Development of Guidelines for Parallel Pipelines

2010 ◽  
Author(s):  
Michael R. Acton ◽  
Neil W. Jackson ◽  
Eric E. R. Jager
Keyword(s):  
Natural Gas ◽  
Large Scale ◽  
Operating Pressure ◽  
Sequence Of Events ◽  
Parallel Pipeline ◽  
Pipeline Networks ◽  
Natural Gas Transmission ◽  
Other Substances ◽  
Transmission Pipeline ◽  
Transmission Pipelines

Due to the increasing demand for natural gas in many locations, there is often a need to increase the capacity of existing and future gas transmission pipeline networks. In some situations, there may be a possibility of increasing the operating pressure (e.g. uprating), but in others there may be no alternative but to lay new pipelines, often along the same route as an existing pipeline. If one pipeline fails in this situation, it is possible that a second parallel pipeline may also fail as a result. However, there is also increasing pressure on the use of land and therefore the minimum separations with which pipelines may be laid and operated safely when in parallel to other pipelines need to be considered. This paper describes work carried out as a collaborative project supported by gas transmission pipeline operators to provide guidance on the likelihood of failure of a pipeline, for a range of different conditions, following failure of an adjacent pipeline. A framework has been developed that identifies the sequence of events that could lead to failure of a parallel pipeline, including the possibility of escalation from a leak (or puncture) to a full bore rupture. Work has been carried out including large scale experiments and CFD (Computational Fluid Dynamics) modelling to enable the critical processes in the framework to be quantified. This methodology has been used to produce general guidelines for parallel pipeline assessments, in order to support the design of new parallel pipeline installations. The methodology has been developed specifically for parallel natural gas transmission pipelines. However, the principles are relevant to parallel pipelines transporting other substances, and consideration is given to how the methodology may be adapted for such circumstances. The methodology provides input to any risk assessments of parallel pipeline installations, to quantify the possible contribution to the failure frequency from escalation. General guidance developed using the methodology presented in this paper, has recently been included in the recommendations for steel transmission pipelines, IGEM/TD/1 (Edition 5), published by the Institution of Gas Engineers and Managers. However, where general recommendations are not achievable, the methodology may be applied to take site and pipeline-specific factors into account.

Interactive Simulation of Gas Decompression and Crack Propagation in Natural Gas Transmission Pipelines

2002 ◽  
Author(s):  
Hiroyuki Makino ◽  
Yoshiaki Kawaguchi ◽  
Yoichiro Matsumoto ◽  
Shu Takagi ◽  
Shinobu Yoshimura
Keyword(s):  
Natural Gas ◽  
Crack Propagation ◽  
Shear Fracture ◽  
Interactive Simulation ◽  
Operating Pressure ◽  
Gas Temperature ◽  
Natural Gas Transmission ◽  
Propagating Shear ◽  
Fracture Arrest ◽  
Transmission Pipelines

In this paper, the propagating shear fracture in natural gas transmission pipelines is simulated by an interactive method between gas decompression and crack propagation. A rich gas which contains heavier hydrocarbons than methane is highlighted and the relation between the crack velocity and the distance is simulated for varied condition of pipelines. The results of simulation are shown in the relation between the fracture arrest distance and the toughness of the pipes used, and the effects of the difference in gas compositions, increase of the operating pressure and the change of the initial gas temperature are discussed. The results of the simulation make it clear that the rich gas increases the risk for long running fracture, the simple increase of the operating pressure by increasing the design factor causes long crack propagation, increase of the operating pressure by using higher grade pipes not always invites long crack propagation and lower temperature increases the fracture arrest distance in relatively lower pressure but decreases the distance in relatively higher pressure. All the discussion in this study indicates that the analysis of the decompression behavior of the inner gas is essential for the interpretation of the phenomenon of the propagating shear fracture in pipelines. It is concluded that the fluid characteristics of the gas transmitted and material characteristics of the pipes used should be matched appropriately for the safety of the pipelines.

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.

Safe Separation Distances: Natural Gas Transmission Pipeline Incidents

1998 ◽  
Author(s):  
Eugene Golub ◽  
Joshua Greenfeld ◽  
Robert Dresnack ◽  
F. H. Griffis ◽  
Louis Pignataro
Keyword(s):  
Natural Gas ◽  
Separation Distance ◽  
Transportation Safety ◽  
Physical Parameters ◽  
Operating Pressure ◽  
Strong Correlations ◽  
Area Burned ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Pipeline Failures

The paper discusses a methodology to define safety implications of and damages that have resulted from gas transmission pipeline failures where fire and/or explosions have occurred. The records of the National Transportation Safety Board were examined to determine the area that was burned and/or impacted by a resulting explosion. The impacted area was then correlated with the physical parameters of the pipeline to see if a relationship existed. The parameters considered included the pipe diameter, the operating pressure at the point of release, the volume of material released, the maximum radius burned by the fire, the height of the flame and the maximum distance effected by the resulting explosion (if one occurred). Two strong correlations were found between the operating pressure in the pipe and the area burned in the incident for the two cases, with and without an explosion taking place. These results may be used to define a safe separation distance for a natural gas transmission pipeline.

