The 30th INTERNATIONAL
Pipeline Pigging & Integrity Management Conference™
plus Training Courses and Exhibition
George R. Brown Convention Center and the Marriott Marquis Hotel
January 29 - February 1, 2018
 Keynote address: 30 years – technology, materials, and integrity looking back and into the future, by Dr Simon Webster, Chief Engineer Materials, BP, Sunbury-on-Thames, UK
The presentation provides an overview on select transformational developments in technology over the last 30 years. Key facets that relate to changes in our personal lives are initially highlighted. The theme then focuses on developments and progress relating to engineering and pipeline integrity management with a look at the past, present, and future. Modernization and transformation opportunities are explored with a focus on key challenges
 ILI validation: what are we trying to prove?, by Ian Smith, IDSMITH Pipeline Engineering, Inc., London, ON, Canada
In-line inspection (ILI) is one of the foundational components of most pipeline integrity programs. ILI provides the condition monitoring data that allows for an inspect, assess and then remediate cycle that allows for pipeline anomalies to be managed successfully. A necessary component of ILI programs is validation of the ILI results, which helps to ensure the effectiveness of this process. The most important element of the validation is not the accuracy of the measurements themselves but rather the validation of the assessment to determine if critical anomalies have been identified and evaluated using an appropriate level of conservatism. A case study will be presented regarding an ILI program using an ultrasonic crack detection tool where this ILI validation process was utilized. The case study will include the development of the assessment methodology, ILI and field prove up results, evaluation of the ILI probability of detection (POD) and accuracy specifications, review of outliers, and finally review of the assessment results using both ILI and field measurements. The ILI validation process ultimately answers the question as to whether the assessment met the integrity goals of the ILI program: identifying and repairing anomalies that may impact the safety of the pipeline.
 Analysis of ILI vendor performance on Enable Midstream’s pipeline system, by Joel Anderson, Enable Midstream, Oklahoma City, OK, USA
In this in-depth study of actual in-line inspection (ILI) tool performance on Enable Midstream's pipeline system was undertaken in 2017. To accomplish this, data was collected from post-assessment reports for the years 2010 to 2015 for runs completed by six different vendors. For each anomaly examined, the difference between what was called by the ILI tool and the field measurement was collected along with the Line number and diameter. This analysis creates a qualitative and quantitative comparison relative to the specified tool tolerance for each vendor. In addition, whether the ILI performance is diameter dependent. In this presentation, several analysis methods will be introduced that give a measurement of not just how the tool performed in that instance, but how it is likely to perform in the future. While none of the vendors exhibited a consistent bias, there was significant difference seen between vendors. In fact, the actual in-tolerance performance experienced at Enable is typically closer to 70% rather than the 80% typically quoted in literature. None of the vendors will be mentioned by name. For the purposes of the presentation, all names will be replaced with Vendor A, B, C, etc.
 Quality management systems: starting your pipeline off on the right foot, by Melissa Gould and Megan Weichel, DNV GL, Katy, TX, USA
A new recommended practice (RP) "API RP 1177, Recommended Practice for Steel Pipeline Construction Quality Management Systems" outlines a systematic approach to managing and documenting the construction processes of a new pipeline from design verification, materials manufacturing, procurement, construction, inspection, and testing through the initiation of operations. The new RP is based on the 2015 report developed by DNV GL for the Pipeline Hazardous Materials Safety Administration (PHMSA) titled, "Improving Quality Management Systems (QMS) for Pipeline Construction Activities." Developing an effective QMS and incorporating quality management for new pipelines as part of an effective pipeline safety management system (PSMS) is the first step in ensuring integrity throughout the life cycle of a pipeline. This paper highlights the QMS approach in API RP 1177 and outlines the long-term benefits of a QMS, including how an effective QMS can be used to more seamlessly transition a pipeline into an organization's integrity management program (IMP). Finally, this paper discusses the differences and interactions between QMS and PSMS, as described in "API RP 1173, Pipeline Safety Management Systems," and describes how the two systems can work together to maintain integrity over the life of a pipeline.
 Identification of a unique geometry that contributed to pipeline ratcheting: numerical and metallurgical findings, by David B. Futch, Dr Melanie Sarzynski, and Brent A. Vyvial, Stress Engineering Services, Houston, TX, USA
Stress Engineering Services, Inc. (SES) assisted a pipeline operator with the analysis of an in-service pipeline leak identified in a location where an adjacent pipeline road-crossing had been replaced. ILI data indicated that the leak coincided with a top-of-the-pipe dent. After receiving the pipe sample, SES performed a combination of metallurgical and numerical analysis to determine the likely causes of the observed deformation and the subsequent leak. SES visually examined the pipe and found multiple wrinkles/dents spanning approximately two-thirds of the pipe circumference. Additionally, four cracks were identified (two through-wall and two that contained internal and external surface breaking cracks that did not extend through-wall) in the peaks and valleys of the deformation. All of the observed cracks extended via shear fracture at a 45° orientation to the pipe surface and appeared to be ductile overload based on scanning electron microscopy. Numerical analysis, using FEA modeling, indicated that the areas of cracking correlated with the areas of high stress. This analysis demonstrated that an accumulation of strain (ratcheting) occurred in the subject pipeline due to repeated internal pressure cycles. Based on the results of metallurgical and numerical analyses, SES concluded that the complex geometry of the buckled region was the primary reason for the ratcheting behavior and failure. The interaction between the adjacent dents and wrinkles created a situation where the anomaly region alternated between tensile and compressive yielding during internal pressure loading and unloading.
 Key differences of integrity management regulations and recommended practices for hazardous liquids versus gas pipelines, by Andrew R. Lutz, Satish Pabba, Jay Kaufmann, and Dr Tom Bubenik, DNV GL, Katy, TX, USA
One of the recent emerging trends in the pipeline industry is an increase in mergers and acquisitions. A typical purpose for merger or acquisition is to improve the operator's capabilities, which can include adding capability to transport new products, like a crude oil pipeline operator gaining the capability to ship natural gas and vice versa. Integrity engineers are often tasked with learning to manage a new and different set of considerations for operations, threats, consequences, and integrity assessments. The subject of this study is to identify and explain differences in the regulations and recommended practices between hazardous liquid and natural gas pipelines, as they relate to integrity management. In some cases, the difference in regulations and recommended practices are justified by the need to address intrinsic differences between gas and liquid pipelines. These intrinsic differences are explained by evidence in PHMSA's reporting records and available industry literature. In other cases, the differences seem more arbitrary. This study provides an integrity engineer who has traditionally worked with pipelines of one medium, a summary that would allow them to start gaining a better understanding to manage the other.
 Benefits of networking between the pipeline industry and the AIST Pipe & Tube Technology Committee, by John Cline, Vectren, Evansville, IN, USA
This paper describes the benefits of networking between the pipeline industry and the Pipe & Tube Technology Committee of the Association for Iron & Steel Technology (AIST). It is anticipated that this networking will expand the roles of personnel attending PPIM annual conferences with benefits to both PPIM and AIST. AIST is a steel technology oriented organization with 17,500 members from more than 70 countries. Its 30 technology committees include the AIST Pipe & Tube Technology Committee (PTTC) which consists of international experts involved in steel pipe & tube manufacture, pipe mill design/build firms, metallurgy, process, operations, engineering, reliability, and non-destructive test equipment. Benefits include networking with these steel pipe & tube experts, access to numerous technical papers, and access to the Pipe and Tube Technology Conference (Sept 2018 in Houston) which covers all facets of the manufacturing of line pipe and OCTG. Also of interest to pipeline operators is the Pipe & Tube "Roundup" which is an extensive spreadsheet of US and international manufacturers of Pipe & Tube with key data on their capabilities.
