The 25th INTERNATIONAL
Pipeline Pigging & Integrity Management Conference
plus Training Courses and Exhibition
Marriott Westchase Hotel • Houston, Texas • February 11-14, 2013
Tuesday February 12
Wednesday, February 13
By M.J. Rosenfeld, Kiefner & Associates, Worthington, OH, USA, and R.W. Gailing, Sempra Utilities, Los Angeles, CA, USA
The NTSB’s recommendations to US pipeline operators and regulators, based on their investigation of the 2010 San Bruno, CA gas pipeline incident, have focused attention on validation of MAOP of gas pipelines installed prior to federal or California state regulations. The industry is in the process of understanding the viability of continued operation of “grandfathered” pipelines and pipelines that have experienced loss of records necessary to give full confidence of the quality of installation. A full understanding of the implications requires knowledge of how pressure-testing and recordkeeping practices and requirements have evolved over time. This paper explores these issues, historically and currently, nationally and in California. Similar issues will likely arise in other states. The paper describes the evolution of pipeline pressure-testing requirements, what records have been specifically required, how those records relate to establishing MAOP, why so-called “grandfathered” pipelines exist, and the significance of recently-articulated criteria for records accuracy.
by David Wint, TD Williamson, Tulsa, OK, USAAs the liquids-rich unconventional resource plays are developed, there are multiple challenges and implications for midstream system infrastructure that fit particularly around pigging and integrity. The high liquids content of production from shale formations causes significant issues with slugging, high differential pressures (liquids loading) and corrosion. In addition, crude oil containing high levels of paraffin and other flow reducing contaminants presents flow issues in these midstream pipeline systems. Some on these lines have to be pigged daily to maintain production at the well head. These issues reduce throughput, increase operating costs, impair field production and reduce the economic life of the system. The unpredictability of production volume and liquid content creates significant challenges to pipeline and facility design. These challenges are occurring at an unprecedented pace and scale. As a result, the rules of the game are still undefined as producers and gatherers seek scalable solutions to these issues. The great number of lines to be pigged, and the need to pig often, requires the installation of multiple automated pig and/or sphere launchers. Automation of pigging systems offers compelling economics when compared to traditional manual systems. This paper will discuss the options available to meet this need and the savings of automation over standard manual systems – as well as ancillary pipeline performance-enhancing services.
by Ed Nicholson, NiSource Gas Transmission and Storage, Charleston, WV, USA, Amy Jo McKean, Willbros Engineering, Kansas City, MO, USA, and Nolan Quade, Willbros Engineering, Pittsburg, PA ,USANiSource and Willbros are in year 2 of an ECDA, SCCDA and ICDA Assessment Program and have utilized existing GIS databases for compiling, analysis, field verification and overall data recovery and storage for the Direct Assessment processes. The paper provides an account of the efforts, through project case histories that show how GIS is yet another tool to be utilized during implementation of direct assessment programs. The team concentrated on ECDA in 2011, but have completed not only ECDA but SCCDA and ICDA for the 2012 deadline. The paper will also provide an operator’s account of how the results and early finds saved considerable time and money, along with Lesson’s learned that will hopefully save time and effort by other companies that elect Direct Assessment as their method of Assessment.
by Raed Gasim, Intecsea – WorleyParsons Group, Houston, TX, USAPre-commissioning and commissioning of marine pipelines are essential parts of the design and installation scope; it must be planned correctly to establish integrity and avoid costly repairs or even replacement of a pipeline. This paper does not address a specific project, but rather discusses the pre-commissioning and commissioning processes. It appraises the techniques and best practices for pipeline filling, cleaning, flushing, chemical treatment, hydrostatic testing, dewatering, and drying, including the filling and cleaning of pipelines that contain corrosion-resistant alloys. The main causes of internal corrosion during pipeline filling and hydrostatic testing are also examined.
