities however were only designed to launch spheres, through the side branch of an unbarred tee and included a 30-inch to 36-inch reducer and 1.5D bend. The rescue pig required careful selection and onshore pigging trials were undertaken resulting in extensive modifications to the rescue pig design and set up to demonstrate the rescue pig could successfully traverse all the features in the topsides pipework. Following a successful subsea campaign to fully open the subsea valve, the rescue pig was deployed and successfully recovered the damaged sphere from the pipeline. This paper and associated presentation describes the details of the various challenges and solutions that enabled a safe and successful rescue pigging operation.
Chris Alexander1, Aquiles Perez2, Casey Whalen3
1ADV Integrity, Magnolia, USA. 2ECA Solutions, Houston, USA. 3CSNRI, Houston, USA
Over the past 30 years composite repair technologies have changed the landscape of pipeline rehabilitation and are used to reinforce a wide range of defects including corrosion, cracks, dents, and vintage girth welds. Composite crack arrestors have also played a role in this time period, although their use in this capacity has not been as widespread as their role in structurally reinforcing pipelines as part of integrity management programs. Interestingly, the Clock Spring technology was originally developed as a crack arrestor; however, the pipeline industry was able to conceive alternative uses for composite reinforcing technologies that spawned one of the fasting growing technology applications in the pipeline industry.
Composite crack arrestors have been proven to effectively arrest brittle and ductile running fractures, primarily focused on high pressure gas transmission pipeline systems. This has been validated via full-scale testing on high-energy pipe. For the most part there has been little design guidance provided to the pipeline industry for how a composite crack arrestor should be designed. The approach employed by most researchers has been to design and install a robust arrestor and then conduct testing to experimentally validate its ability to arrest running fractures. The composite crack arrestor design is considered a “success” if it stops the running fracture. Although the science behind modeling fracture is well understood, gaps exist in terms of how to arrest running fractures using composite materials using a well-thought-out design process. Methodologies have established a “qualified” approach rather than a “quantified” approach for design. This paper presents a framework for using composite materials as crack arrestors to arrest running fractures in CO2 pipelines that will be useful for pipeline companies seeking to build new pipeline systems or convert existing assets to CO2 service.
Kevin Spencer1, Phillip Bondurant2, Haraprasad Kannajosyula2, Jabin Reinhold3
1Quest Integrity, Calgary, Canada. 2Quest Integrity, Seattle, USA. 3Quest Integrity, Traverse City, USA
Small diameter pipeline crack in-line inspection (ILI) has typically been an underserved industry segment, primarily due to the difficulties associated with the physical limitations of packaging sensors, electronics and power sources within a small housing which is then able to successfully navigate challenging pipeline configurations. New ILI technologies are often therefore introduced for larger diameter tools and then miniaturized as far as possible. This paper presents the development, testing and implementation of an Electro-Magnetic Acoustic Transducer (EMAT) inspection vehicle specifically designed to detect and characterize longitudinal cracks in small diameter and difficult to inspect gas pipelines.
The paper will present the initial tool development and subsequent implementation on to a free-swimming bi-directional inspection vehicle. Since then, the tool has successfully and safely completed its initial inspections which provided critical information in the tool’s performance and further design improvements. Secondly the paper will present, via case studies, the tool’s performance in detecting and identifying axially orientated cracking anomalies through both full-scale testing and field validations. The case studies include comparisons with additional inspection data streams, providing an integrated approach to the identification of complex morphologies or interacting anomalies.
Daryl Bandstra1, Alex Fraser1, Miaad Safari2, Kai Ji2
1Integral Engineering, Edmonton, Canada. 2Enbridge Gas, Toronto, Canada
The transmission pipeline industry is increasingly utilizing probabilistic models for assessing the probability of failure of anomalies measured during in-line inspections such as corrosion and cracks. PHMSA (Pipeline and Hazardous Materials Safety Administration) has recently classified probabilistic models as best practice, suitable for supporting all types of decision-making, as these models effectively represent the uncertainty in input data using probabilistic distributions. When modeling corrosion using a probabilistic model, the in-line inspection data includes measurements of individual corrosion anomalies. When these anomalies are in close proximity, there is potential for interactions that reduce the overall burst capacity, and the effect of these interactions can be considered by modelling these individual defects as a cluster.
Some probabilistic analyses idealize the clusters as single, large anomalies while others address the added complexity of considering all possible combinations of the individual anomalies that comprise the cluster. This presentation will investigate the differences in the estimated probability of failure of these two approaches by evaluating a range of test cases and real-world clusters. These cases will illustrate scenarios where significant discrepancies exist and areas where both approaches yield comparable results. Additionally, we compare the effects of different approaches for modeling the correlation of measurement errors associated with anomalies within a cluster.
Kirsty McDermott1, Andy Fuller2, Chris Lyons2, Andy Brealey3, Neil MacKay4
1National Gas Transmission, Warwick, UK. 2PIE, Newcastle, UK. 3DNV, Loughborough, UK. 4STATS, Aberdeen, UK
National Gas Transmission own and operate the National Transmission System (NTS), the backbone of British Energy. The NTS feeds homes and businesses the essential gas required for life today in the UK. When operating above 70 bar, like most of the network does, the potential of failure or downtime of these pipelines has a critical impact on how interventions are carried out. However, changing how we do these interventions isn’t as simple, but why can’t we just make it so?
In line isolation tools have never been used on downstream onshore pipelines in the UK before. Regardless of the experience of others, NGT must assure itself through a process of due diligence that the new technologies and techniques do not create an immediate threat, or future integrity threats to the remaining life of the pipeline. NGT has developed an approval process, and has been trialling and testing tools, to develop an unbiased viewpoint built on evidence on the operational acceptance and integrity implications for the pipeline.
NGT has conducted an Isolation Joint replacement using a Pipeline Isolation Tool, instead of traditional venting (emissions reduction) and the need for recompression operations or alternative more invasive options (stoppling and bypass). The technology provided a fail-safe, leak tight double block, and monitor isolation, keeping a 48” pipeline fully pressurized at 56bar for 56km to the nearest block valve upstream. This method can help to reduce NGT’s emissions and operators’ exposure to high hazard methods.
Zain Al-Hassani1, Simon Slater2, Chris Davies3
1TC Energy, Houston, USA. 2ROSEN, Columbus, USA. 3ROSEN, Houston, USA
Gas transmission operators are now required by regulation to reconfirm the MAOP of pipelines lacking traceable, verifiable, and complete (TVC) pressure test records. TC Energy operates a 20” natural gas transmission pipeline in Northern Ohio, which has 54 individual segments that meet the requirements of a covered segment as per §192.624 (a)(1). TC Energy performed an Engineering Critical Assessment (ECA) of the pipeline to reconfirm the MAOP. The foundation of the ECA was a full suite of in-line inspection (ILI) technologies to detect, identify and size the anomalies that remain in the covered segments. This included ILI technologies capable of detecting crack-like anomalies, selective seam weld corrosion, and hard spots. ILI was also used to measure material properties and attributes when these were not known. Using the material data together with other data sets, the different populations of pipes within the covered segments were identified. TC Energy used this full suite ILI approach for ECA as pilot project. As such, a pressure test was also performed to confirm the applicability of the ECA approach. The ultimate aim of the exercise was to compare the two methods holistically across one example line to help develop a better understanding of which method should be used and when. This paper provides a walk-through of the ECA process performed by TC Energy and ROSEN. It provides a description of the documentation and specific content required by §192.632. It is intended to provide operators with an example of how an ECA is performed and highlight some of the critical aspects that have to be considered.
Corey Richards1, Thor-Staale Kristiansen2, John Nonemaker3
1ROSEN Group, Calgary, Canada. 2ROSEN Group, Bergen, Norway. 3ROSEN Group, Houston, USA
In response to pipeline restrictions that prevent the use of common free-swimming in-line inspection equipment, self-propelled inspection solutions have emerged as a transformative alternative. Leveraging robotics, automation, and advanced sensing, these solutions can autonomously navigate complex pipelines without the requirement for conventional access points or product flow. The adoption of self-propelled systems enables operators to conduct comprehensive inspections in pipelines previously considered inaccessible. This paper outlines the utilization of a self-propelled tether approach supported by case studies. The paper will outline in detail the workings of the inspection tool, particularly: the ridged ring UT sensor unit, the modifications and testing to ensure the system could pass features in the line, and the electrically driven propulsion system.
The first case study introduces a self-propelled robotic Ultrasonic Wall Measurement (UTWM) solution deployed in a 16”/20” pipeline. While the focus of this case study is the deployment of this inspection solution in the 20” section, it will also compare a previous operational attempt with running a free-swimming 16”/20” tool in this line. Overall, the case study will outline not only how this solution better ensured the integrity of the line itself, but also how its execution reduced operational requirements while still collecting high-quality in-line inspection (ILI) data.
Case Study two will address the challenge of offshore pipelines situated in remote and rugged terrains. This case study presents a tethered self-propelled inspection device equipped with ultrasonic sensors. What was of particular interest in the case study was the tool’s ability to navigate over 11 complex bends. The study showcases the device’s technical abilities in conducting real-time assessments and overcoming access limitations inherent in such locations. Further the case study will also cover the extensive testing required to safely complete such inspections.
Carlos Madera1, Sean Knight2, Austin Guerrero2, Simon Slater3
1Dow Chemical, Houston, USA. 2ROSEN Group, Houston, USA. 3ROSEN Group, Columbus, USA
With the passage of §192.607 and PHMSA’s subsequent responses in FAQ’s 21 and 22, ILI is an approved method for measuring properties and delineating pipe into populations with similar characteristics. In cases where material properties remain unknown, ILI populations can be leveraged to optimize decision making and test locations to close out material property verification. To enable this, the process must achieve the required confidence without necessarily having to test one sample per mile, which is defined as the default in regulation. §192.607(e)(5) states that an alternative statistical sampling approach can be used if it can “achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid.” This paper will provide details on two alternative sampling approaches that have been approved for use by PHMSA on Dow Chemical’s 8” Mossville to Kaplan line segment. The approaches are based on a combination of ILI and test data using statistical analysis to satisfy the 95% confidence level. The efficacy of these approaches will be demonstrated using the assessment program performed by Dow Chemical to define the status of existing material properties and produce a plan to close out unverified material property values and fulfill the requirements of §192.607. The discussion will provide specifics of the approaches used by Dow Chemical, including the scope of documentation required to support its implementation and acceptance by the regulator.
Bernardo Cuervo
EN Engineering, Houston, USA
As in-line inspection (ILI) yields the highest-per-mile discovery of anomalies, running cleaning pigs and ILI tools are an important part of most integrity management programs. However, not without their risks. On June 28, 2021, a natural gas explosion occurred after workers inserted a gauge plate in a launcher trap as part of a routine pigging activity. The explosion went through the open launcher enclosure, ejecting the pig from the barrel, injuring two workers and killing two more. On November 15, 2021, PHMSA published the Final Rule: Safety of Gas Gathering Pipelines (86 FR 63266). With this rule, more than 400,000 additional miles of gas gathering pipelines are now covered by Federal reporting requirements. Proactive operators are beginning to ascertain the ILI feasibility of thousands of miles of gathering pipelines for future ILI. Many of these pipeline operators are beginning to audit and review their pigging procedures to prevent catastrophic incidents. This paper describes the entire process from the perspective of a pipeline operator; including the experiences of maintenance personnel, and the challenges faced by field operations during the implementation and use of a new methodology.
Atul Ganpatye1, Chris Alexander1, Rodney Clayton2, Tony Rizk2
1ADV Integrity, Inc., Magnolia, USA. 2Boardwalk Pipelines, LP, Houston, USA
Traditional code-based approaches for assessing crack-like flaws in pipelines rely on several idealizations/assumptions regarding flaw shape and orientation, material properties, and applicability of the analytical framework used to estimate pipe performance. The uncertainties in these assumptions often result in an underestimation of pipe performance in terms of failure pressure prediction. Full-scale tests with pipe containing crack-like flaws have shown that the actual failure/burst pressures can be as high as 50% over the predicted failure pressure. This paper outlines an experimental approach to quantify the “effective” fracture resistance for crack-like flaws as it correlates to the results from full-scale testing. Using effective fracture resistance for failure pressure prediction is discussed as an alternative approach to providing better alignment with observed failure pressure data.
The study included full-scale burst testing of 12 samples of 26-inch OD x 0.281-inch wall, Grade X52 pipe, and four samples of 30-inch OD x 0.299-inch wall, Grade X60 pipe, containing crack-like features. Cracks were generated in the base pipe having depths ranging from 20.9% to 69.0% of the pipe’s nominal wall thickness. On average, experimental results showed that the actual failure pressures were between 20% and 40% higher than those predicted using analytical assessment methods. Analytical assessment was performed using three different fracture models: Modified Ln-Sec, MAT-8, and API 579. The paper discusses the interpretation of the discrepancy between the predicted and observed results in terms of effective fracture resistance of the pipe. This resistance is explored as a manifestation of lower crack tip constraint in a full-scale pipe-geometry sample, compared to traditional measures of fracture toughness using sub-scale specimens. Results are also discussed from a practical perspective of the potential reduction in the number of digs based on reinterpretation of failure pressure ratios using the effective fracture resistance.
The study results have the potential to provide a more robust predictive capability for estimating burst pressures of pipes containing crack-like flaws. Using the reinterpreted effective fracture resistance based on actual test data allows a systemic incorporation of almost every single detail in the pipe performance “system” – in this context, the “system” is the collection of all parameters/factors that directly or indirectly influence the pipe performance, such as: pipe properties, flaw morphology, stress intensity due to the presence of the feature, etc. Improved confidence in the predicted pipe performance using full-scale test data has the potential to meaningfully impact integrity management approaches by reducing the number of digs that may be flagged when using the traditional approach.
Rhett Dotson1, Jeff Haferd2, Karim Kabbara2, Nic Roniger2
1D2 Integrity, LLC, Houston, USA. 2Marathon Pipeline, Findlay, USA
The use of bending strain analyses for identifying and managing pipeline geohazards has grown significantly in the last decade. While bending strain assessments are useful for identifying and prioritizing geohazard features impacting pipelines, it is understood that bending strain assessments cannot provide the total strain which is required for comparison to calculated tensile or compressive strain capacities in determining fitness for service. The inability to easily calculate membrane strain and the resulting total strain in impacted pipelines represents a gap in the industry. A few simplified methodologies have been proposed to estimate the membrane strain based on the displaced shape of the pipeline, and some newer ILI technologies are available for explicitly measuring the membrane strains. Level 3 numerical analysis is another method that can be used to estimate the membrane, bending, and total strain states in a pipeline impacted by a geohazard. This paper presents the results of a study covering nine finite element analyses completed on separate geohazards with varying characteristics. The paper discusses the methods used in the study to construct the models, including incorporating initial strains and estimating as-built conditions of the pipeline. Comparisons are provided between the membrane strains calculated explicitly in the models and membrane strains estimated using simplified methods. The study examines how membrane and bending strains develop and progress at larger pipeline displacements noting important differences in axially and laterally oriented geohazards. The conclusions from this study provide useful insights to operators on how to perform level 3 geohazard assessments, and how to properly use the results to make informed integrity management decisions for monitoring or mitigation or geohazards threats.
Rhett Dotson1, Briant Jackson2, Matt Stevenson2, Chris Newton2
1D2 Integrity, LLC, Houston, USA. 2Phillips 66, Houston, USA
Many pipeline operators have performed bending strain assessments based on IMU data and received results that are challenging to interpret and properly sentence, especially if the assessment identified hundreds of features. These challenges can be compounded if the operator acquires a second IMU data set and elects to perform another bending strain assessment or a comparison assessment between the two data sets. In these situations, operators often observe significant variations in the number of reported bending strain features and the reported strain magnitudes associated with those features. These challenges can rarely be solved by comparing the final reports as the graphical information for the bending strain features is often rendered differently between vendors. This paper presents the results of a case study comparing four IMU data sets acquired over a decade on the same pipeline segment where the number of reported features varied from 195 to 384. The paper examines the causes of this variation in reported features including the influence of gage length, signal noise, and analyst judgement. The case study also identifies common challenges that occur when comparing multiple IMU data sets and provides strategies for recognizing and overcoming these challenges. The paper concludes by identifying how bending strain reporting requirements can be standardized and help operators minimize these challenges in future assessments.
Pablo Cazenave, Ming Gao, Katina Jimenez, Ravi Krishnamurthy
Blade Energy Partners, Houston, USA
The possibility of hydrogen-induced cracking and hydrogen-assisted cracking as interactive threats is increasingly becoming a safety concern to pipelines. While few cases exist of fully documented onshore transmission pipeline failures due to CP-related hydrogen-assisted cracking, the possibility of hydrogen-assisted failures needs further investigation, particularly hydrogen interacting with stress corrosion cracking in corrosion potentials more negative than -850 mV CSE.
This paper presents a case study of a 22-inch onshore natural gas transmission pipeline that experienced in-service leaks and a rupture associated with axially and circumferentially oriented crack colonies initially thought to be traditional stress corrosion cracking. In-depth metallographic examination revealed cracking fracture paths consistent with hydrogen-assisted cracking. Further investigation of potential sources of hydrogen concluded that the source is the impressed-current cathodic protection system operated for decades at near the P/S potentials of −1200 mV CSE.
An approach to mitigating the threat of hydrogen-induced cracking in onshore pipelines is also outlined.
Jason Weiss1, Brett McNabb2, Alisdair Blackley1
1Argus, Edmonton, Canada. 2Apache Pipeline Products, Edmonton, Canada
The efficient and safe transportation of fluids through pipelines has been a cornerstone of modern infrastructure for decades. However, pipeline operators often face challenges when it comes to inspection, maintenance, and cleaning. These challenges are often addressed through pigging programs, however a large portion of existing pipelines are considered “unpiggable”. This is primarily due to pipeline size, complex geometry, or unique operational conditions. In recent years, the need to maintain and ensure the integrity of all types of pipelines, including those previously considered unpiggable, has grown significantly. The paper begins by defining what makes a pipeline “unpiggable” and delves into the common reasons for this classification. It will then explore the challenges associated with pigging previously unpiggable pipelines and some innovative solutions for pigging this type of infrastructure.
One of the primary challenges in pigging unpiggable pipelines is the development of suitable pigs and technologies. Traditional pigs are often designed for pipelines with standard dimensions and features. The paper discusses how the industry has responded to this challenge through the development of specialized pigs tailored to the unique requirements of unpiggable pipelines. This includes a summary on the development of various cleaning and product recovery solutions, such as foam pigs and swabbing devices, designed to address the unique challenges posed by unpiggable pipelines. Additionally, the paper includes information on the use of small, single body inspection tools that have been developed by industry to allow for in-line inspection in these applications.
Another large challenge surrounds the changes required to update and modify existing pipelines to include the necessary pig launching and receiving infrastructure and remove or update features that hamper successful pig runs. The paper highlights the challenges associated with collection of data on existing historical pipelines, along with some of the changes required to ensure successful pigging operations. Specifically, the paper outlines how the use of pipeline Pigging Valves and Multi-Pig Launchers can be used as an innovative alternative to traditional barrel-style pig launchers or receivers in previously unpiggable applications.
In addition to technological advancements, the paper delves into the operational, regulatory, and environmental considerations faced during pigging activities in unpiggable pipelines. These challenges include access to the pipeline, transportation and deployment of pigging equipment, high frequency pigging, emissions regulations, and safety considerations.
In conclusion, the pigging of previously unpiggable pipelines presents a compelling challenge that demands innovative solutions. This paper provides an overview of the challenges faced and the technological advancements, operational strategies, regulatory compliance, and economic factors that must be considered. By understanding these complexities, pipeline operators and industry professionals can make informed decisions and effectively address the unique requirements of pigging previously unpiggable pipelines, ensuring the continued safe and efficient transportation of vital fluids in our modern infrastructure.
Casey Dowling1, Pete Barlow2, Joel Van Hove3
1BGC Engineering USA, Golden, USA. 2BGC Engineering, Edmonton, Canada. 3BGC Engineering, Vancouver, Canada
Inertial measurement unit (IMU) bending strain data has been recognized as a crucial tool in detecting ground movement impact along operating pipelines. In Line Inspection (ILI) vendors produce bending strain and movement reports which often include impact from landslides and sinkholes, but also include a host of other causes. While these bending strain reports serve as a useful initial screening tool, previous studies have found that approximately 90% of these reported features are related to pipeline construction or operation, not ground movement impact. It is not uncommon for hundreds of bending strain features to be reported on a single 100-mile pipeline segment, and it is important for pipeline operators to be able to quickly differentiate ground movement caused bending strains. Unlike construction-related bending strains, ground movement tends to increase strain demand over time and often has a larger longitudinal strain component because of axial loading or pipe elongation. Often, landslides and sinkholes produce readily apparent signatures in IMU data that are evident during a cursory review. Drawing upon 10 years of experience using IMU data to characterize and monitor geohazard impact along pipelines and geotechnical assessment of more than 6,500 bending strain features, this paper provides examples of common IMU signatures indicative of landslide and sinkhole impact with the intent that operators can learn to spot the most obvious potential geohazard impact sites and prioritize those for further assessment or action. Examples of signatures from single run and run-to-run IMU data are presented along with a discussion of the basic mechanisms that produce the signatures. Key ground-movement signatures within other IMU outputs such as pitch, heading, and position are also discussed. Construction-related IMU signatures are provided to help operators understand how these differ from ground movement signatures.
Frank Micheli1, Ken Maxfield2, Phil Tisovec2
1Bridger Pipeline, Casper, USA. 2KMAX Inspection, Millcreek, USA
Bridger Pipeline operates a crude oil gathering system, of approximately 3500 miles, in the Williston Basin of western North Dakota, eastern Montana and the Powder River Basin of Wyoming in the USA. The Bridger system contains many small diameter (3” to 6”) gathering lines that are a challenge to inspect with ILI tools. These challenges include low flow conditions, line cleanliness and paraffin build up. Many are first time inspections of pipelines with limited or unknown records, trap configurations, and fittings such as heavy wall tees and elbows. Also of concern are weather constraints with the seasonality of ILI inspection projects for pipeline repair and access. This paper presents how these challenges are addressed to successfully run ILI to comply with Bridger’s integrity management program.
Ali Ebrahimi1, Arash Mosaiebian2, Amir Ahmadipur1
1Geosyntec Consultants, Inc., Houston, USA. 2Enbridge, Inc., Calgary, Canada
Pipelines are linear structures that cross various slope geometries and geologies and are susceptible to geohazards such as landslides. The ground movements from the landslides can potentially induce axial, bending, and torsional stresses in pipelines. Inertial Measurement Unit (IMU) bending strain data are commonly used for assessing the pipeline integrity in the area impacted by a landslide.
Ground movement by landslides oblique to the orientation of the pipeline can cause lateral deflection as well as localized axial elongations/contractions in the pipeline, which will result in accumulation of bending and axial strains on the pipeline. Common factors impacting the magnitude of strain accumulation are pipeline deflection (or out-of-straightness), deflected pipeline length (engaged part of the pipeline within the body of the landslide), pipeline diameter, and orientation of the pipeline relative to the direction of landslide movement.
This paper will review and present the above information for more than 70 landslide sites within the Appalachian region of the USA. This paper will also present a correlation between the measured bending strain from the IMU tool runs and the pertinent pipeline features such as pipeline out-of-straightness, deflected length, pipeline diameter, and pipeline orientation relative to the landslide direction.
This paper is intended to assist pipeline geohazard practitioners in performing the first round of induced bending strain screening under conditions where IMU bending strain data may not be available.
Nikolaos Salmatanis1, Amit Rajput2, Praveen Kumar2, John O’Brien3
1Chevron, Houston, USA. 2XaaS Labs, Sunnyvale, USA. 3itcSkilla, Houston, USA
Reliable detection and accurate localization (especially) of small leaks tends to be the weak link in Leak detection programs for oil & gas pipeline operators. The paper presents the results of a study aimed at assessing the feasibility of reliably identifying pipeline leaks using inline approaches based on minimally intrusive sensing devices that are now available to pipeline operators. These low form-factor sensing devices incorporate sensors based on Audio, Magnetometry, Pressure and Velocity. A test pipeline flow loop was leveraged to create a customized test setup and a test execution methodology was developed and executed towards this end. Sensing equipment from two different suppliers were used to collect various sensor datasets on separate test runs In test scenarios where leak signatures were identified, the team investigated the feasibility of ascertaining the limits of detection using such approaches. Key findings and Lessons learned are summarized
Michael Turnquist1, Yohann Miglis2, Yanping Li3
1Quest Integrity, Boulder, USA. 2Kinder Morgan, Colorado Springs, USA. 3Enbridge, Edmonton, Canada
A critical factor in determining the remaining strength of a corrosion feature intersecting a longitudinal seam weld (LSW) is whether the corrosion is preferential to the weld (often referred to as selective seam weld corrosion or SSWC) or coincident with weld yet no preferential attack of the bondline is occurring. SSWC is a form of corrosion that most often occurs in the bondline of electric resistance welded (ERW) and electric flash welded (EFW) pipe and typically has the appearance of a V-shaped groove. Past research supports that if no preferential attack of the LSW bondline is occurring and the weld has adequate ductility, the presence of the LSW does not reduce the remaining strength of the feature when compared to features not intersecting the LSW, and that industry accepted corrosion assessment models are suitable.
This paper provides an overview of additional full-scale destructive testing and detailed engineering analysis that further supports the observation that under most realistic conditions, the presence of a LSW does not negatively impact the remaining strength of corrosion feature. Potential exceptions to this behavior are related to the ductility of the weld, the constraint effects and morphology from the feature geometry, the operating stress of the pipe, and whether or not preferential attack of the LSW bondline is occurring.
The work presented in this paper is part of the Pipeline Research Council International (PRCI) project EC-02-13 “Response to Corrosion Interacting with the Longitudinal Seam in Liquid Pipelines”. The objectives of this project are to clarify which analysis methodologies are appropriate to assess corrosion coincident with a pipeline LSW and to support the development of recommended guidelines to effectively manage these types of features. This work is being executed in parallel with sibling projects EC-02-12 “Evaluation of Selective Seam Weld Corrosion Susceptibility”, NDE-4-13 “Selective Seam Weld Corrosion Detection with In-line Inspection Technologies”, IM-3-03 “Comprehensive Review and Assessment Guidelines for SSWC”, and IM-1-08 “Pragmatic Application of MegaRule RIN 1 – 192.712 Toughness Values”
Ryan Huntley1, Charles Venditti1, Sammy Hester1, Steven Bevers2, Russ Roberts2, William Freeman2, Kristy Compter2, William Biggers2, Ryan Jacob2
1TRC Companies, Inc, Houston, USA. 2Denbury, Plano, USA
Pipelines are critical to transporting liquids and gas safely and efficiently throughout the United States. Companies have been transporting Carbon Dioxide (CO2) via pipeline for the past several decades, primarily for use in Enhanced Oil Recovery. With efforts to decarbonize projects or reduce global emissions, thousands of miles of new CO2 pipelines are being designed and installed to transport CO2 emissions from the point source to permanent storage locations. Performing risk analysis and mitigation is an important part of the design and operation of any pipeline system. Understanding and predicting the risk of a CO2 pipeline rupture event presents unique challenges due to its dense/heavier than air characteristics when released from the pipeline. Because it will exit the pipeline as a dense gas, under certain weather and topographic conditions it can remain close to the ground, following the terrain and aggregating in low areas, presenting an asphyxiation risk to those who may be in the release cloud. This paper will provide results of a study that is based on a prior analysis completed for a 20” diameter, CO2 pipeline whereby the following parameters were evaluated for flat terrain to develop a general framework: exposure distance, release timing, impact of automating isolation valves, and installation of new automated isolation valves. The paper will also cover the deployment of the general framework to validate the methodology, with the inclusion of topography to model a potential pathway of CO2near a populated area.
Michiel Brongers
Kiefner and Associates, Inc., Columbus, USA
Operators with existing pipelines with laminations may have the desire to perform welding to install fittings or other appurtenances. This paper presents the results of an evaluation of the potential threat of lamellar tearing under in-service fillet welds. The research included modeling to determine the minimum recommended distance for welding at or near laminations, and a full-scale hydrostatic pressure-hold test on laminated pipe with welded fittings to demonstrate if the presence of laminations would interfere with the welds. Four different scenarios were investigated: (1) fitting welded over laminated area, (2) portion of weld bead place on top of a localized lamination, (3) weld bead some distance from localized lamination, and (4) fitting welded on non-laminated area of pipe with laminations elsewhere. The developed approach was a unique and innovative way to evaluate welding on pipe with laminations. The results from this project and the provided guidance that was developed will benefit the pipeline industry as a whole.
Intisar Rizwan i Haque, Ryan Lacy, Simon Bellemare
Massachusetts Materials Technologies, Natick, USA
Growing use of advanced In-line Inspection (ILI) for detecting seam anomalies has increased the demand for Engineering Critical Assessment (ECA) to differentiate the many non-severe features that do not need repair from features in certain assets where repairs are warranted. To perform the ECAs and reduce the number of unnecessary excavations of vintage lines, pipe cutting for laboratory testing has become more common to obtain Charpy V Notch (CVN) toughness, which is often unavailable when legacy manufacturing standards did not require such testing. Non-destructive evaluation (NDE) of pipe seam toughness as a part of opportunistic data collection is an attractive alternative to pipe cutouts and can be applied to prior excavations with sufficient NDE data. An NDE process using the frictional sliding method and other surface measurements has been recently validated for assessing the seam toughness of vintage electric resistance welded (ERW) pipes. This paper details this NDE process and its validation, along with results from case studies of its initial field deployment. The field instrumentation is the same as used for pipe grade determination using the frictional sliding method. When certain conditions are met for a given ERW pipe population, a ductile fracture initiation and an associated CVN toughness of 10 ft-lbs can be positively confirmed when conservatively accounting for measurement uncertainty. Utilizing a toughness of 10 ft-lbs is a significant advantage over conservative values such as 4 ft-lbs for gas transmission pipelines with no history of failure. Field deployment of this process has successfully reduced the total number of excavations on projects. The NDE process capabilities can be further enhanced when combined with an NDE determination of pipe body toughness, using a separate, but complementary, technique.