 Asset-specific mechanical properties from in-ditch pipeline inspection, by S. D. Palkovic and K. Taniguchi, Massachusetts Materials Technologies, LLC, Cambridge, MA, USA, and S. C. Bellemare, Massachusetts Institute of Technology, Cambridge, MA, USA
Pipeline life extension through condition assessment and integrity management relies on the availability of material specification and construction records as well as data from inspection surveys. For corrosion, minimum wall thickness criteria are based on operating pressure, nominal pipe wall thickness and pipe grade. For stress corrosion cracking and fatigue, assessing the risk of a large rupture relies in part on asset-specific material fracture toughness data. Significant progress has been made regarding the measurement and assessment of pipe geometry and material anomalies for these fitness for service evaluation. However, the determination of the maximum allowable operating pressure and maximum allowable flaw size for existing assets can be improved through in-the-ditch testing methods for mechanical properties. This paper describes two mechanical testing methods recently developed and implemented for nondestructive testing of vintage pipeline steel. In the first method, hard blunt styluses of different geometries slide over the pipe surface at constant loads to measure material hardness. The hardness values for dissimilar styluses are input into predictive equations to determine the yield strength and ultimate tensile strength of the steel. When performed over longitudinal seams or girth welds, the tests identify the heat treatment including normalization which enhances the toughness of the steel. In the second method, the instrument is equipped with a wedged-shaped stylus that includes an opening, or stretch passage, where material is locally subjected to tension that results in microvoid growth and coalescence. This material response matches observations from laboratory ductile fracture tests, and is correlated with the fracture toughness through measurements of the crack tip opening displacement on features of the fracture surface that remains on the sample after testing. Ongoing field testing and third-party validation provide examples of application and performance of the methods.
 Pipeline operator and inspection company collaboration to improve in pinhole and pitting corrosion inspections, by Thomas Hennig, Thomas Meinzer, and Nathan Leslie, NDT Global, Dublin, Ireland, and Josh Dobrzeniecki, Marathon Pipe Line
An examination of an ultrasonic metal loss (UM) inspection and subsequent re-inspection using a UMp+ service executed by NDT Global for Marathon Pipe Line. NDT Global and Marathon Pipe Line conducted the tests on an 8" x 65 km (40 mi), with a wall thickness range of 5.5 mm to 8.6 mm (0.22” to 0.34”). The initial test identified areas of small pitting and corrosion, it did not have the highest-resolution scanning grid to get an accurate sizing of such features. The limitations on the depth sizing accuracy from the initial report presented challenges for Marathon Pipe Line's integrity team. The incorrect feature depths meant that Marathon Pipe Line's team was unable to plan the appropriate remediation. After an NDE campaign and feedback from Marathon Pipe Line, it was determined that NDT Global would undertake another inspection using its aforementioned UMp+ inspection service. Following the initial dig verification program, Marathon Pipe Line and NDT Global worked closely together to create a new set of requirements focusing on the accurate sizing of pittings and pinholes.
 Safe criterion for eliminating SCC on pipelines by metal removal, by Dr Jing Ma and Michael Rosenfeld, Kiefner and Associates, Inc., Dublin, OH, USA
Stress-corrosion cracking (SCC) is an environmental cracking condition that can affect buried steel pipelines exposed to specific environments that are influenced by factors associated with the characteristics of the coatings system, soil, and cathodic protection. The crack management program implemented by pipeline operators may provide for grinding or buffing out SCC discovered on the pipe body. The regulation 49 CFR §192.713(b) provides for repairs shown by reliable engineering tests and analyses to permanently restore the serviceability of the pipe. ASME B31.8-2003 and later editions allow repair of SCC by grinding to a smooth contour with metal loss not to exceed what is allowed for corrosion. Therefore, regulations and standards give no concrete specification for maximum grinding dimensions along either dimension of an SCC colony except that the burst pressure calculated from its size must equal or exceed the operating pressure multiplied by a suitable safety factor (SF). ASME B31G-2009 and later recommends a minimum SF of 1.25, consistent with the recognized practice of reducing pressure to 80% of recent maximum operating pressure in some repair situations. Considering compelling safety concerns for field personnel, a couple of topics are explored in this paper to provide more detailed guidance for the SCC grinding process. This article addresses certain practical aspects of repairing SCC by metal removal including maximum allowable grinding size, appropriate grinding sequence, conservatism of pressure reduction, and influence of width dimension on burst pressure.
 Limitations associated with ILI technologies used for assessing corrosion under insulation, by Andrew Kendrick, Kendrick Consulting LLC, Santa Barbara, CA, USA
This paper uses the example of the 2015 Plains All American Pipeline oil spill near Refugio, California, to detail the technical limitations associated with the use of magnetic flux leakage (MFL) technology to assess the threat of corrosion under insulations (CUI). Based on the data presented in the 2016 Failure Investigation Report developed by PHMSA, this paper provides an overview of the strengths and weaknesses or the various in-line inspection (ILI) technologies for assessing different types of pipeline threats; the focus being on tools best equipped for detecting and assessing CUI. As discussed in the Failure Investigation Report, PHMSA and ILI subject matter experts reviewed the inspection conducted immediately prior to the incident. The results of the investigation revealed that a different ILI tool type could have provided a more accurate indication of the CUI damage on the pipeline. The approach recommended in this paper emphasizes the importance of understanding the potential threats to a pipeline, and utilizing the appropriate ILI tools to asses those threats.
 Preventing the onset of corrosion and removing safety hazards for the pipeline industry, by Matthew Boucher, Buddy Powers and Bart Davis, Clock Spring Company LLC, Houston, TX, USA
The evolution of technology in the pipeline industry has enhanced our ability to create product with integrity management at the forefront. It is no longer solely about repair, but the industry is requiring both durable and safe products that can sustain overtime and are both easy and cost effective to install. Manufactures, specifically pipeline, are challenged to meet the needs of the industry and create product that centralizes and protects the pipe. Pulling friction, coating wear, and deflection are issues the industry is attempting to combat with new centralizer and casing spacer products. Carrier pipes are subject to these issues and ultimately require some layer of installation and outside protection, such as a Clock Spring composite application, to maintain the integrity of the pipe and prevent pipe weakness and/or leaks. Although, it is important to note that composite applications do not mask pipeline threats. Continuous monitoring using an in-line inspection tool is required. This paper details the evolution of the casing spacer and centralizer technology, specifically outlining current benefits, both in operations and safety. Furthermore, the paper will provide analysis and third-party research specific to Clock Spring's Casing Spacer product and inspection protocol. In addition, the paper will highlight the need for the industry to adapt safe products and equipment, specifically discussing how the casing spacer application reduces construction time and gets workers out of harm's way quicker, both onshore and offshore.