by Jason Matocha,TD Williamson, Aurora, CO, USARuby Pipeline Company LLC recently constructed a 680-mile, 42-inch diameter pipeline (the Ruby Pipeline) spanning from Opal, WY, to Malin, OR, which was designed under the Alternative MAOP rule (80% SMYS design). Due to potential quality issues on previously manufactured high-yield-strength pipe, PHMSA mandated the use of high-resolution caliper technology for operators to inspect for pipe expansions resulting from hydrostatic testing. Additional requirements were to perform a minimum of two verification digs per segment inspected, and to identify all expansion greater than 0.6% for 42-inch pipe. The tool specifications required multi-finger sensors that contact the pipe internal diameter and have an accuracy of +/- 1% or less to identify expanded pipe and dents. The paper reports on how T.D. Williamson was able to assist Ruby Pipeline in meeting this requirement, providing project management services for 341 miles of inspection, tracking and non-destructive evaluation (NDE).
by Bryce Brown, Rosen, USA, Houston, TX, USAAs natural gas gathering operators begin assessing pipeline segments as part of their asset management programs, they are being confronted with challenging pipeline conditions that are difficult to inspect with existing ILI technology. Because of transient operation, low flow rates, and low system pressures, these gathering pipelines, which are being voluntarily assessed, are more difficult to inspect than transmission lines requiring assessment. Engineering and implementing the modifications necessary to make a pipeline system piggable are often cost-prohibitive and time-consuming; therefore the need to develop new and advanced inspection technologies for unpiggable lines is imperative. Rosen USA and Access Midstream Partners joined together to address this need. The tool development and production was completed in June 2012, and a successful first run was executed in July 2012. The success of the first run can be attributed to the extensive testing that took place onsite allowing for a better understanding of the tool performance in “live” survey conditions.
by Yong-Yi Wang and Dr Jing Ma, Center for Reliable Energy Systems, Dublin, OH, USA, and Satish S Kulkarni, Houston, TX, USAThe girth welds on many pre-1970s pipelines were not 100% non-destructively inspected at the time of construction. These welds may contain flaws that can lead to failures when the lines experience stresses beyond those of normal operating conditions. Recent accidents of vintage pipelines have led to calls for more effective integrity management. Fitness-for-service (FFS) principles offer the best approach to assessment of these welds. Although general FFS procedures are well established, enhancement of these procedures is necessary to take into account the unique features of vintage girth welds. The paper explores key elements necessary for enhancing FFS procedures, and the challenges of estimating input parameters such as applied stress, flaw size, and material properties, which often are not readily available. The limitations and potential of various ILI tools in detecting and characterizing girth weld flaws are presented based on the fundamental principles of tools and published data.
by Jeff Robbins and Maurino DeFebbo, Asel-Tech, Houston, TX, USAMost internal leak-detection monitoring systems in use today are based on mass-balance technology. Although acoustic leak-detection systems have been around since the late 1970s, they did not catch on because of inconsistent performance. Now, advances in digital and electronics technologies have led to development of new acoustic systems based on more-sophisticated architecture and advanced signal processing techniques. The paper will review these new systems, which work substantially better than their predecessors, and in most cases better than other CPM/mass-balance systems. Some advanced systems even allow for integration of the acoustic technology with mass-balance systems, the result being a very versatile/broad spectrum system with built in redundancy.
by Anis Somani and Tim Ross, Pure Technologies, Columbia, MD, USA, and Laura Seto, Enbridge Pipelines, Edmonton, AB, CanadaA joint academic-industry research initiative funded by PHMSA has led to the refinement of a free-swimming tool which is capable of detecting leaks as small as 0.150 liters per minute in oil product pipelines. The tool swims through the pipeline being assessed and produces results at significantly reduced cost compared to current leak-detection methods. GPS-synchronized, GIS-based above-ground loggers capture low-frequency acoustic signatures and digitally log the tool’s passage through a pipeline. A tri-axial accelerometer system gives the odometric position of the ball, and has the accuracy of standard instrumented pigs; several other types of sensors – temperature, pressure, etc. – are also present in the ball. This paper will focus on the technology, analysis and performance of the device in petroleum pipelines.