Richard Mcnealy1, Vahid Ebrahimipour2, Duran Mendoza1, Praveen Kumar3, Nikolaos Salmatanis1
1Chevron, Houston, USA. 2Chevron, Malongo, Angola. 3Xaaslabs, Sunnyvale, USA
While many upstream pipelines and flowlines are piggable, their operating characteristics may render them not smart piggable because they cannot be practically cleaned or configured to enable successful conventional high resolution in-line inspections. Minimally intrusive sensors are now available to pipeline operators that manage in-line navigation risks while recording full length data used to understand the condition of the pipe wall equivalent to a hydrostatic integrity assessment and detecting leak points-of-interest (POIs). This paper presents the results from a pilot deployment of a multi sensor device comprised of large standoff passive magnetometer sensors coupled with acoustic, pressure and temperature sensing capability all integrated into the form factor of a minimally intrusive maintenance pig. An understanding of fundamental magnetic theory is applied to the sensor data to characterize the interaction of a ferro magnetic body, i.e., steel line pipe, within a native magnetic field to conclude relative changes in the mass or changes in pipe wall thickness along the full length of the pipeline. The pilot also illustrates a method that leverages multiple sensor datasets using 1st principles equations to calculate various parameters for characterizing leak location and severity. Comparison of fundamental magnetic, acoustic and temperature quantities, measured by the sensors, with physical pipe wall truth data illustrates the basis for models developed to conclude pipe wall condition and integrity management actions consistent with equivalent understanding derived from a hydrostatic integrity assessment and effective loss of containment risk management using cloud-based software applications.
Matt Ellinger, William Harper, Pam Moreno, Stacy Hickey, Adriana Nenciu, Preston Galloway
DNV, Dublin, USA
Results from magnetic flux leakage (MFL) in-line inspection (ILI) surveys provide valuable information that help pipeline operators make informed and defensible integrity management decisions. When subsequent ILI survey data are available, meaningful, and data-driven corrosion growth rates can be derived along the length of a pipeline by performing a comprehensive ILI-run-to-run comparison. A comprehensive ILI run-to-run comparison should include the following components:
ILI vendors typically identify metal loss anomalies that are on (i.e., crossing) the longitudinal seam weld or near (i.e., adjacent to, or in the heat affected zone) of the longitudinal seam weld versus those that are in the pipe body (i.e., away from the longitudinal seam weld). During a comprehensive ILI run-to-run comparison analysis, the authors of this paper observed a trend in which ‘spreadsheet-based’ corrosion growth rates for metal loss anomalies reported on or near the longitudinal seam weld were consistently higher than those reported in the pipe body. Following this observation, the authors performed an in-depth analysis to better understand this trend. The following tasks were completed as a part of the analysis:
This paper will detail the methodology and results of the authors’ analysis. Key findings and practical applications will be presented. The paper will provide valuable insights into managing pipeline integrity with respect to ILI-reported metal loss anomalies at or near the longitudinal seam weld.
Colin Scott, Abu Muntakim
Northern Crescent, Calgary, Canada
Stress corrosion cracks are typically found in colonies comprised of multiple parallel aligned cracks. However, they are usually assessed as individual (or single interlinked) cracks, assuming the deepest of the colony represents the crack driving force for failure. This common approach does not account for the effects of crack shielding. It is known that neighboring cracks may dissipate stress intensity and result in a lower crack driving force.
In this work we use FEA to estimate the stress intensity factors associated with crack colonies. Results demonstrate how stress intensities in colonies are decreased relative to those of individual cracks. This is consistent with recent industry model studies that tend to underestimate critical failure pressures of in-service SCC flaws. It also indicates a fracture mechanics contribution to the known phenomenon of crack dormancy, which is often attributed to electrochemical and kinetic factors. The findings can be used to modify fitness for service assessments and improve SCC integrity program efficiency.
Tom Bubenik, Steven Polasik, Benjamin Hanna
DNV, Dublin, USA
Effective area calculations are used to identify which corrosion depth measurements control the failure pressure of a cluster of metal-loss anomalies reported by an in-line inspection (ILI). The depth measurements usually correspond to individual anomalies that are grouped together based on defect interaction criteria. The effective area calculations determine an effective length and depth based on the ILI reported cluster and box lengths and depths at the time of the inspection. As corrosion growth occurs, though, the depths of some or all of the individual anomalies within a cluster can increase. As a result, the effective length of the cluster can increase or decrease.
Growth of individual anomalies within a cluster is often non-uniform, with some anomalies increasing in depth (and possibly length) more quickly than others. As a result, local “hot spots” can develop and eventually dominate the effective area calculations. Understanding how corrosion growth affects the effective dimensions of a cluster is important in estimating remaining lives and determining which clusters are most likely to fail first. The flaw geometry at failure depends on the local operating pressure, the corrosion growth rates, and the initial cluster geometry.
Remaining life calculations depend on reliable estimates of both initial and final metal loss depths and lengths. Because differences between individual metal loss box corrosion growth rates can affect effective flaw dimensions, accuracy is important. Initial corrosion depths and lengths are reasonably well known from typical ILIs. Overestimating or underestimating the flaw geometry at failure under operating conditions can lead to overly conservative or unconservative remaining life predictions.
This paper evaluates the effects of corrosion growth on the effective dimensions, flaw geometries at failure, and remaining lives of clusters. The authors examine 20 real-world clusters ranging in length from short to long and containing few to many individual anomalies. The authors determine when and how each cluster’s effective length and critical depth changes as corrosion growth takes place along the cluster until it reaches a failure condition at the local operating pressure. Then, they evaluate how the changes in effective lengths and critical depths affect remaining life predictions. Conclusions regarding how to best estimate remaining lives of clustered anomalies are developed and documented.
KEYWORDS: Engineering analysis, ILI analysis, ILI applications, Corrosion studies
Greg Zinter1, James Staszuk1, Cory Solyom2, Brianna Bossio3
1PureHM, Edmonton, Canada. 2PureHM, Calgary, Canada. 3Enbridge Inc., Edmonton, Canada
Inline inspections tools and cleaning pigs are routinely used to ensure the safe and economical operation of oil and gas pipelines. While in the pipeline, all ILI tools and pigs must be tracked on a real time basis so that the pipeline can be operated safely. Recent developments in remote ILI tool tracking technology have improved the safety of ILI projects by eliminating the need for field technicians to travel to site to witness the tool passage. These improvements have also made tool tracking more reliable and, most often, lower cost.
Remote tracking offers operators a way to track their inline inspection tools without the need to constantly have field personnel actively on the ROW, effectively reducing risks to personnel and the project. This is of particular increased benefit when tracking overnight and over difficult to access terrain. Traditionally, the solution for difficult access has required the aid of helicopters for AGM deployments, and retrievals, meaning significant effort is required to facilitate tracking for every single project. As pipeline owners look to enhance their inspection programs through increased inspection frequency, these issues of accessibility are exacerbated. Advancements in tracking technology and services are addressing this issue and making it easier and cheaper to track their critical ILI tools.
For example, Enbridge has installed a permanent remote tracking system across large inaccessible sections of its Athabasca pipeline network. This system consists of a series of AGMs, strategically located to ensure full tracking coverage. These remote systems are permanently installed and powered by solar energy. Pure HM has partnered with the Enbridge to monitor this system 24/7, year-round to ensure consistent and reliable tracking of any tool used in the line, eliminating the need to mobilize field technicians or helicopters.
This paper will explore the innovative approach Enbridge has taken to mitigate risk and drive a cost saving of over $4,000,000 over the duration of the 5-year program.
Morgan Dormaar1, Derrick Hunter1, Cory Solyom2, Dixit Patel3, Wade Forshner4, Michael Callan5
1PureHM, Edmonton, Canada. 2PureHM, Calgary, Canada. 3TC Energy, Calgary, Canada. 4Pembina Pipeline, Calgary, Canada. 5Keyera Corp, Grand Praire, Canada
Although a lost or stuck pig is rare, when it does occur, the costs can be extremely high, raising the location efforts to the highest priority.
A lost or stuck pig in a pipeline can have a serious impact on an operator’s ability to transport product. While uncommon these days, this does still occur, and when it does it can be detrimental to the safe and efficient operation of an Oil and Gas pipeline. Therefore, the ability to identify the location of the obstruction quickly is of utmost importance and can become a singular highest priority for the pipeline operator. Recent advancements in technology have facilitated such locating efforts, and saved operators time, expense and aggravation.
Oil and Gas pipelines are comprised of ferromagnetic materials, such as iron, nickel, steel and other materials. Large Standoff Magnetometry (LSM) technology is known to be used to identify and locate elevated levels of stress through the measurement of the magnetic field surrounding steel pipelines. LSM detects inverse magnetostriction (also known as the Villari effect) which is the change of the magnetic susceptibility of a material when subjected to mechanical stress. LSM technology has been used to detect defects as they appear as changes in the magnetic field around the pipeline which can indicate the presence of stress on the pipe. Thus, LSM can identify stress concentration caused by full pipeline blockages.
This paper will discuss how the XLI PWA technology works to locate lost or stuck pigs, and review 3 successful case studies.
Case Study 1 will discuss locating a lodged MFL tool in a 42” Gas pipeline. PureHM worked with TC Energy to locate an MFL tool that had become lodged in their line. TC Energy was ready to excavate and cut the tool out but required confirmation that they were in the right area before investing significant resources into the tool retrieval process, PureHM was able to mobilize and confirm tool location in a single day.
Case Study 2 will explore a project where a pig was lost and was fully obstructing the pipeline. Pembina provided several potential locations where the pig was thought to have stopped moving. Within 2 days PureHM was able to locate the stuck pig and the front of the blockage. Pembina was able to free up the stuck pig by Hot-Tapping.
Case Study 3 will present a more complex project where PureHM worked with Keyera to identify the location of multiple stuck pigs that were being obstructed by a wax slug in a 4-inch pipeline. PureHM worked over a period of 4 days to identify the location of the 2 stuck pigs. Keyera was then able to heat the pipeline at the location identified by the XLI PWA Technology and melt the wax obstruction to get the pipeline operational again.
Xiang Peng1, Kevin Siggers1, Johannes Palmer2, Gurwinder Nagra3
1ROSEN Technology Canada Ltd., Kelowna, Canada. 2ROSEN Technology and Research Center GmbH, Lingen, Germany. 3Enbridge Liquids Pipeline, Calgary, Canada
The inspection capability of magnetic flux leakage (MFL) is subject to the angle between its magnetic field and the defect. To get a comprehensive assessment on corrosion defects, more and more pipelines are inspected with two MFL techniques with perpendicular magnetic fields, i.e., axial MFL (MFL-A) and circumferential MFL (MFL-C). Currently, inspection data from each MFL tool are analyzed separately, and two inspection reports are generated respectively. In this paper, we propose a model which aligns the data from two magnetic field orientations and fuses the respective signals into a single inspection result to achieve a 3D metal loss profile with laser-like precision. The alignment of the signals is achieved through conversion into the same modality i.e., MFL-A converted to MFL-C and vice versa. The fusion model is a neural network trained on historical MFL and laser scan data. It takes the aligned MFL-A and MFL-C signal data as the input and produces 3D metal loss profiles with high resolution. In this case study with Enbridge Liquid Pipelines, the proposed model is validated on the field data from an operational pipeline. The depth comparison of the derived 3D metal loss profiles versus laser scan profiles has very promising results. The 3D metal loss profiles are also used as inputs to RSTRENG as well as P² methodologies. The detail of the fusion derived profiles, compared to the box derived profiles, leads to a more accurate estimation of pipeline burst pressure.
Shanshan Wu1, Joseph Bratton1, Jing Wang2, David Kemp1, Luyao Xu1, Greg Quickel1
1DNV, Dublin, USA. 2TC Energy, Calgary, Canada
The Pipeline and Hazardous Materials Safety Administration (PHMSA) issued RIN2 of the Final Rule (frequently referred to as the “Mega Rule”) on August 4, 2022, which will impact the pipeline industry’s approach to the assessment of dents and other mechanical damage. The Mega Rule provides detailed requirements in the Code of Federal Regulations (CFR) Title 49 Part §192.712(c) regarding how to perform a dent engineering critical assessment (ECA). With the Mega Rule taking effect in 2024, it is expected that more dents will be considered for ECA to determine the response plan and timeline.
This paper will share guidance on selection criteria for dent ECA through five case studies. The case studies include Ductile Failure Damage Indicator (DFDI), Strain Limit Damage (SLD), and dent fatigue analysis using finite element analysis (FEA). Additionally, findings from field investigations, laboratory results, and other pertinent information associated with the respective dents will be presented. Guidance regarding best practices to assist operators in selecting suitable locations for dent ECA versus excavation will be provided from the case studies.
The primary objective of this paper is to share experiences to the industry ahead of the upcoming dent ECA requirements outlined in Part §192.712 (c). This paper will share lessons learned for things to consider when evaluating the suitability of performing an ECA and to help avoid sole reliance on ECA results when other factors demonstrate that the results may not be reliable.
Mark Wright, Amin Singh, Tanner Jones
ROSEN USA, Houston, USA
Achieving zero incidents has been a key safety objective across the pipeline industry. The relationship between the pipeline industry and pipeline regulations has seen several iterations since the first regulations were introduced in 1968. Significant changes and rigorous regulations enacted in 2002 required pipeline operators to create a structured framework for risk and integrity management programs. However, subsequent safety performance has been static, as detailed in the preamble to more recent updates in 2019. Pipeline regulations serve as minimum requirements for achieving operational safety by reducing incidents, and there should be hope of a more substantial impact with the effects of rule changes to both gas and hazardous liquid pipeline regulations in 2019.
Failures of pipelines are often complex, involving primary, secondary and even tertiary contributory factors, while rulemaking must be discrete and realistically achievable for compliance. Thus, failures and rulemaking are not completely associative, but neither are they mutually exclusive. The preamble to the 2019 rules identified clear lineages between a subset of significant events and rulemaking i.e. measures that directly address some of the causes of significant events. Whilst this seems intuitively sensible, where do these solutions lie in the spectrum between causality and mutual exclusivity on a wider scale?
All pipeline failures are undesirable, but each provides an opportunity to learn and highlights systemic vulnerabilities by identifying areas for improvement. This paper explores reported failure data for both gas and liquid transmission pipelines in the U.S. between 2003 and 2022. The paper will identify trends and thus residual gaps in understanding of failures within the industry for proactive measures to prevent future incidents. The complexity of failure will be explored by review of supplementary NTSB investigation reports and commentary on the combination of factors at play. The primary goal of integrity management is to operate assets such as pipelines safely. Inherent is that integrity management cannot be about doing everything possible, rather maximizing everything practicable. This paper hopes to identify what practicable may look like now and in the future.
Brian Ellis1, Louise O’Sullivan2, Jake Opdahl3
1pipelinelogic, Lakewood, CO, USA. 2Penspen, London, UK. 3Teren, Inc., Lakewood, CO, USA
The integration of pipeline digital twins with geohazard modeling presents a groundbreaking approach to enhance the safety and resilience of critical energy infrastructure. This presentation explores the synergy between pipeline material data, inline inspection technology, and advanced geohazard modeling techniques to create comprehensive geohazard threat assessments.
Traditional geohazard assessments often rely on limited data sources, leading to potential vulnerabilities in pipeline systems. However, by combining detailed pipeline material information and high-resolution inline inspection data, a more accurate and robust representation of the pipeline’s condition and vulnerabilities can be achieved. These digital twins provide a dynamic and real-time view of the pipeline’s integrity, enabling proactive maintenance and risk mitigation strategies.
The core of this presentation delves into the following key areas:
In conclusion, the integration of pipeline digital twins and geohazard modeling represents a transformative paradigm shift in pipeline management. This presentation demonstrates how this innovative approach empowers pipeline operators to proactively identify and mitigate geohazard-related risks, ensuring the long-term reliability and sustainability of energy infrastructure.
KEYWORD(S) FOR SUBJECT AREA: Geohazards, Geospatial Systems and Data
David Kemp1, Shanshan Wu1, Joseph Bratton1, Luyao Xu2
1DNV, Dublin, USA. 2DNV, Calgary, Canada
With PHMSA’s issuance of RIN2 of the Final Rule, Engineering Critical Assessments (ECA) have become increasingly important in assessing not only the fatigue life of dents and other integrity threats, but also reinspection intervals. ECA’s can be performed for a variety of complex dent features identified from in-line inspection (ILI) or direct examination by following assessment methodologies prescribed in API 1183 along with the fatigue life assessment procedures outlined in API 579.
For those cases requiring a level 3 assessment, finite element analysis (FEA) is often necessary to account for interactions between dents and additional features (i.e., metal loss, bending strain, seam welds, etc.), which can then be used to determine the fatigue life of the dent. A more accurate fatigue life can be calculated using the FEA results to obtain a stress vs. pressure relationship, which is then paired with the pressure history of the specific line segment being assessed. This stress vs. pressure relationship is extracted from a specific location in the vicinity of the dent from the finite element model, and for the sake of conservatism in the assessment, is either taken from the location of maximum stress or the location of maximum change in stress between pressure cycles. Both stress locations are critical to dent integrity, the former is usually associated with crack generation during the dent formation process, while the latter contributes to the fatigue crack initiation and growth. Depending on the dent conditions (i.e., constrained, unconstrained, dent depth, shape, feature interactions, etc.) these two locations are not always coincident and the resulting fatigue stress range could be significantly different in some scenarios.
For this paper, a collection of over 30 dent ECAs are examined to determine under what conditions, such as constraint condition, shape, stress/strain level, etc., the locations of maximum stress and maximum change in stress are not coincident as well as the extent to which these differences impact the overall fatigue life of the dent features.
Mick Ellem1, Krishal Patel1, Mark Sigley1, Olivia Chung2
1First Gas Limited, New Plymouth, New Zealand. 2Quest Integrity NZL Limited, Wellington, New Zealand
First Gas operates the natural gas transmission pipeline network in New Zealand. In 2022, crack-like linear indications on the long seam of the pipeline were identified by non-destructive testing (NDT) carried out opportunistically during coating refurbishment of a length of pre-1971 pipeline. Quest Integrity were engaged to investigate these crack-like linear indications. Metallurgical analysis of coupons removed from the pipeline concluded that the crack-like linear indications observed were Selective Seam Weld Corrosion (SSWC). With knowledge of this new threat, First Gas initiated a work program to manage this risk in the pipeline.
The work program included a Like-and-Similar analysis of the three most recent Magnetic Flux Leakage (MFL) metal loss ILI data sets collected in the pipeline and metallurgical analysis results, and additional field verification using advanced ultrasonic methods to further characterize metal loss features interacting with the long seam. Corrosion growth rates determined from the Like-and-Similar analysis and characterization of features detected ultrasonically and/or metallurgically verified were utilized in a Fitness-for-Service and remaining life assessment of external metal loss features, both interacting with and away from the longitudinal seam weld.
First Gas used the results obtained from the above investigation to update their integrity management plan for their pre-1971 pipelines, now including management of the threat posed by SSWC. This paper presents the full scope of work performed by First Gas and Quest Integrity to manage the threat posed by SSWC for the pre-1971 pipelines and shares the learnings obtained from the process.
Keywords: ERW pipe, Pipeline integrity management, Corrosion, Selective Seam Weld Corrosion, Crack-Like Features
Gemma Simpson1, Nancy Thomson1, Courtney West1, Jane Haswell2, Andrew Cosham3, Gary Senior2
1SGN, Edinburgh, UK. 2PIE, Newcastle, UK. 3ninthplanet, Newcastle, UK
The Local Transmission System (LTS) is the backbone of the UK (UK) energy network, delivering natural gas from the National Transmission System (NTS) to towns and cities across the country.
The four Gas Distribution Networks (GDNs) operate approximately 11,000 km of high-pressure pipelines, operating at pressures above 7barg. The pipelines were originally designed to transport and store natural gas.
The UK Hydrogen Strategy states that: “Low carbon hydrogen will be critical for meeting the UK’s legally binding commitment to achieve net zero by 2050”. Hydrogen behaves differently to natural gas, therefore it is necessary to assess how it affects the existing LTS infrastructure.
The LTS Futures Project is a first-of-a-kind, £30 million, joint funded project between SGN, the UK energy market regulator OFGEM, and the other UK GDNs. The project is led by SGN and looks to repurpose a 30 km natural gas transmission pipeline to hydrogen for a live demonstration trial, which will inform the development of a Blueprint methodology for repurposing the LTS. The LTS Futures Project is researching, testing and collating evidence to understand the compatibility of LTS assets, pipelines, associated plant and ancillary fittings in hydrogen which will be captured in the Blueprint.
The aim of the Blueprint is to provide a methodology to determine if a natural gas LTS asset is fit for hydrogen service and identify any data gaps, or further work needed for repurposing for hydrogen service.
This paper provides details on the technical approach adopted by the project, the progress to date and the plan going forward.
Keywords: Repurposing. Hydrogen.
Tristan Jones, Ivan Thesi, Cesar Espinoza, Andres Gonzalez
ROSEN, Houston, USA
According to 2018 PHMSA Stakeholder Communications Fact Sheet, an estimation of 18% of pipeline failures in the United States (from 1998-2017) were caused by corrosion. Calculating accurate remaining strength of corroded pipe with complex corrosion, such as axially aligned clusters with multiple pitting on pitting metal loss anomalies, has historically been a challenge for operators. Traditional Effective Area Methods (EAM) for assessing the remaining strength of complex corrosion anomalies, such as Modified B31G and Detailed RSTRENG can lead to overly conservative results and extensive repair campaigns. In these cases, it is difficult for operators to distinguish between the critical repairs and uncertainties, potentially preventing them from focusing resources into other pipeline mitigation activities. A more detailed evaluation of corrosion geometry through an advanced fitness-for-service method, known as Plausible Profiles (Psqr), can be used to gain a better estimate of the remaining strength of pipeline areas with complex corrosion. However, it is important to understand when this method is applicable and when it will yield the most benefits for pipeline operators. With proper selection criteria, ideal candidate corrosion anomalies can be identified for this method, which will add efficiency to the pipeline remediation process and provide more accurate results. This paper will discuss the criteria for selecting corrosion anomalies for implementation of the Psqr method in combination with a rationalized repair strategy. The selection criteria consider aspects associated with anomaly morphology, assessment depth, length/width ratio and potential failure mode. This paper will present how a number of excavations was reduced by more than 70%, with no impact to public safety, based on a case study of a natural gas pipeline. The remaining strength of 60 corrosion anomalies was extended, facilitating the optimization of the maintenance planning and expenditure, and supporting the pipeline Integrity Management Plan (IMP).
Tristan MacLeod
Kiefner and Associates, Inc., Ames, USA
Cyclic fatigue of crack-like anomalies is a well-known threat to pipeline integrity. Manufacturing defects in the longitudinal seam (especially in pipe manufactured prior to 1970) as well as stress corrosion cracks in the pipe body may enlarge and fail in service due to pressure-cycle-induced fatigue. In fact, the current U.S. pipeline integrity management regulations require crack growth and remaining life assessments for natural gas pipelines in high consequence areas and segments known to be susceptible to cyclic fatigue.
To manage the risk of failure from pressure-cycle-induced fatigue, pipeline operators should employ integrity assessments either via hydrostatic testing or in-line inspection using a reliable crack-detection tool. The appropriate period for reassessment depends on the sizes and growth rates of potential defects that may still exist after an initial hydrostatic test or in-line inspection. The pressure-cycles applied to the pipeline may cause the just-surviving defects to grow at a rate inherent to the material and its environment. Long-established principles can be used to predict remaining life. Pipeline operators can use these methods to plan timely reassessments to prevent failures.
This paper describes one approach to predicting reassessment intervals. This approach has evolved over a period of more than 30 years. Careful analysis of all of the known data can avoid pitfalls and inappropriate remaining life predictions. The purpose of the paper is to show that while the well-known and widely available basic principles are sound, their application to pipeline integrity management requires an in-depth understanding of the particular pipeline being assessed.
Steven Bevers1, Alexander McKenzie-Johnson2, Kristy Compter1, Kevin Dahnke1, Colby Reece3
1Denbury, Plano, USA. 2Geosyntec, The Woodlands, USA. 3Geosyntec, McKinney, USA
In recent years, geohazards have increasingly become a key focus of pipeline integrity management by operators, regulators, and the public. This paper presents the lessons learned from one pipeline operator from a landslide-caused rupture in a rural area of western Mississippi. This paper looks at the conditions that led up to the rupture, how those conditions were managed after the rupture, and ultimately, how the operator implemented a comprehensive geohazard management program to reduce the likelihood of a similar event occurring.
The paper details:
Finally, the paper looks at how operators can apply the lessons learned from this case study to their programs to reduce geohazard threats during the design, construction, and operations phases of their pipelines.
Lucinda Smart, Benjamin Wright, Dyke Hicks
Kiefner and Associates, Inc, Ames, USA
Within the last few years, there have been increasingly more vendors and operators looking into ways to improve the accuracy of ILI data correlations with both in-ditch validation methods as well as across consecutive ILI runs. It may seem obvious, but it is important to ensure the defects that are being correlated from one data source to the other are, in fact, the same defect. ILI data correlations can be particularly difficult when differing vendors or tool technologies are applied, or if location conventions are not applied similarly from one run to the next. If there are inaccuracies in the locations and orientations provided by the vendor, or if the dig site location is not verified and reference locations are not correct, this leads to meaningless data results. This paper will go into detail in the discussion for guidance of ILI data correlation from both successive ILI assessments for growth rate assessments, as well as in-ditch NDE data to ILI data for tool validation practices. The primary method discussed will be a pattern-matching approach, where sources of error can be reduced by aligning overall patterns of reported defects using modern software tools along with insight from experienced analysts. Applying expertise in this manner leads to more accurate outcomes for tool validation, corrosion growth rate (CGR) assessments, and probability of identification or detection (POI or POD), which then ultimately lead to better and more informed integrity management decisions.
Paige Chenevey1, Eric Bergeron2, Alexandre Thibault2
1Marathon Pipe Line, Findlay, OH, USA. 2Flyscan Systems, Quebec City, Canada
Since the end of 2022, Marathon Pipe Line has been using and testing Flyscan Systems’ remote sensing technology over their liquid pipeline Rights-of-Way (ROWs) to benchmark and validate the use of machine learning (ML) algorithms, photogrammetry and hyperspectral imaging to perform real-time threat detection, liquid leak detection of crude oil and refined products, and other advanced imaging features related to geo-hazards.
This paper will present scientific approaches used, and real-life results from 198 patrols between November 2022 and August 2023 which identified 2,594 threats across 35,706 miles of ROW from Alaska to Texas, including the Rockies and the Mid-west.
Examples will include, what is potentially the first ever detection of a diesel seeper leak, identified below computational pipeline monitoring system detection thresholds using a hyperspectral imaging system during routine aerial patrols. Other examples will include detection of contaminated soils from third party activity, detection of real encroachments and documentation of various types of objects and activities on the ROW of interest to pipeline operators. Finally, examples of new imaging capabilities will be presented, including detection of exposed pipes after serious weather events, vegetation analysis, and erosion monitoring.
Christopher De Leon1, Rachel Brossman2
1D2 Integrity LLC, Houston, USA. 2PBF Energy, Cerritos, USA
In-line inspection (ILI) continues to evolve and prove to be a high-value solution for performing pipeline integrity assessments. Industry has seen ILI promoted through NTSB recommendations, Federal Pipelines Safety Statutes by Congress, and PHMSA’s recent updated pipeline federal regulation. However, each ILI technology and its application by ILI service providers must be vetted by pipeline operators to ensure it is qualified for the inspection goals and objectives. Unfortunately, some ILI technology is not properly vetted commensurate to the risk associated with the integrity assessment for a given pipeline. As governance, PHMSA has now incorporated by reference API STD 1163 In-line Inspection Systems Qualification (API 1163) into both 49 CFR 192 and 195. While API 1163 is generally understood, details can be overlooked, leading to non-compliance. This paper uses two case studies to highlight the topic of ILI System Selection within the API 1163 standard and its importance in performing a sound integrity assessment. The process used for selecting an appropriate ILI system for corrosion and cracking threats will be reviewed, and how compliance with new regulations was specifically considered.
Topics: Regulation and Compliance, Codes and Standards, ILI Applications, ILI Analysis
Chris Alexander1, Tony Rizk2, Rodney Clayton2, Ahmed Hassanin1, Josh Wilson3
1ADV Integrity, Inc., MAGNOLIA, USA. 2Boardwalk Pipelines, Houston, USA. 3Allan Edwards, Tulsa, USA
Composite materials are commonly used in the reinforcement of hoop-oriented defects such as corrosion, dents, seam-weld anomalies, and gouges within pipelines. Additionally, they can be designed to reinforce features susceptible to cracking when subjected to bending and tension loading, including girth welds and wrinkle bends. Of particular interest, given historical failure patterns, is when wrinkle bends are subjected to high strain-low cycle fatigue loads.
This paper presents results and findings of a study that involved full-scale testing of wrinkle bends. The test program encompassed three distinct tests on 26-inch x 0.281-inch, Grade X52 pipes, all of which had wrinkles removed from service. The test program comprised testing an unreinforced wrinkle bend sample, as well as two additional samples that were reinforced with custom-designed E-glass-epoxy and carbon-epoxy composite technologies with axial-dominant fiber architectures.
In the case of the unreinforced wrinkle sample, the maximum recorded axial strains in the wrinkle feature were +/- 1%, in which the sample failed after 107 bending cycles. The two composite reinforced samples utilizing the E-glass-epoxy and carbon-epoxy technologies failed after 1,774 and 863 bending cycles, respectively. These results demonstrate that both systems were able to increase the life of the unreinforced wrinkle sample by as much as 16 times.
From an operational standpoint, these findings imply that the service life of existing wrinkle bends could be substantially prolonged, potentially by decades, assuming that such bends are subjected to loads of similar magnitude 5-10 times per year, as examined in this study. This research offers valuable insights into the transformative role of composite materials in enhancing the longevity and durability of wrinkle bends in pipelines.
Christopher Davies1, Cameron Cooper1, Lee Sellers2
1ROSEN USA, Houston, USA. 2ENERGY TRANSFER, Houston, USA
In response to the discovery of Selective Seam Weld Corrosion (SSWC) on a 12-inch natural gas pipeline, an in-line inspection (ILI) was completed using an ultra-resolution circumferential magnetic flux leakage tool. The closer sensor configuration of this system allowed for a more detailed recording of the magnetic leakage profile and ensures that the peak value of flux leakage is recorded within complicated corrosion morphologies such as SSWC.
Through an optimized evaluation process, all corrosion anomalies considered to be associated with the longitudinal weld were subject to detailed review. The review provides a thorough understanding of the different signal characteristics and likelihood classifications of ‘likely’, ‘possible’ and ‘unlikely’ SSWC are assigned. The initial evaluation process resulted in the identification of 23 ‘Likely’ SSWC anomalies and 35 ‘Possible’ SSWC anomalies. All remaining corrosion anomalies associated with the longitudinal weld were classified as ‘Unlikely’ SSWC. Classification is critical as it pertains to integrity management. Understanding the pipeline’s susceptibility to SSWC, the detection capability of the ILI system and the confidence of likelihood classifications allows for process driven discrimination between SSWC and ‘general corrosion’ in the area of the longitudinal weld.
Validation of the evaluation and classification was achieved through a structured dig program. A total of 3 excavations were performed on the pipeline, which targeted a total of 24 anomalies associated with the longitudinal weld. Evidence of SSWC was observed for 11 of the 13 ‘Likely’ SSWC classifications. Of the five (5) ‘Possible’ SSWC calls investigated, three (3) were confirmed to be SSWC. No evidence of SSWC was observed for the ‘Unlikely’ SSWC classification subject to infield investigation. The results of these excavations were used to reclassify all remaining anomalies associated with the longitudinal weld.
