The 29th INTERNATIONAL
Pipeline Pigging & Integrity Management Conference
plus Training Courses and Exhibition
George R. Brown Convention Center and the Marriott Marquis Hotel
February 27 - March 2, 2017
 The American pipeline dilemma: how we got there and a partial prescription for moving forward, by Jeff Wiese, TRC Solutions, Reston, VA, USA
America’s energy pipeline system network has quite reliably met the nation’s thirst for energy (to fuel our economy and feed our basic human needs) for decades. Surprisingly, we now find ourselves, after just as long, with the ability to meet all our basic energy needs – and then some – though parts of America must be replumbed in the process. However, the ability to grow this critical infrastructure is being seriously challenged by a very loose coalition of people from disparate causes, but aligned on opposition to new pipelines. Like most of the public, these folks have “lost” the connection to the origins of the energy they consume and, moreover, what it will take (and cost) to shift to cleaner burning and renewable sources. Regardless of one’s views of the legitimacy of this opposition, it’s affect is very real. Moving forward it must be our goal, but to ensure a broader consensus – and better performance – is needed if we are to overcome this stalemate.
 A qualification Route Map for the pipeline industry, by Michelle Unger, Rosen Group, Newcastle upon Tyne, UK, and Dr Phil Hopkins, PHL, Whitley Bay, UK
Pipeline standards and regulations require pipeline engineers to be both competent and qualified, but these requirements are neither defined nor explained. This paper starts by defining and explaining both competency and qualifications, and how to demonstrate and attain both. It also emphasizes the importance of ‘job qualifications’ compared to ‘academic qualifications’ and ‘professional qualifications’.
This main part of the paper presents a qualification ‘route map’ for the use in the pipeline industry. It is a process involving competency-based learning programs, leading to certified qualifications in various pipeline engineering disciplines. The main features of the process are:
- Qualifications, based on…
- Competency standards, which are
- Objectively assessed, and supported by
- Competency-based learning programs.
The paper presents examples of both the qualifications and standards, and explains a certification procedure for the qualification. The process can be used by both individuals seeking to confirm their competency, or by companies seeking to implement a competency management system.
 Closing the generational gap, by Jerry Rau, RCP Inc., Houston, TX, USA, and Jane Rau, JTrain Inc., Houston, TX, USA
The great crew change is upon us. According to Oil and Gas Monitor, 71% of people working in the oil and gas industry are over the age of 50. The average age of skilled employees means that many may retire within the next five to 10 years. Because it takes two to five years to become familiar with the industry, and another 10 or more years to take on a leadership position, pipeline operators, who depend on skilled, long-term workers, are feeling the pinch. As valuable people walk out your door, valuable knowledge leaves with them, and often that knowledge isn’t encoded in documentation produced on the job. How companies transfer and manage this hand-off is critical to their ongoing success.
This paper will describe the processes used to identify and prioritize critical organizational knowledge and the needs to transfer that knowledge among the representative generational groups. There are several approaches to transferring knowledge – through every generational transition from Baby Boomers to Millennials – and these methods will be described. We will discuss how to create a work environment that fosters knowledge sharing between generations, strategies to address different working styles while reducing employee tension and improving productivity, and finally methods to incorporate knowledge transfer into training programs.
There are several approaches to transferring knowledge and this paper will address each of them as they relate to the oil and gas sector:
 Preparing to transfer and accept the duty of care, by Chris Yoxall, Rosen Group, Houston, TX, USA, and Eric Lang, Enbridge Energy Partners, Houston, TX, USA
The oil and gas pipeline industry is at a tipping point with regard to transferring the duty of care from its current leaders to the next generation. If we do nothing, we risk the loss of the knowledge and experienced gained within the pipeline industry over the last 20 years. However, if the industry aggressively and collectively works toward the retention and development of the next generation, as well as toward the transfer of knowledge from its subject-matter experts to those prepared to accept it, instead of a potential loss it could be a step-change opportunity for the industry.
The retention of the next generation will likely require some adaptation of more traditional management approaches and methodologies often in use within the oil and gas pipeline industry. For example, where previous generations might have had ambitious goals, the next generation will inform you of them almost immediately and without apology. It is very important not to discount their ambition but rather to help them understand the role they are reaching for, what it will take to get there, and most importantly, hold them accountable for behavior not aligned with their ambition.
The transfer of knowledge, specifically at the rate required, will involve much more effort than management modifications and is likely more critical. Members of the next generation must prepare themselves to accept the duty of care through high performance in their role to absorb as much knowledge as possible, as well as in efforts to gain knowledge and experience outside of their day-to-day activities through industry opportunities and committees. The transfer of knowledge will also require a significant effort from the industry’s leaders. It will require them to seek-out opportunities to mentor and coach, to participate and encourage and offer assistance and support to those preparing themselves to accept the duty of care, and to encourage their peers to do the same. It will also require leaders to appreciate the next generation for its strengths such as being technically very competent, having the ability to find more-efficient and effective ways to problem identification and solving, and being fearless when it comes to taking on technical challenges.
If the industry collectively gets behind its leaders and its emerging leaders, and the different generations leverage one another’s strengths to address the knowledge gap in the near term, the industry’s goal of ‘zero spills’ would be that much more attainable in the future, and we would achieve this in a shorter time frame.
 Developing a new pipeline management system from scratch, by James Kenny, Stantec Consulting, Calgary, AB, Canada
Emera and Stantec recently collaborated to develop a new management system for Emera’s Brunswick Pipeline. This 18-month process was a key part of Emera’s project to assume the operations of the National Energy Board-regulated 145-km long 30-in OD sweet natural gas pipeline asset in New Brunswick, Canada. Stantec developed a process for gathering all of the regulatory, environmental, legal, and technical requirements into a single database repository, and then assigning the applicable requirements from these source documents to the various management-system programs, plans, manuals, processes, and procedures. One major document to come out of this work was an integrity-management program (IMP). Stantec and Emera collaborated on writing the management-system documents to meet the clauses identified in the requirements database. The management system was developed from the ground up to be suitable to a small organization with a single, yet regionally important, pipeline asset. This paper provides a summary and overview of the process used to generate the database repository and the corresponding management-system documents.
 ALARP and zero leak tolerance – applications for the pipeline industry, by Phillip Nidd, Dynamic Risk, The Woodlands, TX, USA
An integrity-management plan (IMP) comprises a series of processes and linkages that must encompass a risk-management framework and fit within a company’s overall corporate and asset-management system and safety culture. The IMP serves as the cornerstone in the management of pipeline risk and safety performance, and is critical in preventing system failures, injuries, property damage, and other serious consequences.
‘As low as reasonably practicable’(ALARP), ‘so far as is reasonably practicable (SFAIRP)’, ‘best practice’, and ‘industry leading practice’ are all terms applied within our industry as IMP performance measurement tools and target goals.
On a practical level, application of these target goals and measurement tools raises questions relating to how we truly measure the effectiveness of an IMP and how application of ALARP and best-practice approaches can be reconciled with our over-arching pipeline industry zero-leak-tolerance target goal.
Firstly, the application of an ALARP approach, while perhaps not formalized within an IMP is – in reality – ‘how we do our business’. Once a risk is established and quantified for a specified threat, maintaining that risk as low as reasonably practicable forms the basis for pipeline operator integrity-management programs and risk-management decisions.
Secondly, to achieve an acceptable ALARP level of risk, pipeline operators must, as a minimum, undertake specified actions in compliance with regulation. However, most operators, in addition, apply a supplemental ‘best-practice’ approach based upon subject-matter expertise and appropriate consensus industry standards.
Thirdly, terms such as ‘low’, ‘practicable’, ‘best practice’, or ‘leading industry practice’ exhibit widely varied connotations in terms of pipeline-operator application, both internally as a justification for allocation of resources and funding, and also externally as interpreted by a regulator, outside parties, or through legal scrutiny.
A pipeline-management system (the Management System) provides a framework to manage risk throughout the pipeline lifecycle and documents the objectives and the associated performance requirements, and identifies the proper sequence of processes and procedures to be managed, scheduled, tracked, documented, communicated, and reported. An effective Management System is based upon a foundation of underlying principles that include leadership, management of change, performance and accountability management, quality management and continuous improvement, workforce competency and qualifications.
A properly structured and developed pipeline-operator management system must provide a framework to establish over-arching pipeline-integrity and risk-management effective measurement metrics as follows:
 Human-centric approach to improve pipeline NDE, by Patrick McCormack, Battelle Memorial Institute, Columbus, OH, USA
The USA is critically dependent on natural gas and petroleum liquids transported through pipelines. Assuring the long-term integrity of these existing pipelines through non-destructive evaluations (NDE) is essential. However, NDE may lack vital accuracy and reliability due to unintentional human error. Often pipeline operators feel that they can trust only one individual NDE inspector. This uneasiness in NDE is warranted as human error poses a significant threat to safe and efficient pipeline operations. Recognizing these facts, the Department of Transportation (DOT), Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (PHP) issued a Research Announcement (DTPH5615RA00001).