by W Kent Muhlbauer, WKM Consultancy, Houston, TX, USA
Risk assessment, and in particular, pipeline risk assessment is a specialized field. Yet, under newer regulations and industry standards, most pipeline operators are being directed to engage in this somewhat esoteric practice. Technically, they are to practice formal ‘risk management’ which is not exactly ‘risk assessment’, but the former does not occur without the latter.So, is pipeline risk assessment, as it is currently attempted by many operators, sufficient for formal integrity management programs (IMP)? Not according to some regulators who have expressed increased skepticism regarding how pipeline operators are measuring risks. Regulators’ recent criticisms are not unjustified. There is currently great disparity in approaches and level of rigor applied to risk assessment by pipeline operators. This is largely due to the absence of complete standards or guidelines covering this complex endeavor. The disparity leads to inconsistent and problematic oversight by regulatory agencies. Without some standardization or at least consistency of understanding, regulators cannot readily determine where deficiencies may lie. On the other hand, too much standardization—a mandated, prescriptive approach—is inefficient and stifles innovation. A better solution is to establish guidelines of essential ingredients necessary in any pipeline risk assessment. Critical elements would be identified and it would be left to the operator subject matter experts (SME) to detail those elements. This paper presents such a set of essential elements for pipeline risk assessment.
by Stephen Gower and David Whitman, BP Exploration
- Geoff Foreman, PII Pipeline solutions/GE Oil & Gas
- Holger Hennerkes, Rosen Swiss AG
- Kirk Langford, Baker Hughes
- Ulrich Schneider, NDT Systems & Services GmbH & Co. KG
First run success is a key performance measure used in BP’s Global In Line Inspection (ILI) Contract. Although run success rates are often referred to across the industry, there has been little standardization in the terminology, or the factors that lead to a successful run.
As part of BP’s continuous improvement process, ILI Suppliers and internal stakeholders were brought together for a facilitated workshop to understand the factors affecting first run success rates. The workshop identified a number of common themes which were consistent across all of the Suppliers, addressing both operational issues and tool performance.
A Guidance Note was then developed with the ILI Suppliers to drive improvements in first run success rates. This was shared with the Pipeline Operators Forum (POF) in October 2011 and has been further developed as a POF Guidance Document. A separate guidance note has been developed to address recommended practices for collecting and verifying field data.As the industry starts to inspect more difficult and challenging lines it will be important to improve ILI run success rates. Across the industry we probably know how to do it, but doing it consistently is the challenge. The development of industry Guidance Notes is a step toward achieving this objective.
Thursday, February 14
by Vishal Pooran, Sasol Gas, Johannesburg, South Africa, Leen Pronk, Gasunie, Groningen, Netherlands, Peter Baars, GDF SUEZ, France, and Rob Bos, PIMS International, Haren, The Netherlands.
The integrity management is a process of continuous improvement and should be an integral part of the daily practice of the pipeline operator. Risk assessment plays a key role in this process: (new) risks are identified and mitigated by appropriate (new) measures that are the basic elements for the Annual Periodic Integrity Management Plan. Any Safety Management System (SMS) has a primary focus on the effectiveness of integrity and risk control but, in general, costs are of secondary importance. The methodology described in this paper brings these ideas together: it supplies the tools that enable the pipeline operator to manage integrity and risk in an economical way.
An overview of the bowtie methodology including the derivation of performance indicators (PIs) is given. The major elements hat have been developed are:
- A process model demonstrating the transparency of all integrity-related operational activities and the way the cycle of improvement has been embedded in daily practice
- The method of risk assessment being applied (bowtie)
- Performance Indicators (PI) demonstrating the way risk and integrity of the grid are controlled and the necessary points of improvement.
by Nader Al-Otaibi, Saudi Aramco, Dhahran, Saudi ArabiaAs a result of an Electro-Magnetic Acoustic Transducer (EMAT) In-Line Inspection (ILI) Program, Saudi Aramco has discovered a number of SCC defects in its pipelines. Prioritization criteria based on operating parameters, age and condition were established to manage utilization of the EMAT technology. An extensive field verification program was put in action that illustrated the capabilities of these tools. The paper will review the primary findings of the inspection program. A case study of a gas pipeline — in which SCC cracks were found as a result of EMAT ILI runs — will be provided to outline the actions required in response to the discoveries, and how well the prioritization criteria worked to focus the program on segments of the pipelines most in need of evaluation. The paper will also discuss the proactive approach implemented to maintain the integrity of these pipelines while maintaining reliability of supply. A recent case study of a UT Crack Detection run on an old pipeline is also included. UT Crack Detection ILI tools can provide more flexibility for pipeline operators to inspect liquid lines with respect to cracks, with the ability to inspect wall thickness at the same time. Saudi Aramco Pipelines Department’s future plan for managing pipeline cracks is highlighted.