A critical aspect of the likelihood classification process is iteratively incorporating information from field investigations. This paper presents the close collaborative efforts performed by a pipeline company and an ILI service provider, to help manage the threat of SSWC on a 12-inch pipeline. It is intended to present an ILI based approach to assess SSWC and share recent experience with the industry on a targeted approach in managing the threat of SSWC.
Santiago Urrea1, Jordi Aymerich2, Sayan Pipatpan1, Tannia Haro3, Alex Hensley3, Christopher Newton4
1NDT Global, Stutensee, Germany. 2NDT Global, Barcelona, Spain. 3NDT Global, Houston, USA. 4Phillips 66, Houston, USA
Pipeline operators employ various strategies to ensure the operational safety of their pipeline systems. A crucial element of this strategy involves In-line inspection (ILI) and Non-destructive examination (NDE). However, what happens when all available evidence points to a systematic limitation in the performance specification of these systems? How can the operator utilize this data within their Integrity Management Program (IMP)? Lastly, can this data be effectively utilized to derive new rules and analysis processes?
NDT Global, in collaboration with an operator, has been tasked with investigating, documenting, and delivering a novel approach to identifying crack complexity, specifically hook cracks, within a population of previously detected and undersized features. Currently, there is no ILI tool available in the specific required diameter and wall thickness range in the market that meets the requirements or performance specifications necessary to provide essential information for engineering assessments and the proper ranking of such features.
The primary objective of the research and validation is to develop an approach that provides a systematic method for identification and, potentially, a correction factor for depth sizing. These critical attributes can then be effectively used for engineering calculations, priority ranking and risk mitigation activities.
This innovative approach incorporates years of accumulated knowledge from other pipelines to develop a systematic analysis approach. Additionally, it involves the calibration of this approach through collaboration with the operator, utilizing advanced and non-conventional in-ditch NDE techniques to determine accuracy, and potentially employing destructive testing during lab testing.
This paper is a summary of the research and collaboration between NDT Global’s international experts and a USA pipeline operator.
Hamed Fatiminia1, Eduardo Munoz2
1Dynamic Risk, Calgary, Canada. 2Dynamic Risk, Houston, USA
Sensitivity analysis is paramount for improving the accuracy and robustness of oil and gas pipeline quantitative risk models. As a result, sensitivity analysis of the risk models is now a requirement under §192.917(4)c of the Gas Mega Rule – Part 2 for gas pipelines. The inherent complexity and interdependency of factors influencing pipeline risk require an in-depth comprehension of the sensitivity analysis methods. Fitness-for-service calculators are integrated into some quantitative models; though extensive validation work has been reported, a proper sensitivity analysis has often been omitted in benchmark studies and reviews. The primary objective of this paper is to provide an in-depth review of various sensitivity analysis techniques, highlighting their strengths, limitations, and practical applications in pipeline risk assessment. The comparative analysis is conducted based on multiple criteria, comprising computational efficiency, accuracy, ability to capture interactions between risk variables, and suitability for handling uncertainties inherent to pipeline systems. The findings of the comparative study provide valuable insights into the strengths and limitations of various methods, aiding practitioners in selecting the optimal sensitivity analysis technique based on their modeling objectives and data availability. Real-world case studies are provided to illustrate the practical application and results of some of these techniques.
Anthony Tindall1, Steve Farnie1, Jeff Sutherland2, Stuart Clouston2
1Baker Hughes, Cramlington, UK. 2Baker Hughes, Calgary, Canada
It is well known that when corrosion pits interact, the interpretation of inspection data gathered by Magnetic Flux leakage tools (an indirect measurement technique) becomes challenging due to the nature of the overlapping and superimposing signal responses across the multi-defect profiles. Such “complex” corrosion is of particular concern to pipeline operators as it is these areas, particularly axially oriented, that are often the most critical to pipeline integrity. And then, being the most difficult to both interpret and size accurately, these can lead to “outliers” relative to conventional ILI specifications and industry guidelines (e.g. API 1163). Such outliers are increasingly grouped into two types, namely Safety Outliers (where defect severity is under called leading to underestimated remaining strength) or Resource Outliers (when defect severity is overcalled potentially leading to unnecessary digs).
The goal of any in-line inspection method is to represent corrosion fully and accurately on the pipe. To achieve best performance, we must be able to first detect when these complex or interacting signals occur and then, more importantly, interpret them correctly. In physics terms, the nature of MFL field leakage is a 3-dimensional vector and predictable, yet different signal responses to metal loss (and other features) are observed in each of these 3 vectors which can be quantified and characterized as an improved means to translate leakage signals to the corrosion they more accurately represent.
Single axis MFL, whether conducted with axially or circumferentially oriented magnetizers, will reach limits in its capabilities regardless of sensing resolution. MFL is a mature technology, and an operator today should expect most tools to perform to specification on isolated corrosion. However, the adoption of long proven Triaxial sensors, at optimal resolution, on Magnetic Flux Leakage inspection vehicles provides an integrity engineer significant advantages to minimize potential outliers when things are not so straight forward.
This paper will outline how the three independent components of the triaxial flux leakage response provide unique identifiers for cases of axial corrosion, highly asymmetrical defects, corrosion in corrosion, wide area erosion/corrosion with pitting, to name but a few. At the same time, the additional signal components provide independent measures that enable better performance in latest generation algorithm techniques and development than those trained on fewer inputs.
The authors will present real world examples of these unique identifiers being used in practice to interpret highly complex corrosion and the latest work Baker Hughes has been conducting in close partnership with our customers with the common goal to best manage these “complex morphologies” successfully and efficiently with one inspection.
Willem Vos, Jan Ove Toskedal, Gary Dye
NDT Global, Bergen, Norway
In the early 2000’s, the research group in DNV (Norway) developed an ILI technology for the inspection of dry gas pipelines (without using a liquid batch). The technology has subsequently been used to inspect over 10,000 miles of operational gas and liquid pipelines around the world.
The authors are presenting a review of lessons learned during the deployment of this innovative technology and reflecting on the advantages and limitations.
A summary is presented of validation work completed through pull testing. Field validation is also considered and presented.
Several different use cases are considered; the first being the deployment of acoustic resonance ILI for the baseline inspection of new construction gas pipelines. In particular, a series of newly constructed long-distance gas transmission pipelines that have been inspected using acoustic resonance ILI.
Further, the tools have shown remarkable flexibility in the field of difficult-to-inspect pipelines. Notably, large diameter variations and bidirectional inspections have been performed, as well as very long gas pipeline inspections. Influence of wax on the inspection data is reviewed.
A summary of completed work will be of value to all offshore pipeline operators of challenging pipelines, demonstrating challenging pipeline inspection projects which have been completed successfully.
Ron Thompson1, Xavier Ortiz2, Richard Kania3, Andrew Corbett1, Guillermo Solano1
1Novitech Inc., Toronto, Canada. 2Plains Midstream Canada, Calgary, Canada. 3KanEnergy Partners Inc., Calgary, Canada
In the late 1990’s, the discovery of stress corrosion cracking (SCC) in orientations other than the axis of the pipe triggered new studies into the factors associated with off-axial cracking. Since most of the crack colonies appeared to be close to 90 degrees to the axis of the pipe, the investigations focused on circumferentially oriented SCC (CSCC). Notwithstanding, there have been many documented cases of cracks at angles other than 90 degrees, notably at the same angle of the spirally applied tape in tape-coated pipelines. These off-axis cracks have been incorporated into the models developed to address CSCC.
CSCC management programs use of a combination of quantitative and qualitative data involving bend strain along with susceptibility criteria, geohazards and areas of pipe movement, and ILI where available. As CSCC investigative and remedial work continues, off-axis cracking is starting to be found in larger numbers, with skew angles to the axis of the pipe ranging from 45 to 90 degrees. These skew angles can exceed the specified detection range of ILI tools, leaving operators without a diagnostic option for modelling these types of features.
This study illustrates the successful management of both circumferential and off-axis SCC by using a magnetic based ILI system to determine crack depth, crack length and the primary crack colony skew angle. The determination of all these crack attributes, particularly the skew angle, enabled modelling the interaction between axial and hoop stresses, to calculate the pipeline’s remaining strength.
The diagnostic data for the program was obtained using ILI technology that included three sensor systems: AMFL, CMFL, and IDD-SM™. This technology reliably provided crack length and depth sizing with an accuracy of +/- 15% and, for this study, the measurements of the primary colony skew angle with a target accuracy +/- 10°.
The ILI’s crack sizing and crack skew angle measurements were corroborated through an extensive excavation campaign, which also established ILI detection (POD) and identification (POI) greater than 95%, this accuracy supported the use of crack model predictions that could be incorporated into reliability programs.
The ILI reported and verified CSCC locations also supported the management of geohazards as it was possible to identify potential ground movement locations that were not highlighted by geotechnical desktop and field investigations.
The lines used in this study had a nominal diameter of 8.625” and were investigated for occurrences of all threat types including off-axis and circumferential cracking. Field inspection data was gathered to support the finding of this study and the implementation of the model.
Chris Alexander, Chantz Denowh
ADV Integrity, Inc., Manolia, USA
One of the greatest challenges facing today’s pipeline integrity engineers is determining the threat level a given feature or defect poses to a pipeline system. The process employed by most pipeline integrity engineers starts with inspection measurements made with in-line inspection tools or in-the-ditch inspection technologies. If the measured data are deemed a threat to pipeline integrity, an assessment is conducted using either closed-form engineering equations or numerical modeling techniques such as finite element analysis. To supplement assessment efforts, a well-designed and conducted full-scale testing program can provide valuable insights about the true performance characteristics of a defect and improve the accuracy of failure prediction methods.
This paper includes examples of how full-scale testing can be used to provide a more accurate and complete picture of defect performance under various loading conditions including burst, cyclic pressure, tension, and bending. Included is a brief description of the types of tests that can be conducted, accompanied with photos from actual tests. Information is also included on the types of equipment and measurement devices that are used in full-scale testing. The goal of this paper is to demonstrate the inherent benefits in employing full-scale testing as a means for better understanding and predicting the threat levels associated with certain defects.
Chantz Denowh1, Robert Stakenborghs2, Liang Yu3
1ADV Integrity, Inc., Houston, USA. 2Advanced Microwave Imaging, Baton Rouge, USA. 3Baker Hughes Flexible Pipe Systems, Houston, USA
The use of spoolable composite pipe technologies in the onshore oil and gas industry has expanded significantly over the past decade. It is anticipated that interest will only continue to grow as oil and gas operators transition to transporting alternative fuels such as hydrogen and carbon dioxide. Currently, these technologies have been limited to non-regulated lines such as gathering lines or produced water transport, but the need is growing to expand into the high-pressure transmission pipelines. These lines will typically be in the 4-inch to 8-inch size range and rated up to 3,000 psig. There are several gaps in knowledge to address though before making this step. One gap is the need for viable inspection technologies that pipeline operators can for long-term integrity management.
This study works to address this gap by progressing the multifrequency microwave technology and evaluating its accuracy against simulated defects that commonly occur to spoolable composite pipes in the field. The phases of the study described in this paper include an initial calibration of the microwave technology to the pipe design, material types, and layer depths. Following calibration, an open inspection was completed on pipes with known defect location, size, and depth. This information was shared with the microwave vendor to improve sizing and location accuracy of equipment and software. Additional pipes with similar defects were then used for a closed inspection to evaluate the technology’s ability to accurately locate and size unknown defects. The pipe used in this study was nominal 4-inch with a nominal pressure rating of 1,500 psig.
The last phase of the study included inspection of pipe samples with simulated damage that commonly occurs in the field. Examples of recreated damage include pipe ovalization, overbending (kinking), and over-tensioning. This damage was recreated in a laboratory setting. The damaged pipes were subjected to destructive testing following the inspection (test results not included in this paper). Results and findings from each of the above phases are described in this paper including an evaluation of the location and sizing accuracy. Inspection of the simulated damage is discussed and compared to results of the destructive testing where damage indicated the presence of damage in the pipe reinforcement.
Michael Rosenfeld1, Richard Gailing2, Benjamin Zand1, Joel Anderson3
1RSI Pipeline Solutions LLC, New Albany, OH, USA. 2Retired, Sandy, OR, USA. 3RSI Pipeline Solutions LLC, Oklahoma City, OK, USA
To reconcile differing requirements for pipeline cover in various standards and regulations, an evaluation was performed of the effect of cover depth and consistency on susceptibility to damage, other threats, risk, cost-benefit, and construction, with some surprising results. Current and historical US and foreign gas and liquids standards and regulations were compared. US and international incident data were analyzed to determine the relationship between cover depth and mileage-normalized risk of damage, and risk of other integrity threats such as geohazards and corrosion. FEA was performed to understand how cover depth and trench design affects susceptibility to rock damage. A cost-benefit analysis of increased depth of cover was performed. Sensitivity of transported product (gas vs liquid) to the benefit of cover were determined. Recommendations were made for improved codes content.
Rick Sugden
Kiefner and Associates, Denver, USA
Modern hydrostatic testing is often seen as a “check the box” for new construction. It is required by code for most pipelines. In the fast-paced culture of “get ‘er done” world, is pipeline hydrotesting still needed? With so many technological advances, can we just remove this requirement? In the mind of the inspector, are discrepancies: “just temperature”, “not regulated”, “don’t matter?” This presentation is designed for the inspector that is signing off their name on a hydrostatic test. Do you believe that this pipeline is safe, that it is not leaking? I will discuss what is obvious, what is not so obvious and why You as inspector or engineer should verify all the data. By the way, what are you signing for? What should you be concerned about? How will the new regulations impact the future of hydrotesting?
Woosik Kim1, Dongil Kwon1, Dongseong Ro1,2
1FRONTICS INTERNATIONAL Inc, Seoul, Korea. 2FRONTICS AMERICA Inc, Mount Prospect, USA. 3
US federal rules, DOT 49 CFR §192.607, require that records documenting physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade, must be maintained for the life of the pipeline and be traceable, verifiable, and complete. Specifically, the PHMSA report on the integrity verification of ERW seam pipelines highlights the significant impact of local properties on failure pressure and remaining life predictions and thus reinforces the development of inspection tools in routinely quantifying local strength and toughness of materials.
This paper investigates the effects of different ERW seam manufacturing processes on the local microstructure and mechanical properties of seam welds on operating pipelines using AIS system of FRONTICS Inc. The instrumented indentation technique, followed by additional microstructural observations, was utilized to assess hardness, tensile properties, and fracture toughness of LF ERW and HF ERW pipes with different manufacturing years. Ultimately, this paper will present a strategy for the non-destructive analysis of operating ERW pipelines, simultaneously providing a classification guideline on seam welding methods and pipe integrity assessment.
Rick Wang1, Ming Gao2, Ravi Krishnamurthy2
1TC Energy, Calgary, USA. 2Blade Energy Partners, Houston, USA
In API1183, the EPRG 2000/API579 Level 2 model is adopted as an alternative approach to BMT shape-parameter method for Level 2 fatigue severity assessment of unconstrained single peak plain dents in pipelines This model along with its earlier version, EPRG 1995, has been commonly used for dent integrity assessment in North American and worldwide because it is recommended by the highly recognized pipeline defect assessment manual. However, Pipeline industry practice in North America found that the EPRG equations provide conservative, in many cases, very conservative predictions that may have resulted in unnecessary excavations and repairs. Therefore, the objective of this paper is to improve the model accuracy and less conservatism. A critical review of EPRG/PDAM fatigue life prediction models (1995 model and its 2000 update) and other models including PRCI/BMT shape-parameter fatigue severity model (Level 2) and FEA/BS7608 fatigue life prediction (Level 3) are essential and given first, which provides a basis for improvement of EPRG equations from both safety and cost-effective perspectives. The newly improved and simplified model is then developed with PRCI MD 4-2 full-scale fatigue testing data and validated using PRCI MD 4-11, MD 4-14 and MD 4-15 full scale fatigue test results. Finally, a comparison among the newly improved model, EPRG 2000/API 579 Level 2 model, and PRCI/BMT/API 1183 Level 2 and Level 3 models is made, which provides a framework to further carry out the study of dent-interacting with welds, gouge, cracks, and corrosion.
Mick Collins
Intero Integrity Services, Houston, USA
Traditionally, Gulf of Mexico (GoM) Outer Continental Shelf (OCS) owners and operators have sought alternate methods to assess the integrity of their gathering lines than inline inspection. In April 2010, the Deepwater Horizon explosion, and subsequent blowout, brought significant scrutiny from both state and federal regulatory agencies.
A customer approached Intero Integrity Services in 2019, in order to evaluate feasibility of inline inspections of its liquid gathering system in the GoM. The feasibility included three areas: 1) Technical ability to inspect; 2) Cost of inspection; and 3) Value of reported results.
From a technical standpoint, the customer conditions challenged just about every aspect of standard inline inspections: Never pigged for maintenance nor integrity assessment; 1500 psi static pressure; limited operating space on platform; remote location (90+ miles offshore); inability to track during the inspection (2,000’ water depth); limited pipeline availability based on production schedule; 8” nominal x 0.812 wall thickness x 25 mile pipeline; back to back “jumpers” to loop pipeline; and pumped in sea water. This paper will explain how, working closely with the operator, flow conditions were tightly controlled.
From a cost perspective, the customer had limited assessment options. The field was initially developed in 1998 and has operated in multi-phase production for 20+ years. If pipeline replacement is required, the field will just shut-in based on ROI compared to the current production curve. External assessment methods are limited (ROVs and divers) and need to be more comprehensive. Other than inline inspection, a hydrotest was the only option. Again, not valuable information for the cost.
Corrosion was detected in an area that had limited access; therefore, the operator decided that an annual inspection would be conducted and detailed corrosion growth assessments completed, and also to quantify the effectiveness of corrosion mitigation methods. Data sets will be presented that show the challenges of detecting defects under external clamps, and the variability between said datasets.
With the 0.812” wall thickness, the only inline inspection solution was ultrasonic (UT) technology. Magnetic (MFL) tools would not be able to saturate the pipe wall to provide accurate measurements.
Xuejun Huang, Bryan Feigel, Victor Jablokov
Massachusetts Materials Technologies, Natick, USA
Material toughness is needed when analyzing the critical crack size that would fail at MAOP and when performing a fitness-for-service evaluation with cracks discovered during inspection. If toughness data is not available, gas transmission operators will be required to use conservative values or perform cut-outs for lab testing or other industry-accepted data, such as collected by nondestructive testing per 49 CFR §192.607. A portable, minimally invasive technique has been developed to provide pipe body toughness data using the planing-induced microfracture method. The material removal from the test is in the range of 0.010 to 0.030 inch deep. A crack is successfully introduced by the technique through a unique stretch passage feature. FEA simulation has confirmed a high triaxiality value in front of the generated crack that is comparable to the one in a compact tension specimen used in a conventional fracture toughness test. Toughness results obtained using this new technique were compared to lab test results using Charpy impact and fracture toughness tests. Preliminary results from a small test of 13 samples showed that the technique could predict KIc within ±15% of the lab values. The achieved accuracy was in a similar range as estimating KIc using lab CVN test data on the same samples. A more extensive validation test will be performed on 50 vintage pipe samples with various toughness values. This paper will give an overview of the planing-induced microfracture method, the new portable tool, the process to obtain fracture toughness from the test data, and results from the validation test. A prototype device based on this technique is being tested for pipe body toughness, as a complement to the existing frictional sliding technique to test for longitudinal seam toughness.
Rogelio Guajardo1, Eder Prestegui2, Träumner Dr. Katja3, Victor Haro3
1NDT Global Spain, Barcelona, Spain. 2NDT Global Mexico, Mexico City, Mexico. 3NDT Global Germany, Stutensee, Germany
ERW penetrators are a subtype of lack of fusions. They are planar anomalies located in the bonding line. What differentiates them is that they are short in length (<1.0in) but deep e.g., >50% of the pipe wall. The integrity risk of these anomalies is the possibility to leak instead of bursting.
Ultrasonic Shear Wave (UTCD) technologies are the recommended ILI choice to address planar/linear anomalies such as the lack of fusions and therefore the penetrators. However, the minimum probability of detection (POD) dimensions from the UTCD tools in the long seam are 1.0in x 0.079in (length x depth) placing the penetrators below performance specification. This raises the questions: 1- What options do we have to address these features? and 2- What are the capabilities from UTCD ILI inspections?
The goal of the paper is to provide a comprehensive evaluation of 1- UTCD tool settings and configuration, 2- UTCD measurement techniques pulse echo and pitch & catch, and 3- Analysis procedure updates required to identify and size these features which will allow the reader to understand the shear wave capabilities when selecting and ILI UTCD technology to address these features.
Key words: ILI inspection, UTCD, Lack of fusion, ERW weld, crack detection, UT technology, Seam weld, ILI application, ILI analysis
Janille Maragh1, Jonathan Gibbs2, Peter Martin3, Jeffrey Kornuta4, Peter Veloo5
1Exponent, Inc., Menlo Park, CA, USA. 2Pacific Gas and Electric Company, San Ramon, CA, USA. 3RSI Pipeline Solutions, LLC, New Albany, OH, USA. 4Exponent, Inc., Houston, TX, USA. 5Pacific Gas and Electric Company, Oakland, CA, USA
Nondestructive testing (NDT) of chemical composition is a critical component of the Pacific Gas and Electric Company’s (PG&E) materials verification program. Additionally, 49 CFR § 192.607 states that the operator must “conservatively account for measurement inaccuracy and uncertainty using reliable engineering tests and analyses.” Accurate and precise NDT composition data can be used to determine or verify certain characteristics of a pipe, for example vintage, grade, or manufacturing process. However, it has been observed that composition measurements may at times be inconsistent across various field analytical tools, possibly due to the variability of experimental, environmental, and other statistical (random) factors. Anomalous field NDT measurements are problematic because they could lead to the mischaracterization of pipe features during the materials verification process.
In this paper, we present a tool for the in-field checking of chemical composition NDT data for potentially erroneous or inconsistent measurements. The presented tool, which is spreadsheet-based and therefore easily and independently implemented by operators, identifies sets of measurements that exhibit two commonly observed irregularities in field data: large standard deviations, which usually indicate the presence of outliers or excessive scatter; and greater-than-usual differences between the chemical compositions at different test locations on the same pipe joint. For a given set of measurements, the tool flags the standard deviation as too large if it is high relative to standard deviations that have been previously observed for the tool/element combination of interest. Large differences between the chemical composition measurements at different test locations on the pipe joint, which may be the result of surface contamination, surface preparation issues, or environmental differences, are identified through comparison to compositional differences that have been observed on all previously tested pipe joints. Because this tool is designed to work with raw data from NDT chemical composition tools, it may be used to enable field technicians to identify potential errors in near real-time. The improved data reliability increases confidence in downstream analysis and reduces the need to return to a site to perform re-work, allowing for a more efficient and less costly materials verification process. The implementation and in-field use of this tool for live retesting to mitigate potential downstream issues are demonstrated for a set of portable X-ray fluorescence (XRF) data.
James Dean
Plastometrex, Cambridge, UK
Indentation Plastometry is a novel approach for measuring stress-strain curves from indentation tests. It differs from scratch testing and Instrumented Indentation Testing (IIT) in several important ways – all of which are covered in the presentation. The underlying scientific methodology (an accelerated inverse finite element analysis) is also discussed in detail. A new tool for in-ditch Material Verification that employs Indentation Plastometry is now available and in use, but to support its adoption on oil and gas transmission pipelines, the tool has recently been subjected to a period of intense validation in cooperation with several network operators, several service providers, and the PRCI. By June 2023, 125 pipes had been tested. Those test results indicated that the tool has industry-leading accuracy levels (MAPE numbers) which is expected to be of interest to pipeline integrity management teams. These assertions have been corroborated through independent analyses of the validation testing data by RSI Pipeline Solutions LLC. In addition to MAPE numbers, alternative metrics for characterizing the accuracy of this and other tools for material verification were also examined (through tests conducted on the same pipe samples). These statistical methods included Clopper-Pearson, Hanson-Koopman, a one-sided prediction interval method, and a linear regression method, with the outcome being that Indentation Plastometry is extremely well suited for fast, accurate and repeatable measurement of pipeline material properties.
The presentation will cover the details of the validation testing journey, the validation test results, and the statistical analyses that were conducted. Further results obtained between June 2023 and February 2024 (predominantly through blind network qualification tests) will also be covered.
Kerstin Munsel1, Thomas Meinzer2
1NDT Global, Houston, USA. 2NDT Global, Stutensee, Germany
When a pipeline is inspected, recorded pipeline data is manually or automatically evaluated. Regardless of the pipeline condition (such as degree of corrosion), once the features meet performance specification requirements, the data analysis and its result are in no way affected.
But what about inspections that, for various reasons, do not correspond to the standard and feature complexities are at the limit of the performance specification or are completely below it? What if the feature is still detected but not recorded correctly and the data evaluation is permanently impaired or appears impossible at first glance? What if the relative position of the features further increases the complexity of the analysis? Is it still possible to extract the essential information from the recorded signals?
Even under difficult conditions, detailed UT data analysis can provide high-precision results. This was evident in a non-standard 6″ project, confirmed by field measurements, and will be presented in more detail in this paper.
KEYWORD(S): 6” pipeline, challenging internal corrosion anomalies, non-standard analysis
Jeff Sutherland, Melissa Gurney
Baker Hughes, Calgary, Canada
Since the introduction and validation of ILI Magnetic Flux Leakage (MFL) specifications for pinhole corrosion defects more than 10 years ago, industry has benefited greatly with gained experience with such capabilities.
This paper provides a brief review of the nature of “pinhole” ILI performance particularly for MFL inspection including the influences in providing accurate inspection results, as well as technical development steps to date regarding pipeline corrosion inspection and reporting.
The interpretation of API 1163 guidance has played a role in such perceptions and specifications that will be outlined in this paper. Similarly, the nature of “hard boundaries” behavior related to corrosion type categories (the “POF (Pipeline Operators Forum) categories”) plays a role. The need to address such perceptions will be described and real examples of features will be presented with case examples of isolated and complex corrosion morphologies.
Industry feedback, both in the field measurement improvements and volume of feedback features, has led to further improvements and possibilities beyond current ILI conventions.
The paper will then describe with examples of alternatives and with some description of new conventions of ILI performance for the future.
Joel Anderson
RSI Pipeline Solutions, Oklahoma CIty, USA
The regulations published by PHMSA in October of 2019 require non-destructive examination (NDE) to determine the material properties of pipelines that lack traceable, verifiable, and complete (TVC) records. To meet this requirement, operators must conduct verification of pipeline material properties in accordance with 49 CFR 192.607. Inherent in these requirements are requirements to achieve a 95% confidence level and the use of “statistically valid basis”. But absent in the regulations is how to determine if this has been met. Consequently, this leads to uncertainty on the part of the operators if they’ve done enough and are the observed differences indicate that the samples truly are different.
Differences will always exist between the measured value and the true value since perfect measurements are impossible. Errors of varying magnitude will always exist due to random effects from any number of sources. The inevitable question arises is whether these observed differences are enough to be significant and have enough samples been completed to be able to tell the difference.
This paper will discuss how to set up a sampling plan to meet the necessary goals. Including how to determine if a sample is inconsistent with some value, determining sample size and comparing two samples.
Joel Anderson1, Michael Rosenfeld2, Peter Martin2
1RSI Pipeline Solutions, Oklahoma City, USA. 2RSI Pipeline Solutions, New Albany, USA
The requirements of 192.607 state that if an operator lacks traceable, verifiable, and complete records they must implement procedures to verify the physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade. Since pipe grade can’t be directly measured, it must be inferred from measurable physical characteristics like strength, geometry, and composition. Because the minimum yield strength (YS) specified by the pipe grade factors directly into calculation of MAOP, there is a tendency to incorrectly use the measured YS as the sole indicator of the immeasurable grade. Though the two are loosely correlated, they are not equivalent. Grades are assigned labels that relate to ranges of allowable YS, composition, geometry, inspection requirements, and manufacturing practices. Additionally, a single YS can overlap up to four different adjacent grades. This makes YS a vague indicator of grade at best.
The mapping of YS into a single grade classification in the absence of additional information can be done quickly and with minimal effort, making it seem like an attractive approach. But this technique is fraught with potential issues that can lead to non-conservative assumptions that have a cascading effect. This paper will demonstrate the various challenges to pipe grade classification and why it is necessary to consider all the available information. Not just YS but consideration of operating history, design standards, chemical composition, and microstructure is necessary to provide a high level of assurance of a safe MAOP that will stand up to scrutiny.
Anthony Tindall1, Todd Yakimoski2
1Baker Hughes, Cramlington, UK. 2Baker Hughes, Calgary, Canada
Combination in-line inspection tools (most equipped with Magnetic Flux Leakage, Caliper and Mapping capabilities) have reduced the need to run standalone Caliper and Mapping inspection over the last decade. However, there has been a recent notable increase in pipeline operators’ focus on threats posed by geohazards, construction and third-party interference.
This increased focus on what are generally strain related issues, has resulted in the need for some operators to inspect for geohazard threats more regularly. If the required frequency of inspection for geohazards falls outside the repeat inspection interval of the magnetic combination tool, high resolution caliper and IMU tools are often selected as a more efficient alternative to gather the off-cycle strain data.
While some operators may be able to reduce the pipeline flow rate to accommodate the frequency of a magnetic combo tool or can employ speed control tools to offset flow reduction, the shorter time interval required between caliper and IMU inspections means that in some cases it may be critical to maintain pipeline production flow rates, while at the same time, ensuring accurate and reliable data is gathered, i.e., below the tool’s maximum operating speed.
This paper discusses the adaptation and development of a proven speed control system to equip a strain monitoring tool to allow successful regular monitoring for geohazard and other strain related threats while maintaining operational flow rates.
Mike Kirkwood1, David Stordeur2, Neil McKnight1
1T.D. Williamson, Swindon, UK. 2T.D. Williamson, Nivelles, Belgium
As the industry transitions to renewables and de-fossilization of the energy sector, “new” products are being introduced into pipelines. Pipelines will remain a relevant and efficient way to transport energy over long distances, but this energy, and associated byproducts, could take some form other than natural gas. Such products as hydrogen, biofuels, ammonia, carbon dioxide, steam and hot water are the talk of the pipeline industry but, are these products new?
For many years, operators of transmission and distribution pipelines have focused on the development of expertise to safely operate natural gas pipelines. Operating a pipeline with other products will bring some new challenges but it may not be necessary to start from a blank page – these products are not completely new to the pipeline industry.
This paper will share some experiences of pigging, inspection, intervention and isolation in some of these challenging products. Each product has its own characteristics that make it difficult to work with but, over the years, technology and processes have been developed to ensure that these pipelines can be cleaned, inspected, accessed and repaired. The paper will also present the experiences in developing these solutions and how this knowledge can be applied to current and emerging applications today.