Battelle entered into a Transaction Agreement (DTPH5615T00010) Human centric approach to improve pipeline non-destructive evaluation performance and reliability to apply a phased approach to first conduct a front-end analysis (FEA) to identify major human-factor influences on NDE inspector performance (Phase 1), and then address those high-impact positive and negative influences in subsequent phases with human (Phase 2) and technology interventions (Phase 3) designed to improve inspection performance across the work population.
In this first phase of the effort, Battelle conducted a human-performance technology (HPT) FEA with 24 accomplished NDE pipeline inspectors from three partner organizations (Mistras Group, Jentek Sensors, and ApplusRTD). The FEA comprised a structured interview to identify what accomplishments (i.e., valuable outputs) are necessary to achieve the inspector’s overall goal of producing structural integrity data and, in turn, what critical skills and behaviors (i.e., actions) are implemented to produce the outputs necessary to meet that goal. In addition, inspectors were asked general, open-ended, questions regarding positive and negative influences on the successful completion of the inspection process. A pipe sample was provided to a subset of inspectors who were asked to demonstrate the inspection process as part of the interview.
Analysis of the structured data suggests a close agreement between inspectors regarding their overall job accomplishment as an NDE inspector and the associated major accomplishments. Inspectors largely agreed that “Asset structural integrity data suitable for engineering and management decisions” was the overall job accomplishment. Average difficulty and importance ratings indicate that inspectors place the greatest emphasis on (1) the coating and pipe assessment, (2) decisions regarding data acceptability, and (3) production of the final report.
An analysis of the comments from the HPT process identified several performance-shaping factors and positive and negative influences on the inspection process. Performance-shaping factors were organized into seven categories: (1) organizational, (2) operational, (3) work task, (4) technology, (5) physiological/cognitive, (6) personality, and (7) environmental. In general, inspectors are team-oriented individuals who value clear communication. Commonly mentioned positive influences included good team chemistry, positive feedback, management involvement, and good communication. Negative influences included workload, time pressures, and poor communication.
Battelle will work with its partners to select, implement, and evaluate a number of interventions in later phases of this project. Some potential interventions that could be selected for evaluation include: organizational interventions, such as an improved communication process between management and inspection teams; operational interventions, such as expanding training opportunities; work-task interventions, such as promoting a healthy work-life balance; and technological interventions, such as updated equipment requiring less manual signal interpretation.
 Comprehensive NDE technology assessment for LF-ERW seam anomalies, by Jennifer O’Brien, Battelle Memorial Institute, Columbus, OH, USA, and Pushpendra Tomar and J. Bruce Nestleroth, Kiefner & Assocs, Columbus, OH, USA
Improved in-line and in-the-ditch inspection tools for assessing low-frequency electric-resistance welds (LF-ERW) are emerging for the pipeline industry. Pipeline owners need data on the performance of these tools to manage the integrity of their lines. Government regulators need to understand the capability and limitations to these tools to establish meaningful regulations. The purpose of this paper is to provide data on accurately and reliably detecting and sizing crack-like defects in the seam of LF-ERW pipe, properly identify the anomaly type, and provide sizing information for fitness assessment.
Pull tests of electro-magnetic acoustical transducer (EMAT) and magnetic-flux leakage (MFL) ILI tools from two vendors examined the pipe samples that were removed from service. The current inventory includes through-wall cracks, part-through-wall surface cracks, and embedded flaws. Crack geometries vary from hook cracks and cold welds to selective seam-weld corrosion. In addition, the inventory consists of multiple vintages, various grades, and several manufacturers. Non-destructive evaluations (NDE) techniques for in-the-ditch applications were used to down-select pipe samples for ILI testing. Methods included magnetic-particle inspection, phased-array, time-of-flight diffraction, and a full-field inversion technique. The detection and sizing capabilities of each were tested.
Actual crack sizing was then confirmed via metallography and burst test. A three-way comparison was conducted between the crack sizes as determined by destructive examination, EMAT ILI, and in-the-ditch NDE methods.
 ILI and NDE characterization of pipeline manufacturing flaws and confirmation through full-scale testing, by David Futch, Ronald W. Scrivner, and Rhett L. Dotson, Stress Engineering, Houston, TX, USA, and Andrew Pulsifer, Enable Midstream Partners, Houston, TX, USA
Pipeline-manufacturing flaws, such as slivers, can be difficult to accurately characterize and size during in-line inspection. After discovery of longitudinal flaws of varying depth and length, full-scale burst tests and metallography were conducted to confirm the size and morphology of the features. Metallography was performed on the samples to characterize the flaw morphology. Metallography indicated that the flaws present were consistent with original manufacturing mill slivers. The metallography also confirmed that the flaws showed no evidence of in-service growth. While flaw depths varied, the remaining wall thickness of the pipe was within API 5L minimum tolerances. Flaw depths measured via metallography were compared to those reported by the original ILI vendor (ILI), phased-array ultrasonic testing (PAUT), and RTD’s IWEX system. Flaw-depth measurements varied between systems but were consistently greater than those determined through metallography. Slivers are typically very shallow flaws; consequently, they can be difficult to accurately size under ideal conditions with typical NDT methods such as PAUT. Sizing the flaws in these samples was further complicated by the presence of inclusions and laminations typical of vintage pipeline steels. In this respect, the IWEX system was superior in that it allowed the user to visualize the flaw through the pipe wall. In this case, the flaw orientation was shown turning parallel to the pipe’s outer surface in the IWEX scans. Research indicated that manufacturing flaws such as slivers represent a minimal integrity concern in pipelines unless they grow during fatigue cycling, which is unusual. This assertion was confirmed through full-scale cycle and burst tests of the flaws.
 In-ditch materials verification methods and equipment for steel strength and toughness, by Michael J. Tarkanian, Steven D. Palkovic, Kotaro Taniguchi, and Dr Simon C. Bellemare, Massachusetts Materials Technologies, Cambridge, MA, USA
Material verification for strength and toughness is an ongoing challenge for oil and gas transmission pipeline integrity. In this paper, we describe two portable and non-destructive technologies developed to provide this data without requiring the shutdown of operations. The hardness strength and ductility (HSD) Tester probes the outer surface of a pipe to determine tensile properties. This technology has been validated for determining the steel grade and welded seam type of electric-resistance-welded (ERW) pipeline materials. The HSD Tester provides a safer and cheaper alternative to hydrostatic testing for determining allowable operating pressures without the risk of additional fatigue cycles. We are also developing the fracture-toughness tester (FTT) which evaluates fracture resistance by generating local tension in a small volume of surface material. This will eliminate the need for expensive fracture-toughness experiments and provides the first practical method for field measurements of toughness. The material-verification data that these testing solutions provide will reduce uncertainty regarding the risk of catastrophic failures, and help to prioritize inspections and repairs to extend the lifetime of existing pipelines.
 Non-destructive testing to meet materials verification requirements, by Hamood Rehman, G2 Integrated Solutions, Houston, TX, USA
The new Gas Mega Rule provides additional emphasis to resolving ‘incomplete records’, requiring a plan and procedures to verify the physical characteristics of all pipe and fittings in Classes 3 and 4, and HCAs where reliable, traceable, verifiable, and complete (RTVC) records do not exist. Instrumented indentation testing (IIT) along with optical-emission spectrometry (OES) is being used for non-destructive determination of mechanical properties in the ditch, including yield strength, ultimate tensile strength, and chemical composition. Owners and operators will need to incorporate costs of these new tools and techniques in their budget planning for all pipelines where RTVC records do not exist or are currently inadequate. This paper will cover aspects of the material documentation plan required by §192.607, and discuss where non-destructive testing can be applied to meet the proposed regulatory requirements. The paper will also present data that seem to show the good agreement between the destructive tensile laboratory tests and non-destructive indentation tests in the field.
 Collective effects of leakage, temperature changes, and entrapped air during hydrostatic testing, by Dr Lawrence Matta, Stress Engineering Services, Houston, TX, USA
Hydrostatic testing is commonly used as a means to verify the integrity of a pipeline. Testing prior to placing a pipeline in service is intended to demonstrate the adequacy of the materials and construction methods used, and periodic retesting can be used to show that the pipeline maintains adequate strength. While not the intended purpose, it is tempting to consider using hydrostatic testing as a means for detecting leaks in a pipeline segment. This study explores the sensitivity of the pressure drop due to leakage compared to other factors that cannot be completely controlled during hydrostatic testing.
A decrease in pressure during hydrostatic testing does not necessarily indicate the presence of a leak. It is well known that temperature variations will also result in pressure changes during testing, and that temperature changes can mask the effects of small leaks. Trapped air can also mask the presence of a leak, because gas pockets can significantly affect the apparent compressibility of the water in the pipeline. If a small leak is present, the pressure loss due to the leak may be less than expected because the expanding air in the pipeline will tend to keep the pressure constant. Trapped air also reduces the effect of temperature changes on pressure.