by Toby Fletcher, Wood Group Integrity Management, Newcastle upon Tyne, UKAssessing how quickly defects may corrode can be a complex undertaking. To simplify such assessments, a single corrosion growth rate may be applied to all defects in a pipeline; this approach is frequently taken as the basis for determining an ILI re-inspection date. The Pipeline Operators’ Forum provides guidance on classifying defects based on pipeline wall thickness, defect axial length and defect circumferential width. Examples include pitting-type defects, general-corrosion-type defects and pinholes. This paper examines the use of these classifications to estimate corrosion growth rates by fitting the dimensions of defects to different statistical distributions. The use of these methods helps to refine estimates of corrosion growth rates and determine more accurate intelligent pig re-inspection intervals.
by Ted L. Anderson, Quest Integrity Group, Boulder, CO, USAThe integrity of pipelines with cracks and other planar flaws has received renewed interest by operators and regulators, due primarily to a number of high-profile incidents. The pipeline industry currently assesses planar flaws with methodology that dates back approximately 40 years. The traditional crack assessment models can lead to gross errors in the prediction of burst pressure. This paper points out the problems with these models, using both theoretical analysis and a comparison with burst test data. The field of fracture mechanics has advanced considerably in the last 40 years, and improved methods are available. This paper describes several such methods, and uses burst test data to demonstrate that state-of-the-art models lead to much more accurate predictions of failure pressure and critical flaw size.
by Dr David Batte, Macaw Engineering, Newcastle upon Tyne, UK, Dr Ray R Fessler, Biztek Consulting, Evanston, IL, USA, Mark L Hereth, PPIC, Bloomfield, CT, USA, Jim Marr, TransCanada Pipelines, Calgary, AB, Canada, and Steve C Rapp, Spectra Energy, Houston, TX, USA
In-line inspection (ILI) tools based on Electromagnetic Acoustic Transducer (EMAT) technology offer an alternative to hydrostatic testing that does not have the disadvantages of interrupting service and requiring the use and disposal of large quantities of water. Furthermore, they have the advantage of providing information about the sizes and locations of cracks that would be left in the pipeline after a hydrostatic test. However, there are issues that arise due to uncertainties regarding the application of EMAT ILI; these center on:
- the possibility of EMAT missing a crack that would otherwise have failed in a hydrostatic test,
- inaccuracies in the dimensions of the cracks that are detected, and
- inaccuracies in the predicted failure pressure.
During a recently-completed Joint Industry Project (JIP), eight major gas pipeline operators have collated and reviewed their experience with current-generation EMAT ILI for detection, sizing and evaluation of stress corrosion cracking (SCC). Results were available from over 45 pipeline inspections totalling more than 3000 miles, during which over 100 features have been confirmed by excavation to be SCC that would probably have failed a hydrostatic test. This experience has demonstrated that features of the size that would just survive a hydrostatic test can readily be detected using EMAT ILI.Other work completed during the JIP has established that the failure pressures of pipe containing SCC can be predicted conservatively to within +/- 20% using the well-established fracture mechanics methods for axial flaws. Finally, the reliability of these methods for SCC threat management has been confirmed by recent field experience with 16 valve sections where EMAT ILI has been followed by hydrostatic testing.
by Richard Kania, TransCanada Pipelines, Calgary, AB, Canada,
Ralf Weber, ILI Consulting, Karlsruhe, Germany, and Stefan Klein, Nikola Jansing, and Michael Meuer, Rosen Innovation Center, Lingen, Germany
by Mark Slaughter, Weatherford, Houston, USA, Michael Huss, Adria-Wien Pipeline GmbH (AWP), Klagenfurt, Austria, and Yuriy Zakharov and Andrey Vassiljev, Weatherford, Moscow, RussiaThe predominant ILI applications utilizing ultrasonic technology have been for wall loss and crack inspection. Despite a high success rate, technological improvements are needed. Among them are higher confidence in the Probability of Detection (POD), improving detection reliability under different pipeline conditions, increased ranges for pipeline operating parameters and utilizing combo WM‐CD mode in one run. In 2010, Weatherford Pipeline and Specialty Services (P&SS) commissioned its new generation fleet of ultrasonic wall measurement and crack detection tools. One of the design objectives was to address some of the ILI tool limitations identified above. This paper reviews the latest design improvements for the new-generation tools and presents a case study on a recent survey conducted on the Adria‐Wien Pipeline (AWP). The pipeline sections inspected were the 30” x 4 km and 18” by 420 km pipeline.