The paper will present the historic development of the solutions and use case studies to illustrate how these tools and techniques can be applied today. Areas where additional development is still needed will be highlighted and current industry response will also be discussed. The aim of this paper is to share previous learning to ensure that the move to de-fossilization happens safely.
Key Words: Energy Transition, De-fossilization, Hydrogen, Carbon Dioxide, Ammonia, Pigging, Inspection, ILI, Intervention, Isolation, Repairs
Tyler Tunic1, John Chekan2, Beau Gribbin3, Cailin Harrington4, Josh Harris1, Tyler King5, Quang Vo6, Scott Schubring1
1Williams, Houston, USA. 2Williams, Big Piney, USA. 3Williams, Pittsburgh, USA. 4Williams, Fort Lupton, USA. 5Williams, Connellsville, USA. 6Williams, Tulsa, USA
Natural gas-powered electricity generation enhances reliability in the U.S. electric power grid and provides the necessary backup supply that supports growth in renewable forms of energy. The nation’s natural gas supply continues to grow, leading to stable and affordable energy costs for customers. As demand for lower carbon energy intensifies, natural gas pipeline operators like Williams are exploring options to reduce greenhouse gas emissions during the transmission of natural gas. Improvements in operational efficiency and design have already led to a significant reduction in fugitive methane emissions. Pipeline operations also create carbon dioxide, the mitigation of which is distinct from that of methane.
One solution under consideration is the replacement of combustion-driven compression with electric-driven compression. This switch will lead to a significant reduction in station Scope 1 emissions, particularly carbon dioxide. It is important to consider the additional challenges and consequences that come with replacing gas-fired drivers with electric motor drives. For example, not only do electric drivers produce Scope 2 emissions, but their installation represents a coupling of two systems critical to the nation’s energy system, reducing redundancy across the value chain. In the interest of analyzing these challenges and consequences, Williams conducted a thorough examination of the potential impacts of transmission station electrification.
Electrification of compressor stations will expose the energy value chain to further reliability risks with highly regionalized greenhouse gas reductions. Installation of electric drives should be considered on a case-by-case basis alongside other decarbonization strategies to ensure the continued delivery of clean, reliable energy.
David Futch
ADV Integrity, Inc., Magnolia, USA
Charpy v-Notch tests are a common laboratory test to infer the toughness of a material. These tests are quick, relatively inexpensive, and allow for the development of a ductile to brittle transition curve. Standard geometry is specified with a cross section of 10 mm x 10 mm. This cross section is typically not achievable when testing pipeline steels unless it’s of thicker wall thickness and/or larger diameter so the curvature doesn’t impact the specimen. Half-size (or smaller) specimens are more often than not required for vintage smaller diameter pipes.
Although not specially mentioned in industry codes and standards, fabrication of the specimens may require flatting to obtain a larger wall thickness during testing. However, flattening these specimens results in additional cold work, which may locally alter the material properties of the specimen. In some cases, it’s necessary to flatten, however, in many cases a smaller subsize specimen is obtainable without flattening.
This study compares the results of flattened vs non-flattened specimens for varying vintage, seam type, and geometry (outer diameter and wall thickness). Results show both conservative and non-conservative shifts in the CVN transition curves when comparing flattened specimens to non-flattened specimens. Finally, these results are utilized to compare how the shift in CVN outputs affects a remaining life calculation where upper shelf CVN absorbed energy is an input.
Ryan Holloman1, Greg Thorwald1, Michael Turnquest1, Mark Neuert2
1Quest Integrity, Boulder, USA. 2Enbridge, Edmonton, Canada
Accurate evaluation of the remaining strength of crack-like flaws identified via pipeline inline inspection (ILI) or in-ditch non-destructive examination (NDE) is critical to ensuring continued safe operation of liquid and gas transmission pipelines. Modern pipeline ILI tools have sufficient resolution to detect longitudinally overlapping crack-like flaws that exist in the same radial plane, referred to as stacked cracks. Depending upon the crack sizes and pressure loading, stacked cracks can interact to reduce burst pressure below that of any of the individual stacked cracks.
Closely located cracks are often evaluated using interaction criteria, such as those provided by API 579-1/ASME FFS-1 Part 9 (API 579), which specify how and when multiple nearby cracks can be combined into a single crack for the purpose of an integrity assessment. When applied to stacked cracks, the interaction criteria can often lead to a more urgent response from the pipeline operator.
Here, improved interaction criterion was developed for stacked cracks based on the results of elastic-plastic finite element analysis (FEA) models of multiple combinations of stacked crack sizes and orientations, pipe material properties, and operating stress. These improved interaction criteria provide pipeline operators with an easy-to-apply methodology to analyze stacked cracks that reduces the excess conservatism associated with legacy methods.
Daniel Bahrenburg1, John Norman2, Jeffrey Haferd3
1ROSEN USA, Houston, USA. 2Teren, Lakewood, USA. 3Marathon Petroleum, Findlay, USA
Landslide threats continue to be a prevailing concern for pipeline operators and the public. Although several methods and technologies exist to detect and monitor these geohazards, determining what strategies are most effective and efficient for integrity management can be challenging. High-resolution inertial measurement (IMU) data can be utilized to detect anomalous strains resulting from pipeline displacement. The knowledge of experienced geotechnical experts can then be leveraged to review and characterize geohazards coincident with these anomalies in more detail. Although this strategy is extremely effective, timely and detailed geohazard reviews can be challenging due to a manual analysis process and expert availability. However, without expert review, pipeline company integrity managers can be left with concerns regarding how to determine what results constitute an actual concern for the pipeline. To streamline efforts to prioritize landslide-affected pipelines, Marathon Petroleum has adopted an alternative, highly efficient approach to geohazard screening, which incorporates IMU-based bending strain assessments and automated geohazard detection/characterization using high fidelity LiDAR (Light Detection and Ranging) data. This paper will present a brief overview of the ROSEN method of pipeline movement detection using IMU data from multiple in-line inspections, followed by an outline of the Teren method for streamlined geohazard screening and severity assignment. To conclude, a review of several case studies will provide examples where a combination of high strain and/or pipeline movement was detected coincident with high-severity landslides based on an Absolute Geohazard Assessment (AGA) score for areas of confirmed slope movement.
Gavin Duncan
Online Electronics, Aberdeen, UK
Pig tracking using electromagnetic (EM) transmitters is not a new concept, yet we are still uncovering ways to improve detection. As an example, the industry standard frequency for EM transmitters used in pigging applications is 22Hz however after extensive testing and by applying the science, it is now becoming evident 22Hz is not the optimal frequency for pig detection. We can now look at the actual performance of different frequencies in a variety of pig tracking applications and how this affects the task at hand. We have always known that signal strength can be affected by project specific factors such as pipeline diameter, material & wall thickness, pig design, pig velocity and if the pipeline is buried or subsea. However, in addition to frequency, we now know that the specification and configuration of the transmitter itself can also have a significant impact.
This paper will detail the factors that have previously been overlooked when trying to optimize pig detection and will provide recommendations on how to positively impact the effectiveness of this task. It will evidence this using a recent example whereby we carried out comprehensive “real life” testing prior to a project to ensure that the EM transmitters were configured to ensure the highest probability and greatest efficiency of detection while meeting the battery life constraints. It will also answer the question…is there any logic in specifying an EM transmitter’s performance by distance through air?
Megan Grzelak1, Trevor Ortolano2
1NiSource, Merrillville, USA. 2CAMPOS EPC., Denver, USA
The intent of this technical paper is to illustrate a repeatable approach to validating station assets through a complete records and material verification process to better understand MAOP Reconfirmation.
By utilizing modern technology, established best practices and detailed records research, one can generate a near complete understanding of the assets at a particular facility. Using the data gathered from records and subjecting it to effective tooling with the use of a file geodatabase, the operator can understand the compliance challenges of these assets spatially and better prepare for the execution of MAOP Reconfirmation. A final, but not to be overstated, aspect of this program is a demanding definition of Traceable, Verifiable and Complete records that is well understood by all parties involved.
To better aid the understanding of the results, a series of “one line” isometric drawings are also created to act as a visual aid relative to requirements like pressure test coverage, %SMYS, Work Order History, etc. These tools are especially effective when presenting large stations (multiple settings built and upgraded over many decades) to the various stakeholders for their input and support as this evidentiary process becomes a plan of action relative to MAOP Reconfirmation.
With these deliverables [file geodatabase (FGDB), single line isometrics and a final report with relevant information and appendices] an operator can assess gaps in Compliance Material and explore further material verification efforts to mitigate the impacts of MAOP Reconfirmation to their respective systems and budgets.
While the initial efforts of this program are geared predominantly at executing MAOP Reconfirmation, by introducing the FGDB at the onset, the operator can develop a living data organism that has many applicable uses to many departments within an operator’s organization over the life of that facility.
Categories: MAOP Verification and Materials Verification
Vinnie Szymkowiak1, Kaushik Parmar2, Stephen Edmondson2
1Ayeksa Pipeline, Fairbanks, USA. 2Direct-C, Edmonton, Canada
Vaults are employed along pipelines to accommodate pumping and shut off systems that require a large volume of space around the pipeline. Within each vault a number of flanges and other potential leak points are present. Monitoring these flanges for leaks is problematic because the vaults are often in very remote locations and are prone to flooding due to rain and snow run-off. This paper describes the development of an IIoT vault monitoring system which monitors the water level within the vault and detects the presence of any liquid Hydrocarbons in the vault. The operator, Alyeska Pipeline, will provide their perspective on the challenges with this type of monitoring and describe how they have worked with their supplier to develop and deploy this new leak detection system within their vaults over three installation cycles at multiple locations. Ground movement monitoring is currently under development as an additional monitoring capability within the same IIoT, some initial trial data relating to this will be presented.
Tom O’Malley, Wes Gardner
STATS Group, Calgary, Canada
Operators can often encounter difficulties in isolating sections of their pipeline to facilitate essential safe repair or maintenance activities if appropriate valves are absent from the line. In-line isolation pigs provide fully proven and monitored dual seal barriers that ensure the safe breaking of containment on pressurized systems in compliance with the highest industry standards.
Unlike traditional Line Stopping activities, piggable isolation tools require no welding or cutting into live lines, leaving no residual fittings or hardware on the pipeline. This eliminates project costs associated with fittings, welding and inspection and reduces the risk of leak paths from buried pipeline flanges post operations.
Line stopping often requires pipeline excavation and site establishment including lifting and rigging operations which is usually eliminated by deploying inline isolation pigs. Tracking, operation and communication with in-line isolation pigs can be achieved remotely through ground and pipe wall preventing the need for costly site establishment and reducing the risk of digging and lifting operations around the pipe.
In-line isolation tools significantly reduces, and in some cases eliminates, the requirement to vent or flare harmful emissions into the atmosphere during maintenance activities. One of the most significant environmental advantages is the substantial reduction in greenhouse gas emissions vs venting the pipeline. In the case of long, large diameter gas pipelines, this can prevent the potential discharge of thousands of tons of methane into the atmosphere.
Following the completion of the maintenance activities, a reinstatement leak-test of the replaced valve or pipework can be performed while the isolation is still in place. And provides an alternative to golden welds.
Real world examples will be discussed where double block inline isolation tools have facilitated pipeline modification, resulting in reduced project costs and production downtime, while minimising the discharge of emissions.
The utilization of in-line isolation tools not only enhances the efficiency and safety of pipeline repair and maintenance but also aligns with increasing demand to reduce emissions and create a more sustainable energy infrastructure for the future.
Challenges for this technology will also be discussed, including long distance deployments in gas pipelines where the tools must be stopped midline with suitable accuracy. Also, a high degree of confidence of pipeline condition (bore, wall thickness) is required before inline isolation tool pigging as the hard OD of the tools is close to the ID of the pipe and good information is sometimes difficult to obtain.
Jane Dawson, Steven Farnie
Baker Hughes, Cramlington, UK
The determination of corrosion growth rates and their application in the prediction of future severity is a critical part of pipeline integrity management. Accurate corrosion growth rates are needed to predict pipeline reliability as a function of time, to identify the need for and timing of field investigations and/or repairs and to determine optimum re-inspection intervals. The consequences associated with both underestimating and overestimating growth rates can be significant in terms of both safety and resource performance.
The use of repeat ILI data to match and compare metal loss sites in order to estimate the corrosion growth rates at individual defects along a pipeline is a well-used and established practice in the industry. There are many ways that corrosion growth rates can be used in future integrity predictions with most approaches only accounting for corrosion growth in the depth dimension taking no account of surface area growth and potential interactions between adjacent corrosion areas over time.
Now that we have a wealth of historical data with 3, 4 or even 5 sets of ILI data for the same pipelines we are able to experiment with more advanced three-dimensional modelling and have the ability to test new approaches vs actual “truth” data. With the benefit of this progressive viewpoint, the methodologies employed for evaluating and applying ILI based corrosion rates are being further improved and refined to give more accurate predictions of the future pipeline condition, the response schedule and for setting the timing of re-inspections.
This paper describes a new approach that predicts how an area (cluster) or corrosion could grow over time combining with surrounding corrosion defects and with newly developing defects as well as in the depth dimension. The main differences between this and the more established approaches are:
The new approach is illustrated and compared to the more established methodologies via the use of case studies on real ILI data sets.
Peter Martin1, Nathan Switzner1, Joel Anderson1, Joshua Stuckner2, Owen Lopez-Oneal3, Sophia Curiel3, Peter Veloo3
1RSI Pipeline Solutions, New Albany, USA. 2NASA, Cleveland, USA. 3Pacific Gas and Electric, Oakland, USA
Pipeline operators in the United States are increasingly relying upon materials verification programs (MVP) to establish the properties of pipelines lacking reliable records. The ongoing MVP at the Pacific Gas and Electric Company (PG&E) applies external nondestructive testing (NDT) to exposed line pipe to gain insight into the grade, vintage, and manufacturing method of the pipe. PG&E supplements the standard NDT methods for composition, strength, and geometry with the nondestructive collection of surface microstructures using metallographic replicas. The microstructures are quantitatively evaluated for ferrite grain size and fraction of pearlite. These are then used in conjunction with other measured characteristics to support determination of grade and vintage, and to identify populations of similar pipes. Automating these analyses is of interest because the manual evaluations are labor intensive and subject to variability associated with evaluator skill, judgement, and fatigue.
Traditional methods for automating microstructure analyses are often challenged by small variations in sample or image quality. Machine learning (ML) models have been shown to be more robust, but training these models typically requires hundreds of manually pre-processed images. This creates a high initial investment that impedes practical implementation in an operational environment. Recently, pre-training ML models on a large number of generic images has been shown to substantially reduce the required number of application-specific training images. This work will describe the performance of an open-source ML model pre-trained on a database of over 105 microscopy images and subsequently trained on fewer than 20 line pipe microstructures. The training and validation of the model will be presented, along with a comparison of ML and manual evaluations of more than 150 microstructures from more than 50 line pipes. The results will show the performance of the ML model to be comparable to that of manual evaluations.
Rod Lee
Intero Integrity Services, Toronto, Canada
This paper presents a comprehensive examination and validation of the Pipe Explorer robotic inline inspection metal loss specification by comparing predicted results with extensive field NDE measurements from a 12-inch pipeline and a 20-inch pipeline. Thousands of metal loss anomalies, both internal and external, across various defect size categories were matched to achieve an exhaustive understanding of the accuracy and specification. Smaller anomalies are more difficult to detect and predict accurately but pose a threat to the integrity of pipelines. This paper focuses on these anomalies with a smaller footprint such as pits, pit-in-pits, pinholes, as well as both axial and circumferential slots.
Fraser Gray, Susannah Turner, Jack Davies
Highgrade Associates Limited, Newcastle upon Tyne, UK
In-line inspection (ILI) is the primary technique used for detecting and sizing corrosion metal loss in pipelines. The Pipeline Operators Forum (POF) requirements state that ILI vendors should provide Probability of Detection (POD) and sizing specifications for metal loss anomalies of different sizes (classified by the detected anomaly length and width). However, these sizing classifications do not represent the often complex morphology of corrosion. For example, deep pits within shallower general corrosion may be simplistically categorized within the general sizing classification.
This paper explores the impact of corrosion morphology on ILI tool detection and sizing capabilities, using real life examples. The review considers corrosion validation data for three anonymized pipelines, with ILI data from three different vendors using two different tool technologies, Ultrasonic Wall Thickness Measurements (UTWM) and axial Magnetic Flux Leakage (MFL). Methodologies given in API 1163 (2021) have been used for the analysis of ILI tool performance and examples of validated corrosion and associated ILI sizing are discussed. The potential impacts on integrity assessment are also considered.
The review presented in this paper provides insight on the performance of both MFL and UTWM ILI detection and sizing capabilities for complex corrosion anomalies (such as deep pits within shallow general corrosion). The potential for integrity assessment of pipelines with this type of corrosion morphology to be non-conservative due to treatment of ILI sizing tolerance is also discussed, considering both through-wall leak and pressure-driven burst failures. The findings of this paper further support previous research stressing the importance of validating more than just the deepest ILI reported anomalies, to understand the corrosion morphology, the actual sizing uncertainty of the ILI, and the associated impact on integrity assessment.
Nikos Salmatanis1, Craig Champlin2
1Chevron Technology Company, Houston, Texas, USA. 2Upstream Vee, LLC, Golden, Colorado, USA
PHMSA has mandated that operators of hazardous liquid pipelines implement at least two technologically complementary forms of leak detection on all pipelines by October 1, 2024. This includes sections not part of high-consequence areas (HCAs). In-line acoustic leak detection multi-sensing inspection balls (MSIBs), a type of Small Inspection Device (SID), are a popular complement to conventional pressure monitoring because, with the right pipeline operational conditions, they are able to detect very small leaks that conventional pressure monitoring systems may miss. Further, MSIBs do not require a pipeline shutdown and require little to no modification of existing lines. This talk presents a patent-pending tool for extracting MSIBs from an operating pipeline without having to shut down the line or reduce its flow rate. This tool extracts the MSIB through a pressure-balanced 2 or 4-inch lateral tee, avoiding the expense and complexity of installing and operating a pig trap or pigging valve.
KEYWORD(S) FOR SUBJECT AREA: Emerging Issues, Leak Detection, NDE, Receivers, Traps, “Unpiggable” inspections and technologies
Brian Cooper1, Matthew Moshier2, John El-Hallal2, David Anstead3
1HT Engineering, Inc., Grand Rapids, USA. 2TC Energy, Chicago, USA. 3bp, Chicago, USA
This paper presents the lessons learned by the team that planned, designed, and managed a project to run gauge pigs and in-line inspection (ILI) tools through an idled pipeline. The runs covered the multiple piggable segments of a nitrogen-filled 450-mile liquid hydrocarbon product line in preparation for its return to service. Running ILI tools in lines previously in liquid service and subsequently filled with nitrogen presents challenges. This study provides insight into the pipeline system characteristics, including human factors, that must be addressed to achieve successful tool runs in nitrogen.
For this project, the team synthesized requirements from management, technical, and operations stakeholders, and developed an execution plan. During planning, the team built a numerical hydraulic model to calculate the nitrogen flow rates and pressures required to successfully run the pigs. The team worked with local operations personnel and the ILI vendor to develop detailed work procedures. During operations engineers worked on site tracking procedure completion and monitoring operating conditions. Two ILI runs failed to meet acceptance criteria, one due to abnormal ILI tool drive cup wear and one due to inadequate nitrogen control procedures. The team identified the problems and designed solutions. After each operation, the team captured lessons learned and updated subsequent procedures accordingly.
The execution plan provided the company’s management with confidence that the project could be completed safely. The numerical hydraulic model allowed the team to optimize nitrogen injection and release locations, plan injection and release operations, and verify that pressures and pig speeds could be kept within acceptable operating ranges. The solutions for the failed runs (a revised ILI tool drive cup design and a new procedure for nitrogen control) prevented recurrence of the problems and resulted in successful reruns. The lessons learned process allowed the team to improve its numerical model and human performance as the project progressed. By monitoring and analyzing the operating conditions in real time, the engineers were able to provide the project manager with the information and recommendations needed to run the operations safely and recognize emerging problems quickly.
Pipeline operators are frequently faced with the need to respond to changing market conditions and must be able to safely inspect idled lines in a timely manner. The results of this study provide operators with insight into the factors that must be addressed to achieve successful tool runs in nitrogen. These results complement the findings of Bonner, D., Greig, A., Lindner, H., Becker, J., Roulston, B., (2018, September 24-28). REACTIVATING A LEGACY PIPELINE – SIMULATING ILI RUN BEHAVIOR, OPERATION OPTIMIZATION, AND PROJECT CHALLENGES. International Pipeline Conference, Calgary, Alberta, Canada.
Sergio Limon, Ming Gao, Ravi Krishnamurthy
Blade Energy Partners, Houston, USA
An increasing number of in-line inspections (ILI) for assessing pipelines for cracking and seam weld anomalies are being carried out for the first time in more pipeline segments than before and reassessments are more common. These inspections have resulted in an increased need to evaluate and identify which planar defects pose an immediate or future safety concern to pipelines, since not all cracks and seam weld defects are injurious. For PHMSA regulated gathering and transmission pipelines, a prioritized response criteria for ILI reported indications now include response conditions based on failure pressure predictions. However, there is no unified single failure stress model nor method for estimating the failure pressure of pipelines with cracking and seam weld anomalies. The analyst is tasked with choosing from several failure stress models available to evaluate the rupture pressure capacity of a pipeline in the presence of planar defects and to estimate leak/rupture behavior.
In this paper, considerations for the selection of failure stress models are provided within the context of the type of defect being evaluated, the pipe known or expected fracture mechanism (brittle cleavage/quasi cleavage, or ductile/micro-void coalescence), fracture toughness data available or assumed, failure criteria, the fracture mechanics basis of the models and their solution space for cracks and seam weld defects. A miss-match between any of these factors can result in unreliable predictions or overly conservative results.
David Futch1, Josh Wilson2
1ADV Integrity, Inc., Magnolia, USA. 2Allan Edwards, Inc., Tulsa, USA
Repair options for linear crack-like features have expanded in recent years. The introduction of Type A Compression Sleeves and more intensive testing of carbon fiber composite repairs has resulted in additional options to the traditional Type B steel sleeve. These repair techniques can often be used in very similar scenarios, so determining when to use one over the other has grown increasingly difficult.
This study examines the benefits of varying repair methods with respect to fatigue life and concludes by comparing the cost for the repair systems. To do so, a test program was designed to evaluate simulated crack-like features installed in a LF-ERW seam weld bond line. Each axial EDM notch was cycled to form a sharp crack and then repaired by one of several repair techniques. These included a Type B sleeve, a Type A Compression Sleeve, and several carbon fiber composite repairs of varying thickness. Each repair was then cycled until failure occurred or a runout of 100,000 cycles.
The testing program demonstrated increased repair life when a thicker composite was used and when a filler material was applied under the Type B sleeve. Safety factors applied to each repair may help a pipeline operator select the best option, especially as repairs grow in length. A cost analysis was also performed to compare the material and installation cost of each repair technique. These results provide an approximate cost comparison to help determine when one system may be a more attractive option.
Brandon Peterson1, Justin Stewart2, Dejan Kloth3, Chris O’Dell4
1NiSource, Lexington, USA. 2NiSource, Fort Wayne, USA. 3NiSource, Gary, USA. 4NiSource, Valparaiso, USA
On June 27, 2022, during in-line inspection activity, a mainline valve was mis-operated. This event resulted in gas pressure that exceeded the normal operating pressure of a station, although there was fortunately no result of injuries, property damage or customer outages.
This paper outlines the initiation and result of a root cause analysis from this incident, and continuous improvements identified through the execution of the future/ongoing assessment activities.
Outlined herein are the corrective actions identified to mitigate the recurrence of such an event. These improvements include Human Performance Improvement tools such as three-way communication, rigorous procedures with clear and precise instructions, procedure revision control, clearly defined roles and responsibilities, along with several other improvements.
This paper will also describe the end results of implementing these changes as part of the current In-Line Inspection program at NiSource.
Keywords: ILI, procedure, safety, corrective action, process improvement, standards
Johannes Keuter1, V Mackissack2
13P Services, Wietmarschen, Germany. 23P Services, Chicago, USA
An 18″, North Sea, heavy wall, offshore wet gas flowline with known debris interference, had to be inspected. The total length is 286km with up to 27.3mm nominal wall thickness. Potential corrosion had been detected in a previous 3rd party in-line inspection. However, the POI was limited and no clear differentiation between corrosion and debris was possible. Hence, the previous inspections were not fully successful, and the data couldn’t be used for a full evaluation of the client’s problems. 3P Services was asked to perform a metal loss inline inspection of the pipeline as soon as possible. Following on from a specific cleaning program, 3P proposed an 18″ GEO/MFL/DMR combo tool. This tool combines a heavy wall magnetizer with a geometry measurement segment and special DMR sensors, wall guided as well as in a stand-off configuration. The combination of these different sensor technologies allows an optimized differentiation between debris, internal corrosion, or internal corrosion with debris. This information was used to improve the POI and anomaly sizing. The challenges and solutions of this outstanding project are explained in this paper.
Owen Lopez-Oneal1, Joel Anderson2, Masoud Moghtaderi-Zadeh1, Peter Veloo1
1Pacific Gas & Electric Company, Oakland, USA. 2RSI Pipeline Solutions, New Albany, USA
In compliance with CFR §192.607, Operators must opportunistically verify material properties, including grade, for pipeline features lacking traceable, verifiable, and complete (TVC) records. Among other requirements, the grade defines the specified minimum yield strength (SMYS) that manufacturers must satisfy when producing line pipe steel. While the yield strength (YS) of the material can reasonably be measured in situ with nondestructive examination (NDE) methods, this by itself does not determine the grade. Grade and YS are weakly correlated but there are large overlaps between grades that make it difficult to determine a specific grade based on measurements of YS alone. The Pacific Gas and Electric Company (PG&E), in collaboration with RSI Pipeline Solutions, has developed a machine learning (ML) model to predict pipe grade. This ML model’s input variables include in situ NDE measurements for mechanical properties and chemical composition, as well as pipe dimensions, to generate its grade predictions.
This paper will explore the sensitivity of the ML model’s grade predictions to its input variables such as YS and composition elements. Case studies of modern and vintage line pipe steels will demonstrate instances where the predicted grade is highly sensitive to YS. In other instances, the predicted grade may have low sensitivity to YS and be dominated by other input variables such as chemical composition. The paper will also demonstrate how the model’s sensitivity, to its input variables, compares to the uncertainty from in situ NDE measurements.
Amir Behbahanian1, Adrian Belanger2, Robert Coleman1, Paul Dalfonso1, Ron Lundstrom1
1T. D. Williamson, Salt Lake City, USA. 2T. D. Williamson, Houston, USA
Machine learning tools have been used for over a decade to process the large amounts of in-line Inspection (ILI) data and to report accurate sizing of metal loss features. With the explosion of software solutions that came with the advancement of graphic processing units, (GPU) power and memory available to the commercial market, the use of machine learning in processing magnetic flux leakage (MFL) tools for corrosion sizing now standard in the industry. An aspect of automation that does not get as much attention is the identification of features such as fixtures. Traditionally this task has been done either manually or with a semi-automated process based on signal pattern recognition by utilizing operator provided survey data. As fixtures are commonly used as a reference point when performing dig verifications, fast and effective methods for locating them are helpful.
This paper will present an approach using a machine learning method called semantic segmentation. There is an enormous amount of information contained in an MFL survey that has an image like structure with magnetic measurements sampled both axially and circumferentially on a grid. The powerful technique of semantic image segmentation, which is used in applications like autonomous driving, medical imaging, urban planning, manufacturing, robotics, etc., is ideal for analyzing this data.
Four different models will be presented to demonstrate how a combination of them can perform the task of identifying and classifying pipeline features. This work will lay the foundation of not only automating a semi-manual task but training models to focus on features of concern to the operator. Due to concerns about aging infrastructure, identifying certain types of fixtures can help with integrity threat management. The use of these models has the potential of identifying specific features that have known integrity concerns and facilitate a pipeline owner’s remediation plan.
Jed Ludlow1, Adrian Belanger2, Ron Lundstrom1, Miguel Maldonado1
1T.D. Williamson, Salt Lake City, USA. 2T.D. Williamson, Houston, USA
Reliable assessment of pipeline corrosion remains an important concern for pipeline operators, especially when the corrosion presents itself in complex patterns and in large quantities. We present an approach to this problem using magnetic flux leakage inline inspection employing multiple magnetization directions simultaneously. The approach is accomplished in production data analysis and scales to large quantities of corrosion anomalies.
An axial magnetic flux leakage data set and a spiral magnetic flux leakage data set are gathered simultaneously during the same inline inspection run, and the signals from both data sets are also analyzed simultaneously. Detection, identification, and sizing of metal loss anomalies can be accomplished using one or the other magnetization direction and even a combination of both magnetization directions where appropriate. After sizing, metal loss clusters can be formed from applying interaction rules to combinations of the metal loss anomalies regardless of the data set from which they originate. This facilitates reliable failure pressure estimation using effective area methods even for narrow axial corrosion morphologies that would not be well addressed by conventional axial MFL alone and for other complex corrosion patterns. Application examples demonstrate that comparisons of failure pressures estimated from inline inspection data are in close agreement with those calculated using data from non-destructive evaluation in the ditch.
Keywords: inline inspection; magnetic flux leakage; corrosion; effective area methods
Michael Byington1, Facundo Nahuel Ignacio Lamas2, Rodolfo Eduardo Rodríguez2, Celeste Vera2
1INGU, Houston, USA. 2Pan American Energy, Cerro Dragón, Argentina
The development of conventional inline inspection technology has been geared towards ultra-high resolution tools requiring a completely cleaned pipeline and coming with increasing costs and data handling time. By comparing data between inspections, unconventional inline inspection tools equipped with off-the-shelf micro-electromechanical magnetometers provide actionable information on the best allocation of resources for digs and high resolutions tools as well as the location of unexpected changes such as illegal hot tap installations. To ensure an accurate comparison between inspections, the data of subsequent inspections must be perfectly aligned. This presentation will discuss a fully automated approach to align inspection data using Monte-Carlo based time warping strategies.
We will illustrate the method with a case study conducted by Pan American Energy. They installed a hot tap at an undisclosed location along a nearly 3,000-meter steel pipeline and asked INGU to locate it. The hot tap was unambiguously identified and Pan American Energy confirmed that the provided location was within the 6 meter acceptance criterion for the project.