This paper reports an analysis of the comparative effects of temperature, trapped air, and leakage on the pressure during hydrostatic testing. Equations were developed to investigate the effects of temperature changes and leakage rates on the pressure during hydrostatic testing with trapped air present. By comparing the relative magnitudes of the effects of these factors for a given pipeline geometry, insight can be gained into the minimum size of a leak that can be reasonably detected using hydrostatic testing.
During hydrostatic testing, leaks in the test section will result in a loss of test pressure, and a reduction in water temperature during the test hold time will also typically result in a pressure decrease. The results of this study confirm that small leaks become more difficult to detect as the length of the hydrostatic test section increases. The detectability is not necessarily a function of the precision of the pressure-measuring device, because the effects of leakage can be masked by temperature changes and the effects of trapped air in the piping. Small leaks are most easily detected in short test sections with stable temperatures and when very little air remains trapped the piping.
The magnitudes of pressure changes resulting from temperature variations and leaks depend on the starting temperatures and test pressures. The effect of temperature changes on the test pressure are minimized for cold-temperature tests with water near 40°F, and increase as the test temperature increases.
The results also show that the presence of relatively small volumes of trapped gas can significantly affect the apparent compressibility of the test fluid. If a small leak is present, the pressure loss due to a leak may be less than expected. This effect becomes smaller at higher test pressures.
 Practical considerations for minimizing hydrostatic-test failures, by Gary Zunkel, Rachel Sorrentino, and Megan Halver, Lake Superior Consulting, Bloomington, MN, USA
The use of integrated, historical, pipeline data can allow pipeline operators to understand and manage risk when planning and preparing for hydrostatic testing of pipelines. With the proposed changes to the US natural gas transmission pipeline regulations, hydrotesting activity will likely increase over the next several years. If the operational impacts of that testing are to be minimized, in-depth planning of each hydrostatic test will need to consider not only the efficiency of test execution but also the likelihood and consequence of test failure. Historically, industry focus has been on application of the results of hydrostatic testing to ongoing operational and integrity-management decisions, with less emphasis placed on using integrity-management principles and existing data to predict and manage the results of specific hydrostatic tests. The application of risk-management principles within the context of hydrostatic-test planning and execution varies widely within the industry. This paper will offer guidance on incorporating such principles and data into hydrostatic-test planning in a way that facilitates decision-making regarding risk-mitigation activities to be taken prior to or during a hydrostatic test, and will provide examples of risk mitigation and cost/schedule savings which were achieved on real hydrotest projects by applying this guidance.
 Multiple functions of automated pigging systems, by David Wint, Audubon Field Solutions, and Roxy Mounter, WeldFit Energy Group, Houston. TX, USA
In the past, automated pigging systems have been synonymous with gravity-feed spherical pig systems. Spherical-type pigs serve a singular purpose for the removal of liquids in rich natural gas systems. However, their liquid-removal efficiency can be unpredictable, along with the inherent issues of stalling at fittings and their inability to travel in low-flow conditions. Recent innovations of automated pigging systems allow the use of multi-purpose pig types to provide quantitative results for operators to perform numerous functions. Most recently, the latest design of horizontal automated pigging systems can accept up to ten of any maintenance pig type to provide cleaning, batching, liquid removal, and in-line inspections.
This presentation will focus on operational pigging case studies with data provided by two domestic operators with automated pigging systems that include:
The case studies that are presented will illustrate a direct correlation between the use of automated pigging systems to achieve economic benefits and risk reduction.
 Quick-opening closures, by Jack Lollis, Kyle Corriveau, Jesse Green, and Larry Payne, Pipeline Equipment, Inc., Tulsa, OK, USA
Quick-opening closures are used on pipelines and process equipment to allow the operator quick and easy access to the inside of a pressure vessel. It is estimated there are over 100,000 closures active on any given day within the USA. Primarily, quick-opening closures are used on pig launchers and receivers, pressure vessels such as filter separators, and blowdowns on vertical vent stacks.
This paper will discuss the differences between a closure and a quick-opening closure, applications for closures, the codes that regulate the design of closures, and the features and benefits of various closures in today’s market.
 Performance of a low-drag seal assembly for pipeline pigging and a novel corrosion-pit cleaning brush, by Dr Dan Fletcher, Vincent Foong, and Michael Hooper, Fiberbuilt Manufacturing, Calgary, AB, Canada
Pipeline corrosion mitigation is critically important to ensure the safe and responsible operation of the world’s pipeline infrastructure. Pipeline-maintenance and cleaning pigs are typically utilized in an overall corrosion-mitigation program which can include: utility pigging stages for debris and wax removal, scouring and cleaning of the interior pipe walls and batching chemical application, and intelligent pigging stages for the inline identification, inspection, and monitoring of internal corrosion.
Cleaning internal corrosion pitting presents a specific challenge in pipeline-corrosion mitigation. Localized corrosion pitting in pipelines can create localized environments supporting under-deposit corrosion (UDC) and the ideal environment for microbially-induced corrosion (MIC). Small-diameter pits deep into the pipeline wall represent the most challenging scenario due to the difficulty of reaching deep into the small pits and removing sludge and deposits. If allowed to progress without effective cleaning, these small corrosion pits can lead to pinhole pipeline leaks that are difficult to detect with standard SCADA and flow-assurance methods, but which can lead to significant environmental incidents.
The Pipeline Integrity and Corrosion Monitoring (PICOM) team at Alberta Innovates Technology Futures (AITF) has developed and previously presented a standardized testing methodology and flow loop to quantify the effectiveness of pigging for cleaning corrosion pits. These detailed studies identified that significant improvements are required to more effectively address cleaning corrosion pits to improve the mitigation of under-deposit corrosion.
Fiberbuilt Manufacturing has developed a new pipeline pig system to address and improve the cleaning of these pipeline corrosion-pit features. This newly developed pigging system was tested to quantitatively determine the improved corrosion-pit cleaning performance. The new Fiberbuilt pigging system was also tested in multiple pigging run scenarios to determine and define the optimum strategy for corrosion-pit cleaning as a part of the overall mitigation pigging program. The original testing and qualification program was extended from previous studies and the full results will be presented here.
In addition to the advances in corrosion-pit cleaning, this novel pigging system utilizes a next-generation seal design providing an effective pigging seal with only a very low differential pressure required. The seal platform creates a customizable drag (operating differential pressure) for pipeline pigs that can virtually eliminate pig surging. When used in an ILI application, the new pigging seals provide an extremely stable pigging-speed profile that improves overall inspection performance and accuracy. Detailed results including demonstrations of the customization of operating back pressure will be presented.
 A primer on isolating pipe-in-pipe hot-oil pipelines: a Northern Alberta case study, by Stephen Rawlinson and Doug Krokosz, STATS Group, Houston, TX, USA
Pipe-in-pipe (PiP) systems onshore are a new approach for transporting viscus fluids particularly for buried pipelines in cold climates. This paper presents the results of the first onshore PiP isolation to facilitate the repair and replacement of a damaged section of pipe. It focuses on the technical challenges encountered and solutions developed for addressing the pre-strained forces incumbent in the PiP design. While the context of this paper is the PiP example, it is applicable to other extreme temperature applications where pipelines can be susceptible to movement during the isolation and repair stages.
 Advances in pig detection and assurance, by Andy Marwood, Online Electronics, Aberdeen, UK
Detecting the launch, receipt, and passage of pigs passing features is critical to effective pigging operations. Advances in the method(s) of pig-passage detection have been made in recent years which are of substantial benefit to the pipeline operator. The modern technology used for this purpose has features which can also provide an insight into what else is happening within the pipeline, thus supporting assurance efforts such as chemical dosing, cleaning pigging and – potentially – monitoring for wax and scale deposition.
 Integrity inspection - identifying and locating leaks on buried terminal piping, by Ian Harris, Praxair Services Inc., The Woodlands, TX, USA
Unpiggable buried pipelines continue to be a major issue for the many of the petroleum terminals and bulk-fuel-storage facilities throughout the U.S. In recent years, many facilities have experienced failures and demand better methods to completely inspect and verify leak-tightness of buried pipelines within a facility. As a result, terminals have been investing in a facility-wide leak-detection inspection programs. This paper details the methodology of the Tracer gas-leak detection and expected results.
Typically, owner/operators review facility assets and develop testing matrix based on associated risks and consequence of failure for each. The focus of the leak-detection program is specific to buried piping such as drain lines, manifold lines, product lines, prover lines, and rack lines.
The paper also details the Tracer gas technology, how it works, its benefits, as well as the limitations of the technology. Also described are the findings from the facility tests, and lessons learned and recommended best practices, when using the method.
