The 24th INTERNATIONAL
Pipeline Pigging & Integrity Management Conference
plus Training Courses and Exhibition
Marriott Westchase Hotel • Houston, Texas • February 6-9, 2012
Provisional programme – updated January 20, 2012
Download a printable version (pdf file)
Tuesday 7 February
Wednesday, February 8
by David Russell and Neil Errington, Pipeline Engineering & Supply Co Ltd, Catterick Bridge, UK
Recent advances in the technology of debris detection in pipelines can be shown to allow improvements in assessing the effectiveness of cleaning programs. Successful intelligent inspection depends on the cleanliness of the pipeline, and previous techniques, relying on measuring quantities of debris produced, have not always given acceptable results.
Early experience with Pipeline Engineering’s cleanliness-assessment tool suggests that the use of this type of tool can make a valuable contribution in allowing a reliable judgement to be made regarding when a pipeline has reached a state which will permit a successful intelligent inspection run.The paper presents data from recent cleanliness-assessment tool surveys, demonstrating how the recorded data gives an objective measure of the progress of a cleaning operation, and allows an improved understanding of the internal state of a pipeline. Measurements of wax films down to a thickness of the order of 1mm have been made.
by Hubert Lindner and presented by Chris Yoxall, Rosen, Houston, TX, USA
by Angus Bowie, Technical Director, STATS Group, Aberdeen, UK
Double Block and Bleed is a term often used to define a level of isolation sufficient to perform maintenance activities. The true definition relates to incumbent valves providing two proven levels of isolation against the outboard pressure to permit breaching of containment in the isolated pipe. This paper assesses how temporary isolation devices can provide equivalent isolation where incumbent valves do not exist at appropriate locations in the system.It will reference several examples from around the world of where temporary isolation devices have been used to replace valves and perform repairs in trunk pipelines without depressurising the whole pipeline. It will also cover examples of isolating live process pipe to perform maintenance activities outside plant shutdown.
The examples include:
- Isolating 800Km of 40” gas pipeline at 1500 psi to facilitate the refurbishment of a welded in ball valve in the North Sea.
- Isolating 38” gas line with high H2S in the Middle East.
- Removing an 18” dead leg without interrupting the production flow.
by Mike McGee, Quest Integrity Group, LLC, Houston, TX, USA
by Scott Miller and Stuart Clouston, Baker Hughes, Calgary, AB, Canada
MFL is an indirect measurement system and a mathematical model or algorithm is used to translate MFL signals recorded by the tool into estimations of pipeline corrosion feature depth, length and width respectively. The derivation of these mathematical models can be anything from a simple calibration process of a representative sample of manufactured features in a pull rig to an in-depth development process of highly complex algorithms.
One of the challenges to MFL technology is that the signal response and hence sizing performance is directly related to the shape of the corrosion. More importantly, since the MFL measurement technique is indirect and models are “trained”, in some cases when the geometries of real corrosion differ significantly from those used to develop sizing algorithms, higher than expected sizing error can occur. This situation is of course of most importance when corrosion is aggressive and can lead rapidly to deep, potentially injurious defects.This paper describes a process which utilizes a large volume of statistically significant high resolution NDE data as a primary means to train and optimize MFL sizing models when defect geometry is a major contributor to poor MFL inspection sizing performance. The practical application of the method to a Canadian oil pipeline is discussed in detail along with the approach used to achieve greater than 90 percent sizing confidence on field verified automatic UT data.
by Jeff Sutherland, PII Pipeline Solutions, Calgary, AB, Canada
Eric Quick, PII Pipeline Solutions, Houston, TX, USA
Kevin Spencer, PII Pipeline Solutions, Calgary, AB, Canada
On August 25th 2011, PHMSA issued an Announced Notice of Proposed Rulemaking (ANPRM) within which there are specific questions relating to cracks and methods available to assess them. This paper will review these pipeline threats and the ILI technologies available to assess them as well answer the questions PHMSA has requested comments on, such as:
- Are there statistics available on the extent to which various tools and methods can accurately and reliably detect and determine the severity of SCC?
- Are tools or methods available to detect accurately and reliably the severity of SCC when it is associated with longitudinal pipe seams?