KEYWORD(S) FOR SUBJECT AREA: ILI Analysis; Emerging issues, technology; Unpiggable Inspections and Technology
Mohamed Elseify
Baker Hughes, Calgary, Canada
Pipeline systems experience a range of strain conditions along their length. These are either factored into the pipeline design as known operational strains or as strain resulting from additional external loadings that are potentially unknown during the design or construction phases. Detecting, monitoring, and understanding these additional strains in combination with operational strains are a key part of a pipeline integrity management program. Surveying with inertial mapping tools have been commonly used since the late 1980’s for accurate measurement of bending strain – which unfortunately only provides a part of the picture. The development of the ILI axial strain measurement tool (AXISS™) was a response to fulfilling a pipeline operator’s need for axial strain measurement in combination with available bending strain information to enhance their geohazards risk management programs.
After a long period of comprehensive field testing and validation, supported by a number of partner customers, Axial Strain Inline Inspection transitioned from a developmental to commercial service more than 10 years ago. Since then, over 20,000 km of data has been collected with many high strain locations successfully identified and mitigated. While axial strain inspection is now established as a proven and important tool for a pipeline operator to assess geohazard and other strain related threats, that experience has provided key insights as to where the current technology strengths lie and of course where we need it to go next to provide the level of information truly needed to optimize our full understanding of strain-based threats. This paper gives a detailed overview of some of those experiences discussed, examples of the applications of the technology and the types of strain events identified. Secondly, and more importantly, this paper provides key insight into the latest developments of the technology that will address the remaining unmet needs of the geohazard and stress engineers tasked with establishing a complete picture of pipeline strain condition, allowing them to effectively optimize any mitigation measures or repair programs.
Joel Van Hove1, Casey Dowling2, Pete Barlow3
1BGC Engineering Inc., Vancouver, Canada. 2BGC Engineering Inc., Golden, USA. 3BGC Engineering Inc., Edmonton, Canada
Well-structured geohazard management programs (GMPs) for pipeline systems have become common over the last two decades in North America as pipeline companies have become more aware of the risks presented by natural hazards and the value in adopting proactive approaches to manage risk. The case study presented in this paper represents the GMPs of 30 major pipeline companies in North America comprising approximately 150,000 miles of operating and actively managed pipeline. The performance of these GMPs has been measured to reduce pipeline failure rates from geohazards between 300% and 500%. Over the past 10 years more than 95% of the observed geohazard pipeline failures have been from slow-moving landslides. A total of more than 15,000 known landslides intersect pipelines within the study scope. The annual probability of failure given pipeline impact from a slow-moving landslide has previously been estimated at 1 in 50, meaning any landslide which is actively moving and intersecting a pipeline presents a potentially serious integrity concern. The primary challenge with managing slow-moving landslide hazards is that determining landslide activity without instrumentation is often not possible, and installing conventional instrumentation such as slope inclinometers at such a large number of landslides is prohibitively expensive. Slow moving landslides also cannot reliably be visually identified as movement rates are often low enough that visible surface disruption is subtle or undetectable, but those same movement rates will be enough to cause pipeline failure over the life of the pipeline. To address this challenge many forms of low-cost instrumentation have been pursued to measure ground movement and/or pipeline impact including Interferometric Synthetic Aperture Radar (InSAR), lidar change detection, and in-line inspection tools such as axial strain and inertial measurement unit (IMU). Over the last 10 years IMU has become a critical and frequently utilized tool for assessing landslide activity and has been integrated into the geohazard management programs of all the operators in the study scope. In 2022 IMU was credited for identifying 50% of the active landslides where operators completed critical interventions to manage risk (e.g., pipeline shut in, stress relief mitigation). Key lessons and observations for successfully integrating IMU into GMPs are presented from a case study spanning 10 years and 150,000 miles of pipeline.
Brian Leis1, Amin Eshraghi2
1Consultant, Worthington, USA. 2Acuren, Calgary, Canada
API’s release of the first edition of its Recommended Practice 1183 titled “Assessment and Management of Pipeline Dents” in November 2020, and Errata 1 a few months thereafter, marked the culmination of 14 plus years of work. Against that backdrop, the PRCI, in collaboration with the PHMSA initiated Project MD-5-1, which sought to assess that activity, to identify technology gaps and aspects of that work that could enhance API RP 1183 or broaden its capabilities. Concurrently, the PRCI also in collaboration with the PHMSA initiated Project MD-5-2 whose purpose was to enhance previously developed tools being adopted in API RP 1183. Aspects of these RP 1183 developments were evaluated rather critically at PPIM2023 in a paper that discussed what were termed “enhancement of indentation crack formation strain estimation” in PRCI’s reporting MD-5-2. Independently, about the same time a four-part series of papers was being planned with a similar but much broader intent and complexity, which is now in part in print in a refereed journal. This paper is the practical synthesis of that breadth and complexity, distilled with guidance and with takeaways concerning the issues and limitations of RP 1183 as released above by API.
It is shown that RP 1183 is effective for larger fully symmetric inverse-dome-shaped dents, as might be formed by smooth symmetric round field boulders that lay along the bottom-dead-center of the pipeline. However, for such dents formed over smaller diameter rocks it becomes evident that the threat posed by areas of locally high curvature can be eradicated by the smoothing practices applied by the RP. Asymmetric inverse-dome-shaped dents, like those formed by smooth symmetric round field boulders that lay to either side of bottom-dead-center of the pipeline are also considered. Such dents are neither symmetric nor do they form radially into the pipe-wall, which is contrary to the scenario quantified and used in developing API RP 1183. It is shown that the severity of smooth asymmetric dents can be underpredicted by the RP by almost 100%, with similar issues evident for skew dents at angles less than the RP-acceptable 30° angle. Guidance and takeaways are provided to help manage such scenarios, and as well as concerns involving multipeak dents.
Jeff Sutherland
Baker Hughes, Calgary, Canada
This paper will discuss aspects of pipeline integrity, and a perspective of threats and the damage mechanisms of pipelines, namely the presence of defects and the susceptibility (threat) for such defects to initiate and occur, through their related mechanisms.
We start with the broad premise that damage mechanisms become accelerated with the presence of hydrogen in natural gas pipelines, while acknowledging that ongoing research is very active to refine and qualify specific parameters and situations.
Also, as a premise of treating this situation of a pipeline conversion as a change of service, with some common direct steps to establish a readiness for service. A key premise is the need to establish a baseline reference for defects and integrity and failure/leakage sources. Including some conventional defects that may become more prominent for integrity concerns due to their potential nature to concentrate H2. (Historically, a significant change would be a liquid to gas operation or vice versa – or a notable change in product like sour gas versus conventional gas).
And fundamentally from a conventional integrity perspective, we will describe aspects of what is the same and what is different for integrity data coming from ILI tools and achieving a state of readiness. This includes a perspective of what readiness means for ILI tools, their operation in hydrogen blended pipelines, and expectations for data reporting.
Ana Paula Gomes1, Marco Marino1, Giuseppe Giunta2
1Enivibes, Milan, Italy. 2Eni, San Donato Milanese, Italy
This paper focuses on detection of leakage occurrences, particularly those that occur on buried pipelines and can be caused by factors such as corrosion, wear, or illegal tapping. Such events can cause considerable harm to the pipeline operator and the environment, including critical damage to the pipeline and surrounding lands, leading to large remediation expenses and operational downtime.
The management of assets has the primary objectives of ensuring reliability and integrity of pipelines during their operations. To achieve these goals, procedures and technological systems are implemented to quickly detect and address any possible or real hazards to the integrity of the assets.
Vibroacoustic Technology presents a solution to this problem by detecting both the leakage and its precise location, as well as other anomalies involving the pipe and/or the transported fluid. This technology is currently operative globally, protecting thousands of pipeline kilometers, primarily on buried pipelines.
Initially developed for Leak Detection (LD) applications, the Vibroacoustic Technology has demonstrated excellent performance in detecting and localizing spillages and impact events in real-time. In certain conditions, it has also been shown to identify activities that precede a spill, such as illegal tapping preparation activities, corrosion, and wear. The present work highlights the outstanding performance of this technology in detecting illegal tapping in Italy, with multiple examples reported.
Before the implementation of this technology, Italian pipelines transporting refined products suffered numerous leakages due to fraudulent activities. However, after the extensive deployment of Vibroacoustic Technology across the pipeline network, illegal tapping almost ceased to exist. The use of this technology was later adopted as a prevention tool, and a complete presentation of the challenges and solutions put in place to overcome them is included in this work. The success of this implementation was due to a holistic approach and a high level of collaboration between multiple parties.
In conclusion, Vibroacoustic Technology presents a reliable solution to detect and prevent leakage occurrences, particularly illegal tapping, in pipelines. The technology has demonstrated outstanding performance in real-world scenarios, and its widespread deployment has resulted in a reduction of pipeline incidents, protecting both the operator and the environment.
The present work provides a comprehensive overview of the challenges and solutions involved in implementing this technology, highlighting the importance of a holistic approach and active collaboration between pipeline operator, local inspection teams and law enforcement to achieve successful results.
Laurie Knape
API, Houston, USA
In November 2022, API and the joint Pipeline SMS Industry Team published Pipeline SMS: A Contractor’s Guide to give pipeline contractors and service providers an enhanced understanding of how the scope of their safety programs should be integrated with an operator’s Pipeline SMS. A tool has been created with industry collaboration, showcasing 56 key requirements of API RP 1173: Pipeline Safety Management Systems, that will help operators and contractors integrate their safety efforts. In this presentation, we will show how the newly developed tool will help contractors and service providers mature internal safety programs that support Pipeline SMS. The tool is scalable based on the size of the organization and the scope of work and can be a valuable tool in starting the PSMS journey. In addition to reviewing the tool, we will highlight good practices seen from a pipeline operator and a service company on the value gained from the integration of their safety programs. API and the joint Pipeline SMS Industry Team have created a Contractor SMS Assessment pilot program. We will review the Contractor Assessment program’s step-by-step details and discuss deliverables, scoring, and benchmarking.
Hamza KELLA BENNANI1, Jim Hart2, Ali Fathi3, presented by Mehdi Laichoubi1
1Skipper NDT, Paris, France. 2SSD, USA. 3Enbridge, Canada
Buried pipelines are critical for infrastructure transporting large amounts of oil and gas products across long distance. Several integrity threats need to be monitored to avoid incidents, amongst which geohazard events are responsible for at least 16% of failures over the last 10 years. Geohazards result in permanent ground displacements, which may cause axial and/or lateral deformations that induce bending strains in these structures, leading to catastrophic consequences. To address this issue, Skipper NDT has developed a proprietary embedded system mounted on a drone, with the aim of generating a high-precision digital twin of buried pipelines. This technology enables the acquisition of position data with high data density, which can be utilized to assess bending strain. To validate the effectiveness of the technology, a series of tests were conducted in coordination with Enbridge in North America. The results of the drone-based technology runs were compared against those obtained with an Inline Inspection tool. The comparison showed good agreement in the trends detected in terms of bending strain profiles.
56. Risk Based Prioritization of Hard Spot Mitigation
Kelly Thompson1, Cassandra Moody2
1Dynamic Risk Assessment Systems, Inc., Calgary, Canada. 2Time For Change, LLC., Houston, USA
Abstract
Hard spots are a pipeline defect created during original manufacturing. These are typically considered stable unless acted upon by coincident environmental factors including coating degradation, atomic hydrogen, and stress. As a result of industry lessons learned and recent hard spot related failures on its system, Williams is executing a hard spot mitigation program that encompasses improvements to our risk assessment model to account for hard spot defects. In this presentation, we will share how we are incorporating this risk into our modeling approach and how those results influence the mitigation effort. Additionally, this presentation will discuss the benefits that can be realized through broader industry collaboration, current collaborative studies underway, and key metrics to advance industry understanding of the hard spot risk that ultimately will improve overall pipeline safety.
Topics of Discussion
Abstract: Pipeline Risk Forum
89. Enhancing EMAT Crack Detection Services Using State of the Art Deep Learning
Stephan Eule1, Thomas Beuker1, Neil Pain2
1Rosen EU, Lingen, Germany. 2Rosen USA, Houston, USA
Abstract
EMAT crack detection technology is used worldwide by many oil and gas operators to detect and size cracks in liquid and gas pipelines. By collecting data of increasingly higher resolution and quality, it is possible to achieve a more and more accurate representation of the integrity reality of oil and gas structures.
However, the prerequisite for gaining insights from this data is provided by Artificial Intelligence (AI) methods and a corresponding Research-First structure of a company. The AI division at ROSEN Research Center invested significant time and resources to apply powerful machine learning in particular Deep Learning methods to ensure timely and accurate inspection results delivered to operators. These efforts are directed towards building data driven applications to ensure reliability of inspection systems. Supported by a modern data engineering infrastructure, AI-powered data-driven applications can be used to enhance both the quality and efficiency of inspection data analysis.
This paper will provide an insight on how ROSEN uses AI-methods to enhance classification and sizing of metal-loss and crack indications in pipeline inspection data. Particularly, how Deep Learning methods help ensuring the quality of EMAT-Crack detection services.
KEYWORD(S) FOR SUBJECT AREA: Machine Learning, EMAT Technology
88. EMAT Lessons Learned Using Assessment Findings
Christopher De Leon, Rhett Dotson
D2 Integrity, Houston, USA
Abstract
The INGAA Foundation formed a joint industry project (JIP), on behalf of INGAA, to develop an industry technical guidance document specific to the use of Electromagnetic Acoustic Transducer (EMAT) in-line inspection technology for management of cracks, with specific emphasis on stress corrosion cracking (SCC). EMAT ILI has been used for over two decades and has reached a level of maturity where both the performance specifications and response planning can be systemized. However, the use of EMAT has mostly been limited to early adopters and requires implementation of processes and procedures particular to EMAT for it to be used as an integrity assessment. With recent changes to gas pipeline regulations in 49 CFR 192 associated with integrity assessments and MAOP Reconfirmation, the use of EMAT ILI for crack management is expected to increase by new and existing users. This technical guidance document was developed to benefit industry from the experience of the JIP members and provide knowledge sharing. This presentation will provide a knowledge transfer on this subject through an overview of how to use the published guidance document and the lessons learned from its development.
87. Inline Inspection Monitoring and Data Interpretation Using Fiber-Optic Sensing
Jerry Worsley1, Jason Reynaud2, Tony McMurtrey3, Adnan Chughtai4, Josh May4
1Schlumberger Midstream Production Systems, Dubai, UAE 2Schlumberger Midstream Production Systems, Houston, USA 3Midstream Integrity Services, San Antonio, USA 4Schlumberger Midstream Production Systems, London, UK
Abstract
Fiber-optic sensing systems are becoming more commonly used for leak and third-party intrusion detection on pipeline infrastructure throughout the world. This has been recognized by their recent inclusion in the latest editions of API 1130 and API RP 1175. Sensing systems also have a part to play in the operational aspect of pipeline management. This includes the monitoring of most pipeline pigs, ranging from typical batching or cleaning pigs that may be run frequently to the critical inline inspection tools that inspect pipelines less frequently.
Early adopters of fiber-optic distributed acoustic sensing (DAS) systems discovered that these solutions could identify the location of pigs as they traversed the pipeline as well as pinpoint the location of a stuck pig, enabling the pipeline operator to immediately take action to dislodge the stuck tool and even mobilize to the location to remove the pig through intervention. The latest evolution of DAS from qualitative to quantitative data means that the information gathered is richer, and the greater fidelity results in more precise and certain feedback for the operator.
This paper focuses on operational pigging data gathered by Midstream Integrity Services for a 720-mile pipeline in Texas and confirms that fiber-optic sensing can support and complement routine operational pigging as well as intelligent pigging by removing the risk and inaccuracy associated with traditional pig tracking methodology.
86. Inline-Inspection Crack Diagnostics for Gas Pipelines – A Novel Technology
Willem Vos, Thomas Hennig
NDT Global, Bergen, Norway
Abstract
Older gas transmission systems, specifically those built between the mid-20th century and the early 1980s can be affected by Stress Corrosion Cracking (SCC). A common methodology to address this threat is to utilize ILI tools using EMAT transducers to characterize the asset. It is common practice to utilize a magnetic flux leakage tool (TFI) in addition to the EMAT inspection to support identification and characterization of EMAT signals. Furthermore, EMAT tools have a limited operational envelope with regards to wall thickness and speed.
NDT Global has reached a significant milestone in the development of an alternative technology which addresses crack detection, identification, and sizing in gas pipelines. This new method is based on the generation of guided Lamb waves, using gas coupled ultrasonic transducers. The method allows inspection of the asset without any contact of the sensors to the pipe wall, allowing for higher inspection speeds and a wider range of wall thicknesses.
This paper presents some of the historic developments, starting with a gap analysis of existing solutions, small scale lab test results and full-scale pull testing. The developed solution combines newly developed gas coupled guided wave principles with several principles from the proven technology operated in liquids.
Keywords: Crack detection in gas, Stress Corrosion Cracking
85. Pathfinder Foam Caliper Pig Overcomes Severe Pipeline Conditions to Successfully Identify and Locate Geometric Deformations in Gas Pipeline, Mainland China
David Cockfield¹, Peter Ward¹
¹Pipeline Innovations Ltd, Cramlington, UK
Abstract
OBJECTIVE/SCOPE
This paper is to share the development of Self-Propelling Robotic In-Line Inspection technology that PETRONAS embark as OPEX optimization for un-piggable pipeline. Lack of conventional inspection methods to inspect un-piggable pipelines such as vent pipelines without pig traps facility and low flow pipelines, has prompted PETRONAS to embark on technology development journey for Self-Propelling Robotic ILI.
METHODS/PROCEDURES
The development of the Self-Propelling Robotic In-Line technology consists enhancement of robotic tethered crawler tool to a wireless robotic tool, testing and validation using actual full scale fabrication test loop. Fabricated test loop includes horizontal and vertical section with bends of 1.5D to simulate the inspection tool travel as per actual site condition representing vent line.
The enhancement consists of wireless connection range, optimum speed and distance, movement of slippery surface which grease was applied on the vertical section and emergency extraction of inspection robot.
RESULTS/OBERVATIONS/CONCLUSIONS
Robotic ILI qualification test which was successfully met PETRONAS requirement based on full scale factory acceptance test. The test was focused and able to meet below success criteria: –
Robotic ILI tool able to self-propel on vertical test spool.
Robotic ILI tool able to move with wireless connection for the intended travel length.
Emergency retrieval tool procedure and mechanism in the event of faulty robotic ILI or loss of connection.
Sensor detection capability at POD 90% and POI 80%.
Based on the evaluated technology, Robotic ILI solution is feasible in ascertaining the un-piggable pipeline integrity and recommended solution to tackle high operational costs that upstream operators face when inspecting their pipelines using current available methods. Deployment of this technology is estimated to provide up to 30% OPEX optimization.
The technology has been evaluated to be technically ready and pilot tested PETRONAS asset which will be shared in our detail paper covering below areas:
1. Robotic ILI tool able to travel successfully total length of pipeline.
2.Detection capability at POD 90% and POI 80% for anomalies covering metal loss and girth weld anomales.
NOVEL/ADDITIVE INFORMATION
Current approach to inspect un-piggable vent or low flow pipeline is Crawler ILI type technology which propelled by umbilical cable whereby the pipeline requires to be in shutdown mode. While, inspection using Self-Propelling Robotic ILI can be applied for un-piggable pipeline i.e. low flow pipeline and vent line with short duration or no requirement of shutdown.
84. Axial Flaw and Crack Detection in Multi-diameter Low-Pressure Gas Pipelines
Lance Wethey1, Pete Clyde2, John Nonemaker1
1ROSEN, Houston, USA. 2LG&E, Louisville, USA
Abstract
Louisville Gas and Electric (LG&E) owns and operates numerous natural gas transmission pipelines in the greater Louisville, KY area. Many were constructed during the 1950’s and therefore present extensive challenges to inline-inspection (ILI) efforts. Multi-diameter pipeline geometry and transient operating conditions combine to create an environment that proves difficult for running in-line inspection tools. LG&E has utilized high resolution geometry and metal loss detection solutions optimized for low-pressure multi-diameter pipelines ILI devices in their integrity management program. There was a desire to expand the technologies deployed to include technologies best capable of detecting axially oriented anomalies and cracking. To address these concerns, circumferentially induced magnetic flux leakage (MFL-C) and electromagnetic acoustic transducer (EMAT) technologies were suggested, however applying these detection methods in low-pressure multi-diameter pipelines was not available.
MFL-C & EMAT-C ILI devices capable of inspecting a pipeline with both 16″ and 20″ diameters in a low-pressure gaseous environment needed to be developed. In addition, traversal of all restrictive features, such as tight radius bends and minimal spacing between fittings, must be achieved with minimal differential pressure to facilitate stable run behavior and allow optimal data capture. ROSEN reviewed all known details regarding the targeted pipelines and compiled a list of challenging fittings to define the required mechanical passage capabilities. The conceptual design, manufacturing, and assembly stages of development resulted with redesigned low-friction ILI tools capable of full circumferential sensor coverage in 16″ – 20″ pipeline diameters. The tools were then pumped with water through a test loop that included the most restrictive features identified in the targeted pipelines. Performance results confirmed mechanical passage and determined the average ∆P’s necessary to pass the included restrictive features. Finally, validation pull tests occurred to confirm data capture functionality within established specifications. After mechanical and data capture performance were verified, the new low pressure multi-diameter 16/20″ MFL-C & EMAT-C were deemed fit for service and deployment.
This technical paper outlines the development process with examples and observations from the testing program. Difficulties related to MFL-C & EMAT-C technologies as related to low-pressure and multi-diameter environments are discussed in further detail. The paper includes real-world operational challenges and inspection results from two successfully inspected pipelines, as well as a discussion of iterative ILI tool improvements.
83. Validating and quantifying in situ NDT uncertainty of line pipe material properties
Jeffrey Kornuta1, Joel Anderson2, Emily Brady1, Janille Maragh3, Peter Veloo4
1Exponent, Inc., Houston, USA. 2RSI Pipeline Solutions, New Albany, USA. 3Exponent, Inc., Menlo Park, USA. 4PG&E, Walnut Creek, USA
Abstract
The federal rules governing the operation of natural gas pipelines allow operators to use nondestructive testing (NDT) technologies to verify pipeline material properties provided that these tools are validated against destructive test results and conservatively account for measurement inaccuracy and uncertainty. Any measurement methodology inherently has uncertainty due to both systematic and random effects: systematic errors being those that remain constant during repeated measurements, and random errors being those that vary randomly in repeated measurements. This combined uncertainty not only affects the estimation of material properties, but it may also propagate to downstream analyses, such as during maximum allowable operating pressure (MAOP) reconfirmation. Moreover, this uncertainty might adversely affect the accurate determination of comparable pipe segments when establishing sampling populations.
This paper presents Pacific Gas and Electric Company’s (PG&E) approach for the statistical inference of destructive laboratory values when in situ (field) NDT measurements are collected. This approach has been formulated from an in-house statistical validation of NDT technologies whereby NDT measurement results are compared against laboratory destructive test results. The types of material properties that PG&E has evaluated using NDT technologies include microstructure, hardness, chemical composition, yield strength, and ultimate tensile strength. In total, several thousand NDT measurements across approximately one-hundred pipe features have been evaluated against laboratory test results. The authors describe this statistical analysis approach whereby the lab results are compared to NDT measurements through a regression model to account for systematic errors. Once the regression is performed, the scatter of the data is quantified using a prediction interval to account for the random portion of the uncertainty. Finally, the total uncertainty is quantified and propagated to downstream analyses using a Monte Carlo methodology. Current challenges to this approach are presented, and alternate statistical approaches are described which have the possibility of yielding additional benefits.
82. Pipe Grade Classification: Groundbreaking ROI From Your UHR MFL Inspection
Max Harrisson
Entegra, Reading, United Kingdom
Abstract
Operators must be able to see more and know more about the overall condition of their pipelines to keep their operations running safely and efficiently. This paper will show why the delivery of a complete and accurate Materials Classification Report is one of the most significant outcomes of employing the latest in UHR MFL technology.
This paper will take a holistic look at Ultra-High Resolution MFL and how a system incorporating the latest in UHR technology, combined with human-experience based data analysis, can provide an integrity assessment that goes well beyond POD and POI. Understanding the impact of pipe grade, maximum operating pressures, current and projected metal loss and the accurate and cost-efficient confirmation of historical pipeline data are all benefits of a truly integrated system of technology and data analysis.
We’ll look at these factors as well as how they relate to the Mega Rule and its impact on an operator’s ability to maximize throughput, ROI and pipeline integrity.
81. Know your Materials! On-site Non-Destructive Materials Testing for Gas Transmission Pipelines
Travers Schwarz1, Trevor Foster1, Steven Kinikin1, Aaron Crowder2
1SMUD, Sacramento, USA. 2Massachusetts Materials Technologies LLC, Natick, USA
Abstract
The new Mega Rule now requires pipeline operators to have Traceable, Verifiable and Complete (TVC) material records for their pipeline systems. Operators that do not have TVC records for any portion of their pipeline, must develop and implement procedures for non-destructive testing (NDT), destructive testing, examinations and assessments in order to verify these material properties for above ground line pipe and components, and of buried line pipe and components. Because of the recent ruling, Sacramento Municipal Utility District (SMUD), an operator of 76 miles of gas transmission pipeline, recently contracted Massachusetts Materials Technologies (MMT) to conduct three in-situ pipeline evaluations where they implemented positive material identification (PMI) technologies to verify and confirm the pipeline hardness, strength and ductility (HSD) properties for their pipeline. Massachusetts Materials Technologies (MMT) performed this work in compliance with [49CFR192.607]. MMT’s proprietary equipment and test procedures were able to predict pipeline yield strength, ultimate tensile strength, base metal chemical composition characteristics, and pipeline hardness to show material ductility. The technologies also gathered hardness data across the long seam weld to classify the pipe seam weld type. MMT was validated within the industry and selected based on the results of PRCI NDE 4-8 report (Catalog No. PR-335-173816). The destructive test method data attained from SMUD’s original heat analysis, further confirmed the predicted values MMT acquired for each material grade that was investigated at each site. MMT’s predicted test results were found to be conclusive, aligning closely with SMUD’s original pipeline Material Test Reports (MTR’s). This NDT method has further validated SMUD’s original pipe material records and should be considered by pipeline operators that are looking for a proven technology and test method to help confirm pipe populations that do not have TVC records.
80. New Repair Technology – the Path to Field Deployment
Shawn Laughlin
Pipe Spring LLC, The Woodlands, USA
Abstract
Pipe Spring™ technology utilizes the well know material properties of steel with the installation methods and techniques associated with various composite repair products. Thin layer steel is utilized to wrap around the pipe and secured via modern toughened adhesive to fabricate a non-welded steel sleeve. This method removes the long -standing concerns regarding the vast material property differences between steel and various composite architectures and constituent components. It also eliminates welding. This paper will address US DOT, PHMSA regulatory requirements of repair methods. The paper will provide a brief review of the full-scale validation testing completed following ASME PCC-2 guidance. MFL based ILI inspection of the sleeve is reviewed. Data from two ILI service providers will be reviewed. This paper discusses field crews, installation methods and the training and documentation required to satisfy Operator Qualification (OQ) requirements. The simplicity and facility of installations is discussed based on actual operator training efforts.
Key Words: Emerging issues/technology. Repairs and Rehabilitation
79. Composite Repairs Evaluation for Axial and Bending Loads to Simulate Girth Welds Under Risk of a Geohazard Event
Omar Ramirez, Casey Whalen
CSNRI, Houston, USA
Abstract
Pipelines are exposed to environmental induced damage due to corrosion, erosion, and potential Geohazard activities that include earthquakes, floods, landslides, and any other geological or hydrological disasters. These activities could threaten a pipeline’s structural integrity. This paper will focus on geohazard risks as the consequences and risks are generally higher and more immediate than that of wall-loss type defects.
Repair of damaged pipelines has traditionally been accomplished using welded repairs, where a patch material is attached to the substrate over the damage. During the past twenty years, composite materials used to repair damaged pipelines have experienced a considerable increase as these repairs have become more cost effective, efficient, and reliable due to extensive testing.
This paper will focus on describing a test program to evaluate the performance of a composite repair under bending or axial loads to simulate the impact of a potential Geohazard. These repaired specimens will be tested in different configurations of installation pressure, internal pressure cycling and axial force cycling. On this test program, a composite repair was installed on 12-in pipe where an internal local notch (50% deep and 6” on the hoop direction) was installed at the weld to simulate lack of fusion or represent a poor quality weld. Testing results show that a composite repair is capable of considerably reducing strains at the weld and increasing the axial and bending load capacity of the carrier pipe.
Keywords: Composite Repair, Geohazards
78. Use of Mobile Fleet of Leak Detection Devices to Mitigate Risk During Pipeline Repair Program
Adrian Banica1, Steve Edmondson1, Tim Edward2
1Direct-C, Edmonton, Canada, 2Onebridge, Edmonton, Canada
Abstract
New IoT standalone leak detection systems can be rapidly deployed to cover potential leaks, however covering an entire pipeline is cost prohibitive so a method for selecting the locations for deployment is required.
This paper examines how data science & machine learning software combined with environmental assessments can lead to deployment of targeted leak monitoring devices that employ nanotechnolgy based coatings to optimize a pipeline repair program.
When a risk is noted on a pipeline, currently there is little recourse between doing an expensive direct assessment on that location; or letting that location remain unmonitored until resources exist to examine it. New IoT targeted leak detection technology allows an economical middle ground where many risk locations can be monitored for minute traces of signs of a leak, all at a fraction of the price of a direct assessment. With such timely alerting of a leak, the consequences at that site can be greatly reduced. These leak detectors only work in a very localized area and depend on areas of concern being accurately identified. It is modern, advanced ILI alignment and integrity analysis software that provides this key risk placement data.
This leak detection technology uses smart coatings to detect Hydrocarbons, it runs 24/7 and uses alarm-based algorithms to alert to the presence of leaks. It can be rapidly installed in targeted locations that are identified by algorithms as being needed to be repaired and then moved to new locations as those identified defects are repaired.
This paper describes how a fleet of leased mobile leak detection systems were deployed over several months along a pipeline which covered several US States. The units were deployed in High-risk areas that had been identified as needing repair. At the completion of the repair program most of the leased leak detection systems were returned. Feedback from the operator will be included in the presentation.
77. Leveraging Multiple ILIs and Technologies to Identify Possible Integrity Threats Under Type A Sleeves
Michael Plishka1, Kelsey Hooten1, Jason Williams1, Matthew Lewis2
1Colonial Pipeline Company, 2Quest Integrity
Abstract
On August 14, 2020, a leak was discovered on Colonial Pipeline Company’s (Colonial) Line 1 pipeline in Huntersville, North Carolina. The release occurred at a dent, previously repaired with a Type A sleeve. Upon further investigation, it was found that external metal loss and a through-wall crack had developed in the dent sometime after the installation of the Type A sleeve. Type A sleeves are a common remediation method used to reinforce and repair certain anomalies on a pipeline. However, because the sleeve ends are not welded to the carrier pipe, Type A sleeves are not pressure-containing. A remediation plan to identify possible integrity threats under Type A sleeves and convert those Type A sleeves to pressure-containing Type B sleeves on Colonial’s mainlines was implemented.