[20a] Development of an Industry Test Facility and Qualification Process for ILI Technology Evaluation and Enhancement, by Hans Deeb, Pipeline Research Council International, Inc. and Pablo Cazenave, Blade Energy Partners
In 2015, Pipeline Research Council International, Inc. (PRCI) designed and constructed an ILI pull test facility. This project aims to expand knowledge of ILI technology performance and identify gaps where new technology is needed. Additionally, this project aims to provide a continuing resource for ILI technology developers, researchers and pipeline operators to conduct future research at the Technology Development Center (TDC) in Houston, TX. PRCI engaged Blade Energy Partners, Ltd. to conduct the evaluation of the ILI data obtained from testing on the pipeline strings at the TDC, and the resulting data with the findings are presented in this paper.
 The Liquid and Gas Mega Rules - pigs in a poke?, by John Jacobi, G2 Integrated Solutions, Houston, TX, USA
The recently proposed Liquid and Gas Mega Rules significantly change the playing field with respect to integrity management of gas and liquid pipelines that are regulated under 49 CFR Part 195 and Part 192. ILI will be the required method of pipeline assessment and reassessment unless the affected lines are unpiggable. Documentation requirements are proposed to increase significantly, and only individuals qualified by knowledge, training, and experience would be allowed to analyze ILI data to determine if a condition could adversely affect the safe operation of the pipeline. The author of this paper, a recognized regulatory expert and former PHMSA CATS manager, will discuss many of the specifics and the practical implications of the proposed new rules and their impact on the pigging industry.
 A change in paradigm…. TVC will be process and not a project in the future, by Amy Jo McKean, TRC, Kansas City, MO, USA, and Rich Henry, TRC, Englewood, CO, USA
On April 8, 2016, PHMSA published in the Federal Register a Notice of Proposed Rulemaking (NPRM) titled Pipeline safety: safety of gas transmission and gathering pipelines seeking comments on changes to the pipeline safety regulations for gas transmission and gathering pipelines. While this comment period is now closed, there is no question that PHMSA expects operators to complete the ‘traceable, verifiable, and complete’ (TVC) process for their legacy systems. At the pipeline component level, this means operators need backward traceability to identify when a suspect component was installed, inspected, and maintained, as well as where and how it was manufactured, tested, received, and stored before installation.
This paper will outline the effort and research necessary to maintain TVC compliance and support MAOP validation. TRC will also discuss and demonstrate our recommendations, emphasizing the need for operators to adjust the culture within their organization from a “get the pipe in the ground” mentality to one that emphasizes the value of collecting critical data right the first time. Our solution for the industry begins with the end in mind and by changing the culture and process we are saving the operator time and funds in the future. TRC accomplishes this shift in process by encouraging continuous visibility and moving validation further upstream which translates to a TVC process in real-time.
 Effectively assessing the piggability of pipelines – an innovative approach, by Stefan Vages, Rosen Group, Calgary, AB, Canada
For a comprehensive assessment on the piggability of a pipeline various different types of information need to be taken into consideration. Starting with the mechanical configuration of the pipeline (outside diameters, wall thicknesses, bend radii, etc.) and the operating conditions (pressure, flow, etc.) an initial assessment can be created. This initial assessment allows determination of whether the pipeline is piggable in its current mechanical configuration and under the corresponding operating conditions.
In the case where the initial assessment concludes that the pipeline is not piggable in its current state, further options are required to be explored, and are usually considered to include:
The first option (modification of the pipeline) might be the easiest approach in some cases, although it can be very costly for others. New-tool developments present the opposite scenario: while there is no cost with regards to pipeline modifications, more projects need to be available in order to justify the development of a new ILI tool. As a last alternative, it is possible to have modifications to the pipeline and modifications to the existing ILI tools in order to accomplish the goal of obtaining the relevant data.
Typically, these assessments are carried out by the integrity departments of the pipeline operator or engineering and consultancy companies. This paper will describe the advantages of involving an ILI vendor in the process of assessing the piggability of certain pipelines. Concrete examples for the effectiveness of the close co-operation between pipeline operator and ILI vendor will be given.
 Managing the seam-weld crack threat: common pitfalls and recent progress, by Dr Ted Anderson, Team Industrial Services, Boulder, CO, USA, and George Brown, Quest Integrity, USA, Boulder, CO, USA
The crack threat in seam-welded pipe is becoming more acute over time due to the aging pipeline infrastructure. Recent high-profile releases and heightened regulatory scrutiny provide additional motivation for operators to focus on this issue. It is absolutely crucial for operators to apply the best-available technology to managing the crack threat. Moreover, it is important that the industry continue to enhance and improve crack-assessment technology.
One of the most important ingredients in any crack-management program is the fracture model, which relates burst pressure to flaw dimensions and material properties. Errors in burst-pressure estimates propagate through the integrity-management program and can adversely affect decision making. Traditional pipeline-fracture models, including Log-Secant and CorLAS, suffer from a number of serious shortcomings. These methods exhibit significant modeling error in the toughness-controlled failure regime. Benchmarks to burst-test datasets frequently obfuscate the limitations of Log-Secant and CorLAS because the test results are predominately flow-stress-controlled failures, where cracks behave like metal-loss flaws.
Recent PRCI-funded research resulted in the development of a state-of-the-art fracture model that is based on fundamental principles of fracture mechanics. This new fracture model, known as MAT-8, was fitted to approximately 200 3-D elastic-plastic finite-element simulations of pipes with axial cracks.
A limitation of existing fracture models – including MAT-8 – is that they assume sharp planar cracks, oriented perpendicular to the hoop stress, and with ideal crack front profiles. In the near term, naturally occurring non-ideal crack-like flaws can be handled through an empirical adjustment factor on fracture toughness. In the longer term, further research is necessary to incorporate real-world flaw geometries into the MAT-8 approach.
 A case study on circumferential-crack detection, by Thomas Hennig, NDT Global Corporate Ltd, Dublin, Ireland, Mark Brimacombe, Pembina Pipeline Corporation, Calgary, AB, Canada, and Cory Wargacki, NDT Global Corporate Ltd, Dublin, Ireland
Axial cracking has become a significant and well known threat to pipeline systems. Defects are usually found in combination with external corrosion/coating disbondment (SCC) or in/at the longitudinal welds. ILI service providers developed inspection technologies for liquid and gas lines that are widely accepted. Compared to axial cracking, circumferential cracking does not yet play a significant role in pipeline integrity. Nevertheless, pipeline operators observe such defects, often in combination with circumferential welds and/or local stress/strain accumulation. These can be caused by pipeline movement, especially in mountainous areas.
In 2014 NDT Global was approached by an operator to inspect a 12-in pipeline system for circumferentially oriented cracks and crack-like indications. The system is more than 800 km (498 mile) in length and transports crude oil from Northern British Columbia to Kamloops. The pipeline consists of six sections ranging from 61 km to 251 km (38 mile to 156 mile) each. Due to the geographical location of the pipeline, this pipeline was considered to be susceptible to circumferential stress (both in the base material and in the girth welds) evolving from slope subsidence and outside forces acting on the pipe.
In previous integrity digs, circumferential crack-like indications were identified and this entire system required inspection to determine the severity of this threat. NDT Global established a close to achieve a successful ILI campaign addressing this threat.
This paper discusses the challenges resolved during the course of the project. Lessons learned from previously inspected sections have been applied to ongoing inspections. The authors will briefly introduce the pipeline system and inspection campaign. In detail, a discussion of field-verification findings and ILI results will be shown. Finally, conclusions drawn by the pipeline operator are presented.
 Engineering-critical assessment for cracks in pipelines, by Andrew Russell, Rosen Group, Newcastle upon Tyne, UK
Some comments on the methods suggested in the Notification of Proposed Rule Making for Determining Maximum Allowable Operating Pressure by ECA.
Engineering-critical assessment (ECA) is a process used in many industries to apply the science of fracture mechanics to the evaluation of damaged or defective structures. Fracture mechanics and the ECA process have been applied in the pipeline industry for many years in a variety of ways. When installing offshore pipelines in deep water, for example, it is common to complete an ECA to set limits for girth-weld flaws. This generally involves extensive testing of the parent pipe material and sample welds to accurately characterize their strength, ductility, and toughness, allowing detailed fracture-mechanics’ calculations to be completed with some confidence.
For onshore pipelines, simplified assessment methods have been developed with less-stringent material data requirements. These are applicable to normal linepipe materials, to allow the rapid and safe assessment of multiple corrosion anomalies; however, some operators have employed detailed fracture-mechanics’ methods for onshore pipelines. This has led to recently published proposed changes in the minimum federal safety standards for the Transportation of natural and other gas by pipeline (CFR 192). These changes include, in Section 192.624 (c) (3), a requirement that any cracks or crack-like features are analyzed using the methods given in three specified Battelle reports, or other proven methods including API 579, CorLAS, and PAFFC. Further references are made to the Paris Law for fatigue crack growth prediction and the Raju/Newman model for brittle-failure-stress calculation.
This paper provides an overview of these methods based on years of experience in applying them to pipelines around the world, as well as a discussion of the practical issues that can be encountered when applying them to flaws in ageing pipelines (such as limited weld-property data), and a commentary on the implications for integrity management. The issues are illustrated with a number of case studies.