 Recent PHMSA protocols for improving models to consider complex loadings and interactive threats, by Eduardo Munoz, Kiefner and Associates, Inc., Columbus, OH, USA
PHMSA-DOT project DTPH56-14-H-0000 was intended to enhance the understanding of interacting threats to pipeline integrity and to reduce the risk of incidents from such interactions. This project identified important interacting threats and provided guidance for pipeline operators in the form of advanced interaction matrices, decision processes, and data needs for identifying and evaluating complex or interactive situations.
 Modeling pipeline metal loss defects at tool speed, by Matthew Romney and Adrian Belanger, TD Williamson, Salt Lake City, UT, USA
The axial MFL field response in pipeline steel near a metal-loss defect is a complex phenomenon. Although critical for proper sizing model development, the effects of tool speed due to product flow is very difficult to account for during finite element analysis (FEA) modeling, and therefore is often overlooked. However, understanding the dynamic MFL response is crucial for proper ILI tool design and the development of accurate defect sizing algorithms. T.D. Williamson (TDW) utilizes dynamic computer simulation modeling, paired with laboratory testing, to develop the complex parametric relationships between metal-loss geometry, pipeline material, and ILI tool speed. This blend of simulation and physical test results allow for TDW to iterate more quickly across multiple physics variables with simulation models, while maintaining a firm footing in reality with physical test validation. Accurately simulating magnetic field responses of metal-loss under dynamic conditions produce the data necessary to identify optimal magnetizer design, including optimizing sensor spacing and placement for metal-loss defect sizing and characterization. This paper will provide an overview of advances in the computer simulation modeling for predicting dynamic flux leakage field response. Besides increasing accuracy, results from this work will extend specifications beyond optimal speed ranges and provide the basis for general corrosion profilometry predictions from decomposition of the full MFL signal.
 Modeling of real crack profiles using finite element analysis, by Alex Brett and Dr Bob Andrews, Rosen Group, Newcastle upon Tyne, UK
The usual practice when assessing the integrity of a cracked structure is to idealize the crack as an ellipse if buried or a semi-ellipse when surface breaking. The length of this idealized crack is set as the overall length reported by the inspection and the through wall height is the maximum height reported anywhere along the length of the crack. This approach is simple and expected to be conservative. It is the approach of codified assessment methods such as BS 7910 and API 579. In-line inspection technology for steel transmission pipelines has developed to the point where vendors can now report the actual profile of an axial crack. Whilst simple screening assessments will continue to use the maximum height and length, for critical cases modelling of the actual crack profile is now possible. This may remove excessive conservatism from the assessment, so avoiding unnecessary shutdowns or repairs. This paper presents results from a study in which finite element analysis (FEA) has been used to model a series of actual crack profiles found by in-line inspection and derive stress intensity factors. The stress intensity factors calculated for these profiles have been compared to the stress intensity factors calculated using handbook stress intensity factor solutions based on both the total length and maximum height of the cracks and also using an effective area type approach to assess sub profiles within the full crack profile.
 Teaching old data new tricks using data science, by Jeffrey Lachey and Tony Alfano, DNV GL, Columbus, OH, USA
As we journey into the 4th Industrial Revolution of Cyber Physical Systems, data storage has now become an extremely cheap service, whether stored on a cloud based server or on a hard drive. Companies will continue to record, collect, and store data which translates to an exponentially growing repository where subject matter experts (SMEs) are struggling to process the meaningful elements daily. Within the massive collection of data lies insight into the very problems that those SMEs are trying to solve, but potentially not to the naked eye. Across countless industries, new tools and techniques are being utilized to solve existing issues in what is considered an untraditional way. The current process of creating a direct link (or algorithm) using a predefined number of inputs to get an output is transitioning with the use of machine learning and data science to provide additional insight into those existing problems, as well as creating new relationships that are not explicitly apparent to SMEs. The pipeline industry is moving into the realm of machine learning to solve current industry problems, whether it be the ability to provide a more accurate prediction of a specific threat using existing data or merely a tool to assist in scrubbing data into a richer dataset. This presentation will provide insight into the ongoing digitalization initiative within DNV GL, and the industry, focusing on a case study demonstrating how machine learning tools can assist engineers in identifying those data elements that are most critical to their decision making.
 Statistical approaches for assessment of ILI data: two case studies, by Dr Puneet Agarwal, Stress Engineering Services, Houston, TX, USA
While NDE data is typically more accurate than ILI, only a limited number of excavations or digs can be practically performed. Two questions regarding the use of the ILI and NDE data are addressed in this paper: (1) how to validate the ILI tool against NDE results to assess the performance of the ILI tool in field conditions, and (2) how many NDE digs should be performed such that a statistically significant number of samples are available for validation to be meaningful. Data from two pipelines is analyzed in this paper and demonstrates that informed integrity decisions can be made by utilizing multiple statistical methods, since different methods can give slightly different results. The first case study uses data from ILI scan of a pipeline (referred to as Pipeline A) with an ultrasonic crack detection tool that resulted in more than 40,000 gradable crack and crack-type features. More than 100 excavations were performed to measure features using NDE techniques. In the second case study, data from an ultrasonic ILI tool for detecting metal loss due to corrosion for another pipeline (referred to as Pipeline B) was used. The tool detected more than 200 internal wall loss features. The goal was to estimate the statistically significant number of NDE digs that will be required for the ILI tool performance assessment with NDE data to be valid.
 Benefits of leveraging advanced data integration and information analysis methods, during the ILI criticality analysis and repair decision process, by Chad Haegelin and Eric Coyle, Integrity Solutions Ltd, Houston, TX, USA
In this presentation, we will impart the benefits of leveraging multiple streams of pipeline related information, along with timely data integration methods, when developing the dig verification plan during the criticality analysis of in-line inspection (ILI) results. It will demonstrate how this process is further enhanced by integrating information from historically lagging processes like corrosion growth rate (CGR) analysis, based on anomaly-to-anomaly comparisons of consecutive ILI assessments. When making repair or investigative dig decisions based solely on ILI results alone, the risk of overlooking anomaly types that fall outside an ILI tool's limitations is inherent. By understanding expected anomaly types based on pipeline specific threat screening and by reconciling those anomalies with the known capabilities and limitations of an ILI tool technology (i.e. probability of identification, sizing, etc.), the information gaps can be filled using timely data integration techniques. In doing this, the patterns of certain combinations of events can be identified that may indicate a concern based on past experience and knowledge of the possible threats. During the presentation, in addition to discussing various data integration examples, ILI tool limitations regarding various types and sizes of anomalies versus expected degradation geometry based on the threat analysis of the pipeline will be discussed. A case study using a pipeline with AC induced corrosion will be examined. In this example, it will be demonstrated how layering pipeline related data, including other field collected assessment data and CGR analysis results, enables operators to make informed and timely field investigative decisions.
 Assessing repeat ILI data using signal-to-signal comparison techniques, by Sarah Jane Dawson and Geoffrey Hurd, Baker Hughes, Cramlington, UK
For pipelines with successive in-line inspection (ILI) runs, the detected population of corrosion defects can be compared to identify both internal and external corrosion growth. Depending on the number of defects to be compared, the assessment can demand significant effort and expertise to ensure accurate and meaningful correlations between often very large ILI data sets. Specialist ILI comparison software facilitates efficient and accurate signal-to-signal matching and the determination of defect specific growth rates across very high defect populations. However, since ILI as a measuring technique is subject in inherent uncertainties, the prediction of where corrosion is active and the rate of growth from consecutive ILI runs also has a degree of uncertainty.