In close conjunction, Colonial and Quest Integrity developed a plan to first identify every sleeve on Colonial’s mainlines. Once the comprehensive sleeve list was compiled, a qualitative analysis of all sleeve locations was initiated. Utilizing multiple inline inspections (ILI) and tool technologies, such as Ultrasonic Wall Measurement (UT-WM), Ultrasonic Crack Detection (UT-CD), and Combo (MFL + Caliper), each sleeve location was reviewed to determine:
Results from the sleeve review were used to provide a prioritization of the Type A to Type B conversions.
This paper uses case studies from this sleeve characterization and review project to show:
76. Comparing Laser Scans Against In-Line Inspections and Quantifying Bias for Assessment Methods
Sayan Pipatpan, Andreas Pfanger
NDT Global, Stutensee, Germany
Abstract
Ultrasonic technologies have been part of the portfolio of in-line inspection (ILI) vendors for decades, but many operators rely on magnetic flux leakage (MFL) technology when it comes to metal loss corrosion.
This case study is based on a 28” pipeline with external metal loss which was inspected using a MFL tool and – 5 years later – ultrasonic wall thickness measurement (UTWM) tool. This was followed by laser scans at 7 different sites which detected mostly pinholes and pitting corrosion. The number of verified anomalies allowed a statistical analysis of sizing deviations between ILI and field verifications. While most verifications happened after the UTWM inspection, a subset was completed shortly after the MFL inspection.
Detailed side-by-side comparisons between UTWM and the laser scans further illustrated the level of detail offered by direct measurement techniques. They provided in-depth insights on their advantages and limitations, as well as the influence of clustering strategies on length and width sizing accuracy.
Additional assessments in this pipeline led to the investigation of potential bias influencing the corrosion growth estimates. Utilizing subsets of features where no growth was expected, and by integrating the results from laser scans, this bias was quantified.
KEYWORDS FOR SUBJECT AREA: ultrasonic tools, magnetic flux leakage, metal loss corrosion, correlation, verification
75. Dig Data Warehouse to Enable ILI Continuous Improvement
Nathan Verity, Hong Sang, Pu Gong
Onstream Pipeline Inspection Services Inc., Calgary, Canada
Abstract
In order to improve various facets of the ILI product cycle, including sizing accuracy, anomaly or feature identification, and repeatability of inspections a dig data warehouse is needed. Traditionally different vendors and operators have internal formats for this data which can be difficult to use in validating and comparing results across multiple inspections.
To be effective and enable future research, the breadth of data captured in the warehouse, is formatted in a standard format, includes raw inspection data, pipeline metadata, analysis results, and dig measurements including raw laser scan data. The increased in the confidence of ditch measurement enables better trend analysis and adjustment of ILI sizing models. New data signals can also be compared to signals in the warehouse to help identify and classify against verified signals reducing any analysis bias.
This paper will describe the methodology for capturing and utilizing this data to both close the loop of the ILI continuous improvement cycle and provide feedback to customers on the ILI tool performance in the field.
74. Proof of Performance: Flow-Loop-Testing Validation of UHR MFL Technology in the POD, POI and Sizing of Pinholes
James Lavender
Entegra, Houston, USA
Abstract
A major liquid pipeline operator with assets throughout Texas and the Midwestern United States recently engaged us in a blind flow loop test to compare the pinhole detection, characterization, and sizing capabilities of Ultra-High Resolution (UHR) Magnetic Flux Leakage (MFL) vs. their legacy state-of-the-art Ultrasonic In-Line Inspection (ILI) results.
Testing was carried out at PRCI’s Technology Development Center in Houston, Texas. This paper will discuss how the latest advancements in MFL technology impact true pinhole assessment and will present the flow loop test setup, execution and results.
73. Tool Tolerances in MFL In-line Inspection and Why They’re Needed
Kenneth Maxfield1, Mark Briell2
1KMAX Inspection, Millcreek, USA. 2KMAX Inspection, Toronto, Canada
Abstract
While the principle of magnetic flux leakage is relatively simple, it’s application in in-line inspection of carbon steel pipe is far more complex. MFL system design and analysis encompass complex interactions between the magnetic field and flux leakage produced by defects in the pipe wall, making signal identification & interpretation difficult. Thus, the need for tool tolerances.
This paper discusses the cause and effect of wide-ranging factors which influence the reported depths & dimensions of MFL In-line Inspection data. Including,
72. Application of Advanced Data Analytics to Improve Metal Loss Tolerance Specifications
Geoff Hurd¹, Keila Caridad², Scott Miller¹, Melissa Gurney¹, Samaneh Sadeghi¹, Aaron Schartner², Vincent Tse²
¹Baker Hughes, Calgary, Canada, ²TC Energy, Calgary, Canada
Abstract
In recent years there has been greater and greater desire to reduce pipeline maintenance costs through improvements to the effectiveness and efficiency of integrity management programs. Extracting as much information out of data obtained through each In-line Inspection (ILI) to better understand sizing tolerance performance and accuracy is an area of key interest as it has direct impact on repair decisions. Today, higher data volumes captured through multiple sensing techniques are being collected by ILI tools than ever before and the interpreted results are established as one of the most effective assessment techniques for managing pipeline safety.
In addition to this improved condition assessment data, validation programs are generating exponentially increasing volumes of now highly reliable and accurate truth data. This essential combination of high-quality inspection and validation data provides the opportunity to re-think how we establish performance specifications for the different ILI technologies. Traditional methods of utilizing relatively low volumes of isolated artificial defects that attempt to represent defects expected to be found can be replaced with vast ranges of actual real-world defects. Extensive “Big Data” libraries of high-resolution field measurements married to raw signal data captured by the tools provides new and exciting opportunities for innovative improvements that can be made to the detection, characterization and sizing of pipeline anomalies.
This paper will present a machine learned technique applied to vast quantities of dig and tool data to improve metal loss (corrosion) sizing tolerance performance. This method goes beyond the common industry practice to divide metal loss into a small number of categories based on arbitrary discrete defect length and width to include a much wider range of factors that truly affect Magnetic Flux Leakage (MFL) metal loss sizing to predict an individual defect-by-defect tolerance. This provides a more precise prediction of metal loss tolerances that reduces the general conservatism that has been built into existing tolerance specifications over the years while maintaining the necessary conservatism when needed to ensure pipeline safety. This paper will also present examples of the specific benefits operators may realize utilizing these newly predicted tolerance specifications.
71. Integrity Planning Utilizing In-Line Inspection Data
Brian Dew, Amin Eshraghi, Evelyn Rawlick
Acuren, Calgary, Canada
Abstract
Three in-line inspection (ILI) runs were done on a 10-inch Grade X52 sour gas pipeline which was constructed in 2009. There was suspected oxygen ingress early in the operating life of the pipeline and uninhibited methanol was regularly used in the pipeline. The ILIs were completed in 2010, 2015, and 2020. The first run identified 789 internal metal loss features with the deepest feature being 41% of wall thickness deep. The second run identified 1917 internal metal loss features with the deepest feature being 55% of wall thickness deep. The third run identified 3812 internal metal loss features and 494 cluster anomalies and reported the deepest metal loss feature to be 80% of wall thickness deep.
Probability of Exceedance (POE) analysis was utilized to assess the 2020 ILI data due to the significant degradation being found in the pipeline. The work presented in this paper utilized the ILI and subsequent integrity dig data to further support the POE analysis. Upon receipt of 2020 ILI data, the internal corrosion features were characterized, first, and the burst pressure for each feature was calculated. Based on the calculated burst pressure, it was recommended that the pipeline maximum operating pressure (MOP) be lowered from the original 9,930 kPa to 5,500 kPa to reduce the number of required immediate repairs. Next, a POE analysis was conducted using the calculated unmitigated corrosion rate and the recommended reduced MOP. Features which exceeded the specified POE threshold from Year 0 to Year 5 were identified and integrity digs for the identified joints were prioritized and recommended to the pipeline operator.
After completion of the integrity digs and direct inspection of the pipe, the 2020 ILI run was regraded, and the POE analysis was updated. Additional findings from the inspection associated with blisters and cracking were addressed and added into the integrity program along with the POE assessment.
This paper provides details of the ILI data analysis, corrosion rate calculation, and the methodology used to prioritize the integrity digs. In addition, the incorporation of integrity dig data into refining the future integrity program and updating the POE assessment is discussed.
70. Determining Active vs Passive Internal Corrosion using Data Science
Yevgeniy Petrov1, Megan Scudder1
1OneBridge Solutions, Boise, USA
Abstract
Integrity engineers struggle with determining active vs passive internal corrosion, specifically on legacy pipelines with a history of internal corrosion. ILI tools typically under-call internal metal loss anomalies and each ILI tool vendor has different pitting algorithms. This can create issues when attempting to compare run to run data. There may be a mix of over- and under-called anomalies throughout the entire population that when compared on a system level, can create a false narrative that the corrosion is not active or severe.
This research considers two methods that address this problem: specific identification of newly-replaced pipe and an analysis of the distribution of localized pit-to-pit anomaly growth values. Pipe sections that have been replaced between ILI runs essentially act as large coupons, providing valuable data about the active growth of internal corrosion. The second model uses a localized corrosion growth score based on the mean, standard deviation and skewness of the distribution of individual pit-to-pit anomaly growth measurements. Constituent anomalies for the growth distributions are accumulated in sections spanning roughly 500 feet, designed to be sensitive to local corrosion conditions. Using this approach, will reduce the influence of tool bias and provide operators with a ranking system based on a calculated growth score to understand where they have a high density of active internal corrosion and where severe internal corrosion is occurring.
69. Optimizing a Reassessment Plan with Probabilistic Monte Carlo Analysis: A Summary of Recent Developments to Better Support Operational Decision-Making
Michael Turnquist1, Ted Anderson2, Miguel Martinez1
1Quest Integrity, Boulder, CO, USA. 2TL Anderson Consulting, Cape Coral, FL, USA
Abstract
The economic conditions surrounding the oil and gas industry are in a permanent state of flux. Pipeline operators constantly need to evaluate different options for managing their assets to achieve the greatest potential commercial benefit without sacrificing safety and reliability. Seam weld integrity continues to be one of the most challenging threats for pipeline operators to manage. The continued improvement of crack-detection ILI technology provides operators with more options for reassessment, as it may be more prudent to deploy this technology for assets that have been previously managed with hydrotesting only.
The probabilistic analysis methodology discussed in this paper focuses on the management of crack-like features in the pipeline longitudinal seam weld. TL Anderson Consulting and Quest Integrity have developed an industry-leading probabilistic model to assess the seam weld integrity threat (this model has been presented at multiple past PPIM conferences and other industry events). This paper will present an overview of recent improvements to the model which will enable operators to identify an optimal reassessment plan. These recent improvements will provide pipeline operators with direct answers to the following questions:
The probabilistic analysis methodology presented in this paper will quantify the probability of failure over time associated with multiple future hydrotest and ILI scenarios. Specifically with regards to ILI, this analysis methodology will identify the expected number of required repairs following the inspection and the corresponding reinspection interval in order to maintain an acceptable level of reliability. This information is critical for pipeline operators to decide whether to move forward with ILI or hydrotesting as the primary strategy for reassessment.
68. Failure Analyses and Consequent Mitigation: Case Studies
Ming Gao, Ravi Krishnamurthy
Blade Energy Partners, Houston, USA
Abstract
It is well established that pipelines have the fewest fatalities of any of the various modes of transportation. Failures do occur, however, for a variety of reasons. In this paper, cases of failure due to SCC, weld defects and hydrogen-assisted cracking are analyzed with interdisciplinary approach that combines metallography/fractography, environmental chemistry, fracture mechanics and hydrostatic/ILI based assessment to identify root cause of the failures. Lessons learned from each of the cases analyzed serve as a basis for development of improved integrity management plan for prevention and will be presented in the paper.
For illustration, analysis of an onshore natural gas pipeline that failed recently in South America is shown here. Fractographic analysis with high-resolution matting fracture surface technique identified hydrogen assisted cracking is the mechanism for the failure while the source of hydrogen was driven by cathodic protection operated at near − 1200 mV CSE. Microstructural analysis showed no hard spots associated with the failure. API 579 FAD Level-3 tearing instability analysis confirmed that critical crack size was 90% deep x73 mm long that is consistent with macro-fractographic analysis based on chevron marks and the failure pressure. From the lesson learned, improvement of the distribution and control of the cathodic protection current is critical to avoid high generation of hydrogen at sites where the coating is broken or has faults
67. A Case Study of Crack Diagnosis in Natural Gas Liquid Pipelines
Nathan Leslie1, Andreina Guedez1, Sayan Pipatpan2
1NDT-Global, Houston, USA. 2NDT-Global, Stutensee, Germany
Abstract
Natural Gas Liquids (NGL) are a group of hydrocarbons that are a biproduct of natural gas processing and refining including ethane, propane, normal butane, isobutane, and pentanes plus also known as natural gasoline. As the infrastructure to aid in the exportation for NGL’s have grown so have the requirements to safeguard the assets that are used to transport these liquids by utilizing in-line inspection technologies.
This case study will focus on the deployment of an ultrasonic in-line inspection technology in an NGL Line as well as comparison of crack data analysis from the tool and NDE data from field verifications. The service was deployed for a north American customer to diagnose the potential for hook cracks in their 154 mile, 18” pipeline.
The main challenge that had to be overcome was configuring the service to properly diagnose potential cracks in the pipeline given that the medium for this inspection differed significantly from typical liquid inspection mediums regarding sound velocity and attenuation.
Results from data analysis from the ILI service showed accurate detection and identification of crack like features and were validated with NDE phased array UT measurements which characterized these complex crack geometries.
66. CVN or CTOD for Pipeline Fracture Mechanics? An Overview of Advantages and Disadvantages
Jonathan Brewer, Colton Sheets
Stress Engineering Services, Inc., Houston, USA
Abstract
The longitudinal seam weld fracture toughness of 36-inch OD x 0.406-inch WT, Gr. X52 pipe was evaluated using both Charpy V-notch (CVN) and Crack Tip Opening Displacement (CTOD) testing. Both testing results were converted to the fracture toughness parameter, K, using the methodology outlined in API 579-1/ASME FFS-1 Annex 9F. The correlations between fracture toughness and CVN data results in a large range of toughness values. However, the correlation between fracture toughness and CTOD data results in a single toughness value. This paper describes the fracture toughness calculations and how these results are implemented for pipeline fracture mechanics analyses. This is relevant to engineers and managers as it shows the technical differences between completing CVN vs. CTOD testing for pipeline integrity management assessments.
65. Automated Methods to Estimate Transition Temperature, Upper Shelf Energy, and Uncertainty from Charpy V-Notch Data
Nathan Switzner2, Michael Rosenfeld2, Peter Martin2, Peter Veloo3, Brian Patrick3, Lanya Ahmed1, Joel Anderson4
1American University of Iraq, Sulaimani, Sulaymaniyah, Iraq. 2RSI -Pipeline Solutions, New Albany, USA. 3Pacific Gas and Electric, San Ramon, USA. 4RSI -Pipeline Solutions, Oklahoma City, USA
Abstract
Pipeline feature toughness is a critical input for fitness for service assessments and MAOP reconfirmation based on the ECA approach. For these applications, toughness has historically been estimated from laboratory Charpy V-Notch (CVN) testing via the Upper Shelf Energy (USE) and 85% Shear Appearance (ductile to brittle) Transition Temperature (SATT). Two approaches are widely accepted for estimation of the USE and SATT from a set of CVN tests performed over a range of temperatures: (1) curve fitting a hyperbolic tangent to the experimental data, and (2) analytical solution of a system of empirical equations.
From a practical perspective, the unconstrained curve fitting method (1) is only accurate when the test data span a sufficient range of temperatures to sample both the lower and upper shelves and contain multiple points in the transition region. Additionally curve fitting is a manual, time-consuming procedure with poor repeatability.
Because of these challenges, pipeline operators often use the analytical solution method (2) that was originally proposed by Rosenfeld (Oil and Gas Journal, 1997) and later implemented in API-579 9F.2.2. However, this approach uses assumptions that can lead to over- or under-conservative estimates of toughness. Additionally, the uncertainty associated with the solution has not been quantified. As a result, both approaches often require the pipeline operator to accept unknown and potentially significant uncertainty in their toughness estimates.
This paper will provide a consistent and repeatable method to estimate the ductile to brittle transition temperature and upper shelf energy for CVN data that is applicable to any pipeline regardless of vintage. The method utilizes the hyperbolic tangent approach by applying several simplifying assumptions to effectively constrain the curve fitting to a physically meaningful range without compromising the accuracy of the solution. It will be shown that this approach increases the accuracy and reliability of the calculated values for incomplete datasets. We will identify the physical meaning of the assumptions and show how to estimate the uncertainty such that conservatism can be maintained for subsequent calculations compared to other methods.
64. Measuring Toughness with Instrumented Indentation Methods: Fact or Fiction?
Ted L Anderson
TL Anderson Consulting, Cape Coral, USA
Abstract
There is a strong desire among pipeline operators to quantify material properties with nondestructive in-ditch measurements. In addition to operators’ obvious motivation to maintain pipeline integrity and to avoid releases, PHMSA’s new Mega Rule for vintage gas lines imposes regulatory pressure to characterize pipe properties. Performing destructive material testing on cut-outs is an effective but very expensive option. Consequently, the prospect of nondestructive in-ditch material testing is extremely attractive.
A number of vendors offer in-ditch technology to infer yield and tensile strength. One such technology entails pressing a small spherical indenter into exposed steel on the OD of a pipe joint. This technique resembles a conventional hardness test, except that these modern indentation devices are instrumented to measure the force versus deflection response.
While instrumented indentation methods are certainly capable of measuring the strength properties of steel, some vendors have claimed that this technology can also measure material toughness. The present paper examines this claim in detail.
The author invokes basic metallurgical principles to argue that it is simply impossible for an indentation test to “measure” fracture toughness. The plastic flow properties of steel are weakly related to fracture properties. That is, two steels with identical strength properties can have very different toughness properties. The indentation test cannot distinguish between two such steels. This paper includes experimental benchmarks that demonstrate the lack of correlation between tensile properties and fracture toughness.
63. From One to Many – Composite Repair of SCC
David Futch1, Casey Whalen2, Sean Moran3
1ADV Integrity, Waller, USA, 2CSNRI, Houston, USA, 3Williams, Salt Lake City, USA
Abstract
Composite repairs have been traditionally utilized as a means to repair features identified on pipeline systems including corrosion and dents. Recently, several industry-based studies have been performed to investigate the repair of longitudinal cracks and crack-like features. These studies demonstrated the ability to reinforce crack and crack-like indications, however, were reinforced with overdesigned repair thicknesses and only repaired a singular approximately 3-inch-long crack. While this is conservative, additional layers increase cost and complexity of the repair.
This paper summarizes a two-phase program utilizing pipe containing field-identified colonies of stress corrosion cracking. Phase 1 of the testing program utilized nominal 30-inch OD x 0.325-inch WT, API 5L, Grade X52 pipe material and Phase 2 of the testing program utilized nominal 10-inch OD x 0.188-inch WT, API 5L, Grade X52 material.
Varying repair thicknesses were installed to further investigate the ability of a carbon fiber composite repair system to reinforce SCC indications of varying lengths and depths. Additionally, one sample during both testing phases was repaired while under pressure. To accomplish a comparison between samples, several criteria were compared: the ability to survive full-scale pressure cycling and subsequent burst test, a reduction in strain measured across repaired crack-like indications, and any subsequent growth identified after completion of the full-scale tests.
9. Damage Prevention 2.0 : Analysis of operational data from an automated ROW airborne visual inspection of seven pipelines: crude oil leak detection, 3rd party encroachment detection and advanced image documentation.
Eric Bergeron1, Alexandre Thibeault1, Ray Philipenko2
1Flyscan Systems Inc., Quebec, Canada. 2Enbridge Pipelines, Edmonton, Canada
Abstract
For years, pipeline operators have relied on human observers flying at low altitude to perform the mandated visual inspections of their right-of-way (ROW), often completed in single pilot-observer configuration, without any automatic documentation or detection system. This paper presents the first real-life results of a test campaign performed by Flyscan Systems over ROW’s of seven operators in seven US states and two Canadian provinces. Capabilities developed by Flyscan in collaboration with Enbridge include real-time hyperspectral leak detection and location and reporting of threats in the right-of-way. The paper will discuss the technology and system capabilities with details outlining detection of unauthorized 3rd party activity (machinery, abnormal construction activities), as well as generation of high definition 2D orthomosaics and 3D point cloud, vegetation analysis and digital surface ground mapping of the entire length of a 500-meter-wide ROW.
The paper will also review how new technologies can provide operators with a complementary tool that provides consistent, repeatable, and automated detection of high-priority threats to the integrity of pipelines. Statistics on detection performance will be presented, including unplanned threats and simulated (hidden) leaks. Real-life operational results will be covered including latency in detection, volume of data to be manipulated, cloud computing aspects as well as operational “up time” that can be expected. A development roadmap will be reviewed illustrating the path to fully automating all functions performed by human observers, including detection of ground movement, riverbank erosion, marker counting and localisation, exposure of pipelines after serious weather events, and automation of class location determination.
2. Evaluating the Suitability of the US Pipeline Network for Hydrogen service
Simon Slater1, Neil Gallon2, Ryan Sager3, Richard Ingolia3, Sebastiaan Schuite3
1ROSEN, Columbus, USA, 2ROSEN, Newcastle upon Tyne, UK, 3ROSEN, Houston, USA
Abstract
In response to the move towards net-zero carbon emissions, operators in the US are considering if and how existing natural gas pipelines can be converted to blended or 100% hydrogen service. Particularly given the cost of, and public opposition to, new pipelines.
This change will bring new challenges in terms of integrity management and at a minimum require a re-evaluation of the way the pipelines are operated. Building new pipelines specifically for hydrogen transportation can clearly mitigate the risk, but it may not be necessary. European operators are envisaging that ~60% of their European Hydrogen Backbone will consist of repurposed pipelines. When considering which pipelines are suitable for repurposing, the first reaction may be to dismiss the use of vintage pipelines, which are assumed to have inferior material properties compared with modern pipelines, and thus increased susceptibility to issues of embrittlement and accelerated fatigue crack growth, and hence higher risk. This may be unduly pessimistic, and we first need to consider the condition of existing lines.
A long history of pipeline inspection means that ROSEN has a significant database, which provides an indicative picture of both the material properties and condition of the US pipeline networks. In this paper some of the questions raised regarding the suitability of the pipeline network for hydrogen service in relation to existing knowledge and code guidance are explored. Specifically, we investigate the extent of existing features, such as crack-like features, dents, hard spots, and significant corrosion that could be a concern in hydrogen service under various scenarios of operating pressures and pressure cycling. In addition, we review the range of material properties and attributes present in the current natural gas transmission system, and how these compare with guidance in standards for hydrogen pipelines and developing industry knowledge.
Finally, we consider how pipeline condition and properties may influence integrity management in the presence of hydrogen. In some cases, converting these vintage lines to hydrogen may offer an opportunity to meet the existing guidelines for conversion and establish a safe operating envelope for hydrogen transportation, without the need for new-build. This paper will discuss the pro’s and con’s for the industry in terms of integrity management of converting existing pipelines to blended or 100% hydrogen service and a best practice approach for selecting candidate pipelines.
38. Variability and Mitigative Measures for Estimating Yield Strength in Line Pipe by Instrumented Indentation Testing
Peter Martin1, Jeffrey Kornuta2, Emily Brady2, Nathan Switzner1, Jonathan Gibbs3, Peter Veloo3
1RSI, New Albany, USA. 2Exponent, Houston, USA. 3Pacific gas and Electric, Walnut Creek, USA
Abstract
Natural gas pipeline operators in the United States are increasingly implementing materials verification programs (MVP) to validate the properties of pipelines that lack reliable records. These programs rely on nondestructive testing (NDT) methods, such as Instrumented Indentation Testing (IIT), to estimate the mechanical properties of pipeline steels in situ. The NDT approach is attractive because it does not require material to be cut from the pipe, as does traditional mechanical/tensile testing. However, IIT and other NDT methods infer the bulk mechanical properties from a relatively thin surface layer, and extrapolation to through-wall properties can introduce errors due to factors including material inhomogeneity and residual stresses from manufacturing. This work will consider the variability in the IIT yield strength from seven line pipes tested in multiple locations by two different vendors. It will be shown that while the measured IIT yield strength is often within ±10% of the tensile test result, some results can exceed this range. Furthermore, it will be shown that the yield strength estimated by IIT can vary by as much as 20% based on both the axial and circumferential location on the pipe. Sources of this variation, including the effects of sampling depth, will be discussed with consideration of residual stress, decarburization, and alloying variability. Recommendations will be made for best practices to identify and mitigate measurement uncertainty related to these effects.
48. Development of a Multi-Diameter and Low-pressure Compatible Tool to Inspect for Selective Seam Weld Corrosion
John Nonemaker1, Lance Wethey1, Colin Bradley2, Mustafa Jamaly2, Susanna Kaumeyer 2, Kirk Strachan2
1ROSEN, Houston, USA. 2Enbridge, Houston, USA
Abstract
Enbridge operates a low-pressure multi-diameter natural gas pipeline in the Northeast United States that is susceptible to selective seam weld corrosion (SSWC). The diameter ranges from NPS 24” to NPS 30” with 15 diameter changes over a length of 13.0 miles. SSWC is an environmentally assisted mechanism in which there is increased degree of metal loss in the longitudinal weld in comparison to the surrounding pipe body. Rosen’s RoCorr MFL-C Ultra technology was selected to obtain inspection data in a single in-line inspection for metal loss and long seam features. The multi-diameter and low-pressure operating characteristics of the pipeline presents in-line inspection challenges such as stuck tools, speed excursions and degraded data, particularly when the tool encounters bends and fittings. This paper presents a systematic approach for developing an appropriate in-line inspection tool from the perspective of a natural gas pipeline operator and in-line inspection technology provider, including a description of the in-line inspection execution considerations, in-line inspection tool design and testing process, tool features to mitigated degraded data and field validation results. This case study demonstrates that tool developments for low-pressure and multi-diameter pipelines should be considered as a long-term integrity management strategy.
46. Making hard decisions
Simon Slater1, Khanh Tran1, Jason Edwards1, Ann Reo2, Sean Moran2, David Futch3
1ROSEN, Columbus, USA. 2Williams, Tulsa, USA. 3ADV Integrity, Magnolia, USA
Abstract
The definition of a hard spot is introduced in the updated Gas Rule 49 CFR 192 Part 2 as “an area on steel pipe material with a minimum dimension greater than two inches (50.8 mm) in any direction and hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or Vickers 345 HV10)”. This update sets an expectation for operators to manage the threat through a combination of assessment, using ILI and in-ditch validation, and an appropriate response.
Over the past two years, Williams Transco has utilized in-line inspection technology capable of detecting, identifying and characterizing hard spots on several transmission pipeline systems. Various types of reported material hardness anomalies have been subsequently verified in a validation campaign, of which a number occurred on not only flash welded A.O. Smith pipes, but also vintage DSAW pipes from a wide range of manufacturers.
This paper will present the results of extensive non-destructive and destructive testing of validated material hardness anomalies, to establish a thorough understanding of the different types of hard spots that can exist, and discuss recommendations for assessing these anomalies and defining appropriate response options.
15. Preventing Product Releases into Coastal Waterways and Ship Channels
Joseph Lamberth
Quest Integrity, Stafford, USA
Abstract
Pipeline failures in today’s social, environmental, political, and global sustainability climate have a consequential impact on pipeline operators and owners. These consequences are exponentially higher when the hydrocarbon release takes place near, over or into coastal waterways, ship channels and oceans.
Even so, regulatory pressure and compliant stewardship lags the onshore transmission pipeline industry and related Integrity Management Programs (IMP’s). The financial impact and ramifications to shareholder value for spills over the past couple of decades have impacted the safety and health of neighboring communities and wildlife and ultimately cost operators billions in fines, legal costs, and the negative impacts to brand equity and sustainability goals. High consequence assets require direct measurements that cover the entire pipe surfaces to help ensure the fitness for service and flow assurance necessary to support their critical yet intermittent operation.
This presentation will highlight how a Northeastern Pipeline Company with wharf line operations is taking this threat seriously by using built-for-purpose ultrasonic inline inspection technology, seldom needing line modifications, to assess the integrity and fitness for service of their wharf line piping network. This approach enabled the company to optimize capacity by safely maximizing throughput while also minimizing risk to environment and business continuity.
The Operator had multiple pipelines spanning several diameters servicing a wharf used to transfer fuel from the dock to the tank farm. The goal for this project was to gain confidence in the continued safe and reliable operation of these pipelines by having 100% of the piping inspected to ensure all potential integrity threats were known, and if needed, appropriate action could be taken to mitigate any significant risks identified in the assessment. To accomplish this, the Operator utilized ultrasonic inline inspection technology to inspect the lines for both wall loss and deformation in a single pass.
Additional reasons to those above for selecting this technology included the need for a bi-directional tool capable of negotiating tight bends that posed the least risk for getting lodged during operations, while collecting direct, accurate measurements of anomalies across the entire pipeline. The end result was a successful execution on the first mobilization, preliminary and final reporting were delivered in an expeditious manner to help ensure safe continued operations.
By nature, inspection of dock side pipelines requires different planning and support than onshore pipelines. This paper will elaborate on such a process and how the efficiency and ease of a well-planned project can impact future operations by reducing risk, ensuring the safe and reliable service of critical energy infrastructure.
66. Fatigue Testing (Small and Full Scale) Validation of SCC Recoating
Ryan Milligan1, Ming Gao1, Ravi Krishnamurthy1, Richard Kania2, Elvis Sanjuan2
1Blade Energy Partners, Houston, USA. 2TC Energy, Calgary, Canada
Abstract
For gas pipelines it is important to identify SCC colonies that can be recoated without grinding and operate for another 50+ years. One of the key elements of this study was the small scale and full-scale fatigue testing of SCC colonies for validation. The focus of this paper is on the testing methodology and results.
The fatigue testing was conducted in the base metal, weld and HAZ. Small scale testing was first utilized to establish the baseline behavior along with J-R data. The full-scale testing was conducted in pre-existing SCC colonies in the base metal and utilized application of hydraulically pressurized water.
For the weld region, SCC cracks were not adjacent to the weld, consequently a crack was generated using an EDM notch. The crack growth in the full-scale ring-samples was generated using a servo-hydraulic machine. This required development of a specialized K solution using FEA.
The nature of the fatigue cracking was matched between small- and full-scale testing using SEM analysis of the fracture surface. Integrated analysis of the small scale, full scale and fractographic results validated more than 50 years of remaining fatigue life for recoated SCC cracks in gas pipelines.
