Inline Inspection Decisions and Results Using an Integrated Technology for a Baseline Inspection Program on a Large Diameter High Pressure Gas Transmission and Interconnect System

2004 ◽  
Author(s):  
Stephen Westwood ◽  
Arti Bhatia
Keyword(s):  
High Pressure ◽  
Large Diameter ◽  
Lessons Learned ◽  
Metal Loss ◽  
Pipeline System ◽  
Pressure System ◽  
Integrated Technology ◽  
Pressure Transmission ◽  
Transmission Pipeline ◽  
Integrity Management

The Alliance Pipeline System consists of 2664 Km of NPS 36 high pressure transmission pipeline and 339 Km of NPS 42 high pressure transmission pipeline. The mainline systems are connected by lateral and interconnect pipeline sections ranging in diameter from NPS 4 to NPS 24. The pipeline system extends from northeast British Columbia to Illinois. The Trans border nature of the pipeline means that it needs to satisfy both the Canadian and US regulatory requirements related to pipeline integrity management. Part of the approval process for the pipeline system was that it had to be inspected on a regular basis with a baseline inspection program to be initiated upon start-up of the pipeline system in 2000. This paper outlines some of the unique challenges the high pressure transmission pipeline presented to both the operator and the inline inspection (ILI) vendor in developing a successful in line inspection program. It discusses the vendor selection criteria used by the pipeline operator and the design process undertaken by the ILI Vendor to meet the requirements of this unique pipeline system. By the end of 2004, the mainline sections in Canada and the US will have been inspected as well as most of the smaller diameter interconnect and lateral system. Results are presented from the ILI inspection of both the high pressure system and the smaller diameter system. While the inspections have used Magnetic Flux leakage (MFL) Technology to detect metal loss features, the use of integrated technology in particular the inertial navigation system aboard the vendor’s inspections tools has allowed geometric features to be detected as well. Lessons learned from both the operator and the ILI Vendor will be presented on the execution of the inline inspection program as well as discussion on ways of ensuring that the ILI process goes smoothly and if not how to address these concerns.

scholarly journals Experimental Studies of Releases of High Pressure Natural Gas From Punctures and Rips in Above-Ground Pipework

2000 ◽  
Author(s):  
Geoff Hankinson ◽  
Barbara J. Lowesmith ◽  
Philippe Genillon ◽  
Gilbert Hamaide
Keyword(s):  
High Pressure ◽  
Natural Gas ◽  
Experimental Studies ◽  
Gas Industry ◽  
Size And Shape ◽  
Experimental Parameters ◽  
Pressure Transmission ◽  
Transmission Pipeline ◽  
Release Height ◽  
Gas Cloud

The gas industry has an excellent safety record in operating high-pressure transmission pipelines. Nevertheless, it is important that pipeline operators have an understanding of the consequences of possible accidental gas releases, in order to help manage the risks involved. This paper presents a programme of full scale experiments, undertaken by an international collaboration of gas companies, to study the consequences of both unignited and ignited releases of natural gas from simulated punctures and rips in a 900mm diameter above-ground transmission pipeline. Experimental parameters varied during the programme included release orifice size and shape, release pressure, release height, release direction, wind speed and wind direction. Instrumentation was deployed to obtain detailed data on the dispersion of gas, the ignitability of the gas cloud produced, the levels of incident thermal radiation and the resulting fire size and shape, following ignition. The results provide important data for the validation of mathematical models, used in developing risk assessment methodologies for gas pipelines, and in establishing those standards and design codes that are risk based.

Inspection and Prioritization Methods for Small Diameter Auxiliary Piping

2014 ◽  
Author(s):  
Adam Pecush ◽  
Mark McTavish ◽  
Brian Ellestad
Keyword(s):  
Oil And Gas ◽  
Large Diameter ◽  
Small Diameter ◽  
Oil And Gas Industry ◽  
Lessons Learned ◽  
Pipeline System ◽  
Gas Industry ◽  
Model Sets ◽  
Pump Stations ◽  
And Storage

To serve the pumping and storage needs of its customers; Enbridge operates more than 25 terminals and 150 pump stations across North America. In each of these facilities, small diameter (NPS 6 and smaller) piping is used in auxiliary systems including instrumentation, measurement, and product re-injection. Traditionally, in the design of facilities, this small piping has received less attention than large diameter process lines and, during construction, has typically been field run based on standard installation details. This, in conjunction with 65 years of changing design and construction philosophies, as well as asset acquisitions, has resulted in a wide variety of installation configurations across the Enbridge liquids system. The Small Diameter Piping Program in the Facilities Integrity group centrally manages the integrity of all small diameter auxiliary piping across the Enbridge liquids system. Historically, the management and remediation of small diameter systems has been based on addressing specific installation types identified through incident investigations. While generally effective at minimizing re-occurrence, this approach has been limited in its ability to proactively identify installations that should be addressed. In support of our goal of zero incidents, Enbridge has developed a proactive methodology for the inspection and prioritization of small diameter auxiliary piping. Installation types are evaluated on their susceptibility to specific damage mechanisms. An inspection and prioritization model was developed through the combination of internal lessons learned and prioritization methodologies outlined in industry publications, specifically those from the overseas oil and gas industry. This model, sets a standardized process to assign a likelihood of failure (LOF) score to individual small diameter installations of specific types and/or functions. Presently, likelihood of failure scores are used to identify installations requiring remediation, and to most effectively prioritize system-wide remediation activities. Over time, these scores will also be used to demonstrate an overall reduction in the likelihood of failure for small diameter piping in the Enbridge liquids pipeline system.