 The challenge of small pipelines, small defects, and small flow figures, by Peter van Beugen, Pipesurvey International, Zwijndrecht, Netherlands
The industry has a continuous demand for extending proven technology to applications at new frontiers. A number of challenges have been overcome successfully, like bidirectional or multidimensional MFL. Starting from the state-of-art technology, this presentation will zoom in on three areas of growing demand: (1) tools for small pipelines, 3" and 4" which can deal with short radius bends and give hi-res data; a comparison is made of newly developed small size UT and MFL tools; (2) defects in girth welds have long been considered to be not critical, but in areas of potential ground movement they will be; new software has been developed to improve the detection of crack-type defects in girth welds; (3) regional or aging pipelines operate at low flow figures; a case history is given of an operating pipeline at less than 0.1 m/s.
 Small-diameter tools for low-flow and low-pressure environments, by Tod Barker, TD Williamson, Salt Lake City, UT, USA
Small diameter pipelines have many challenges when attempting successful in-line inspection (ILI). This is especially true for 4" and 6" pipelines where pressures can range from 100-300 psi. These pipelines often have some heavy wall pipe e.g. NPS Schedule 80 and 1.5D centerline 90° bend radius fittings. ILI tools capable of navigating these conditions and producing a desirable speed profile under these conditions are challenging to design. T. D. Williamson has developed a unique approach to achieve successful inspections in small diameter pipelines that present these conditions. This unique solution provides both geometry and metal loss inspection on the same tool, in a single inspection. This paper will discuss some of the significant benefits and observed capabilities these low flow, low pressure ILI tools provide.
 Robotic in-line inspection of unpiggable buried pipelines, by Jonathan Minder, Diakont, Calle Fortunada, CA, USA
Diakont was commissioned to assess the integrity of a several pipelines that were considered unpiggable; over a bridge, under a river, buried within concrete, and facility piping at a natural gas compressor station. Each of the pipelines in these inspection projects was considered unpiggable due to difficult geometries or accessibility concerns and had never been inspected before. Since these piping systems had operated over thirty years each, the pipeline operators would have been forced to replace the lines if they could not inspect them and verify their integrity. Diakont developed a self-propelled robotic in-line inspection (ILI) crawler capable of handling the unpiggable pipelines. The new robotic crawler tooling traverses challenging pipeline geometries using a ruggedized multiple track system, which allows for navigation across horizontal surfaces. Moreover, the tool can extend the tracks to the pipe wall for stabilization. This arrangement provides the traction that is necessary to hold the tool rigidly in place while inspecting difficult-to access pipeline applications (such as inclines and vertical sections), where conventional ILI tools may not be feasible. This system moves at a deliberate pace to provide accurate mapping of anomaly locations within the pipeline. Being self-propelled and bidirectional, the crawler can also be deployed and retrieved from a single access point, which was another key feature in its selection for this inspection program. This presentation will provide case study details for the four "unpiggable" inspection projects that were completed this year, including the challenges, inspection procedures, and inspection results.
 A probabilistic method for prioritizing repairs following an ILI crack tool run, by Dr Ted Anderson, TL Anderson Consulting, and Jim Andrew and Jason Moritz, Koch Pipeline, Wichita, KS, USA
In-line inspection is seeing increasing use in the integrity management of aging pipelines that contain seam weld anomalies. ILI crack tool runs are commonly used as a substitute for, or as a supplement to, hydrostatic testing. Data from an ILI crack tool run usually prompts decisions on digs and repairs. Traditional rules-based approaches to repair decisions rely on deterministic calculations of burst pressure. Given the limitations in ILI flaw sizing accuracy and the variability of material properties in pipe joints, deterministic burst pressure estimates contain a high degree of uncertainty. When a fracture analysis assumes worst-case flaw dimensions and material properties, it often predicts that many of the pipe joints containing crack-like flaws detected by ILI should have failed already. Such a result may lead to an inordinate number of digs and repairs, even though the worst-case deterministic analysis is clearly at odds with reality. This paper presents a new probabilistic model for assessing seam weld anomalies and prioritizing repairs. This model considers the uncertainty in flaw dimensions, strength properties, and fracture toughness. The failure probability of each detected flaw is computed individually, and the combined probability of failure in the line is inferred from standard probability relationships. This model does not merely rank flaws by burst pressure, as is common in both deterministic and probabilistic approaches. Rather, the model considers time-dependent degradation due to pressure cycling. Key ingredients to the model will be outlined in the presentation.
 CorLAS - the next generation, by Dr Tom Bubenik and Steven Polansk, DNV GL, Dublin, OH, USA
Pipeline operators face challenges in dealing with crack-like anomalies. CorLAS™ is widely recognized as the most accurate method for calculating the burst strength of a pipe with crack-like anomalies, but it isn't widely available, and the user interface is outdated. More importantly, its validity has not been demonstrated below a Charpy V-notch energy of 5 ft-lbs, which limits its utility for pipelines that could fail in a brittle manner. PHMSA, and pipeline operators in North American, need analysis capabilities for low-toughness quasi-brittle materials to address threats associated with older ERW and flash welded pipelines. This paper summarizes a new joint-industry project (JIP) to extend CorLAS™ to lower toughness materials and update its user interface. The JIP combines small-scale and large-scale testing to demonstrate how to analyze low-toughness quasi-brittle materials. The goal is a robust analysis method that can be used in place of the so-called Raju-Newman method, which is known to be extremely conservative.
 Assessment of pipeline crack and crack-like colonies: a case study, by Johnathan Hardy, TD Williamson, Salt Lake City, UT, USA and Dr Mike Kirkwood, TD Williamson Middle East FZE, Dubai, UAE
T.D. Williamson (TDW) inspected a 10" transmission line in Canada using multiple dataset (MDS) and electromagnetic acoustic transducer (EMAT) in-line inspection (ILI) tools. The data from these platforms were used in an immediate defects assessment to establish the criticality of crack-like defects on their pipeline, and assess the feasibility of increasing the maximum allowable operating pressure (MAOP) of the line. From the in-line inspection data, 13 linear indications were reported in the preliminary EMAT report, with three reported as axial crack-like colonies in the pipe body and 10 reported as axial crack-like defects in the long seam. A failure pressure calculation was applied to these defects utilizing the latest fracture mechanics model from Battelle Memorial Institute, using their software PipeAssess PI, which was developed under a DOT PHMSA research contract. The assessment was made more complicated by the unknown crack geometry, large crack lengths, and the customer's limited knowledge of the pipeline's material properties. However, a solution was developed to report failure pressures for each defect using a range of material toughness values and crack assessment categories. Ultimately, a defect assessment report was generated for the customer. The main deliverables were a list of reported crack-like defects ordered by predicted failure pressure severity and recommendations for how to verify the EMAT findings and associated failure pressure calculations. The assessment and recommendations were leveraged by the customer to; determine how to proceed with investigating the reported features, and utilize the information to establish a higher MAOP.