 The impact of crack profiles on pipeline integrity: advancing assessments with new ILI capabilities, by Jennifer O’Brien, Battelle Memorial Institute, Columbus, OH, USA, Sean Moran, TD Williamson, Tulsa, OK, USA, and Dr Mike Kirkwood, TD Williamson, Dubai, UAE
This paper presents the current status of ILI tools using multiple sensors to measure not just a defect’s depth profile but also other information that can be used in the integrity assessments of crack-like anomalies. As ‘crack-mission’ ILI tools improve in performance it is now possible to get a defect profile as opposed to the traditional method of presenting the length and a binned range for the depth. Also, certain ILI tools are now generating supplementary information (such as material data) that presents an interesting opportunity to assess the integrity of the anomalies using advanced engineering critical assessment methods.
The paper will highlight current ILI technology using both high- and low-field magnetics as well as electromagnetic-acoustic transducer (EMAT) technology to acquire data for an advanced engineering-criticality assessment (ECA) to be conducted on anomalies reported by ILI. The paper also presents three levels of assessment that can be applied to the ILI data:
The paper will provide a case study based on the ILI technology along with Battelle’s PipeAssess software to demonstrate the value of the approaches presented.
 The need for pinhole leak detection: a comparison of different technologies and the professional approach with ATEX-certified leak detection pigs, by Rene Landstorfer, Gottsberg Leak Detection GmbH & Co KG, Oststeinbek, Germany
Pinhole leaks in pipelines can be a big problem for operators, particularly because they cannot be detected with conventional methods like SCADA, connected permanent monitoring, or other online systems. Today another increasing problem is hot tapping and theft from pipelines: the criminals are very sophisticated with a lot of experience and professional equipment, so that there occurs – for example –no big pressure wave that can be detected by pipeline-monitoring systems. Also, the holes they drill are so small, they cannot be detected with on-line leak-detection systems. Even the amount of product removed is small enough to not be detected by the pipeline’s flow-measurement systems.
All these very small leaks, whether they occur naturally or by third-party intervention, can lead to spills that possibly will not be detected over a long time; many operators underestimate the risks of these spills and necessities of leak detection for leaks with a spill rate down to a few liters per hour.
Conventional methods will detect leaks of several hundred liters per hour in the best case, and complex wall-thickness inspections with UT or MFL tools cannot find every defect that may cause a leak at some time in the future. For example, defects that have a size too small to be detected with these devices can grow and lead to a small leak from which nobody knows of, and which cannot be anticipated. This leak can then continue over weeks or months, and will not be recognized with conventional leak-detection systems.
This paper describes Gottsberg’s latest leak-detection system: the company is a developer and manufacturer of one of the world’s leading products in the field of leak detection for smallest leaks, and has again improved the safety for pipelines. The pioneering technology has been optimized for any disturbance events to be eliminated. For example, new filtering algorithms have been developed which are better adjusted, together with a next-generation amplifier for the new, even-more sensitive, hydrophones. This is mainly used for better noise detection of relevant processes within the line and for clear recognition and evaluation of noise after the run.
The presentation will give an overview about the challenges pipeline operators are facing in regard to the smallest or creeping leakages, as well as with reference to national and international regulatory frameworks such as TRFL or API 1175. Different technologies for leak detection will be introduced and focus will be placed on the technical improvements of the new generation of leak-detection pigs.
 Evaluating ILI tool performance using a validation process, by Dr Yanping Li, Gordon Fredine, Yvan Hubert, Janine Woo, and Sherif Hassanien, Enbridge Pipelines, Inc., Edmonton, AB, Canada
Since there is a wide array of ILI tools currently available from a number of different ILI vendors, it is important to evaluate the tool performance to ensure that an appropriate tool has been selected for the expected defect types on the pipeline. ILI tool performance can be evaluated for each individual inspection using the validation process, and the validation results are critical to an excavation program. ILI tool performance can also be evaluated using the combined ILI data sets of several inspections by the same ILI tool to evaluate the tool’s overall performance. The validation results identify the strength and weakness of an inspection tool which help ILI tool selection. The validation information can also be used by ILI vendors to improve the tool performance.
API 1163 In-line inspection systems qualification, and CEPA’s metal-loss ILI-tool validation guidance document, provide two main methods for ILI validation. Enbridge has reviewed API 1163 and CEPA methodologies and developed a process to validate ILI results. This process uses API 1163 for the tool-performance acceptance criteria, while CEPA method is used to provide additional information such as depth over-call or under-call. The process captures the main concepts of both the API 1163 and the CEPA methodologies, and adds a new dimension to the validation procedure by evaluating different corrosion morphologies, depth ranges, and proximity to long seam and girth weld. The process also checks ILI results against previous ILI data sets and combines the results of several inspections. The process can be used for both metal-loss and ILI crack tool evaluation.
This paper presents the validation process and its applications. It is demonstrated that the tool-performance evaluation is important when making excavation decisions and selecting appropriate ILI tools.
 Automated signal comparison and normalization - an advanced method of comparing repeat ILI data, by Johannes Palmer, Artur Miller, and John Knudsen, ROSEN Group, Lingen, Germany
 ILI of a 1950s vintage pipeline using multi-technology tool, by Andrew Greig, Kinder Morgan Canada, Calgary, AB, Canada
With the large array of ILI technologies now available to the industry, operators have the ability to utilize numerous data sets to discover and investigate integrity anomalies. However, these data sets may come from different tool technologies and multiple tool vendors, so data integration can be a challenge. Having multiple tool technologies incorporated within a single tool unit can therefore be a distinct advantage in terms of data integration and anomaly investigation, leading to eventual mitigation. This is especially apparent in pipelines with differing and interacting anomalies where one specific inspection technology may not be able to detect, size, and classify all features.
The Trans Mountain Pipeline (operated by Kinder Morgan Canada), is one such pipeline, having a unique set of integrity anomalies, given its location (transiting through varied terrain) and date of construction (early 1950s). The pipeline has been inspected with numerous technologies over the decades, but starting in 2014, Kinder Morgan Canada began using the TD Williamson multiple data set (TDW MDS) tool. This tool contains four distinct inspection components: axial magnetic-flux leakage (MFL), spiral MFL, low-field MFL and geometry/caliper, all of which produced distinct data sets. Each data set is eventually integrated and analyzed by qualified data-analysis technicians and algorithms.
The paper will outline the history, operation, and previous integrity inspections of the Trans Mountain pipeline while also highlighting the features of the TDW MDS tool. The bulk of the paper will include a discussion on the use of the multiple-data-set ILI tool as a component of Kinder Morgan Canada’s integrity-management plan. Topics will include: operational challenges, ILI data results and anomaly dig/ILI correlation with a focus on the unique characteristics of the pipeline and tool.
 Robotic Inspection of Deep Well Booster Pumps, by Jonathan Minder, Integrity Solutions Engineer at Diakont
A major North American pipeline operator was having difficulty inspecting deep well booster pumps tasked with moving crude oil. The pumps were made to be removed from the 18 foot deep steel wells, but the wells themselves were installed in concrete casings making them difficult to extract. However this was the only method available so the operator was forced to take them out of service for extended periods of time to remove and inspect.
The pipeline operator approached Diakont to develop an new robotic solution capable of inspecting the deep wells while installed in the concrete. The solution developed uses electromagnetic acoustic transducers (EMAT) to provide comprehensive condition data on the well wall without removal from the concrete installation. A robotic crawler is used to hold the sensors in place to provide a comprehensive condition assessment of the well walls and the flat portion at the bottom.
The inspection project is currently underway and the final presentation and paper will provide details on the operators problem, the inspection solution and the results.
 Latest improvements of ultrasonic ILI, by Herbert Willems, Thomas Meinzer, and Gerhard Kopp, NDT Global Ltd, Stutensee, Germany
The main task of ILI is the early detection of potentially hazardous pipeline anomalies (such as metal loss) as well as their precise sizing, thus providing reliable input data for integrity assessment. For the inspection of liquid pipelines, ultrasonic tools offer specific advantages with regard to resolution as well as measurement accuracy. Over the last two decades, inspection tools have been considerably improved by taking advantage of the progress in electronics, data-processing technology, and data-storage capabilities as made available from other application areas. For example, the currently achieved measuring resolution allows for the reliable detection of tiny pinholes, even in welds. Further improvements are related to inspection speed, inspection range, and online monitoring of medium properties in order to control medium-dependent inspection settings. Apart from hardware-driven developments, ultrasonic modelling is becoming more-and-more important as a supporting tool for a better understanding of ultrasonic signal behavior as well as for optimizing inspection solutions. In this contribution, recent progress and its benefit for ultrasonic ILI will be presented and illustrated by inspection results as well as by modeling results.