Gas Transmission Pipeline Safety and Integrity Activities and Results for INGAA Pipeline Companies

2012 ◽  
Author(s):  
Terry Boss ◽  
J. Kevin Wison ◽  
Charlie Childs ◽  
Bernie Selig
Keyword(s):  
Natural Gas ◽  
Management Practices ◽  
Pipeline System ◽  
Mandated Reporting ◽  
Pipeline Systems ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Integrity Management ◽  
Pipeline Safety ◽  
Transmission Pipelines

Interstate natural gas transmission pipelines have performed some standardized integrity management processes since the inception of ASME B3.18 in 1942. These standardized practices have been always preceded by new technology and individual company efforts to improve processes. These standardized practices have improved through the decades through newer consensus standard editions and the adoption of pipeline safety regulations (49 CFR Part 192). The Pipeline Safety Improvement Act which added to the list of these improved practices was passed at the end of 2002 and has been recently reaffirmed in January of 2012. The law applies to natural gas transmission pipeline companies and mandates additional practices that the pipeline operators must conduct to ensure the safety and integrity of natural gas pipelines with specific safety programs. Central to the 2002 Act is the requirement that pipeline operators implement an Integrity Management Program (IMP), which among other things requires operators to identify so-called High Consequence Areas (HCAs) on their systems, conduct risk analyses of these areas, and perform baseline integrity assessments and reassessments of each HCA, according to a prescribed schedule and using prescribed methods. The 2002 Act formalized, expanded and standardized the Integrity Management (IM) practices that individual operators had been conducting on their pipeline systems. The recently passed 2012 Pipeline Safety Act has expanded this effort to include measures to improve the integrity of the total transmission pipeline system. In December 2010, INGAA launched a voluntary initiative to enhance pipeline safety and communicate the results to stakeholders. The efforts are focused on analyzing data that measures the effectiveness of safety and integrity practices, detects successful practices, identifies opportunities for improvement, and further focuses our safety performance by developing an even more effective integrity management process. During 2011, a group chartered under the Integrity Management Continuous Improvement initiative(IMCI) identified information that may be useful in understanding the safety progress of the INGAA membership as they implemented their programs that were composed of the traditional safety practices under DOT Part 192, the PHMSA IMP regulations that were codified in 2004 and the individual operator voluntary programs. The paper provides a snapshot, above and beyond the typical PHMSA mandated reporting, of the results from the data collected and analyzed from this integrity management activity on 185,000 miles of natural gas transmission pipelines operated by interstate natural gas transmission pipelines. Natural gas transmission pipeline companies have made significant strides to improve their systems and the integrity and safety of their pipelines in and beyond HCAs. Our findings indicate that over the course of the data gathering period, pipeline operators’ efforts are shown to be effective and are resulting in improved pipeline integrity. Since the inception of the IMP and the expanded voluntary IM programs, the probability of leaks in the interstate natural gas transmission pipeline system continues on a downward slope, and the number of critical repairs being made to pipe segments that are being reassessed under integrity programs, both mandated and voluntary, are decreasing dramatically. Even with this progress, INGAA members committed in 2011 to embarking on a multi-year effort to expand the width and depth of integrity management practices on the interstate natural gas transmission pipeline systems. A key component of that extensive effort is to design metrics to measure the effectiveness to achieve the goals of that program. As such, this report documents the performance baseline before the implementation of the future program.

Enhanced Use of ILI Data to Improve Integrity Decisions

2012 ◽  
Author(s):  
Collin Taylor ◽  
Renkang Rain Zhu
Keyword(s):  
Metal Loss ◽  
Pipeline System ◽  
Precision Data ◽  
Data Alignment ◽  
Joint Characteristics ◽  
Tool Performance ◽  
Integrity Management ◽  
Data Improvement ◽  
Longitudinal Seam ◽  
Flux Leakage

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. • New 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 weld types for integrity management purposes. 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, such as magnet flux leakage tools, ultrasonic crack tools, and ultrasonic metal loss tools, to distinguish different types of longitudinal seam welds is also discussed.