by Collin Taylor, Enbridge Pipelines Inc, Edmonton, AB, Canada
With the current generation of in-line inspection (ILI) tools capable of recording terabytes of data per inspection and obtaining millimeter resolution on features, integrity sciences are becoming awash in a sea of data. However, without proper
alignment and relationships, all this data can be at best noise and at worst lead to erroneous assumptions regarding the integrity of a pipeline system.
This paper will explore the benefits of a statistical alignment method utilizing joint
characteristics, such as length, long-seam orientation (LSO), wall thickness (WT) and girth weld (GW) counts to ensure precision data alignment between ILI inspections. By leveraging the “fingerprint-like” morphology of a pipeline system, many improvements to data and records systems become possible, including but not limited to:
- Random ILI Tool performance errors can be detected and compensated for.
- Repair history and other records become rapidly searchable.
- HNew statistically accurate descriptions are created by leveraging the sensitivities of various ILI technologies.
One area of material data improvement focused on within this paper relates to long-seam type detection through ILI tools. Due to the differing threat susceptibility of various weld types, it is accordingly important to identify the long-seam welds. Construction records of older vintage lines do not always contain information down to the joint level; therefore, ILI tools may be leveraged to increase the accuracy of construction records down to this level. In this paper, the possibility of ILI tools to distinguish different types of longitudinal seam welds is also discussed.
by Ian Smith and Lisa Barkdull, Quest Integrity Group, Houston, TX, USAThis presentation will demonstrate the application of an all-inclusive ILI data set engineering assessment using API 579 fitness-for-purpose methodology and a comparative analysis to the traditional data analysis/engineering assessment approach. The combination of automated processing and human expert intervention form the basis of the ILI data analysis process. Thresholds and boundaries are set during this process in order to present the data analysis results in a spreadsheet or database format. Engineering assessments most often follow the data analysis process, thus the engineering assessment process is only applied to what is found in the spreadsheet. By utilizing compression wave ultrasonic ILI data and API 579 fitness-for-purpose Part 5 Level 2 methodology, the engineering assessment process can be applied directly to the ILI data set. The API 579 methodology evaluates the remaining strength of the complete pipeline, using all of the ultrasonic wall thickness measurements, not just assessing areas where metal loss has been identified and boxed through data analysis process. By assessing the entire ILI data set, thresholds and boundaries no longer limit information the pipeline operator receives about the pipeline. Advantages of this approach include accuracy, no dependence on metal-loss interaction criteria, repeatability and more informative run comparisons.
by Michael Rosenfeld, Kiefner & Assoc./Applus RTD and Robert Fassett, Kleinfelder, Santa Rosa, CA, USAThis paper provides data on pressure-related ruptures due to interacting threats on pipelines that were operating below 30% SMYS. The broader discussion will consider areas of technology that the industry may want to focus on to address issues that may affect local distribution companies more than interstate natural gas operators. The paper will also discuss the types of interaction that caused the ruptures and provide a high-level decision tree that will allow operators to begin to address how to model their systems to determine if they may have these same threat combinations.
by Colin Cochran, Williams Gas Pipeline, Houston, TX, USAWhen coupled with a structured relational data model, GIS provides a sustainable platform for the unique data integration requirements of oil and gas pipeline companies, especially in support of risk assessment and integrity management activities. This presentation presents lessons learned by Williams in the implementation of GIS as an enabling technology for integrity management and regulatory compliance. The presentation includes a review of best practices to support High Consequence Area (HCA) and class location analysis, and ongoing management of modeling results. WGP best practices for integration of inspection and survey data from multiple vendors and sources will also be reviewed, along with risk modeling techniques. Finally, the presentation will include a summary of next steps that are underway to proactively respond to the changing regulatory environment in the US.
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