 Techniques for the enhanced assessment of pipeline dents, by Jane Dawson, Julie Hedger, and Ian Murray, PII Pipeline Solutions, Cramlington, UK
Dents can occur during pipeline construction or in-service, causing a local stress and strain concentration and a local reduction in the pipe diameter. If failure as a result of a dent is not immediate, it is possible that the damage can deteriorate in service and cause failure at some time after the initial impact. The challenge to the pipeline operator is the identification of the dents that may threaten the future integrity of the pipeline from those that are dormant and require no further action.
In recent years there has been a shift from simple depth-based assessment of plain dents to the use of strain-based assessment that uses the dent’s local radius of curvature to define severity. Furthermore, as pipeline dents subject to cyclic pressure loading can also develop fatigue cracks, it is necessary to assess dent-fatigue life. Until recently, the options for fatigue assessment were essentially a simple, conservative, dent-depth-based assessment or the use of finite-element analysis (FEA). A new approach developed via a PRCI research project uses measurements from the dent’s axial and circumferential profiles to predict dent-fatigue severity and the cyclic-pressure spectrum to derive the dent’s remaining life.
This paper discusses the benefits and limitations of the new approaches that can be used to evaluate dent severity and fatigue life. How the dent-attribute input measurements are extracted from smoothed ILI dent profiles and used in the equations is demonstrated. Real case studies are provided to illustrate the process and to compare the findings to the older depth-based methodologies used previously.
 Investigating 16-in EMAT tool performance for a low-frequency ERW seam inspection, by Sean Moran, TD Williamson, Salt Lake City, UT, USA, and Dr Mike Kirkwood, TD Williamson, Dubai, UAE
Due to growing regulation and industry integrity-management requirements, pipeline operators are redoubling their efforts to mitigate cracks. As a result, demand has increased for ILI crack-tool technology that can detect and size defects such as environmentally-assisted cracking (EAC) and seam-weld cracks.
Electromagnetic-acoustic transducer (EMAT) technology has become an increasingly popular crack tool for gas and liquid operators. EMAT overcomes limitations of alternatives such as hydrostatic testing, which can miss defects below a critical length and depth, and ultrasonic crack detection (UTCD), which requires a liquid couplant.
Following a long-seam failure, a liquid operator in the US required a comprehensive seam assessment for crack and crack-like features on a 16-in, low-frequency-electric-resistance welded (LF-ERW) pipeline. The operator validated the efficacy of EMAT technology used in conjunction with the multiple dataset platform that combines individual ILI technologies on a single inspection device. Additionally, the operator ran a transverse-field inspection (TFI) tool and a UTCD tool on this pipeline to correlate results and compare tool performance.
This paper analyzes EMAT tool performance when combined with a multiple-dataset inspection and compares those results to the other ILI technologies (TFI and UTCD) utilized for this seam assessment. It also presents an analysis technique that demonstrates how the shapes of crack and crack-like features (such as hook cracks, lack of fusion, etc.) in the long seam can be utilized for an integrity assessment.
 Pipeline integrity management: program or system? The key to success, by Enrique Acuña, Dandilion Ingeniería Ltda, Santiago, Chile
In 2010 the Chilean Pipeline Regulator issued new safety requirements obliging pipeline and distribution operators to formally manage asset risk, in order to prevent incidents (manage threats) and minimize the potential impacts on people, property, and services (manage consequences).
To ensure successful implementation, this new regulation (Sistema de Gestión de Integridad de Redes – SGIR), was modeled evaluated and improved, with the active participation of industry players. This joint effort resulted in the publication in 2014 of the SGIR development and implementation guide.
The SGIR structure was based on ANSI/ASME B31.8S standard guidance, together with some additional requirements, which fit very well with the new ANSI/API RP 1173 standard. The result constitutes an effective, efficient, and sustainable risk-management system, or Chilean SGIR. This paper will present the principal concepts developed in the SGIR Guide and demonstrate how this management system, as compared to a program, will provide important improvements in pipeline-integrity management.
The goal of this presentation is to present the SGIR model and Guide elements, emphasizing the key factors intended to produce a successful risk-management system, including: corporate commitment and policies; organizational structure; performance management and indicators; risk management; and decision-making process.
 A review of pipeline defect-assessment methods: Pipeline Defect-Assessment Manual, 2nd Edition, by Susannah Turner, Penspen Ltd, Newcastle upon Tyne, UK
The 1st Edition of the Pipeline Defect Assessment Manual (PDAM) was released in 2003 from the same-titled joint-industry project, to address industry’s need for a document providing definitive guidance on the use fitness-for-service defect-assessment methods. The joint-industry project currently consists of 33 international sponsors representing operators, consultancies, suppliers, and regulatory bodies.
PDAM 2nd Edition was issued to its participants in late 2016 and this paper provides a summary of the updates made. The paper will focus on the updates made to guidance given for the assessment of corrosion, mechanical damage, fracture, fracture propagation, fatigue, and weld defects. The updated are based on the literature reviews conducted by a selection of experts of the latest published guidance and the assessment of the most recently available full-scale test data conducted up to 2016. The paper will present which technical documents were reviewed and what test data was obtained for our assessment of the available methods.
Updates have been made to chapters relating to mechanical damage. In particular, resulting from the inclusion of 29 additional full-scale tests, calculated modeling uncertainty factors used in the assessment of these defect types have been re-assessed and will be discussed in this paper.
 Probabilistic determination of pipe grade, by Michael Rosenfeld and Dr Jing Ma, Kiefner & Assocs, Columbus, OH, USA
A prominent aspect of proposed US pipeline regulations is the requirement of an integrity-verification process that identifies or confirms the materials installed in existing pipeline facilities. Material identification becomes a challenge where documentary evidence is incomplete or non-existent. A lack of material identification makes it impossible to verify that a pipeline operating at a pressure established by prior operation complies with the most basic design requirement as set forth in the steel-pipe-design formula. In order to verify compliance to design requirements, it is necessary to state the pipe specified minimum yield strength, not its actual strength. Compliance depends on determining what grade of pipe was selected and purchased by the operator, and represented to be by the manufacturer, irrespective of the actual strength of the pipe. Many factors are associated with common linepipe grades, including distributions of mechanical properties and chemistry. Thus, determination of the most-probable grade and maximum operating pressure of undocumented material is an inherently probabilistic problem. This paper explores a process for determining the most-probable grade of pipe, accounting for expected variations in pipe attributes and measurement error inherent to non-destructive materials’ characterization.
 On-site visits provide proven cost-reduction and value for uninspected pipelines, by Geert Bontekoe and Laurie Todd, Quest Integrity Group, Stafford, TX, USA
Pipelines that have never been inspected are typically considered unpiggable by traditional ILI tools. While new technology allows previously unpiggable pipelines to be accurately and quickly inspected, there are still many challenges that may arise due to operational constraints.
When preparing for an inspection of a pipeline that has not been inspected before, it is important to first understand the possible inspection methods and associated challenges through preliminary discussion and collection of information, including drawings and pipeline questionnaires. In simple cases, this approach may be sufficient. However, for more-complex projects we often find that there is a gap in the available information and understanding of the possible inspection methods.
It is therefore recommended that a site visit by a project manager be carried out in the early stages of first-time inspection. For challenging lines, it has likely been established that there are very few suitable ILI tools due to the complexity of the pipeline. The objective of the pre-inspection site visit is to gather all available information, including operational constraints and preferences, so that a successful inspection procedure can be developed. By customizing the cleaning and inspection plan, the best procedure for the project, at the lowest total project cost for the operator, can be developed.
The cost for the initial site visit is seen by many clients as difficult to justify. However, experience has shown that a small investment up-front can achieve big savings for the total project cost through the reduction or elimination of pipeline modifications, pipeline down-time, and the equipment necessary to facilitate the intelligent pigging of the pipeline.
A variety of solutions is available to address problems related to pipeline modifications and equipment requirements. Some examples include: the use of flexible hosing to create looped pipeline systems, using pressure of the fire-water system to propel the tool, designing a high-bypass tool for high-flow conditions, or even launching or receiving the ILI tool from a spoolpiece between valves if there is no launcher or receiver. In order to determine which methods are appropriate for a specific set of challenging pipelines, it is imperative that an on-site visit be performed by an inspection expert.
This paper will illustrate the inspection planning and on-site visit process, as well as the various methods used to mitigate unnecessary inspection expenditures. Several case studies featuring pipelines that had not been previously inspected will be used to illustrate these methods.