A Midstream Pipeline Operator’s Perspective on the Implementation of API 1183

2020 ◽  
Author(s):  
Jeremiah Konell ◽  
Brian Dedeke ◽  
Chris Hurst ◽  
Shanshan Wu ◽  
Joseph Bratton
Keyword(s):  
Selection Process ◽  
Management Program ◽  
Operating Conditions ◽  
Metal Loss ◽  
Pipeline System ◽  
Stress Risers ◽  
Integrity Management ◽  
Primary Focus ◽  
Condition Assessments ◽  
The Impact

Abstract In preparation for the upcoming (currently in draft form) Recommended Practice (RP) on Dent Assessment and Management (API 1183) [1], Explorer Pipeline Company, Inc. (Explorer) has performed an internal procedural review to determine how to effectively implement the methodologies into their Integrity Management Program (IMP). Explorer’s pipeline system transports hazardous liquids and is comprised of over 1,800 miles of pipeline ranging in diameter from 3 to 28 inches. The majority of the system was installed in the 1970s, but parts of the system were also installed as early as the 1940s. The primary focus of this review and implementation into the IMP is in regard to performing and responding to in-line inspection (ILI) based integrity assessments. Prior to the development of API 1183, dent assessment and management consisted of following a set of prescriptive condition assessments outlined in the Code of Federal Regulations (CFR) Title 49, Part 195.452. In order to do this, pipeline operators required basic information, such as dent depth, orientation, and interaction with potential stress risers such as metal loss, cracks, gouges, welds, etc. However, in order to fully implement API 1183, additional parameters are needed to define the dent shape, restraint condition, defect interaction, and pipeline operating conditions. Many new and necessary parameters were identified throughout the IMP, from the very initial pre-assessment stage (new ILI vendor requirements as part of the tool/vendor selection process) all the way to defining an appropriate reassessment interval (new process of analyzing dent fatigue life). This paper summarizes the parameters of API 1183 that were not part of Explorer’s current IMP. The parameters are identified, and comments are provided to rank the level of necessity from “must have” to “beneficial” (e.g. can sound and conservative assumptions be made when a parameter is not available). Comments are also provided to explain the impact of applying assumptions in place of parameters. The table of identified parameters should provide a useful tool for other pipeline operators who are considering implementing API 1183 as part of their overall IMP.

Pipeline Separation: A Review of Requirements, Guidance and Best Practices

2014 ◽  
Author(s):  
Danielle Demers ◽  
Arti Bhatia
Keyword(s):  
High Pressure ◽  
Natural Gas ◽  
Best Practices ◽  
High Energy ◽  
Separation Distance ◽  
Pipeline System ◽  
Buried Structures ◽  
Right Of Way ◽  
Natural Gas Transmission ◽  
Transmission Pipeline

Alliance Pipeline (Alliance), an integrated Canadian and U.S. high-pressure, high-energy natural gas transmission pipeline system, is committed to the development and application of best practices for the full lifecycle of its pipeline system. Currently, there are several publications which individually set out minimum pipeline separation requirements, and discuss considerations for establishing an appropriate separation distance between adjacent pipelines or other buried structures sharing the same right-of-way (RoW). Alliance has reviewed these existing publications, and has consolidated the requirements, guidance, and best practices discussed therein for application in its own company practices. This paper summarizes the review and consolidation of these requirements, guidance, and best practices.

The Development of a Facilities Integrity Management Program Recommended Practice for Canadian Energy Pipelines

2014 ◽  
Author(s):  
Reena Sahney ◽  
Mike Reed ◽  
Darren Skibinsky
Keyword(s):  
Management System ◽  
Performance Metrics ◽  
Systems Approach ◽  
Management Program ◽  
Management Systems ◽  
Pipeline System ◽  
Main Challenge ◽  
Transmission Pipeline ◽  
Integrity Management ◽  
Major Equipment

The Canadian Energy Pipeline Association (CEPA) is a voluntary, non-profit industry association representing major Canadian transmission pipeline companies. With the advent of changes in both CSA Z6621 as well as the National Energy Board Onshore Pipeline Regulations (OPR)2, the membership determined a Recommended Practice regarding a Management Systems Approach for Facilities Integrity was needed. As such, the Pipeline Integrity Working Group (PIWG) within CEPA formed a task group to support the initiative. The outlined approach was intended to have two main philosophical underpinnings: it must comprehensively support safe pipeline system operations and it must provide a practical mechanism for implementing a management systems approach for Facilities Iintegrity. The main challenge in developing a framework for a Facilities Integrity Management System lies in the broad range of equipment and system types that the management system must encompass. That is, equipment, in the context of Facilities Integrity Management, must encompass not only station equipment (such as rotating equipment, valves, meters etc.,) but also categories such as high pressure station piping and fuel lines. Further, there was the recognition that Operators already have an array of tools, processes and techniques in place to manage their various equipment and systems. In light of these observations, the Recommended Practice describes a framework that uses major equipment types as a key differentiator. This is an approach that can be easily aligned with existing corporate computerized maintenance management systems (CMMS) such as SAP™ or Maximo™. Once the equipment categorization has been established, the Recommended Practice then provides guidance regarding the specific requirements that should be addressed for each equipment category based on the framework in CSA Z662-11 Annex N. Specific suggestions are provided in the areas of: alignment with corporate goals and objectives, scope, definitions, performance metrics, risk assessments, competency of personnel, change management as well as documentation. The approach also maximizes the opportunity to leverage existing systems and processes to the extent possible. Overall the Recommended Practice should provide operators with a practical way to achieve a greater degree of rigor and alignment of facilities integrity management while ensuring detailed study and analysis is focused in the most appropriate areas.