Ignition Probability for High Pressure Gas Transmission Pipelines

2008 ◽  
Author(s):  
Michael R. Acton ◽  
Philip J. Baldwin
Keyword(s):  
High Pressure ◽  
Statistical Analysis ◽  
Natural Gas ◽  
Large Diameter ◽  
Recent Analysis ◽  
Operating Pressure ◽  
Ignition Probability ◽  
Underground Pipelines ◽  
Natural Gas Transmission ◽  
Transmission Pipelines

For most fuels transported by pipeline, whether or not ignition of an accidental release occurs is a critical factor in determining the extent of the resulting hazard. The probability of ignition is therefore a key input when undertaking pipeline risk assessments and the value chosen is a direct multiplier of the risk calculated. Typically, the ignition probability assigned is based on an analysis of historical data. However, the pipeline industry has a good safety record and major incidents are rare, sometimes resulting in widely differing values being used due to the scarcity of reliable data. For high pressure natural gas transmission pipelines, it is observed that ruptures of large diameter underground pipelines operating at high pressures can result in ignited releases even in remote areas with no obvious ignition sources present. Conversely, failures of small diameter pipelines operating at lower pressures rarely result in ignited releases, suggesting that ignition sources generated as a result of the failure event itself may be significant in causing ignition of high pressure natural gas releases from underground pipelines. The results of analysis previously reported at IPC2002 indicated a trend for the ignition probability to increase with pd2, with p the pipeline operating pressure (bar) and d the pipeline diameter (m). The relationship forms the basis of the default ignition probabilities recommended for use in the PIPESAFE package developed for risk assessment of gas transmission pipelines. Since the previous study was carried out, the number of pipeline rupture incidents in the dataset used has increased by about 20%, and following a recent review, the statistical analysis has been extended and refined. This paper reports the results of recent analysis of the most comprehensive incident dataset available to Advantica for natural gas transmission pipelines, presenting the correlation derived from a simple statistical analysis together with consideration of possible physical explanations for the trends observed based on an ongoing programme of research into the causes of ignition.

Supporting Guidelines for Reviewing Reliability-Based Assessments of Onshore Non-Sour Natural Gas Transmission Pipelines

2012 ◽  
Author(s):  
Marcus McCallum ◽  
Rafael G. Mora ◽  
Graham Emmerson ◽  
Thushanthi Senadheera ◽  
Andrew Francis
Keyword(s):  
Natural Gas ◽  
Operating Pressure ◽  
Crucial Step ◽  
Location Class ◽  
Preventative Measures ◽  
Natural Gas Transmission ◽  
Assessment Guidelines ◽  
Pipe Replacement ◽  
Integrity Assessments ◽  
Transmission Pipelines

In Canada, a great deal of effort has been invested into the use of reliability-based techniques for the design and assessment of non-sour natural gas transmission pipelines. This led to the inclusion of Annex O in the Canadian onshore pipeline code CSA Z662 in 2007, which gives detailed descriptions of all of the key components of reliability-based approaches. However, the annex does not and is not intended to provide recipes for using the reliability-based techniques for particular fields of application such as evaluating the acceptability of changes to location class, service or increasing maximum operating pressure. Consequently, the onus is on the reliability/integrity engineer to tailor the approach to the particular field of application and the specifics of the pipeline. This means that even working in accordance with the code, the approach and optimizing techniques adopted by one engineer may be very different to that adopted by another. This presents a challenge for those reviewing reliability based plans, designs and alternatives for approval. The National Energy Board (NEB) engaged Andrew Francis & Associates Ltd (AFAA) to assist them with constructing a set of supporting guidelines to assess the comprehensiveness and safety of reliability based submissions. Unlike customary design reviews, the guidelines are geared towards provoking a reviewer into asking delving questions rather than into going through a ‘box-checking’ questionnaire. Indeed, asking the case-specific and clarification questions is regarded as a crucial step towards determining the adequacy and effectiveness of the measures proposed in the content and conclusions of a particular filing. Simply questioning whether Annex O has been followed is not encouraged and, even when safety criteria appear to have been met (i.e. box-checking), a reviewer is prompted to challenge the reasonableness of assumptions and ask whether safety levels are providing the lowest practicable risk to the Canadian public. One line of inquiring might be: are sufficient data available; are the data reliable; are the data relevant to the case under consideration; or have the data been analyzed using a valid method applicable to the case. Other typical questions would be have the consequences been properly assessed and are the mitigative and preventative measures providing the lowest practicable risk compared to pressure reduction and pipe replacement. The purpose of this paper is to present an overview of the assessment guidelines and the approach and key considerations for conducting efficient, consistent and fair reviews of reliability based assessments of hazardous material pipelines. In doing so, the paper also identifies some of the pitfalls that engineers conducting reliability based integrity assessments should seek to avoid.