- Can ILI be used to find seam integrity issues? If so, what ILI technology should be used and what inspection and acceptance criteria should be applied?
by Dr David Batte, Macaw Engineering, Newcastle upon Tyne, UK
Dr Ray R Fessler, Biztek Consulting, Evanston, IL, USA
Jim E Marr, TransCanada Pipelines, Calgary, AB, Canada
S C Rapp, Spectra Energy, Houston, TX, USA
In 2006 a group of natural gas transmission pipeline operating companies in North America collaborated in a joint-industry project (JIP) to address the integrity management of SCC in high-consequence areas. The outcome of the work was a series of reports examining the occurrence of SCC extending over 40 years up to 2005, and developing experience-based guidance for the conduct of hydrostatic testing and excavations for the assessment of the severity of discovered cracks and for establishing the interval before the next assessment. The outcome was published in ASME STP-PT-011 (2008) and provided the basis for proposed revisions to ASME B31.8S. It also enabled the closer alignment of ASME B31.8S with the revisions to the CEPA Recommended Practice for SCC.
Five years later, a slightly enlarged group of operators has revisited the current status of SCC threat management in North America. The operational experience relating to over 160,000 miles of gas transmission pipelines during the last five years has been compared with that seen up to 2005. The threat-management procedures and practices, including the application of hydrostatic testing, SCC direct assessment, and the latest generations of crack-detection ILI, have been examined and benchmarks for good practice have been identified. The increasing application of SCC direct assessment and crack detection ILI has raised issues concerning the accuracy of predicted failure pressures for discovered SCC, and these are being addressed. Data already obtained by the JIP Phase II members has been used to establish the best methods of calculating failure pressure, and to explore the contribution of flaw profile to the uncertainties that arise, both from the interpretation of the ILI signal and from the characterization of complex profiles in the calculation method. The accuracy of such calculations has a significant bearing on the safety factor applicable to any flaws that remain in service after an assessment.
This paper presents an overview of the JIP Phase II program to assess the integrity management of SCC in high-consequence areas. The outcome of Phase I was published in ASME STP-PT-011 (2008) and provided the basis for proposed revisions to ASME B31.8S. Data obtained in Phase II has been used to establish best methods of calculating failure pressure, and to explore the contribution of flaw profile to uncertainties that arise, both from the interpretation of the ILI signal and from the characterization of complex profiles in the calculation method. The accuracy of such calculations has a significant bearing on the safety factor applicable to any flaws that remain in service after an assessment.It is intended that the outcomes of the individual work packages will be disseminated for the benefit of the wider industry, so that they can provide an informed basis for any proposed modifications and improvements to industry guidance and regulations.
by Pamela J. Moreno, DNV, Katy, TX, USA
Neil A. Bates, DNV, Calgary, AB, Canada
David A.R. Shanks, DNV, Calgary, AB, Canada
William V. Harper, Otterbein University, Westerville, OH, USA
David J. Stucki, Otterbein University, Westerville, OH, USA
Clifford J. Maier, DNV, Dublin, OH, USA
Thomas A. Bubenik, DNV, Dublin, OH, USA
Pipeline integrity assessments are often based on conditions that are assumed constant over long sections of pipeline – perhaps entire pipeline systems. Such assumptions generally lead to conservative but unrealistic corrosion growth based results. As integrity assessment methodologies continue to evolve, so does the ability to account for local conditions. When multiple in-line inspections of a given pipeline segment have been performed, Statistically Active Corrosion (SAC) methods may be used to estimate local corrosion growth rates.
By incorporating local growth rates into the analysis, fewer features will require mitigation. It is also possible that the re-inspection frequency can be extended. These cost savings can be recognized by operators that use corrosion growth rates determined using statistical multi-inspection comparisons.This paper presents a Statistically Active Corrosion (SAC) method to reduce the number of excavations and extend the re-inspection interval for several pipeline operators. A case is presented in which the local corrosion growth rates from an SAC analysis will be compared against growth rate values traditionally used in Probability of Exceedance (POE) analyses. Additionally, verification of SAC growth rates by examination of the raw signal data is addressed.
by Jane Dawson, Principal Consultant, Integrity Engineering, PII Pipeline Solutions, Cramlington, UK
by Lee Shouse and Matt Logan, TD Williamson, Tulsa, OK, USA, and Gene Brock and H.G.(Butch) McCormick, JACAM Chemicals, Sterling, KS, USA
by Ming Gao, Samarth Tandon, and Ravi Krishnamurthy, Blade Energy Partners, Houston, TX, USA
Despite the fact that EMAT technologies have become available in recent years, There is only limited information, experience and field validation of EMAT tool capabilities, limitations and potential for characterizing SCC cracks in gas pipelines.