A Structured Approach for Managing Engineering Assessments

2014 ◽  
Author(s):  
Mike Reed ◽  
Reena Sahney ◽  
Darren Skibinsky
Keyword(s):  
Decision Making ◽  
High Pressure ◽  
Systematic Approach ◽  
Program Review ◽  
Pipeline System ◽  
Right Of Way ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Structured Approach ◽  
Specific Challenge

Alliance Pipeline, (Alliance), an integrated Canadian and U.S. high-pressure rich natural gas transmission pipeline system, conducts Engineering Assessments for a variety of reasons related to integrity activities such as investigative digs, right-of-way crossings, encroachments and program review; however, the need for a consistent and systematic approach to perform work of this nature was identified. As such, the company launched an initiative to develop a structured approach for undertaking, reviewing and approving Engineering Assessments. The specific challenge in developing a framework for conducting Engineering Assessments is twofold: the framework must be scalable, to address a broad range of situations, while remaining practical to use and understand. In light of these requirements, Alliance chose to adopt a “Tiered” approach to identifying requirements associated with each engineering assessment. The Tier of the Engineering Assessment is defined based on two primary factors: the complexity of the analysis (i.e., whether the methodology of the analysis is well established or not) and the nature of the underlying assumptions (i.e., whether the assumptions associated with the analysis are within established parameters). Once the appropriate Tier has been selected, the framework then provides guidance regarding the specific requirements in the areas of: responsibilities and qualifications of individuals for preparation, review and approval of the assessment as well as documentation. The implementation and use of the structured approach was intended to ensure the Engineering Assessments undertaken within pipeline integrity were technically sound, while recognizing that a broad range of technical complexity, skill level and decision making are associated with Engineering Assessment. Overall, this approach will allow Alliance to achieve a degree of uniformity of its Engineering Assessments in order to manage risks effectively, while addressing the needs of a broad range of scenarios that rely on the methodology.

scholarly journals Full Flow High Pressure Hot Taps: The New Technology and Why It’s Indispensable to Industry

1998 ◽  
Author(s):  
John A. McElligott ◽  
Joe Delanty ◽  
Burke Delanty
Keyword(s):  
High Pressure ◽  
New Technology ◽  
Large Diameter ◽  
Cost Savings ◽  
Pipeline System ◽  
Gas Industry ◽  
The North ◽  
System Integrity ◽  
Pressure Pipeline ◽  
High Pressure Pipeline

The connection of a new pipeline lateral or loop to an existing high pressure pipeline system has always been fraught with high costs and the potential for major system impacts. Pipeline owners and operators have historically had to choose between a traditional cold connection with its high associated costs and a less expensive but more mysterious hot tap. Although the cost savings of a hot tap have always been considerable, they were not always sufficient to justify the risk of complications during the branch weld or hot tap or during the subsequent operation of the system. Despite their extraordinary costs and throughput impacts, the perceived certainties of cold connections were often sufficient to justify their regular use. The recent Kyoto Protocol on Climate Change has resulted in new commitments by the world’s governments to reduce greenhouse gas emissions. For the North American gas industry, these initiatives could result in voluntary compliance objectives, incentive based programs or legislated reforms — any of which will have significant impacts on current practices. TransCanada PipeLines Limited (TransCanada) has successfully managed the risk/reward conundrum and completed more than 700 large diameter (NPS 12 to NPS 30) horizontal high pressure hot taps without incident since 1960. TCPL’s research and development work has enabled it to refine its procedures to the point where it can now complete branch welding and hot tapping work with minimal effects on throughput, negligible emissions and no system integrity impacts. For TransCanada, the direct advantages of a hot tap over a cold connection have resulted in the avoidance of gross revenue losses of $1 million or more per hot tap, no environmental emissions, seamless service and no impacts whatsoever to shippers. TransCanada PipeLines Services Ltd. (TPSL) has further streamlined the supporting field procedures and now provides a complete turn key service to industry.

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