 Is the Paris fatigue crack growth relation the only model appropriate for pressure cycle fatigue analysis of pipelines?, by Sergio Limon, Elevara Partners, Salt Lake City, UT, USA, and Robert Pilarczyk, Hill Engineering, Rancho Cordova, CA, USA
Fatigue is the progressive cumulative damage that structures experience during cyclic operation. In-service fatigue failures of energy pipelines typically occur due to the cumulative effects of operational pressure cycles driven by internal pressures that are less than the Maximum Operating Pressure (MOP) or Maximum Allowable Operating Pressure (MAOP). While it is challenging to establish the conditions, and predict the time for cracks to initiate in pipelines, their growth rate and behavior can be reasonably predicted by applying a fatigue crack growth model supported by experimental fatigue crack growth testing derived from engineering Fracture Mechanics principles. Fatigue crack growth modeling is generally derived from standardized fatigue testing of samples taken from the material and structure of interest. Therefore, a fatigue crack growth model should carry the measured effects of the environment, temperature, loading frequency, stress ratio and mean stress of the loading spectra. The choice of a fatigue crack growth model directly affects the final fatigue life prediction of pipelines with cracks and the determination of the next integrity assessment interval. This paper reviews the most common fatigue crack growth relations developed by the aircraft industry and applicable to pipelines when modeling fatigue crack growth. These relations are Paris, Forman, Walker, NASGRO and a tabulated form. The stages of fatigue life and the fundamental principles of fatigue crack growth analysis will be presented and discussed within the context of and applicability to energy pipelines.
 Crack inspections in liquid natural gases, by Dr Thomas Hennig, Ernesto Suarez, Rogelio Jesus Guajardo, and Peter Haberl, NDT Global, Dublin, Ireland
Crack inspection services have become a standard solution in pipeline integrity programs within the last 2 decades, especially for liquid pipelines. Common pipeline media such as crude and light oils, water, diesel, benzene, or similar are used as a coupling medium for ultrasonic crack inspections. The impact for operators is therefore relatively small as the latest generation of UT crack tools is capable to inspect pipelines without reducing flow rates to accommodate the tool. The above-mentioned media have relatively constant ultrasonic characteristics with varying pressures and temperatures and are therefore very suitable for ultrasonic inspections. The situation significantly changes as soon as the medium in the pipeline does not fall within the common media as described. Especially for liquefied natural gases (LNG) or liquefied petroleum gases (LPG) where temperature and pressure have a significant impact on the ultrasonic characteristics of speed of sound, density, and attenuation. LNGs and LPGs typically contain high amounts of propane, butane, and some other higher order alkanes. Due to the high variability of these components to external boundary conditions, in-line inspections in these types of media require more preparation and investigations in advance for a successful ILI. This paper will focus on the challenges and aspects that must be considered to perform successful in-line inspections in LNGs. We will present a standardized and systematic approach to overcome limitations of the technology in such media.
 A comparison of steel vs composite sleeves for pipeline repairs, by Jerry Rau, RCP, Inc., Houston, TX, USA, and Shawn Laughlin, Pipe Spring LLC, Houston, TX, USA
There are four different methods that may be chosen when a pipeline defect is discovered that needs to be repaired: 1) replace with a pipe cylinder, 2) repair by grinding out the defect, 3) apply a weld overlay over the defects, 4) add a reinforcement sleeve over the defect. Each of these has their technical, practical, and economic benefits and applicability. For this paper we will concentrate on the sleeve repair option. In general terms there are two categories of repair sleeves; those made of steel and those made of a composite material. The decision on which of these options is the best choice may not be straight forward. An analysis of the defect type, pipeline operational conditions and installation parameters need to be considered. In this paper we provide some details of these two types, historical context, advantages/disadvantages, and economics for each.
 Monitoring the condition of a pipeline repair and the anomaly beneath the repair, by Alan Turner, Lloyd’s Register Energy - Drilling, Houston, TX, USA, Ryan LaVergne, and Dr Chris Alexander, ADV Integrity, Inc., Magnolia, TX, USA
High profile pipeline leaks and explosions are a concern for both pipeline operators and regulatory agencies. As a result, regulatory authorities are requiring a more robust repair and monitoring methodologies. Pipeline repairs have been around ever since pipelines themselves were first installed many years ago. Steel sleeves, mechanical clamps and now composites are being used to treat our aging infrastructure. Our growing population, and the resulting expansion of urban and commercial areas over these existing pipelines, has created a need for reclassification in the high occupancy areas. This reclassification will require increased due diligence of repairs and reinforcements of pipelines. "Smart" or "intelligent" repairs will enable monitoring of the health of the repair and the anomaly beneath the repair in these high-risk areas. Advances in sensor and software technology now permit more accurate methods of pipeline condition monitoring. Fiber optic sensing technology and associated data analytics have evolved to a point where we can derive an accurate understanding of what is happening inside a repair and the condition of the anomaly by integrating the sensors into the repair. A proof of concept and prototype have been developed and tested. This paper will show the results of the development and testing of the "smart" or "intelligent" repair.
 Utilizing consecutive ILIs to monitor corrosion growth underneath composite repair applications, by Kevin Spencer, Baker Hughes, Calgary, AB, Canada, and Kevin Seaman, Williams Gas Pipeline
Composite reinforcement sleeves are an accepted repair method that can be used to reinforce a defect-weakened but nonleaking area of pipe. Typically used for external corrosion repair, they are available in a variety of materials. The advantages of using a composite repair include that no welding of the pipe is involved, and the material does not corrode. Corrosion defects that were repaired by the sleeve are still visible in the ILI data and the signals recorded are unaffected by the presence of the sleeve. This paper will address the issues presented through the experiences of a North American pipeline operator. In this case study a comparison of multiple ILI inspections was performed to monitor ILI signals recorded at areas of composite sleeves. As the ILI signals are unaffected by the sleeve it was possible to compare signals before and after installation and then monitor for any changes in subsequent inspections. This analysis revealed the presence of new corrosion anomalies underneath composite sleeves that were not associated with the original corrosion cell requiring repair. Excavation results confirmed the ILI findings and it was determined that the growth had occurred outside the original shrink sleeve area. This ILI comparison analysis enabled the operator to identify repairs that did not permanently restore the serviceability of the pipe and to arrest the external corrosion before it became a significant integrity concern. Furthermore, the information was used to review the current composite sleeve installation procedure and identify improvements.
 Determining the acceptability of bottom side dents with metal loss, by Rhett Dotson and C. Holliday, Rosen Group, Houston, TX, USA
Dents reported by in-line inspection (ILI) with associated metal loss pose a challenge for operators. Current regulations addressing dents with metal loss target gouging resulting from mechanical damage. Dents associated with gouging are particularly challenging to assess without excavations due to uncertainties in the shape of the gouge and the potential for cracking. However, many pipelines contain dents interacting with mild corrosion, which can be assessed to determine their acceptability without the need to conduct expensive excavations. This paper presents a case study demonstrating how a remaining life analysis can be used to assess a bottom side dent interacting with corrosion. The process begins with an expert review of the ILI signals to confirm the nature of the metal loss features, followed by multiple finite element analyses that address the burst pressure and remaining life of a dent interacting with metal loss. The assessment examines the impact of restraint on the remaining life of the dent, and reviews the different methodologies that can be used to assess dents interacting with corrosion, including approaches based on typical S-N curves and fracture mechanics. The paper concludes by providing guidance to operators for assessing bottom side dents interacting with corrosion.