 The use of PGS ILI technology and Pipeline DNA process to determine the populations of undocumented pipeline sections, by Christopher Deleon, Simon Slater, Thomas Eiken, and Daniel Molenda, Rosen Group, Houston, TX, USA
PHMSA advisory bulletins and proposed rule-making has focused on producing and establishing appropriate documentation on pipeline materials to justify maximum allowable operating pressure (MAOP). In-line inspection (ILI) can support the documentation and data integration process and therefore meet multiple integrity and regulatory requirements. This can be achieved by extracting additional value from existing data and utilizing new technologies. ILI is traditionally used to detect, identify, and size pipeline anomalies. However, ILI technologies can also be used to satisfy the industry’s need to verify and complete pipeline-property documentation as well as the “data gathering and integration” requirements specified in CFR §192.917 (d). Inappropriate pipeline-property and material documentation may be considered a derivative of the construction and manufacturing threat, and - as in the case of external corrosion - ILI can be used for integrity assessment. This paper describes how recent developments in ILI technology provide state-of-the-art sensor technology and data analytics to establish an as-built pipeline record that is reliable, verifiable, traceable, and complete.
ROSEN has developed a solution to define pipe properties based on data collected by the PGS technology in combination with existing documentation and historical pipe manufacturing data, to characterize the pipe properties. The PGS technology can be deployed in combination with other ILI services. This solution provides the Operator with a characteristic ‘DNA’ that is used to describe the types of pipe within any given pipeline. This solution has two key benefits; the first and most transparent benefit is the non-destructive determination of essential pipe properties: wall thickness, outer diameter, and now the yield strength and ultimate tensile strength for each joint. This in itself addresses a significant part of ongoing PHMSA initiatives and can be used to identify potential integrity concerns such as pipe with strength values below that expected and other outliers. The second benefit is the ability to accurately identify the pipe populations based on a wide range of attributes, including length, wall thickness, etc. This allows the operator to target specific excavation locations in order to ensure that a) the pipeline is robustly characterized and b) the number of excavations required may be reduced by using a smart approach to determining excavation locations. This analytical approach by ROSEN is called Pipeline DNA.
The aim of this paper is to present the PGS ILI technology and Pipeline DNA assessment process. It will also discuss how the process is applied in ongoing integrity assessment plans in response to the recently published DOT NPRM publication. The Pipeline DNA process will be illustrated using a collection of the ILI data and a presentation of the data on the basis of a worked-example demonstration.
 Velocity independent sizing of axial planar anomalies using oblique magnetization, by Adrian Belanger, James Simek, and Dane Burden, T.D. Williamson, Inc., Houston, TX, USA
Reduction in wall thickness is a constant integrity issue in pipelines. Since the 1960s, ILI with magnetic-flux-leakage (MFL) tools has been used to detect the location and size of metal loss. Using axially-oriented magnetizers, MFL tools created fields aligned along the axis of the pipe, as that was the most-efficient method based on the pipeline’s geometry and the functional requirements of the ILI tool. However, these original designs had limited sensitivity to axially-oriented anomalies in the pipeline wall, which often pose the greatest integrity threat.
In the 1990s, new MFL tools were developed to enable improved performance for detection and sizing of axially-oriented anomalies, using magnetizers with circumferentially (transverse) applied fields. A later study of velocity effects on circumferential magnetization indicated a reduction of magnetic flux in the outer regions of the pipe wall, which suggests metal-loss anomalies located in that outer region may be harder to detect and resolve compared to anomalies located closer to the inner pipe wall.
To enable detection and sizing of axially-oriented anomalies, an oblique magnetizer design was introduced in 2009. This design allows detection and sizing of axial planar anomalies using a single magnetizing body which may then be coupled to an axial MFL tool. The oblique magnetizer creates a field in a direction between the axial and the circumferential, providing a performance vs speed de-rating profile similar to that of the axial magnetizer.
This paper will present theoretical modeling and empirical testing that shows detection and sizing of anomalies, especially axial planar, are not affected by velocity in the range of a conventional axial MFL tool.
 Inspecting and managing a pipeline with internal surface roughness due to top-of-the-line CO2 corrosion: a case study, by Kai Xin Toh, Quest Integrity Group, Stafford, TX, USA
Ultrasonic ILI technology, which uses the propagation of ultrasonic waves to obtain pipe-wall measurements, generally has issues with internal surface roughness, which scatters the ultrasonic waves and reduces the quality of the returning echo. This often leads to echo loss, causing a blind spot in the area of internal surface roughness, which can hide severe corrosion detrimental to the integrity of the pipeline.
When an operator discovered a pinhole leak adjacent to girth weld in its partially-insulated pipeline, it quickly repaired it and commenced a root-cause failure analysis. As the previous inspection had not identified metal-loss defects in the area, the operator also needed to re-inspect the line to detect any other potential areas of high risk of aggressive corrosion growth. The pinhole leak was in an area of internal surface roughness, which posed a challenge to UT (ultrasonic technology) inspection. Thus, a flow test with a UT vendor was commissioned. However, the vendor failed to collect data at areas of internal surface roughness. Subsequently, the operator approached Quest Integrity to conduct a flow test with the InVista UT inspection tool: the tool successfully collected data throughout the flow loop, and was then used for the full pipeline inspection. The in-line inspection data was subsequently used to conduct a fitness-for-service and remaining-life assessment for the pipeline.
 Managing the threat from weather and outside force using ILI, by Jane Dawson and Ian Murray, PII Pipeline Solutions, Cramlington, UK, Kinder Morgan, Houston, TX, USA
Weather and outside force are threats to many pipelines. Pipelines can be loaded by external forces caused by different types of events, including settlement, wash-out/flooding, subsidence, landslides, earthquakes, and human activity adjacent to the line. In some cases the effect can be immediate. However, in other cases, the progressive increase in loading can occur over time. There are various methods to monitor pipeline movement in-situ, such as slope inclinometers or strain gauges, but these techniques have limitations. Often pipelines are long, running through areas of remote terrain or areas where access is challenging. Thus, there are considerable practical challenges to operators to monitor their full systems using these techniques.
Running an IMU (inertial-mapping unit) tool as part of an ILI survey has become a routine practice for many pipeline operators. The IMU provides a synchronized stream of mapping information which, aligned to the ILI data, provides the means to accurately and easily locate pipeline anomalies, features, and fittings. Specialized assessment of the IMU data can be performed to calculate curvature and to derive the consequential bending-strain levels throughout the pipeline to identify potential weather and outside-force events. In addition, when the bending-strain information is combined with the anomaly data collected by other ILI sensors (ovalities, dents, buckles, girth- or spiral-weld cracks or anomalies, pipe-body cracks, and widespread metal loss) this facilitates the identification and assessment of immediate and sub-critical integrity concerns in the pipeline that may otherwise have been missed in the absence of the x, y, z mapping data. Furthermore, the comparison of repeated mapping runs enables accurate identification and assessment of pipeline-shape changes, indicating areas of potential movement that may have occurred between inspections, providing the further information needed to manage the on-going threat from weather and outside-force threats.
This paper describes the pipeline-integrity assessments that are possible from the single and repeat IMU runs and the associated multiple integrity-management benefits. The assessment techniques and the stress and strain limits that can be applied to both anomaly-free pipe and when anomalies are coincident with the bending strain are discussed. Real case studies are used to describe how the IMU mapping, curvature, and strain data are used in combination with other above-ground survey data in order to manage the weather and outside-force threat on a large network of pipelines. Further discussion is included regarding how the IMU mapping, curvature, and strain results are checked in-field in order to validate the findings.
 Avoiding future pipeline failures by detecting, identifying, and prioritizing mechanical damage, by Chuck Harris, T.D. Williamson, Inc., Houston, TX, USA
Although rare, pipeline failures that result in the release of product can have grave and costly consequences. Personal injuries, environmental impacts, expenses related to property damage, clean-up, and repair, and – ultimately –lost revenue can all occur. One of the leading causes of pipeline failure worldwide is mechanical damage, typically defined as a combination of dents, gouges, and/or cold work caused by the application of external forces.
The Pipeline and Hazardous Materials Safety Administration (PHMSA) indicates that damage resulting from excavation equipment generally results in immediate failure. However, there are notable exceptions where the aftermath of mechanical damage has been delayed by several years.
Focused on a legacy pipeline that failed as the result of backhoe damage decades earlier, this white paper examines how advanced ILI equipment with multiple technologies configured on a single inspection vehicle enabled the pipeline operator to identify, rank in severity, and prioritize the repair of 350+ excavation-damage locations. Specifically, the paper addresses how the multiple-dataset (MDS) platform for the 16-in pipelines detected, characterized, sized, and provided inputs to prioritization techniques for interacting threats that were most likely to negatively impact pipeline integrity.
 Risk-based mitigation of mechanical damage, by Dr Jing Ma and Fan Zhang, Kiefner & Assocs, Columbus, OH, USA, and Guy Desjardins, Desjardins Integrity, Calgary, AB, Canada
According to the PHMSA data on reportable incidents, for the 20 years ranging from 1995 to 2014, excavation damage accounted for 16.4% of the incidents on 301,732 miles of gas transmission pipelines and 15.6% of the incidents on 199,210 miles of hazardous liquid pipelines. On the whole, excavation damage is a major cause of incidents, ranking third following incidents caused by material/weld/equipment failure and corrosion.