53. Above and Below: A Holistic Geohazard Monitoring Solution
Daniel Bahrenburg1, Andy Young2, Jason Edwards1, Amin Singh1, John Norman3
1ROSEN, Houston, USA. 2ROSEN, Newcastle, United Kingdom. 3Teren, Lakewood, USA
Abstract
Geological and hydrological processes continuously reshape the surface of the Earth in ways that are not always predictable or easy to detect. Both cataclysmic and routine weather events are drivers of the geological and sedimentary change that ultimately result in pipeline geohazards. Operators need to consider these processes when constructing new pipelines or managing the integrity of existing assets.
Accounting for the influence of onshore or subsea land movement on structures is the primary goal of any effective geohazard management program. Traditionally, geotechnical monitoring programs are based on distributed point measurements in a defined area of ground movement. Active monitoring of ground movement and pipeline stress states is typically performed with discrete monitoring equipment, such as slope inclinometers or strain gauges. This can provide sufficient information for management of simple pipeline geometries located within basic geological environments and, most importantly, where hazards have already been identified. Frequently, hazards that result in pipeline failures are unmonitored or in areas that do not appear to be problematic, particularly where the surface expression is subtle and not identified by traditional surveillance methods.
To meet the demands placed on operators by advancing regulation and severe weather conditions, more frequent and comprehensive appraisals of pipeline right-of-way corridors will be required. For liquids transmission operators, this occurred in 2019 with 49 CFR 195.414. For gas transmission operators, this will become effective in May 2023 with 49 CFR 192.613.
This paper will demonstrate a holistic and integrated geohazard monitoring solution, which utilizes in-line inertial mapping and electromagnetic stress measurement to assess the condition of the pipeline alongside aerial laser topographical surveys (also known as light detection and ranging, or LiDAR) to evaluate the state of right-of-way at the surface. LiDAR provides invaluable insights into the characteristics of the land surface and whether there are features or anomalies that could represent land instability. Inertial mapping reveals the occurrence of discrete flexural loading and its proximity to performance limits. Additionally, recent case studies have shown the ability of new ILI technologies to accurately measure uniform longitudinal stress resulting from axial loading on pipelines. The integration of these three data collection techniques ultimately results in a high level of confidence when diagnosing and characterizing active geohazard threats.
This approach not only provides the ability to identify geohazards, but also assists with setting appropriate inspection intervals to track changes to pipeline integrity and hazard development. An additional advantage of these complementary technologies is that they provide a robust baseline for any geotechnical program and increased efficacy in the design of site surveys, the selection of monitoring points and guidance toward the most appropriate remediation solution.
40. Combining Nondestructive Techniques to Obtain Full Vintage Pipeline Asset Fracture Toughness at Both the Seam and Pipe Body
Intisar Rizwan i Haque, Bryan Feigel, Brendon Willey, Simon Bellemare, Parth Patel
MMT, Natick, USA
Abstract
For vintage transmission pipeline assets, material toughness data is often limited to laboratory testing of opportunistic pipe cutouts because, even if original Material Test Records (MTR) are available, the manufacturing specifications for the line pipe did not have fracture toughness requirements until they were added in the 1980s. Given the need to obtain Traceable, Verifiable, and Complete (TVC) material data in certain assessments and re-confirmation, nondestructive evaluations (NDE) are an attractive alternative to pipe cutouts if these solutions can be validated and accepted. Past attempts to validate indentation and frictional sliding techniques for the pipe body toughness have proved challenging. This paper summarizes recent progress in developing and validating two recent techniques based on frictional sliding. The first technique uses the Hardness, Strength, and Ductility (HSD) testing process which operates on the principle of frictional sliding over longitudinally welded seams, allowing, by a combination of surface field test and a database, to produce predictions for the Charpy V Notch (CVN) properties. A prediction of the CVN shear transition for these seams is currently validated and used for pilot projects. The second technique is a new concept that evolved from Nondestructive Toughness Testing (NDTT) using a wedge stylus to Blade Toughness Meter (BTM) which uses a significantly sharper stylus to mimic more closely the conditions at the tip of a crack. In a lab prototype phase, the BTM tester is intended to be adapted for pipe body testing as early validation studies show a stronger correlation with the laboratory toughness results in comparison to NDTT. This paper presents the recent progress and the validation status of both techniques as well as their benefit through initial case studies.
23. Innovative Pipeline Evacuation Technology for Reducing Methane Releases to the Environment During Pipeline Maintenance and Pigging Operations
Rita Hansen, Jeff Witwer, Mitch Jacobs
Onboard Dynamics, Bend, USA
Abstract
Pipeline operators are showing a growing interest in adapting new technology solutions and operating practices to reduce methane releases during pipeline operations and maintenance. This increasing attention is focused on methane capture and recovery during routine pigging operations. The number of pigging operations, and the fact that they are usually conducted on a predictable schedule, suggests that this source of methane release should be a prime target for operators seeking to improve their environmental profile.
This paper will provide an overview of technologies and operating practices that can be implemented to reduce methane releases during pigging, highlighting technology features that are most important in determining project success. The important product features that will be discussed include gas capture time, system set up time, and consideration of equipment physical size and how these factors all impact gas capture time and cost.
We have developed and will present a calculator that can be used to estimate the reduction in methane released for every launch and receive operation based on pipeline size and pressure.
22. ILI Tool Speed Control Using Gas Recompression –– Better Data / No Venting or Flaring
Adam Murray, Branden Allen
WeldFit Corporation, Houston, USA
Abstract
The purpose of in-line inspection (ILI) is to provide reliable information about pipeline integrity so operators can prioritize maintenance and repair. Typically, ILI tools are propelled through pipelines mechanically. Either they flow at the same rate as product or are moved by differential pressure, which occurs when the operator releases downstream pressure through flaring or venting.
However, both methods are limited in their ability to reliably control the speed of the ILI tool as it travels through the pipeline. Lack of speed control, that is, failing to keep the inspection tool moving at a reduced and constant speed, makes it more difficult for the tool’s sensitive sensors to pick up critical anomalies, affecting data quality. If the tool moves too quickly, it can miss defects or damage, producing inaccurate or incomplete readings. When the tool travels too slowly, it can exaggerate findings, creating a false impression of the pipeline’s wall condition. In addition, varied tool speeds make it more difficult for data analyzers to piece together information about the pipeline.
Unreliable ILI data can lead to expensive and time-consuming tool reruns or unnecessary digs. To improve data results, many ILI tool manufacturers incorporate speed control into their devices. However, this limits the vendor options for operators.
After lack of speed control during five consecutive ILI tool runs led to insufficient data each time, the nation’s largest interstate natural gas operator turned to a novel, engineered solution to controls gas flow and ILI tool speed: recompression technology.
Recompression technology is typically used to reduce methane emissions during pipeline isolation. In this case, equipment with straight-line capabilities, meaning it moves gas at a constant rate, created a constant pressure differential across the ILI tool. That enabled the tool to travel at consistent speed throughout the pipeline.
Using recompression technology, the operator collected accurate data in a single run. They also avoided flaring product, helping them achieve their environmental, social, and governance (ESG) goals.
This white paper will discuss problems related to ILI tool speed control and describe how recompression technology was used to improve ILI data collection while also eliminating nearly 100% of methane emissions.
45. Knowing the Long Seam: Essential Insights Using UHR MFL Technology
Miguel Galeana, Rick Desaulniers
Entegra, Indianapolis, USA
Abstract
Metal loss that aligns with a pipe’s long seam poses an imminent integrity threat as well as a threat to an operator’s bottom line. But the impact and potential costs of false calls – both negative and positive – can be mitigated with an integrated ILI system that combines Ultra-High Resolution MFL technology with the insight and assessment of human-experience based data analysis. In this paper, we’ll explore how the ever-growing capabilities of MFL – and the ability to extract nuanced data from it – can improve both outcomes and efficiency.
From coincidental metal loss to preferential metal loss, trim and other manufacturing anomalies, we will investigate state-of-the-art MFL technologies, including their ability to detect ERW and flash-welded pipe and size axially-oriented anomalies. Then we will show how the latest in UHR and its facilitation of DA makes all the difference when assessing pipeline integrity.
10. A Probabilistic Method to Predict Nominal Wall Thickness
Owen Oneal1, Masoud Moghtaderi-Zadeh1, Peter Veloo1, Colin Bullard1, Cameron Fisch1, Michael Fernandez2
1Pacific Gas & Electric, Oakland, USA. 2Kiefner & Associates, Inc., Sugarland, USA
Abstract
Under the PHMSA 2019 Gas Transmission Rule, Operators must opportunistically verify material properties, such as nominal wall thickness (NWT), for pipeline features lacking traceable, verifiable, and complete (TVC) records. Non-destructive examination (NDE) such as ultrasonic testing (UT) might be performed on one or more locations to measure the wall thickness. The number of measurements collected can vary by several orders of magnitude depending on the technique used, ranging from manual 12-point UT measurements to automated UT measurements which can scan the entire pipe surface generating tens of thousands of measurements. Prior to the PHMSA 2019 Gas Transmission Rule, Operators had to assess NWT following §192.109, which by design resulted in conservative outcomes. Because NWT has a first order impact on design pressure, excessive conservatism risks reducing operating capacity. This can have serious financial and operational consequences including pressure reductions and disruptions to normal operations. Operators could benefit from developing their own procedures for verifying unknown NWT using NDE under §192.607; however, they must demonstrate that the new procedures meet the special requirements for nondestructive methods and provide an equivalent or better level of safety to §192.109.
The Pacific Gas and Electric Company (PG&E) has developed a methodology, known as the Confidence Interval Method (CIM), to assess unknown NWT intended to satisfy the requirements of §192.607 by demonstrating a conservative accounting for measurement inaccuracy and uncertainty. PG&E collaborated with Kiefner and Associates, Inc. to implement CIM in a software tool. CIM uses statistics and probability theory to combine in situ wall thickness measurements, industry standards for NWT dimensions, and manufacturing tolerances encapsulated in historical editions of American Petroleum Institute Specification 5L Line Pipe. A comparison between CIM and §192.109 was performed using a validation dataset consisting of in-situ wall thickness measurements taken on pipes with TVC NWT of record. It was observed that CIM more accurately predicted the TVC NWT of record compared with §192.109. CIM addresses the uncertainty in measurement data, and when necessary, makes conservative assumptions with 95% confidence levels. The paper will also discuss how the number of measurements influences the NWT assessment by comparing results where 12-point UT and automated UT were both performed and make recommendations on the minimum number of measurements that should be collected.
29. Beyond Standard ILI Analysis – Meaningful Interaction to Look Out for Specific Threat
Dennis Vogel1, Gurwinder Nagra2, Matthew Ma2, Garrett Meijer2
1Baker Hughes, Stutensee, Germany. 2Enbridge, Edmonton, Canada
Abstract
Within the framework of the requirements defined by API 1163, close cooperation between the operator and ILI service provider is required to manage pipeline integrity. Nevertheless, many factors could contribute towards the lack of cooperation – discussion of requirements and challenges, lessons learnt, and sharing of NDE results. There is growing evidence of a willingness to share NDE results; however, this paradigm shift is not just because operators understand that the vendor always has full visibility of ILI data to support performance validation. Rather, there is also the realization that improvement processes can be stimulated in general. Furthermore, through meaningful interaction, a holistic inspection project can be achieved on a pipeline-specific basis. A case study will show how a specific pipeline threat was addressed by considering historical records beyond the standard analysis of an inspection project by utilizing additional ILI data sets (integrated analysis). This would not have been possible without close cooperation from the start of the inspection project.
24. Keeping Pigging Safely Grounded as Hydrogen Takes-Off
Neil McKnight, Mike Kirkwood
T.D. Williamson, Newcastle, UK
Abstract
16. OPEX Optimization for Unpiggable Vent Line/Low Flow Pipeline via Self-Propelling Robotic ILI Tool
Mohamed Ali Abdullah¹
¹PETRONAS, Kuala Lumpur, Malaysia
Abstract
OBJECTIVE/SCOPE
This paper is to share the development of Self-Propelling Robotic In-Line Inspection technology that PETRONAS embark as OPEX optimization for un-piggable pipeline. Lack of conventional inspection methods to inspect un-piggable pipelines such as vent pipelines without pig traps facility and low flow pipelines, has prompted PETRONAS to embark on technology development journey for Self-Propelling Robotic ILI.
METHODS/PROCEDURES
The development of the Self-Propelling Robotic In-Line technology consists enhancement of robotic tethered crawler tool to a wireless robotic tool, testing and validation using actual full scale fabrication test loop. Fabricated test loop includes horizontal and vertical section with bends of 1.5D to simulate the inspection tool travel as per actual site condition representing vent line.
The enhancement consists of wireless connection range, optimum speed and distance, movement of slippery surface which grease was applied on the vertical section and emergency extraction of inspection robot.
RESULTS/OBERVATIONS/CONCLUSIONS
Robotic ILI qualification test which was successfully met PETRONAS requirement based on full scale factory acceptance test. The test was focused and able to meet below success criteria: –
1. Robotic ILI tool able to self-propel on vertical test spool.
2. Robotic ILI tool able to move with wireless connection for the intended travel length.
3. Emergency retrieval tool procedure and mechanism in the event of faulty robotic ILI or loss of connection.
4. Sensor detection capability at POD 90% and POI 80%.
Based on the evaluated technology, Robotic ILI solution is feasible in ascertaining the un-piggable pipeline integrity and recommended solution to tackle high operational costs that upstream operators face when inspecting their pipelines using current available methods. Deployment of this technology is estimated to provide up to 30% OPEX optimization.
The technology has been evaluated to be technically ready and pilot tested PETRONAS asset which will be shared in our detail paper covering below areas:
1. Robotic ILI tool able to travel successfully total length of pipeline.
2. Detection capability at POD 90% and POI 80% for anomalies covering metal loss and girth weld anomales.
NOVEL/ADDITIVE INFORMATION
Current approach to inspect un-piggable vent or low flow pipeline is Crawler ILI type technology which propelled by umbilical cable whereby the pipeline requires to be in shutdown mode. While, inspection using Self-Propelling Robotic ILI can be applied for un-piggable pipeline i.e. low flow pipeline and vent line with short duration or no requirement of shutdown.
63. Leveraging ILI Crack Profiles
Lyndon Lamborn1, Stephan Tappert2
1Enbridge Liquids Pipelines, Edmonton, Canada. 2Baker Hughes, Stutensee, Germany
Abstract
As an ultrasonic crack in-line inspection tool probes a crack, the depth at each ‘ping’ return can be estimated from the amplitude vs depth algorithm. The result is a crack ‘profile’. Leveraging this profile as part of integrity decision-making is not a new notion, and represents a natural progression from legacy rectangular, to (current) semi-elliptical, and finally to equivalent fracture ellipse based on the profile. With technological advancements in the past decade on both the ILI and in-the-ditch crack assessment sides, sufficient data quality and quantity exist to judge whether consideration of crack UTCD ILI profiles is appropriate for integrity decision-making.
17. 192 Final Rule (RIN2) – Essential Elements and Guidelines to Perform a Dent Engineering Critical Assessment
Shanshan Wu1, Joe Bratton1, David Kemp2, Jing Wang3
1DNV, DUBLIN, USA. 2DNV, Dublin, USA. 3TC Energy, Calgary, Canada
Abstract
The Pipeline and Hazardous Materials Safety Administration (PHMSA) issued RIN2 of the Final Rule (frequently referred to as the “Mega Rule”) on August 4, 2022, which will impact the pipeline industry’s approach for the assessment of dents and other mechanical damages. The Mega Rule prescribes detailed requirements in the Code of Federal Regulations (CFR) Title 49 Part §192.712(c) for how to perform a dent engineering critical assessment (ECA).
This paper is purposing to share the understanding of the requirements from the Mega Rule when performing a dent ECA by a detailed example. The example includes the identification of other potential threats in the vicinity of a dent, dent profile comparison, dent strain assessment using the Ductile Failure Damage Indicator (DFDI) and Strain Limit Damage (SLD) methodologies, and dent fatigue assessment.
To fathom the new Mega Rule for gas operators and achieve the best compliance, guidance regarding best practices in performing a dent ECA will be provided hereby through a detailed work example. Limitations of utilizing the methodologies prescribed in Part §192.712 (c) will be discussed in conjunction with the guidance for awareness.
35. Optimizing Risk Decisions with Imperfect Data
Joel Anderson
RSI Pipeline Solutions, Oklahoma City, USA
Abstract
In any integrity management program, there are always competing alternatives for any decision. Such as dig or not to dig, replace or not to replace. If perfect information were always available, like a math problem where everything except the answer is given, risk engineers would be an unnecessary expense. The next best alternative would be an exhaustive corpus of data with frequencies of every outcome and condition combination. However, in all but the most trivial cases, these don’t exist either and the engineer is dealt partial, imperfect information where the true state of nature is uncertain. To deal with this uncertainty in everyday life people develop heuristics, mental shortcuts that allow us to process this information with the least amount of effort and time. But when the probabilities are imprecise and the data imperfect, decisions based on these shortcuts can be fraught with biases and fallacies. All decisions carry some risk that is dependent on the (uncertain) true state of nature, and the potential loss associated with a given course of action.
This paper will discuss the fundamentals of decision theory and demonstrate an innovative application of them that incorporates existing knowledge and potential consequences. This will be used to quantify the tradeoffs of competing alternatives in an pipeline integrity management program to arrive at a decision that minimizes the risk based on the state of knowledge that is available.
36. Estimating Excavation Damage (Outside Force) ‘Hit Rates’ Using Machine Learning Models Trained on In-Line Inspection Data and Geographical Information
James White, Steven Carrell, Amine Ait Si Ali, Jonny Martin, Roland Palmer-Jones
ROSEN Group, Newcastle upon Tyne, United Kingdom
Abstract
External interference damage is one of the main causes of pipeline failure reported in publicly available industry statistics, from agencies such as the United States Pipeline and Hazardous Materials Safety Administration (PHMSA). Thus, failures due to external interference are often the most significant contributors to pipeline probability of failure in risk assessments and can play a significant role in operator decisions regarding risk-control measures, for example when it comes to the installation of additional impact protection, pipeline diversion or pressure restrictions.
The probability of failure due to external interference damage can be estimated by combining the probability that damage occurs (i.e. that the pipeline is hit), the probability that the impact is sufficient to cause instant failure and the probability of degradation to failure, given that damage has occurred. Degradation to failure is assessed using industry standard engineering models (such as the limit state functions given in Annex O of CSA Z662-19). However, the key challenge is predicting where, when, and with what energy the external interference damage may happen.
The prediction of a “hit-rate,” or impact frequency, is often subjective or based on statistics which may not be applicable to the pipeline under assessment. Top-of-line (ToL) deformation damage (dents) reported by in-line inspection (ILI) are a clear indicator of past external interference, which could have been caused by third parties, contractors or the operator themselves. In a recent in-house research study ILI data and pipeline parameters from ROSEN’s Integrity Data Warehouse (IDW) – which at the time of writing contains results from over 20,000 inspections – has been combined with geographical information on population density, land use, crossings and socioeconomics, and used to train machine learning models to estimate the frequency of external interference damage (per mile-year), or ‘hit-rate’ for pipelines where the route is known but reliable statistics for ‘hit-rate’ are not available.
This paper presents the results of the study describing the extensive dataset used from a selection of pipelines in the USA, the development of the models and how they were trained and tested, and finally showing the model performance, discussing the capabilities and limitations, and implications for risk assessment studies.
37. Gas Transmission Valve Closure and Emergency Response Considerations
Keith Leewis
L&A Inc, Calgary, Canada
Abstract
This paper provides a summary of transient flow predictions from an ignited gas rupture site when closing both valves in a valve section at increasing timing intervals. The closure response time from detection of a line break to valve closure has less effect on emergency responder search and rescue initiation inside the PIR than the public may expect. The effect of various mitigations to shorten the interval will be discussed.
39. Identifying Irregular and Erroneous Chemical Composition Data from In Situ Nondestructive Testing
Janille Maragh1, Peter Martin2, Joel Anderson2 Jonathan Gibbs3, Peter Veloo3, Jeffrey Kornuta4
1Exponent, Inc., Menlo Park, CA, USA. 2RSI Pipeline Solutions LLC, New Albany, OH, USA. 3Pacific Gas and Electric Company, San Ramon, CA, USA. 4Exponent, Inc., Houston, TX, USA
Abstract
Nondestructive testing (NDT) of chemical composition is a critical component of the Pacific Gas and Electric Company’s (PG&E) materials verification program. Additionally, 49 CFR § 192.607 states that the operator must “conservatively account for measurement inaccuracy and uncertainty using reliable engineering tests and analyses.” Accurate and precise NDT composition data can be used to determine or verify certain characteristics of a pipe, for example vintage, grade, or manufacturing process. However, it has been observed that composition measurements may at times be inconsistent across various field analytical tools, possibly due to the variability of experimental, environmental, and other statistical (random) factors. Irregular or erroneous field NDT measurements are problematic because they could lead to the mischaracterization of pipe features during the materials verification process.
In this paper, we present a systematic procedure rooted in data science for the analysis of field NDT chemical composition data. First, NDT composition data for a set of pipe features are collected using field analytical techniques, such as optical emission spectroscopy (OES), laser induced breakdown spectroscopy (LIBS), X-ray fluorescence (XRF), and laboratory analysis of filings by atomic absorption (AA) and combustion. Next, the data are statistically analyzed using only the measurements in the incoming dataset and, when possible, are compared to measurements obtained for the same pipe features using other NDT composition analysis techniques. Following this analysis, the data are compared to historical composition data previously obtained for features with similar attributes—such as outer diameter (OD), seam type, and nominal wall thickness (NWT)—to identify potentially erroneous measurements. Finally, we present case studies illustrating the application of the proposed process to data obtained for pipe features at PG&E with abnormally high manganese measurements, and we demonstrate how the identification of the elevated manganese values as anomalous mitigated potential downstream challenges during the materials verification process.
41. ILI Validation Case Study: Evaluating the impact of a weld cap on a vintage ERW pipeline inspected with an ultrasonic crack detection tool
Ian Smith1, Ted Anderson2
1IDSmith Pipeline Engineering, LONDON, Canada. 2TL Anderson Consulting, Cape Coral, USA
Abstract
An ultrasonic crack detection ILI was run as part of a liquid pipeline’s integrity management program. ILI validation, using API 1163, was performed to determine the effectiveness of the ILI in detecting, identifying and sizing cracks. This case study will discuss the results of the ILI validation with specific focus on the impact of the ILI measurement errors upon the severity assessment of the cracks and different options that were used to account for the errors and maintain desired levels of conservatism.
The most common linear anomaly type in this ERW pipeline was crack like lack of fusion flaws. The pipeline had undertrimmed welds with remaining weld caps and the ILI only specified measurement in the ‘base material’ and would not reliably detect reflectors located in the weld cap. The ILI did not meet its specifications for detection, depth or length accuracy with a tendency to undersize both depth and length. The impact of the weld caps were identified as the primary cause for the errors.
The impact of under prediction of both depth and length on the burst pressure assessment was evaluated. To evaluate the impact of the field found anomalies upon the integrity of the pipeline a FEA assessment was performed using the phased array field verification results upon the most severe anomaly not identified by the ILI to account for excess conservatism in longer cracks with a complex profile. Integrity decision making was made using the context provided by the evaluations of the impact to severity assessments and not solely upon measurement accuracies.
Keywords: ILI Validation, Engineering Assessment, Integrity Management
42. Tool Performance Estimation Considering the Effect of Fixed vs Variable Slope
Thomas Dessein, Alex Fraser, Juan Rojas, Jason Skow
Integral Engineering, Edmonton, Canada
Abstract
The performance of in-line inspection (ILI) measurements is one of the primary sources of uncertainty for corrosion and crack assessments. Operators typically perform validation digs to determine how well the ILI performed at sizing features. The API Standard 1163, “In-line Inspection Systems Qualification”, defines three levels of analysis that operators use to validate the ILI sizing accuracy. The first level relies on previous experience with the ILI system and adherence to operating procedures, the second level uses validation dig data to determine if the vendor specification can be used, and the third level uses advanced statistical methods to estimate performance from validation dig data.
The recently published third edition of API 1163 provides two example methodologies to perform a level 3 analysis. Both methods make simplifying assumptions to reduce the complexity of the problem, but one of the key differences between them is that the first method assumes the slope of the best-fit line on a unity plot is fixed at 1.0. In this paper, the effect of fixing the slope at 1 to estimate tool performance is investigated and compared against a method where slope is allowed to be variable. Several realistic datasets are evaluated using both methods and the results are compared. The effect on burst pressure for representative corrosion features is also investigated for both methods.
43. Tolerance of ILI Validation Inspections, Why Is It Important, and How to Reduce It.
1, Spencer Fowler2, Daniel Torres3
1ROSEN, Newcastle, United Kingdom. 2ROSEN, houston, USA. 3ROSEN, Houston, USA
Abstract
ILI tools are supplied with a strictly controlled and validated tolerance to apply to integrity calculations in order to make safe engineering decisions. It is a requirement under API 1163 to validate the performance of the ILI tool in the ditch following an ILI campaign with field verification technicians using a range of technologies and procedures. What is the tolerance of the technique being used? And since they are manually applied and dependent on the operator, what is the tolerance associated with the technician?
In contrast to what is commonly assumed, field verifications are not absolute and there can be a significant variation between operators, technologies, and sizing techniques. It is a costly and sometimes complex operation to understand the performance of field verification technicians using a range of technologies, but an important aspect in ensuring compliance and safe operation of pipelines.
This paper discusses the attempts at understanding a universal tolerance by international codes and standards which can be used in conjunction with API 1163, and how these values can be utilized in a validation exercise of ILI tool performance. If these universal values are not suitable then we will discuss how these tolerances can be reduced and measured. We will look at a practical example of this application for inspection of thin walled ERW inspection and the implications of understanding the tolerance of the inspector on the validation process and ultimately the safety of the pipeline network.
44. A novel concept addressing material properties and loading conditions with a dynamic micro-magnetic sensor
Sebastian Huehn, Dietbert Wortelen, Werner Thale, Christian Otte
ROSEN Technology and Research Center GmbH, Lingen, Germany
Abstract
In 2013/14, an eddy current sensor in a magnetic field for material properties was introduced; together with a population approach that addresses the requirements stated in current U.S. regulations, it determines pipe grade. A novel sensor technology has been developed now, called DMPL (Dynamic Material Properties Loading), which addresses a broader range of material properties, including toughness and, additionally, the axial and circumferential stress condition of a pipeline.
The patent pending technology is a high-resolution non-harmonic micro-magnetic sensor. Essentially, micro-magnetic sensors consist of a magnet yoke, an excitation and a receiving coil to generate and record a hysteresis curve. When testing a component, the generated hysteresis curve contains information about the mechanical properties and the loading conditions of this component. Conventional micro-magnetic sensor applications are mainly used as handheld devices for static local measurements and play a reliable role in quality control of steel plates during manufacturing. To cope with such challenging conditions during in-line inspections as high tool velocities, low power consumption and sensor liftoff, the sensor technology was upgraded and adapted. Using an extensive material database for machine learning is the key factor in this multitalented concept.
This paper provides an introduction of the technology and its suitability in the areas of axial stress condition and material properties demonstrated by laboratory measurements, full-scale tests and first operational experiences. Based on these tests, which comprise a large set of test samples, a first assessment of sizing capabilities is given, and further aspects such as measuring resolution are discussed.
KEYWORD(S) FOR SUBJECT AREA
ILI applications
Stress
Strain
Loading conditions
Strength
Toughness
47. Validating Selective Seam Weld Corrosion Classification Using ILI Technology
Matthew Romney, Dane Burden, Ron Lundstrom
T.D. Williamson, Salt Lake City, USA
Abstract
Selective seam weld corrosion (SSWC) occurs when a susceptible long seam, such as low-frequency electric resistance welding (LF-ERW) manufactured prior to 1970, is subjected to an active corrosion environment. When this occurs, the seam weld corrodes more aggressively than the pipe body, resulting in a deep V-shaped groove aligned with the seam axis. An SSWC anomaly poses a greater threat to pipeline integrity, when compared to a similar volume of general corrosion crossing the long seam (CCLS), due to the aggressive corrosion depth growth rate and orientation to the primary stress.
The pipeline industry has struggled to consistently distinguish between SSWC and CCLS anomalies. In an effort to overcome this gap, T.D. Williamson (TDW) participated in a DOT project that resulted in the development of a SSWC classifier. The classifier leverages the data collected by the Multiple Dataset (MDS) platform. MDS incorporates 5 primary technologies (high-field axial magnetic flux leakage, high-field spiral/helical magnetic flux leakage, low-field axial magnetic flux leakage, high resolution geometry, high resolution mapping), overcoming gaps in each individual technology, providing a comprehensive integrity assessment. The classifier has since been used with various operators to characterize long seam corrosion anomalies.
In 2022, TDW published an industry first specification that characterized the performance of the SSWC classifier. The paper will discuss the statistical backing of the published specification, demonstrating the field data basis and validation. Examples of SSWC and non-SSWC feature classifications will be discussed.
Keywords: In-line Inspection, Corrosion, Corrosion Crossing the Long Seam, Data Science, Multiple Dataset, Magnetic Flux Leakage, Geometry, Deformation, Interacting Features, Precision & Recall, Selective Seam Weld Corrosion, CCLS, DEF, GEO, ILI, MDS, MFL, SMFL, SSWC
49. ILI Ultrasonic Shear Wave and Compression Wave Inspections Capabilities for Selective Seam Corrosion (SSC)
Rogelio Guajardo1, Debbie Wong2, Anna Rodriguez1, Diego Luna3
1NDT Global, Barcelona, Spain. 2NDT Global, Calgary, Canada. 3NDT Global, Mexico City, Mexico
Abstract
Selective seam corrosion (SSC) can be considered as a complex feature from the Ultrasonic (UT) ILI perspective. The main reason is that it is a metal loss (corrosion) which would infer that a compression wave inspection is the best technology to address it. However, because of its geometry and dimensions it does provides reflections similar to cracks, so the shear wave technology would be optimal to detect narrow corrosions.
These features being at/in the long seam can be a threat to the pipeline and need to be known to the pipeline operator so that the required actions and measurements are taken to ensure the safety of the asset.
This raises the questions: 1- Which UT technology should be used to detect these features? and 2- What are the capabilities of the UT compression wave and shear wave ILI tools in regard to selective seam corrosion (SSC)?
This paper will present the results from a systematic approach where simulations, pull tests, and NDE correlations from ILI runs were performed. As conclusions it will provide the reader a guide on:
50. One Step Ahead: the Italian Experience on Coping with Illegal Tapping
Marco Marino1
1SolAres Srl, Milan, Italy
Abstract
As widely known and reported by prestigious publications such as CONCAWE reports, the phenomenon of Illegal Tapping in Europe was – and still is, with a much lesser impact – the main cause of concern for pipeline operators, especially in the years from 2015 to 2020.
This presentation aims at providing an insight on a specific country, Italy, which experienced a very high impact over illegal tapping phenomena.