 Considerations and methodology for seam integrity analysis, by Dr Ramsey Hilton and Michael Rosenfeld, Kiefner and Associates, Columbus, OH, USA
When evaluating the longitudinal seam integrity of a pipeline, several characteristics of the pipeline must be taken into consideration. Characteristics such as seam type, manufacturing process, vintage, operational history, and pipe mechanical properties can influence how one approaches seam integrity. The product must also be taken into consideration due to the operational differences between liquid and gas pipelines. The duration and frequency of pressure data sampling are important factors and how the data are analyzed must be efficient and realistic. Additionally, a pipe attributes pre-screening process can be employed to reduce the total number of analyses that must be conducted. When calculating fatigue lives, several methods can be employed, including an approximation using an integrated Paris Law and equivalent cycles. Results of a fatigue analysis can be presented in either a probabilistic or deterministic form, depending on the needs of the pipeline operator.
 Application of quantitative risk assessment, by Patrick Vieth, Dynamic Risk, The Woodlands, TX, USA
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 Pipeline integrity for industrial metropolitans: managing the urban infrastructure crisis, by Ron Maurier, Quest Integrity, Stafford, TX, USA, and T.Y. Liang, Formosa Plastics Corporation, Taiwan
On July 31st, 2014 the city of Kaohsiung, Taiwan experienced one of the most catastrophic urban pipeline failures in recent history. The failure, ultimately attributed to post-construction infrastructure interference (third party) initiated many years earlier, resulted in 32 deaths, 321 injuries, countless buildings and vehicles damaged or destroyed. Latest reports tally on-going restitution cost now in exceedance of 1 billion USD. In reaction to the public outcry for improved safety, the Kaohsiung regional government commissioned an in-depth international pipeline safety probe with the purpose of; Reviewing latest technologies for testing and inspecting petro-chemical pipelines including those considered unpiggable. On May 18th, 2017 after more than two years of study and deliberation government regulations for pipeline safety management were approved. Eighty-nine (89) petro-chemical pipelines in the Kaohsiung jurisdictional region, are now required by law, to be inspected with In-Line Inspection (ILI) technology during the coming twenty-four (24) month period ending May 18th, 2019. Additionally, a second inspection of each pipeline will be required in the following five (5) year period to provide a basis for ongoing comprehensive integrity management. This paper will explore the pre-regulatory compliance and leadership position established by the Formosa Plastics Corporation (FPC) as they become one of the first pipeline operators in the region to provide detailed integrity results for pipelines under their ownership.
 Quantification of uncertainty in input variables to understand the variance in fitness-for-service assessments, by Bruce Young, Jennifer M O’Brian, and Mitchell A. Doerzbacher, Battelle Memorial Institute, Columbus, OH, USA
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 Going from in-situ nondestructive testing to a probabilistic MAOP, by Michael Rosenfeld and Dr Jing Ma, Kiefner and Associates, Inc., Columbus, OH, USA, and Troy Rovella and Peter Veloo, Pacific Gas & Electric, Los Angeles, CA, USA
An integrity verification process described in proposed gas pipeline regulations provides for applying engineering analysis in order to confirm undocumented pipe materials, as one component for confirming the pipeline MAOP. This paper describes how results from in-situ nondestructive testing of material strength properties, steel chemistry, and wall thickness dimensions can be used to establish probabilistic design pressures of piping systems within an operator's facilities. Such results can be used to confirm with high certainty that historic operating pressures are appropriate for a particular piping system.
 A novel and practical approach to consistently assess risk for multiple asset types, by Mauricio Palomino, Christian Calvi, and Yeliz Cevik, G2 Integrated Solutions, Houston, TX, USA
Pipeline operators face the ongoing challenge of managing the risk to their assets while addressing increasing demand and aging infrastructure. The most common approach to risk management currently addresses pipeline, facilities and equipment separately, using index models to assess risk across different asset types. These index models, however, are subjective, do not produce measurable and quantifiable risk results and present results in relative terms. As a result, the challenge to operators remain to accurately and confidently compare risk assessments across asset types to drive their CAPEX and OPEX decisions. In addition, The Pipeline and Hazardous Materials Safety Administration (PHMSA) has identified weaknesses in simple index models and their limitations to effectively analyze complex risk factor interactions. PHMSA has called for the industry to develop a more objective, systematic and rigorous approach to risk analysis with processes to analyze interactive threats and a more effective evaluation of ways to reduce or mitigate consequences. This paper will discuss how G2 Integrated Solution's risk methodology overcomes these weaknesses by using inspection results, appropriate mathematical relationships and provide measurable outputs that can be used to manage risk across different asset types (such as wells, flow lines and facilities), and will review details from a practical application in partnership with one of the largest natural gas distributors in the U.S. This new capability allows operators to reduce the costs of assessing pipeline risk while increasing control and awareness of managing risk assessment activities internally.
 A case study for ILI false-positives, by Matthew Ellinger, DNV GL, Dublin, OH, USA
Inspecting ILI reported metal loss features in the field is a costly and time-consuming endeavor. Between analyzing the ILI data, selecting dig-site locations, securing necessary permits, coordinating the dig efforts, executing the field inspection, and restoring the dig site, inspecting lone features reported by ILI can be a daunting ordeal. These efforts are particularly frustrating when it turns out that the field inspection is fruitless, such as when what was reported by the ILI is not found in the field. These false-positives are a drag on time and resources. Therefore, it is prudent to judiciously select dig locations that ensure time and money are properly utilized. And by the opposite token, great care should be taken in omitting locations that are likely to be false-positive ILI features. In order to do this, we must achieve a better understanding of which ILI reported metal loss features are more likely to be false-positives. This case study aims to answer several questions, including, but not limited to: What is the ILI reporting at the false-positive locations (i.e., metal loss depth, length, width)? Can we draw any conclusions as to ILI reported combinations of depth, length and width that are perhaps more likely to yield false-positives? How often does an ILI reported feature between 0% and 20% deep ultimately end up being a false-positive? How about 20% to 30%? Etc. More than 700 data points from more than 50 pipelines from ILI surveys ranging from 2008 through 2016 are included in the study.
 Baseline and follow-up inspections: getting a head start on pipeline health, by Kai Xin Toh, Quest Integrity Malaysia, and Lisa Barkdull, Quest Integrity, Stafford, TX, USA
Although critical pipeline failures are typically not associated with newly constructed pipelines, it is of vital importance to perform baseline inspections to fully understand the complete life cycle of pipeline assets. A baseline inspection of a new or replaced pipeline segment offers innumerable benefits, including early identification of potential problems, damage and wall thickness changes, allowing for accurate maintenance planning according to remaining life calculations. Another significant factor to incorporate into a long-term asset integrity management plan is the performance of follow-up inspections and run comparisons. This allows operators to collect critical and repeatable data, utilizing in-line inspection (ILI) technology, in order to assess long-term patterns of damage or corrosion. By comparing baseline inspection data with subsequent follow-up inspection data, operators are uniquely able to monitor the evolution of any potential damage mechanisms, which is typically unavailable when a pipeline is infrequently inspected. When baseline and follow-up ILI inspections are part of an asset integrity management plan, the operator has a total understanding of the full lifecycle of their equipment from initiation, allowing operators to proactively manage assets from the onset. This presentation will include a real-world case study example, in which follow-up inspection data was compared to previous inspection data, providing the most comprehensive understanding of the pipeline condition over a significant amount of time. This allows for the monitoring and appropriate planning of future maintenance, based on quantifiable historical data.