This paper reviews advances in EMAT technology and its performance with time. Experience with various EMAT tools, including probability of detection, is evaluated with currently available data.
The statistical methods including Binomial Probability Distribution Analysis, Binomial Confidence Interval Analysis and Least Square Linear Regression Analysis are used for evaluating probability of detection (POD), probability of false calls (POFC), probability of identification (POI), and sizing accuracy.
A methodology is proposed to assess EMAT tool performance against hydrostatic testing. The results demonstrate that EMAT can be used not only as a reliable tool for SCC susceptibility detection in gas pipelines, but also potentially as an alternative integrity tool to hydrostatic testing for gas pipeline SCC management.Case studies on EMAT performance vs. Hydrostatic testing are illustrated in detail. Gaps between current EMAT technology and industry needs are identified. Originally presented at PRCI’s Joint Technical Meeting, May 2011. Finally, issues for continued research and technology development of EMAT are discussed.
by Jim Marr, Richard Kania, Gabriela Rosca, Rahim Ruda, and Elvis San Juan Riverol, TransCanada Pipelines Ltd, Calgary, AB, Canada
Ralf Weber, ILI Consulting, Karlsruhe, Germany
Stefan Klein, Nikola Jansing, and Thomas Beuker, Rosen Technology and Research Center Germany, Lingen, Germany
and N Daryl Ronsky, Rosen Canada Ltd, Calgary, AB, Canada
ILI by electro-magnetic acoustical transducer (EMAT) technology for crack detection in natural gas pipelines has been utilized for more than a decade. Identification and sizing of stress-corrosion cracking (SCC) and other critical crack-like defects in pipelines involves a complex data integration and analysis process. This process is aided by using multiple data sets during the analysis to eliminate uncertainties and reduce unnecessary investigative excavations and validation costs.This paper describes EMAT crack-detection the integration and analysis, and how conventional ILI tool data, coating data, soil data, and pipeline construction data combined with EMAT ILI data can promote exceptionally high probabilities of detection (POD) and identification (POI). The effectiveness of this integration approach is illustrated by case studies of two 20-in natural gas pipelines that have a history of SCC.
Thursday, February 9
 Current unpiggable issues and solutionsby Dr Keith Leewis, P-PIC, Libertyville, IL, USA
by Nicolas Cardenas Ortiz1, Martín Sánchez1,2, Laura Zavala1, and Veronica A. Dominguez1
1 Departamento de Integridad, Direccion Logistica, YPF SA, Buenos Aires, Argentina
2 Departamento de Ingenieria Mecánica, Facultad Resgional La Plata Universidad Tecnologica Nacional, La Plata, Argentina
This work describes unpiggable pipeline inspection experience using a combination of two un-conventional methods: Magnetic Tomography (MTM), and Magnetic Metal Memory (MMM). Specific inspection procedures are presented through detailed evaluation of the methods. Magnetic fields perturbations generated either by metal structure imperfections or applied stress in the material are identified and evaluated.
In order to quantify the results of these methods, the authors present a comparison with conventional ILI on a piggable pipeline.In general, we have found that the proposed methods detect the most significant anomalies as the applied ILI method. Although the un-conventional method does not detect all abnormalities found by internal inspection, the combination of MTM and MMM is recommended when other methods are not applicable.
by Tore Magne Skar, Principal Scientist & Project Manager, Det Norske Veritas, Hovik, Norway
The ART Gas Pipe Scanner is a Multi-diameter Gas Coupled In-line inspection tool being developed through a strategic R&D cooperation between DNV and Gassco. The technology has been developed by DNV over 20 years. The tool has demonstrated several significant advantages compared to traditional ILI-tools, e.g. ART measure absolute WT very accurately (no practically upper limit), used in gas without liquid coupling, reduced need for pre-cleaning of pipelines, significantly lighter weight, no moving parts, less sensitive to inclination of the sensors, far more robust on rough surfaces, sensors without wall contact, multi-diameter capabilities and calliper measurements with the same tool.Downscaled prototypes have been and are currently being tested in both laboratories and in the field on a real gas pipeline. Field tests have resulted in seven successful runs so far. This paper shows some of the results obtained by the ART Gas Pipe Scanner, and try to show the advantages the ART technology have compared to competing technologies. A sector version of the ART Gas Pipe Scanner is soon to be tested in a test spool. Results from this test is planned to be presented at the conference.