Third-Party Damage Monitoring: Internal Fiber Optic Installation on a Transmission Pipeline Using a Pig, a Disengagement System and a Pack-Off Hanger

2020 ◽  
Author(s):  
Carly Meena ◽  
Neil Gulewicz ◽  
Carl Kennedy ◽  
Tim Collis
Keyword(s):  
Natural Gas ◽  
Fiber Optics ◽  
Fiber Optic ◽  
Pilot Project ◽  
Third Party ◽  
Distributed Monitoring ◽  
Capillary Tubing ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Transmission Pipelines

Abstract The risk associated with third-party damage to transmission pipelines in areas of urban development is high. Distributed monitoring is a modern technique that uses fiber optic cables as sensors to continuously monitor pipeline parameters such as acoustics, vibration, strain and temperature. The fiber optic system notifies the operator in real-time of ongoing events allowing decisions to be made to prevent external interference or quickly address an incident that has already occurred. Traditional methods used to install distributed monitoring systems on pipelines have limitations and are not feasible for all transmission pipelines. For instance, it can be both challenging and expensive to trench in fiber optics in developed areas and other installation techniques require the pipeline to be temporarily taken out of service. SaskEnergy Incorporated’s transmission line subsidiary, TransGas Limited partnered with a Canadian pipeline monitoring service provider to install fiber optics inside of a natural gas transmission pipeline using a pig, steel capillary tubing and a pack-off hanger. A disengagement system was incorporated to release the fiber optics after the desired monitoring distance was reached. It was decided to perform the pilot project on a newly constructed NPS 6 natural gas transmission pipeline located in Humboldt, Saskatchewan. Nitrogen was used as a medium to simulate an in-service pipeline in order to reduce the risks associated with the first attempt of the project designs. The fiber optics were inserted into steel capillary tubing and connected to a disengagement system located at the back of a pig. A pack-off hanger was used to maintain pipeline pressure during and after the installation was completed. The spool holding the steel capillary tubing was stopped once the maximum monitoring distance was reached and the differential pressure activated the disengagement system located at the back of the pig. The pig continued to the receive location and the fiber optics remained in the pipeline for continuous monitoring. The deployment was successful and the fiber optics will remain in the pipeline for a one (1) year monitoring period. The primary limitation to this pilot project was the strength of the steel capillary tubing. The steel capillary tubing’s ultimate tensile strength would have to be higher to accommodate a pipeline with a larger outside diameter, multiple bends, large changes in wall thickness or large elevation changes. In addition, the steel capillary tubing must be removed from the pipeline in order to perform pigging activities.

Integrity Assurance of Natural Gas Transmission Pipelines

1993 ◽  
Vol 46 (5) ◽  
pp. 146-150 ◽  
Author(s):  
G. J. Posakony
Keyword(s):  
Natural Gas ◽  
Preventive Maintenance ◽  
The United States ◽  
Direct Access ◽  
Pipeline System ◽  
Rehabilitation Programs ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Integrity Assurance ◽  
Transmission Pipelines

Natural gas transmission pipelines have proven to be a safe and efficient means for transporting the trillions of cubic feet of natural gas used annually in the United States. Since the peak of construction of these pipelines occurred between 1950 and the mid-1960s, their average age is now over thirty years. However, replacement of these pipelines because of age would be prohibitively expensive and unnecessary. Preventive maintenance and rehabilitation programs put into practice by the pipeline industry provides the key to ensuring the continued integrity of the transmission pipeline system. This article reviews the preventive maintenance practices commonly used by the gas industry. These practices include right-of-way patrols, corrosion control procedures, in-line inspection with intelligent or smart pigs that inspect the pipe while traveling through the inside of the pipe, direct access inspection of the pipe from bellhole excavations, and hydrostatic retesting of pipelines. When pipelines are properly maintained, these practices can ensure the integrity and long-term serviceability of transmission pipelines well into the 21st Century.

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