 IWEX a full matrix capture technique and the next generation of advanced ultrasonic testing, by Jeff Vinyard and Harvey Haines, Applus RTD Technology Center, Houston, TX, USA
Full Matrix Capture (FMC) is the next evolution of Ultrasonic Testing (UT), having the potential to fully replace and or augment phased array techniques used in identifying various indications within a given material. FMC datasets consist of multiple A-scans from every combination of transducer and receiver, using each element within an ultrasonic array to generate a spherical wave, which in turn is received by each transducer element, generating a large ultrasonic dataset. Ultrasonic images are reconstructed from each FMC dataset through high-speed numerical computations using algorithms such as IWEX, a technique generally described as the Total Focusing Method (TFM). Our goal with IWEX processing is to produce an in-focus picture for any arbitrary indication/flaw, with any given orientation angle or possible depth within a material. The IWEX method can process up to 13 modes to reconstruct the entire inspection area, resulting in an image containing all angles of incidence. In addition, these 2-dimensional calculated images (or cross-sectional slices) can be combined into a 3-dimensional data set with the ability to rotate the image and view indications from any angle on multiple axes. This paper will show various flaws in various materials, and how the flaws can be more easily interpreted by using UT images produced from multiple modes, irrespective of flaw orientation and location.
 The development of in-situ test spools for assessing the performance of ILI tools during pipeline inspections, by Colton Sheets and Puneet Agarwal, Stress Engineering Services, Inc., and Matt Krieg, Marathon Pipe Line, LLC
The operation of today's pipelines is critically dependent upon the data provided by in-line inspection (ILI) tools. In order to effectively use the data from ILI tools to make informed integrity management decisions, pipeline operators must understand both the capabilities and limitations of these tools. Validation of ILI tools often consists of inspecting known flaws in a testing environment and comparing the results to the tool's published specification sheet. However, these results are susceptible to testing and data processing biases since they do not represent the actual conditions of an ILI run. The purpose of this study was to eliminate these biases by developing test spools that were installed in-situ during actual ILI runs to verify the tool specifications from various vendors. Over 120 crack-like anomalies were installed in the test spools to ensure a large enough sample size for the results to be statistically significant. The results from initial ILI tool runs highlighted areas for improvement in external versus internal anomaly discrimination, depth sizing near the tool saturation point, and detection of complex features (e.g. stacked flaws). The results also confirmed performance of the tool at or above its published specification for anomaly sizing.
 A case study how reduced uncertainties of latest generation of ultrasonic crack-detection ILI technology benefit engineering-criticality assessments, Stephan Tappert, Baker Hughes, Stutensee, Germany
To provide a more insightful and accurate feature description from crack ILI reporting as per the fitness for service analysis in API 1176, individual crack dimensions must be established to a given accuracy. Baker Hughes, a GE company, has established an absolute depth sizing specification, which already represented a significant shift from a traditional conservative depth reporting format in bands to a more accurate depth sizing. This paper describes how the latest generation of in-line inspection crack detection (CD) tool further reduces uncertainties in the engineering criticality assessment due to its increased accuracy. The development of a high-resolution CD tool and its benefits of supporting a more accurate integrity assessment are covered. The paper provides a case study in which the inspection results demonstrate the added value of the latest generation tool versus standard accuracy inspection. High scanning rates provide enhanced information of the presence of defects as small as 15mm in length. With qualitatively improved data, it is possible for the operator to allocate effort and financial resources more efficiently.
 Multi-diameter ILI tools: a cost-effective solution for the inspection of complex pipeline systems, by Dr Hubert Lindner and Michael Schorr, Rosen Group, Lingen, Germany
Multi-diameter ILI tools, bridging diameter changes between 2" and more than 10", are the main, and often only, solution to allow for in-line inspection of complex pipeline systems. In the oil and gas market, there are two different areas where the diameter changes tend to occur. Each has its own individual characteristics that differ largely from each other: Onshore systems are mainly used for product distribution. These commonly feature various lines of different lengths and various pipe diameters that have grown together over time. The main similarities of these systems comprise short radius bends and/or miter bends, often low pressures, and/or significant variations in flow volume and direction. Offshore systems are usually longer distance pipeline systems that use the diameter difference to overcome pressure variations, or export lines that feed into main trunk lines with larger diameters. Important challenges in these cases are, among others, high pressures, e.g. due to deep water location, gas velocities, challenging installations, and high wall thickness. Both areas require an individual approach to tackle the contradictory challenges these pipelines pose. In its over 30 years of serving the Oil and gas industry, ROSEN has developed a multitude of solutions resulting in the largest tool fleet on the market, virtually covering the entire range of multi-diameter pipelines. This paper will present case studies to highlight some of the significant achievements that have been made in this area over the years.
 Finding and assessing the severity of interacting threats using ILI, by Sarah Jane Dawson and Geoffrey Hurd, Baker Hughes, Cramlington, UK
Historical pipeline failures illustrate that there are often several mitigating factors that have led to the failure. For example, mitigating factors can be the presence of one of more defect types, multiple loadings acting on the pipeline and/or the parent pipe or weld material deficiencies. Threat identification is a key component to managing the integrity of pipelines. Various methods are described in both regulations and industry literature and have been used successfully to prevent, detect and mitigate the pipeline threats individually but not necessarily as threats in combination. Pipelines can, and often are, susceptible to the colocation of multiple threats such as internal and/or external corrosion, seam weld and/or girth weld defects, environmental cracking, laminations, gouging, dents, wrinkles, ground movement loads and other axial loads, etc. The occurrence of these threats individually may not be significant; however, where multiple threats occur together the resulting condition can be more severe. This paper looks at how to manage certain interacting threats via the identification of the locations where multiple threats exist, through to the evaluation and prioritization of the interacting threats in terms of severity. Focused examples are given on identifying circumferential cracking threats such as transverse SCC or where imperfect girth welds with reduced load bearing capacity are affected by the presence of axial tensile loads from ground movement. ILI and other supporting information is used to identify the individual threat indicators and the locations where multiple threat indicators interact. The threat interactions can be evaluated, and the appropriate mitigation identified.