by Scott Thetford, AGR Field Operations, Houston, TX, USA
This paper will discuss several case studies of pipelines that could not be inspected with conventional free-swimming smart pigs. It will describe engineered solutions that incorporate cleaning, launch/entry point, propulsion methods, infrastructure support, etc. for successful inspection of these types of lines. Both on- and offshore applications as well as alternative techniques for deepwater will be covered.
by Prof Sviatoslav A Timashev and A V Bushinskaya, Science and Engineering Center, Ural Branch Russian Academy of Sciences, Ekaterinburg, Russia
The paper describes a tested and proven practical methodology of predictive maintenance of pipelines with two types of defect – metal loss and pipe wall lamination – detected by ILI technology. The laminations, caused by the steel and pipe manufacturing technology, may also appear during pipeline operation, and can be further classified as metallurgical laminations, hydrogen-induced cracking (HIC), or non-metallic inclusions.
For the pipe-wall lamination type of defect, the assessment of the level of danger is conducted only after they are converted to metal-loss types of defect. It presents models on how to adequately convert the pipe-wall lamination defects to metal loss defects. The methodology is described on how to rank the defects according to their level of danger (with respect to failure by the rupture alone), and how to perform a probabilistic assessment of the residual life of the inspected pipeline. The defects detected by ILI are divided, depending on their type, size, and the level of safety factor, into the three categories: ‘dangerous’ (requiring immediate repair); ‘potentially dangerous’ (with sizes larger than the ultimate permissible sizes, as prescribed by international codes, but smaller than the sizes of dangerous defects); and ‘not dangerous’ (which do not decrease the bearing capacity of the pipeline, and do not require external pipeline inspection (DA) or repair).A detailed example of implementation of the methodology to a real product pipeline segment operating in a severe corrosion environment is given.
by Dr Ted L Anderson, Quest Integrity Group, Boulder, CO, USA
Pipelines with longitudinal seam welds have received renewed interest from operators and regulators, due primarily to a number of high-profile incidents. Most assessments of seam weld flaws have relied on methodologies that have changed very little over the past 30 years. However, the status quo is no longer viable, given the heightened public scrutiny and regulatory pressure.This paper presents a number of recent innovations in assessment technology that can lead to improved reliability and cost-effective assessment efforts, including comparison of new and traditional failure models; “virtual burst test” methodology for accurate burst predictions; limitations of Charpy testing on seam welds; and real-time pressure cycle fatigue analysis.
by Pablo D Genta, Saudi Aramco, Dharan, Saudi Arabia
The implementation of a leak-detection system (LDS) on cross-country natural gas pipelines, along with associated pressure-control facilities, presents various engineering design as well as commissioning and test challenges that must be assessed at early stages of the engineering design of a pipelines project. In particular, successful and cost-effective implementations of leak-detection systems that utilize pipeline pressure for determining leak type and leak location (“pressure-based LDS”), require the use of specific best-practices that address the type and location of LDS sensors, the signal-processing and -transmission techniques to be utilized, and the LDS technology’s built-in methods required to overcome nuisances from pipeline operating conditions. To be effective and practical, best-practices must take infrastructure as well as technology limitations into account. Ultimately, the expertise to identify best-practices can only be attained through practical experience in implementation and tests. Based on experience accumulated over more than one hundred LDSs performance leak tests conducted under various types of gas pipelines and operating conditions The author describes relevant challenges in the design, commissioning, and testing of pressure-based LDSs in natural gas pipeline applications. In particular, this paper discusses the influence of pipeline dynamic pressure (such as background noise) in natural gas facilities, the maximum gap between LDS sensors, and the pipeline diameter in relation to the pressure-based LDS performance in sensitivity and accuracy. Further, the paper provides successful field-proven methods and best-practices that address these challenges and achieve optimal, cost-effective results from an LDS.
by John Williams, OptaSense, Houston, TX, USA
Optical fibre is increasingly being deployed in many upstream and midstream applications. It is now regularly used to provide high bandwidth telecommunications and infrastructure for SCADA, and is increasing being used to sense pressure, temperature and strain, both along buried pipelines, on subsea pipelines and down hole. In this paper we present results from the latest sensing capability using standard optical fibre to detect acoustic signals along the entire length of a fibre.