The problem today is considered, if not entirely solved, at least controlled and contained, by looking at today’s numbers related to illegal tapping events. Nevertheless, achieving this result required a process which took several years and the development of an innovative technology, which, coupled with a bold innovation plan on several organizational aspects, led to the success case shown in the presentation.
Looking back to the past, important takeaways can be grasped, most importantly the basic fact that technology alone cannot solve this problem: the reduction of illegal tapping activities/spillages was achieved by developing a multi-disciplinary approach based on technology, engineering, operations, and security.
All the premises above are coupled with the fact that illegal tapping entails the active participation of a malevolent third party, acting and evolving to overcome any implemented strategy and technology.
The past experience can – and currently is – applicable to other scenarios in other parts of the world where the phenomenon is still active or even worse, is entirely at its beginning and finds fertile soil for growth, given the current instable international situation.
51. Challenges Facing Illegal Tapping: Pipeline Protection in Brazil
Fabio Evangelho
Petrobras Transporte S.A., Rio de Janeiro, Brazil
Abstract
Illegal tapping is a global phenomenon. Sharing experiences is the key to understanding how to face and prevent this crime. In a positive way, we believe we have created in Brazil the term “Pipeline Protection” as a concept that gathers all diverse initiatives we have been exchanging with some pipeline operating companies from other countries.
We have used a multidisciplinary approach that involves: innovative control room procedures, legal issues, new technologies search, the subtle art of communication with local communities and public security forces.
It is an industry-wide, international endeavor to demonstrate that illegal tapping is not only a concern for operators, but for society as a whole.
52. Use of ILI data to identify illegal tapping
Milton Carvajalino1
1CENIT, Bogotá, Colombia
Abstract
This presentation will explain development of a methodology to analyze and correlate information from successive, separate MFL ILI inspections to identify illicit valves (taps) in hydrocarbon transportation pipeline systems; generation of recognition patterns for dimensions and configuration of illicit valves; density prediction of areas with greater vulnerability to this threat; consideration of socio-geographic factors along the rights of way.
Deliverables from the project included:
54. How should we respond to geohazards?
Rhett Dotson1, Alex McKenzie-Johnson2
1D2 Integrity, LLC, Houston, USA. 2Geosyntec Consultants, Inc., The Woodlands, USA
Abstract
The threat from geohazards has received increased awareness from operators and increased scrutiny from regulators over the last decade. Most recently the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued an advisory bulletin to highlight the importance for integrity management related to the potential for damage to pipeline facilities caused by earth movement and other geological hazards. The elevated attention from operators has resulted in an increased interest in and use of both bending strain and in-situ site assessments for the identification and assessment of geohazards. However, after properly identifying and assessing a site, many operators experience challenges in determining an appropriate integrity response. Historical integrity practices based on corrosion or crack management have relied upon excavation as a first step in remediation with follow-up responses based on in the ditch findings. Unfortunately, this process is typically not a best practice for geohazards. The excavations are often significantly larger, the site conditions may be less stable, and typical remediations such as sleeves or composites are not practical. This paper will serve as a guideline for helping operators responding to a geohazard threat by providing guidance on data collection, mitigation, and future monitoring.
55. Management of Geohazard Personnel Safety for Working in Challenging Terrain
Emily Ortis1, Tim Waggott2, Evan Shih3, Dave Gauthier3, Chad Fournier2
1Pacific Northern Gas, Vancouver, Canada. 2Pacific Northern Gas, Terrace, Canada. 3BGC ENGINEERING INC., Vancouver, Canada
Abstract
Pacific Northern Gas Ltd. (PNG) owns and operates sweet dry natural gas systems with service extending from Prince Rupert on the British Columbia West Coast to the northeast of the province in the towns of Fort St. John, Dawson Creek, and Tumbler Ridge. PNG’s transmission system operates at high pressures and traverses through one of the most rugged and challenging terrains in North America, with unique weather and geohazard challenges.
There has been an increased focus on the integrity and maintenance of PNG’s assets to ensure a safe and reliable energy supply to the communities. This has led to a considerable increase in the scale and size of PNG’s in-line inspection (ILI) program and, consequently, the associated field activities (e.g., ILI runs, pig barrel modifications, integrity digs, regular maintenance and system betterment projects, etc.) on the pipeline system. This requires field operations in proximity to geohazards and potentially unstable terrain, posing a significant personnel safety risk to the field crews. This presented an opportunity for the development of a management tool to support planning and field-level safety decisions.
A Geohazard Situational Awareness Tool has been developed in collaboration with BGC Engineering (BGC) to manage the identified field safety risks during the construction season. This tool is based on the PNG’s baseline geohazard assessment findings, more specifically, earth and rock slope hazards, debris flow and debris flood hazard crossings, and hydrological hazards of river crossings and rivers in close proximity to the PNG right of way. This tool provides automatic and semi-automatic daily recommendations on the geohazard safety risks based on predictions supported by weather data and hindcasting/forecasting. This tool enables PNG to make field-level risk-based decisions about short-term fieldwork planning and execution to ensure the safe completion of the associated field activities.
This article will present PNG and BGC’s challenges and successes in developing and implementing this pioneer solution for managing identified geohazard risks to personnel safety during the fieldwork season. The intent of this paper is to ensure other operators are aware of the available options to manage personnel safety for working in high-risk geohazard terrains.
Keywords: geohazard, personnel safety, gas pipeline, risk analysis
57. Room Temperature Time Dependent Creep Behavior of Low Frequency ERW Pipe Seams and Implications on Managing Pressure Reversals in Hydrostatic Tests
Dave Warman1, Dan Jia1, Yong-Yi Wang1, Michael Bongiovi2, Chad Destigter2
1Center for Reliable Energy Systems, Dublin, USA. 2Enterprise Products, Houston, USA
Abstract
The presence of low frequency (LF) ERW seam weld defects (e.g., lack of fusion, stitching, and hook cracks) can reduce the pressure-carrying capacity of a line pipe. In cases where these defects may have been subjected to a hydrostatic test, there is a possibility that the seam weld defects could fail at a lower pressure upon re-pressurization. This type of failure, which occurs at a pressure less than the previous pressure and where no time dependent degradation has contributed, is commonly referred to as a pressure reversal.
LF ERW seam flaws can fail when held at a constant load below the straight-off to failure load. This is because ductile materials can exhibit time-dependent creep behavior even at room temperature. Evidence of time dependent behavior is provided by failures that occur during the maximum pressure hold period of a hydrostatic test.
Time dependent growth and reverse yielding can be detrimental when performing multiple high pressure hydrostatic tests which can result in many blowouts during the hydrotests, and flaws that survive the hydrotest may experience some ductile tearing that could be detrimental to fatigue life.
This paper covers:
The testing methodology is successful in showing the time-dependent creep behavior of the bondline flaws at elevated loads, as well as establishing that after reducing the pressure down to zero and back to load, the time dependent creep behavior could be re-activated.
58. Accounting for Residual Stress in the Predicted Failure Pressure Calculation
Michael Rosenfeld1, Scott Fannin2
1RSI Pipeline Solutions LLC, New Albany, Ohio, USA, 2Pacific Gas and Electric, San Ramon, USA
Abstract
Pipeline safety regulations require performing a calculation of the predicted failure pressure (PFP) of defects as part of an engineering critical assessment. Whether to include residual stress from pipe manufacturing, and selecting the magnitude of residual stress, can significantly affect the outcome of PFP calculation. Guidance for accounting for residual stress is inconsistent. A survey was performed of several dozen research reports describing testing and analyses of residual stresses induced by the pipe manufacturing process for various types of line pipe. A simple method for determining whether to account for residual stress, and if so, at what magnitude, has been devised for various categories of ERW pipe, and also for non-ERW pipe.
59. Estimate Pressure at Feature Location in a Complex Pipeline System
Fan Zhang, Daniel Gutierrez
Phillips 66, Houston, USA
Abstract
Determining the pressure level at a feature location in a pipeline is critical for further assessment, such as comparing it with calculated burst pressure, or deriving the local pressure spectrum over time for fatigue evaluation. Currently, API RP 1176 (2016 First Edition) Section 8 provides an equation to estimate local pressure based on immediate upstream and downstream pressure gauge records and the location of the feature. This equation is useful for a simple pipeline with uniform flowrate and up to two pipe segments with different diameters between two pressure gauges. However, real pipeline systems can be more complex. For example, a pipeline segment, located between two pressure transmitters, may be composed of a large diameter subsegment in between two smaller diameter subsegments. The pipeline segment may also include injection or strip off points between the gauges which results in different flowrate along sections of the segment. In this paper, a more universal approach with a group of equations was developed which can calculate the local pressure in a complex pipeline with any number of subsegment of various diameters and flowrates. The methods reduce to the one in API RP 1176 for a simple pipeline system. Working examples are also provided to demonstrate the application.
60. Effect of pipe-soil interaction parameters on pipeline thermal stress analysis
Kshama Roy¹, Suborno Debnath², Joseph Bratton¹
¹DNV Canada Ltd., Calgary, Canada, ²Northern Crescent Inc.
Abstract
Thermal stress analysis is an integral part of the design and integrity assessment of buried pipelines. In the current industry practice, the numerical beam-spring model is extensively used for the stress analysis of buried pipelines under operational (e.g. temperature and pressure) loads. In the beam-spring model, the pipe-soil interaction is simulated using a series of orthogonal soil springs aligned in the axial, lateral, vertical upward and vertical downward directions as recommended by American Lifelines Alliance (ALA) and Pipeline Research Council International (PRCI) guidelines. This paper reviews the assumptions and limitations of the existing methods for structural pipe-soil interaction modelling and investigates the sensitivity of pipe stress values to the pipe-soil interaction parameters using finite element (FE) analysis. The commercial FE software package, Abaqus is used in the present study. A case study mimicked to an actual pipeline is used in the present study to see the practical effects of using different pipe-soil interaction parameters. Results show a significant dependence of the pipeline stresses not only on the pipe-soil interaction parameters but also on using the different design guidelines. The variation in the pipeline stress responses from the FE results indicates that the estimated pipe-soil interaction parameters obtained from different guidelines need to be consistent enough to simulate pipeline stress response under pressure and temperature loading.
61. Know When Using MFL for Effective Area is Wrong!
Christopher De Leon1
1D2 Integrity, Houston, USA
Abstract
Performing corrosion assessments on reported MFL features is a fundamental competency in pipeline integrity management. ASME B31.G provides three methods of calculating burst pressure associated with defect assessment for corrosion, namely B31.G, Modified B31.G, and Effective Area. Each method is based on a geometry and depth profile of the corrosion defect, which may be explicit or an approximation. The technical documentation for each methodology’s application is widely available and well understood. However, the transformation of MFL signal data into metal loss feature characterization as a function of feature length, width, and depth for use in Effective Area calculations is not well understood. If the MFL based depth profile is not representative of the corrosion defect, then the burst calculation using the Effective Area methodology may not be conservative and potentially a safety concern. This paper will use a case study where MFL-A technology was incorrectly used to calculate burst pressure using the Effective Area methodology, highlight MFL technology’s challenge in providing accurate corrosion depth profiles to perform Effective Area calculations, and share guidance on how to qualify MFL data for use in Effective Area calculations.
62. Overcoming detection and sizing challenges for slanted/skewed cracking by combining axial and circumferential crack detection In-line inspections
Oscar Anguila1, Francisco Ibarrola1, Jordi Aymerich1, Rogelio Guajardo1, Katherine Hartl2
1NDT Global, Barcelona, Spain. 2NDT Global, Houston, USA
Abstract
Pipeline operators widely use In-line inspection (ILI) ultrasonic tools to manage their integrity. Specifically for cracking related threats, tool selection will be driven by many factors, one being the crack orientation in relation to the pipe axis. Axial linear anomalies such as; fatigue cracks, lack of fusion and stress corrosion cracking (SCC) can be present due to fatigue, manufacturing related issues, or environmental conditions that favor their development. For circumferential linear anomalies it is not that different, these conditions will also impact their time-dependency state.
Measurement techniques used for crack detection have boundary conditions such as minimum length and depth, but more importantly, the deviation angle from the pipe axis or the circumferential axis will directly have an impact in the ILI tool measurement that will result in an analysis bias to undersize the depth or in a worst case scenario, directly limit the possibility of the feature being analyzed due to signal amplitudes within noise levels and/or below analysis thresholds.
During a field verification campaign of vintage pipe, areas with SCC were uncovered for which the geometries were found to be slanted over the pipe body following areas of coating disbondment. The pipeline had been inspected with both; axial and circumferential crack detection tools which allowed further integration of the data and the possibility to derive a methodology, that is reproducible, providing the user trustworthy and actionable data.
This paper will address the detection challenges of the ILI technology while documenting the necessary steps (incl. non-standard analysis) to derive a methodology that led to improved reporting and depth sizing
KEYWORDS FOR SUBJECT AREA: ultrasonic tools, stress corrosion cracking, spider web cracking, depth sizing, correlation
64. Burst Pressure Prediction for Axial Cracks in Pipelines with Complex Profiles
Thomas Dessein1, Ted Anderson2
1Integral Engineering, Edmonton, Canada. 2TL Anderson Consulting, Cape Coral, USA
Abstract
Crack-like anomalies in pipelines are complex features that typically have an irregular profile. However, due to modelling complexity, the common practice is to approximate such profiles with a semi-elliptical crack whose length is equal to the total flaw length and whose depth corresponds to the maximum depth of the flaw. This approach is very conservative and can result in significant underestimates of burst pressure.
This paper describes recent improvements to the PRCI MAT-8 fracture model that account for arbitrary crack profiles. An extensive finite element study was undertaken to model numerous non-ideal longitudinal crack profiles in pipe joints. The output from these analyses led to a procedure to convert an arbitrary crack profile into an equivalent semi-elliptical crack. The depth of the equivalent crack is equal to the maximum flaw depth, but the length is typically much less than the total flaw length. This modification results in burst pressure estimates that are more accurate and less conservative than the traditional approach.
The procedure improves upon an earlier phase of work (PPIM 2019) that developed an approach which was accurate for cracks with an isolated deeper section that dominates the fracture demand. Since then, more real-world profiles have been assessed and several cases identified for which the previous procedure underestimated the fracture demand. The new procedure resolves this while ensuring a slight conservative bias and maintaining an accuracy that is comparable to typical inline inspection tool length sizing accuracy.
The new algorithm considers interactions between deeper sections of the crack profile to increase the length of the equivalent semi-elliptical crack. While the new algorithm was developed and calibrated using machine learning techniques, it can be implemented without any specialized machine learning tools.
65. Phenomenology and Traits of SCC – and the ILI Challenge it Presents
Brian Leis
Worthington, Worthington, USA
Abstract
Recent work considered the factors controlling SCC and typical cracking speeds based on laboratory test data to identify the factors and quantify the laboratory speeds, which it used to formulate bathtub speed curves that compared favorably to typical field cracking speeds. This paper adds significantly to the hundreds of cracks in the field dataset considered previously. Traits typical of the field cracking are trended and compared with current ILI crack-tool reporting criteria to identify their strengths and potential weaknesses concerning safety and reliability.
Fracture features typical of ruptures and major spills due to SCC are contrasted to those evident for leaks and larger secondary cracking, for benign field cracking, and finally for field cracking at the scale of the steel’s microstructure. It is shown that regardless of the scale the recurrent traits of failures causing ruptures and major spills are comparable down to the smallest of cracking – indicating that the mechanics of SCC is scalable. The associated crack populations are then trended relative to their spacing and sizing as evident on the pipe’s OD surface, on its fracture surfaces, or in x-sections of intact cracking. The resulting populations of surface lengths and profiled depths are then trended for well in excess of a 1000 cracks. That population was then parsed based on their sizes and field response as 1) benign, 2) secondary cracks remote to ruptures and major spills, 3) larger secondary cracks adjacent to ruptures and major spills, leaks and smaller spills, and finally 4) ruptures and major spills.
The parsed dataset was then trended relative to a normalized form of crack aspect ratio as a function of normalized of depth, which effectively discriminated between each of the four parsed datasets. The usual crack-tool reporting criteria specified relative to length and depth were then recast as a function of pipe diameter and wall thickness, such that they could be contrasted with the field data. This identified what amongst this field population would be reported if the tool successfully identified and called each of the cracks. The results showed that the current criteria cull the benign cracking and the smaller secondary features, and report all outcomes that led to ruptures and major spills. Thus, the reporting criteria avoid digs for benign cracking, and successfully capture cracking that poses immediate concern for failure. While effective as just noted, portions of the population that are reaching sizes that have posed a threat in past are less effectively reported. The results indicate that depth is not a key factor in this outcome – rather it was controlled by crack length. This, coupled with the observation that crack length is underreported to an extent controlled by aspect ratio, suggests improved safety and reliability could be affected significantly by improvements in length sizing and length reporting. These aspects are elaborated further in the paper.
KEYWORDS FOR SUBJECT AREA: Crack assessment, ILI applications
93. EMAT Lessons Learned Using Direct Assessment Findings
Matthew Romney1, Kayla Stark Barker1, Ron Lundstrom1, Daniel Bruce2, Alireza Kohandehghan3
1T.D. Williamson, Salt Lake City, USA. 2Pacific Northern Gas, Terrace, Canada. 3Pacific Northern Gas, Vancouver, Canada
Abstract
Different cracking mechanisms can potentially affect pipelines depending on the operating conditions, product, coating type, pipe manufacturing process, and environment. These mechanisms include manufacturing-related crack-like linear indications (e.g., seam weld lack of fusion, subsurface or surface breaking laminations), construction-related cracks (e.g., girth weld cracks, in-service fillet weld toe cracks), cracks formed in mechanical damages, and environmentally assisted cracking (EAC). One of the most important forms of EAC relevant to pipeline structures is stress corrosion cracking (SCC) that has been of particular focus in the past two decades.
Due to the severe consequence of linear indication-related pipeline failures and nonlinear growth and propagation of specific types of linear indication integrity threats, pipeline operators continuously push for new technologies, methods, and procedures for assessing and mitigating pipeline integrity risks pertaining to crack and crack-like anomalies. Inline inspection (ILI) is proven as one of the most effective means that leads to significant improvement in the integrity management of these threats. A key ILI technology that has proven useful for the detection, classification, and sizing of gas pipeline crack and crack-like features is Electromagnetic Acoustic Transducer (EMAT) technology.
Understanding how technologies works and how their performance can be improved is of essence to the success of an ILI-based integrity management program. This article will present and discuss Pacific Northern Gas Ltd. (PNG), and T.D. Williamson (TDW) lessons learned, challenges, and successes of utilizing EMAT ILI technology to identify, classify, quantify, and mitigate crack and crack-like integrity threat risks across multiple gas pipeline systems. Utilizing an EMAT system, populations of anomalies will be reviewed and compared with direct assessment findings. Recommendations and potential mitigation strategies will also be presented.
Keywords: cracks, deformation, electromagnetic acoustic transducer, environmentally assisted cracking, gas pipeline, geometry, inline inspection, magnetic flux leakage, metal loss, Multiple Dataset, pipeline integrity, stress corrosion cracking, , DEF, EAC, EMAT, GEO, ILI, LFM, MDS, MFL, SCC, SMFL
34. Assessing the accurate topography of complex channeling corrosion by means of ultrasonic wall measurement tools. A case study and experiences
Kerstin Munsel1, Katherine Hartl1, Christoph Jaeger2, Santiago Urrea3
1NDT Global, Houston, USA. 2NDT Global, Stutensee, Germany. 3NDT Global, Stutensee, USA
Abstract
This paper presents a case study of an offshore pipeline with pitting and long axial corrosion that had been continuously inspected by Magnetic Flux Leakage (MFL) and was recently inspected with an Ultrasonic Wall Thickness Measurement (UTWM) tool. An anonymized comparison of 3 MFL inspections and the recent UTWM inspection is presented. This analysis demonstrates the challenges associated with the two methods, and how UTWM can be used to acquire topography that describes the complete extent of metal loss. Further, the case study also shows a new and more customized approach to providing data that enables a better comparison of results between different ILI methods. Finally, direct measurement data enables advanced integrity methods, like DNV-RP-F101 Appendix D, which uses wall thickness and standoff data to calculate pipeline capacity and system effect considering the effects of long axial corrosion continuously spanning multiple pipe joints.
KEYWORDS FOR SUBJECT AREA: ultrasonic tools, metal loss corrosion, correlation, complex channeling corrosion, DNV-RP-F101 Appendix D
33. Applying Ultra-High-Resolution MFL To Achieve a Better Integrity Assessment of Pits-in-Pits.
Rick Desaulniers
Entegra, Toronto, Canada
Abstract
The VP of Asset Integrity for a major US west coast liquids operator once asked us to guess the number one cause of leaks on their pipeline systems over the previous year. The answer? 20% deep metal loss … in other words, deep (through wall) pinholes were embedded in an area of less than 20% deep corrosion, also known as “pits-in-pits”. With the advent of Ultra-High Resolution (UHR) Magnetic Flux Leakage (MFL) In-Line Inspection (ILI) techniques, the nuances of complex corrosion can now be reliably explored … including pits-in-pits.
This paper will describe how an increased sensor density and sampling frequency in combination with human-experience based decision making in the analysis process can be deployed to accurately detect, characterize, and size potentially injurious complex corrosion. Data comparisons with in-the-ditch results will be presented.
25. Using Controlled Acoustics to Find a Stuck Pig
Steven Bourgoyne, David Murray
Seismos, Austin, USA
Abstract
SCOPE:
A pipeline operator was preparing to run an in-line inspection on a 4’’ NGL Line in South Texas. Prior to the inspection, the operator launched a 31’’ Mandrel Pig with a Gauge Plate and Cleaning Tool. The mandrel pig was unable to flow the total distance and got caught somewhere in the middle of the pipeline. An unsuccessful second and third pig was launched two weeks later to try and dislodge the first gauge plate pig. Several methods were used to locate the pigs, including geophones, transmitter detection receivers, and mainline block valve pressure differentials.
PROCESS:
To find the missing pig, Seismos used an Acoustic Transmitter, Acoustic Sensor, and Data Acquisition Unit (DAQ) to create controlled acoustics within the pipeline. The equipment was attached to the pipeline at above-ground stations through standard Male Pipe Thread (MPT) connections.
The acoustic transmitter emits a pressure pulse that causes a tube wave to travel via the pipeline media down the length of the pipe. The acoustic energy reflects off the object and the return signal is captured by the acoustic sensor. Signal processing software is used to analyze the return signal providing the object’s precise location.
RESULTS:
Seismos informed the operator of the location of the lost pigs, which ended up being 2+ miles away from where the operator initially thought going into the project. The operator decided to start excavating based on Seismos’ analysis. The pigs were found precisely where Seismos’ analysis had indicated.
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44. Application of MFL ILI Data for Pipeline Material Verification
Joe Craycraft1, Ransom Stamps1, Tim Arnold1, Andrew Corbett2, Rick Gonzales3, Luke Jain1, Guillermo Solano2, Ron Thompson2
1Campos EPC, Denver, USA. 2Novitech Inc, Vaughan, Canada. 3Xcel Energy, Denver, USA
Abstract
Natural gas transmission pipeline operators are required to maintain Traceable, Verifiable, and Complete (TVC) documentation for certain pipe material properties in accordance with United States Federal Code. Pipeline operators are obligated to reconfirm missing TVC material property information. One route of reconfirmation is material verification in accordance with Title 49 CFR 192.607. AMFL and CMFL data from inline inspection is applied in this study to match pipe joints to a specified minimum yield strength (SMYS). This technology application is proposed to provide an alternate methodology to commonly applied destructive and in situ nondestructive test methods. This alternate ILI-based method would reduce compliance costs as well as health and safety exposures associated with pipeline excavation and other activities required to complete destructive testing and in situ nondestructive testing. Material verification using historic ILI MFL data was validated using available TVC documentation as well as destructive and nondestructive test data. Statistical analysis is applied to identify sampling requirements to achieve a 95% confidence level when applying ILI material verification information in combination with destructive testing and/or in situ nondestructive testing data.
Categories: Data management; ILI analysis; materials identification, verification
20. Navigating the New §192.712 Regulation on Dents
Rhett Dotson1, Fernando Curiel2
1D2 Integrity, LLC, Houston, USA, D2 Integrity, LLC, Houston, USA, 2DCP Midstream, Houston, USA
Abstract
API RP 1183 was released in 2021 and was expected to be a precursor for updated regulations addressing dent assessments. In the fall of 2022, the Pipeline and Hazardous Materials Safety Administration (PHMSA) released the final part of the updated gas rule. In this part of the rule, §192.712(c) specifically addressed the assessment of dents and other mechanical damage. This paper examines the new section of code and provides technical guidance on how these dent regulations can be understood and applied in integrity management programs. In addition, this paper will examine where API RP 1183 and the updated gas rule are not aligned.
79. Meet the Transformer Robots in Disguise
McKenzie Kissel1, Dominik Seepersad2, Peter Fisher2, Ryan Kolebaba1, Rob van Woudenberg1
1Onstream Pipeline, Calgary, Canada. 2Enbridge, London, Canada
Abstract
Gas storage is a critical infrastructure that provides the ability to balance natural gas transmission systems to meet short- and long-term user demands. Natural gas can be stored in above ground facilities, and below ground in caverns and rock formations. There are over 400 active gas storage facilities throughout the North America that provide over 20% of the natural gas required to meet the seasonal winter month demand. These storage facilities are part of the gas transmission network and are directly tied to the system to be accessed as needed. Given the criticality of the natural gas storage infrastructure, like all pipeline infrastructure, it must be inspected. In many cases the pipelines from the natural gas storage wells to the main measurement regulating facilities do not have provisions to inspect the lines efficiently while under pressure or via inline with the media due to flow conditions, pipe fittings and lack of launch and receive facilities. Furthermore, given the criticality of the storage infrastructure, there are very tight outage windows to complete the pipeline inspections. Due to the inspection challenges, these systems are usually completed via a robotic crawler. This paper reviews the recent inline inspection campaign of a network system feeding a natural gas storage infrastructure, through detailed planning and pre job testing, the ability to efficiently and effectively utilize MFL combination tether technology to inspect the network in unprecedented time. Using tether technology, the 13-pipeline segment system, was inspected in under one week, which included multiple pipeline diameters, vertical launches, and short radius bends.
ILI Applications, “Unpiggable” inspections and technologies
32. Survey of Impact: RIN-2 Final Rule – Safety of Gas Transmission Pipelines
Chris Bullock1, Lara Gran2, Luke Whitrock3
1Integrity Solutions Ltd, Bossier City, USA. 2Integrity Solutions Ltd, Missoula, USA. 3Integrity Solutions Ltd, Denver, USA
Abstract
New federal regulations contained in RIN 2137–AF39 titled “Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments” impose new requirements on natural gas transmission pipeline operators. This presentation will provide an initial survey of impact of the Final Rule on operators affected by the final piece of a decade-long effort by PHMSA to amend its regulations of onshore gas pipelines, known as the “Gas Mega-Rule”.
This new rulemaking considers lessons learned from recent onshore gas transmission pipeline incidents and codifies a management of change process. The rulemaking also clarifies certain integrity management, assessment, corrosion control, repair, high consequence area (HCA), and extreme weather event requirements, as well as revises or creates new definitions related to the above amendments.
Compliance requirements, key dates, and a sample case study on the ramifications to corrosion control and integrity management repair criteria will be provided. Integrity Solutions® Ltd will not be producing a white paper to support the presentation, however, an advanced preview of the presentation can be provided.
1. PHMSA Updates Related to Data and GIS
Monique Roberts1, Leigha Gooding2, Blaine Keener2
1PODS Association, Houston, USA. 2PHMSA, Washington DC, USA
Abstract
PHMSA Updates Related to Data and GIS
Did you know that the NPMS system uses the PODS model? So, if you have ever uploaded your NPMS submittal you have used PODS! PHMSA has been a member of PODS for over a decade now in fact, so the PODS Association works closely to make sure that all data tables and schema are standardized for use by all operators and service companies that support them. The PODS Model is operator designed to comply with regulations, support specific pipeline operations and decrease risk through digital twin/asset knowledge management.
Joining PPIM in-person will be Leigha Gooding, PHMSA OPS GIS Manager and Monique Roberts, PODS Executive Director. Leigha manages the NPMS system so we will hear first hand on regulation, data and GIS.
This presentation will cover a high-level overview of the NPMS submittal process, the radical increase in segmentation and new attributes that PHMSA is expecting operators to capture as well as some news from the PODS Community and the recent ILI module release on PODS 7.
79. Benefits of MFL Robotic Pipeline Inspection in Assessing Difficult-to-Assess Pipelines
Brent Gearhart1, Chris Figgatt1, Rod Lee2
1TC Energy, Charleston, USA. 2Intero Integrity Services, Toronto, Canada
Abstract
The robotic inline inspection method has been utilized by distribution and transmission pipeline operators for over a decade. Since its inception, many advancements have been made. This paper discusses the implications and applications of some recent advancements. Furthermore, TC Energy and Intero Integrity Services will discuss the operational benefits of using MFL robotic pipeline inspection for two difficult-to-inspect pipelines by drawing experiences from using robotics in a 20-inch pipeline and an 8-inch pipeline.
89. Detection and Sizing of Selective Seam Weld Corrosion Using Axial and Circumferential MFL Micron ILI Technology
Ron Thompson, Andrew Corbett, Guillermo Solano
Novitech Inc., Vaughan, Canada
Abstract
This research and development are for the purpose of optimizing an In-line inspection (ILI) system for the detection, characterization, and sizing of selective seam weld corrosion (SSWC). This technology utilises both Axial Flux Leakage (AMFL) and Circumferential Magnetic Flux Leakage (CMFL) measuring systems. The technology is also designed to take up to 1,600 readings per square inch providing the required resolution to detect and size SSWC.
This paper will present several phases of the study that include conceptual development, pull testing, and field verification from live runs on pipeline systems containing SSWC. It includes the development of software and analysis tools that utilize varying signal responses to both AMFL and CMFL for different metal loss geometries.
The evaluation of SSWC, and of general corrosion coinciding with the long seam weld area, requires both AMFL and CMFL ILI data that has been collected with very high resolution. This research shows that field-tool correlation improves when the process of characterization and sizing SSWC is carried out in the following three steps:
1. The use very high-resolution data to better delineate SSWC from within the general corrosion area, and to provide precise positioning of the long seam weld.
2. Determine whether the long seam corroded areas exhibit wedge, groove, or axial slot like shapes that are typical of SSWC. These features are frequently in aeras of significant corrosion adding to the complexity of characterization and sizing.
3. Apply both AMFL and CMFL sizing algorithms to the preselected SSWC locations to properly size axially orientated wedge or groove-like features.
This paper will also illustrate additional challenges found during field verifications. These include the occurrences metal loss coinciding with seam flaws such as lack of fusion and hook crack flaws, and the current development of analysis tools that address these compounded flaws that can, on occasion be misclassified as SSWC.