 Effective inspection solutions for coated & non-coated subsea pipelines, by Andreas Boenisch, Hans Gruitroij, and Sebastian Hartmann, Innospection Ltd, Aberdeen, UK
This paper presents the advanced MEC and PECT techniques as well as the sophisticated tools that have been developed in response to market demands to resolve subsea pipeline inspection challenges. The next generation MEC (Magnetic Eddy Current) technique is used by Innospection as a key tool for integrity assessments support. With high defect detection capabilities, this technique is often used in combination with other advanced inspection techniques to provide reliable qualitative and quantitative data within a single deployment. The next generation PECT (Pulsed Eddy Current Testing) technique with enhanced wall loss detection capability is used for the inspection of heavy weight coated pipelines with coating thickness up to 250mm. The capabilities and benefits of both techniques shall be presented. As most subsea pipelines are unpiggable and internal inspection with the installation of subsea launcher and receiver involves huge costs, Innospection has developed the MEC-Combi PipeCrawler which is an external subsea pipeline inspection tool able to access and inspect the non-piggable subsea pipelines. The advanced diver deployed Subsea M-PECT DSA Scanner has also been developed to deploy the PECT technique to inspect the heavy-weight coated subsea pipelines. A semi-automatic scanning ring has been developed to improve the inspection performance, particularly the timing and reproducibility of the inspection. Finally, case studies for the inspection of the coated and non-coated subsea pipelines will be presented.
 Minimum bore restriction in offshore liquid pipelines, by Wayne Fleury, Halfwave A/S, Øvre Ervik, Norway and Kelly P. Angelette, Shell Pipeline Company LP
Pipelines are going deeper in depth and reaching even farther in to the lower tertiary fields of the Gulf of Mexico which puts a lot of different challenges in the pipeline systems. These challenges are but not limited to steel catenary risers, flex joints at or near maximum angle of deflection, non-return valves, subsea wyes and high pressure rated topsides infrastructure all contributing to the minimum bore restriction of the asset. In 2016 Halfwave AS was approached by a pipeline operator to inspect a 74 mile 18 liquids asset originating in deepwater Gulf of Mexico. The system is more than 150 miles in total length and produces up to 130,000BPD. The pipeline consists of two sections approximately 75 miles each. Due to the target depth of the platform and the geographical isolation of the Na Kika platform the export pipeline has a lot of special features, which lead to restrictions in bore. High pressure rated topsides infrastructure combined with requirements to base and filter material have led to a near 20% reduction in bore passing capabilities. In previous integrity programs, it was not possible to capture the restriction due to passage capabilities of existing ILI technologies. Halfwave AS and SPLC established a dialogue and integrity project to capture the pipeline threats while traversing a 20% minimum bore restriction. This paper will address the challenges involved in addressing the integrity of the Na Kika export pipeline, demonstrating the value of ART in minimum bore restrictions.
 External subsea pipeline inspection through coating, by Willem Vos, Halfwave A/S, Øvre Ervik, Norway
Since 1993, Halfwave and its predecessors have been implementing wide spectrum acoustic resonance inspections to determine the integrity of mainly gas pipelines. This paper will present methods to inspect subsea pipelines that are unpiggable. ARTEMIS (Acoustic Resonance Technology External Measurement Inspection System) is an ROV-mountable inspection tool for external inspection of subsea assets including rigid and flexible pipelines, flowlines and risers. It is easy to deploy and can be installed on most lightweight ROVs. The ARTEMIS technology's ability to perform inspection through thick subsea coating will be further explained. Other technologies would require the coating to be removed from the subsea pipeline. This is both, time consuming, expensive and potentially jeopardizes the integrity of the subsea pipeline. Some examples of the inspection results will be shown to give audience an idea of the high resolutions results that can be obtained. A case study for a subsea campaign that has been recently completed will be shared as an example. The application of this technology for the area of flexible risers and flowlines inspection will be explained. Halfwave is developing a unique solution together with clients that could bring a permanent solution to the operators.
 ILI of hydrogen-carrying pipelines, by Ronald Wills and Tod Barker, TD Williamson, Salt Lake City, UT, USA, and Ronald M Wills, Air Products, USA
There is already a network of over 1,600 miles of hydrogen pipelines currently operating in the United States and this mileage is growing. With this growth and as the assets age there is the need for periodic inspection of these pipelines for safety and integrity of supply. Magnetic flux leakage (MFL) has been used for decades as an in-line inspection (ILI) technology. MFL technology is very useful for detecting and sizing both internal and external corrosion in gas and liquid pipelines. MFL tools must be durable and robust, therefore MFL tool design has relied on well-established materials like high strength alloy steels and rare earth permanent magnets. These materials are especially susceptible to hydrogen embrittlement. Hydrogen embrittlement occurs when a material is mechanically stressed while being exposed to hydrogen which reduces the material tensile strength and ductility. To successfully inspect these pipelines, Air Products partnered with T. D. Williamson to develop a unique approach for successful in-line inspection in this pipeline medium. To design and deploy a tool that was capable of successfully operating in this environment, alternate materials and manufacturing methods were used. The result is a robust tool that is capable of metal loss inspection in hydrogen carrying pipelines. This paper and presentation will discuss some of the challenges that were resolved in the design, the capabilities of this unique inspection environment and how the entire project was executed successfully.
 ILI: a superior tool over pressure testing for integrity management, by Scott Riccardella and Pete Riccardella, Structural Integrity Associates, Centennial, CO, USA, and Dave Katz, Williams, Salt Lake City, UT, USA
In-line inspection (ILI) technology has improved significantly in the areas of probability of detection (POD) and flaw sizing accuracy, such that a greater level of safety may now be achieved through ILI. With accurate ILI and an associated repair criterion (i.e. repair all flaws greater than a specified size), smaller and greater numbers of flaws will be identified and repaired. A recently completed probabilistic fracture mechanics (PFM) analysis shows that high quality ILI, using EMAT technology, consistently outperforms Hydrotest in terms of probability of failure versus time following the inspection or test. The analysis incorporated several important features, including: vendor-specified sizing error margins and PODs, which were validated via in-ditch and destructive measurements on a substantial number of detected features an updated bathtub curve crack growth and life prediction model for pipeline steels exposed to near neutral pH environments from the recent literature accurate failure pressure predictions based on finite element-based limit load analysis that was validated with respect to Hydrotest failures and burst tests on the subject piping Monte Carlo analysis employing tens of millions of simulations to compute probability of failure versus time. The PFM analysis can also be used to provide guidance in establishing reassessment intervals, as well as to evaluate cost-benefit tradeoffs of various provisions of an integrity management plan. Examples of such uses are described in the paper.
 Using state-of-the-art ILI services to support fitness-for-purpose assessments, by Simon Slater, Rosen Group, Houston, TX, USA
ROSEN developed the RoMat PGS ILI service in direct response to the pertinent issues in the United States surrounding the lack of verifiable, traceable and complete material property documentation on many of the oil and gas transmission and distribution pipelines. The RoMat PGS service provides operators with a practical way of verifying the strength of every pipe spool along a pipeline as part of a combined ILI approach using multiple data sets. ROSEN has published a number of papers on how the service is specifically implemented in relation to the material verification process. In parallel to the continued use of RoMat PGS in that space, it became clear that other regions of the world, e.g. Europe and Africa, have different agendas and are not driven by the regulatory requirements quite as much as the United States. One of the key applications where many operators see a benefit of the RoMat PGS ILI service is the fitness-for-purpose assessment (FFP), for example defining the allowable operating pressure in the presence of features such as metal loss or environmentally assisted cracking. The FFP process is complicated and multi-faceted. The input data used in the FFP must be robust and representative with an appropriate level of conservatism. This paper demonstrates the different ways that the RoMat PGS ILI service could be used to support the FFP process. Example data will be used to show the analysis and decision-making process, and detail how the multiple data sets can be used to optimize the FFP.