The paper discusses a Distributed Acoustic Sensing (DAS) which uses an optical fibre for both sensing and telemetry on a pipeline. In this paper we present results from the OptaSense® system that when connected to an existing standard single-mode fibre (up to 50km in length and deployed in a cable next to a buried pipeline), can use the fibre to listen to the acoustic/seismic activity at every 10 meter interval. We will show that each of the 4,000 independent, simultaneously sampled channels can be used to detect and locate activity within the vicinity of the pipeline and through sophisticated acoustic signal processing, also classify the type of activity.
The authors focus on the ability of the system to use existing fibre optic cables to detect, classify and locate activity such as third party threats to pipelines, real time tracking of pigs, gas leak detection and seismic monitoring. They also show how an existing buried optical cable can be extended to encircle inline facilities such as block valve stations, refineries or pumping stations, and be monitored to provide perimeter protection and condition monitoring.The system is installed on almost 6000 miles of pipeline and other assets globally. and the paper will refer widely to data recorded on field deployed systems around the world, including how DAS is used to map the impact of earthquakes on pipelines, drawing on recent case studies from Turkey.
by Andy Young and Aaron Lockey, Penspen Integrity, Newcastle upon Tyne, UK
Pipelines routed through mountainous areas susceptible to landslides are often inspected using inertial mapping tools to determine position and strain. Viewed in isolation, data from a single inspection only gives an indication of the pipeline integrity at a single point in time. Multiple inspections over a period of time can be used to estimate positional change. To extend the capability of these approaches, a method is required to reliably predict the future development of pipeline integrity based on trends in the mapping data from multiple inspections.
This paper presents a novel method to predict the future integrity of a pipeline subject to landslide loading. The technique takes inertial mapping data from multiple inspections and calculates future strains in the pipeline using finite element analysis. Unlike methods based on interpreting inspection data alone, the finite element model includes the effects of soil-pipe interaction and axial pipeline stress to provide a more complete assessment of pipeline integrity. A case study of a large diameter oil pipeline is described to demonstrate the method.The paper illustrates how the maximum benefit can be derived from existing data, reducing the need for additional inspections. The method may also be used to optimise future inspection strategy, provide timescales for planning and implementation of remedial works, and make a cost-effective contribution to an integrity management system.
by Chris Goller, James Simek, and Jed Ludlow, TD Williamson, Salt Lake City, UT, USA
Mechanical damage continues to be a major factor in reportable incidents for hazardous liquid and gas pipelines. While several ongoing programs seek to limit damage incidents through public awareness, encroachment monitoring, and one-call systems, others have focused efforts on the quantification of mechanical damage severity through modeling and the use of ILI tools and subsequent feature assessment at locations selected for excavation. Current-generation ILI tools capable of acquiring multiple data sets in a single survey may provide an improved assessment of the severity of damaged zones using methods developed in earlier research programs, in addition to supplementing information currently reported. For MFL (magnetic-flux leakage) tools, using multiple field levels, varying field directions and high-accuracy deformation sensors will enable detection and begin to provide the data necessary for enhanced severity assessments. This paper will provide a review of multiple-data-set ILI results from several pipe joints containing damage locations created using excavation equipment of the type often associated with right-of-way encroachment events in addition to field results from ILI surveys using multiple data set tools.
Ed Nicholson, NiSource Gas Transmission and Storage, Charleston, West Virginia, USA
Amy Jo McKean, Willbros Engineering, Kansas City, MO, USA
and Brad Leonard, Willbros Engineering, Pittsburg, PA, USA
Due to an increase in regulations regarding pipeline integrity management directly to aging infrastructures, and ultimately material failures, it is becoming more apparent that operators must utilize existing databases to identify potential areas of threat at an increased frequency and with additional considerations. The paper will demonstrate, through project histories, how GIS is yet another tool to be used during implementation of direct-assessment programs for pipeline integrity compliance. It will also go into an operator’s account of how the results and early finds due to the GIS system saved considerable time and funding for the project.
Direct-assessment analysis and data integration for most operators has come in the form of specialized software from various industry vendors. By utilizing its GIS as the basis for the algorithm, NiSource was able to efficiently move from step to step in the process without considerable loss of ‘daylight’ as deadlines approach for completion due to regulations and heating season.The paper focuses not only on GIS integration of the direct-assessment results, but also provides a real account from NiSource and Willbros Engineering, showing how, at each step of the direct-assessment process, the team worked to determine the best, cost-effective, and compliant approach to each forward step. We will provide a lessons-learned section that will hopefully save time and efforts by other companies that choose direct assessment as their method of assessment.
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