For the purposes of this study, mechanical damage is separated into two categories, i.e. immediate failures and delayed failures. An immediate failure is one which occurs at the instant the damage is done to the pipeline. A puncture, for example, is an immediate failure. Delayed failures involve damage that is not sufficient to cause a leak or a rupture at the time it is inflicted. Delayed failures typically are related to some time-dependent factor that results in the damage becoming severe enough to cause failure after a period of time. On average, 14.6% of the mechanical-damage incidents in gas transmission pipelines and 13.3% of the mechanical-damage incidents in hazardous liquid pipelines can be classified as delayed failures.
The immediate failures are generally minimized through the preventative measures and design efforts. For instance, it is shown herein that the puncture probability can be calculated through the comparison between the likelihood of any given external load being imposed and inherent pipe resistance.
While preventative measures serve to reduce the occurrences of delayed failures as well as the occurrences of immediate failures, delayed failures are largely mitigated through ILI and timely remediation actions. The fact that the assessment methods for mechanical damage are generally not as robust as those for cracks and corrosion tends to limit the reliability of deterministic calculations of response times. Therefore, in the study described here, risk-based approaches to minimizing delayed failures were developed. Three different approaches to deciding which dents need to be excavated after an ILI were pursued. One involves the use of reportable incident rates based on the PHMSA statistics in conjunction with the number of ILI dent indications per mile to get a probability of failure. The second consists of a decision-making process based on the ILI-reported dent depths and the dent fatigue life probability-of-exceedance (POE) function. The third relates to a decision-making process based on successive excavations of dents located by ILI, in which the Bayesian method is applied to compare predicted versus actual severity and thereby determine the probability of failure associated with stopping after a specific number of excavations.
 Fatigue performance characterization of a manufacturing seam defect in high-frequency electric-resistance-welded pipe, by Dr Chantz Denowh and Chris Alexander, Stress Engineering Services, Houston, TX, USA, and Travis Schott, Phillips 66, Houston, TX, USA
The detection, characterization, and sizing of seam anomalies continues to be a challenge for both in-line and in-the-ditch inspection technologies. This paper presents a testing program developed to evaluate the fatigue performance on a planar manufacturing defect removed from service in high frequency electric-resistance welded (HF ERW) pipe. This defect was identified in the field by ILI and confirmed in the lab. by phased-array UT. In addition to the manufacturing flaw, several artificial flaws were sized and placed in the seam weld to evaluate the fatigue performance of the HF ERW seams. Fatigue was simulated in all flaws through a pressure-cycle and surge-test program based on the pipeline’s operational characteristics. At the conclusion of testing, a metallurgical evaluation analyzed the defect fatigue performance, and was compared to the original ILI and phased-array UT data. The metallurgical evaluation also characterized the fatigue growth and provided comparisons to analytical crack-growth estimates. This work provides insight into the fatigue performance of early vintage HF ERW seams and comparisons between ILI and NDE sizing methods.
 A seam-weld-condition model for assessing the general integrity of pipeline segments, by J. Bruce Nestleroth and Stephanie Flamberg, Kiefner & Assocs, Columbus, OH, USA
A fundamental step in assessing the overall integrity of a pipeline is to identify and quantify the threat posed by manufacturing related flaws in the long-seam. Kiefner has developed a model that objectively rates pipeline segments within a company’s system based on attributes affecting the integrity of seam welds. The model evaluates pipeline segments using parameters such as pipe-seam fabrication methods, history of seam failures, hydrostatic-test pressures, ILI results, pipe material properties, and operational data. A scoring system is used for each of these parameters that quantify the roundtable discussion process of many experienced engineers to determine the condition of a pipe segment. The model weights all factors on a consistent basis, and does not allow one parameter to drive the evaluation process. The model reports hydrostatic-test and service-related failure history for the pipe vintage being assessed using proprietary data collected by Kiefner over the past 25 years and the PHMSA database of pipeline failures. The output of the model is a relative score of a pipe segment’s long-seam integrity. This model can be used to:
In general, the model defines pipeline segments with a higher or lower potential for a long-seam event that could cause a loss of product. An added benefit of the model is to allow users to conduct what-if analyses to quantify the reduction in failure potential when various ILI, hydrostatic testing, and maintenance activities are implemented and/or operational changes are applied. As part of this development, a prototype web-based software tool was developed by Kiefner and is being tested and used by two pipeline companies
 Application of an advanced method of comparing repeat ILI data to improve pipeline integrity management, by Andrew Wilde and Michael Smith, Rosen Group, Newcastle upon Tyne, UK
It is widely acknowledged that ILI provides the best indication of the existing condition of corroded pipelines and that repeat inspections provide an effective means of monitoring pipeline integrity. A wide range of techniques has been applied to compare repeat ILI data, with the primary objective focusing on the identification and quantification of corrosion activity throughout the pipeline. This paper outlines a new approach to comparing repeat magnetic-flux-leakage (MFL) data and discusses how this idea can be used to improve pipeline-integrity management.
Advances in signal processing have enabled complete sets of MFL signal data from repeat inspections to be accurately aligned and compared without relying on initial feature or ‘box’ matching techniques. This approach ensures a full evaluation, minimizes the impact of tool-sizing tolerances on the accuracy of estimated corrosion rates, and makes full use of the extensive data that modern MFL tools are now able to gather.
In order for such advances to lead to improvements in pipeline integrity, reduce the number of pipeline failures that continue to occur as a result of corrosion, and optimize repair and re-inspection costs, it is necessary to combine accurate measurements of past changes with other data (for example, coating condition or product composition), using expert knowledge of corrosion-management techniques to select the best future corrosion rates for integrity-management planning.
This paper outlines alternative methods for modeling future corrosion activity by utilizing the results from a new signal-comparison process, demonstrates how to select the best method for any given pipeline, and quantifies the benefits that such an approach can provide to pipeline operators.
 Pipeline integrity and data integrity: the critical role of data in the enterprise, by Dr Otto Huisman and Sebastian Ruik Beyhaut, Rosen Group, Lingen, Germany
Pipeline-integrity-management systems (PIMS) are designed to ensure the safe operation of pipeline systems. PIMS include facilities for data management, tools to perform calculations and assessments, repositories for documentation of integrity assessments, and more.
ISO 55000 defines the key requirements for organizations relating to quality in asset management, of which data management is a key component. Compliance with this standard may therefore require changes to the way data is managed and its storage location. This in turn will impact existing workflows and data flows – possibly affecting system interoperability. A critical part of this step is to ensure optimal storage and manage pipeline and related data, as well as the transition to create asset-management excellence.
There are several questions to consider in this endeavor. Namely, is it beneficial to choose a custom data model that best fits the organization? Does an open standard, such as the PODS model, provide the required functionality? Or is it more advantageous to implement vendor-driven data models which best support querying? Finally, does the final choice fit within the existing infrastructure?
In order to adequately manage the implementation process, an analysis of the client’s enterprise-environment architecture should be performed. This ensures alignment between business rules, technology drivers, applications, and data layers. Using a case-study approach, this paper reports on the installation and migration of integrity tasks to an AIMS for a major South American gas operator. Data collection to support the implementation phase were based on a modified TOGAF framework, and performed by means of a questionnaire and supplementary interviews conducted on-site with client experts. The client’s geodatabase was migrated to a PODS Spatial 6.0 database designed to store pipeline-related integrity information. The data that were migrated included ILI final reports, satellite imagery, and other documents and document links.
 ILI of axial strain: technique, case studies, and best practices, by Dr Mohamed ElSeify and Stuart Clouston, Baker Hughes Canada, Calgary, AB, Canada, and Doug Dewar, Spectra Energy Transmission, Prince George, BC, Canada, and presented by Dennis Janda, Baker Hughes, Houston, TX, USA
ILI tools are a primary instrument for transmission and gathering system pipeline operators to inspect and monitor the condition of pipelines against specific integrity threats. However, when diameters approach or exceed 30 ins, technical and economic factors exist that render the installation of launcher/receiver facilities infeasible or prohibitive. In such cases when conventional inspection using free-swimming tools is not practical, tethered and robotic tools can provide an alternate means to ensure rigorous understanding of the pipeline condition.
Pipeline outage requirements, tool-pulling limitations, development costs, market demand, and other constraints have limited the availability of larger-diameter tethered inspection tools. As such, though not the preferred assessment method, these unpiggable pipeline segments are typically assessed by hydrostatic testing or a direct assessment. High-resolution data and feature-specific information provided by ILI enables operators to more accurately manage the potential integrity threats and, with this in mind, TransCanada approached Baker Hughes for a solution to utilize their tri-axial MFL technology on wireline to inspect its system of large-diameter pipelines (30 to 48 ins) that do not have launcher and receiver facilities.
This paper describes a new, engineered approach to the tethered inspection of large-diameter (34, 36, and 48 in) unpiggable pipelines. Furthermore, the technical, logistical, and project-management challenges inherent in the program from both the operator and service provider perspectives are discussed, including the mitigation of HSE risks and the engineering control measures implemented.