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.

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.

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.

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.

scholarly journals Data Analysis and Model Validation of Natural Gas Transmission Pipeline With Compressor Station

2019 ◽  
Author(s):  
David Cheng
Keyword(s):  
Performance Analysis ◽  
Natural Gas ◽  
Model Validation ◽  
Measurement Data ◽  
Real Life ◽  
Gas Pipeline ◽  
Physical Parameters ◽  
Pressure Drops ◽  
Natural Gas Transmission ◽  
Transmission Pipeline

Abstract Data from the DCS systems provides important information about the performance and transportation efficiency of a gas pipeline with compressor stations. The pipeline performance data provides correction factors for compressors as part of the operation optimization of natural gas transmission pipelines. This paper presents methods, procedure, and a real life example of model validation based performance analysis of gas pipeline. Statistic methods are demonstrated with real gas pipeline measurement data. The methods offer practical ways to validate the pipeline hydraulics model using the DCS data. The validated models are then used as performance analysis tools in evaluating the fundamental physical parameters and assessing the pipeline hydraulics conditions for potential issues influencing pressure drops in the pipeline such as corrosion (ID change), roughness changes, or BSW deposition.

A Precipitation-Induced Landslide Susceptibility Model for Natural Gas Transmission Pipelines

2010 ◽  
Author(s):  
Jason P. Finley ◽  
David L. Slayter ◽  
Chris S. Hitchcock ◽  
Chih-Hung Lee
Keyword(s):  
Natural Gas ◽  
Landslide Susceptibility ◽  
The United States ◽  
Landslide Risk ◽  
Storm Event ◽  
Precipitation Data ◽  
Rainfall Thresholds ◽  
Natural Gas Transmission ◽  
Quantitative Precipitation Estimates ◽  
Transmission Pipelines

Landslides related to heavy rainfall can cause extensive damage to natural gas transmission pipelines. We have developed and implemented a geographic information system (GIS) model that evaluates near real-time precipitation-induced landslide susceptibility. This model incorporates state-wide precipitation data and geologically-based landslide classifications to produce rapid landslide risk evaluation for Pacific Gas & Electric Company’s (PG&E) gas transmission system during winter rain storms in California. The precipitation data include pre-storm event quantitative precipitation forecasts (QPF) and post-storm event quantitative precipitation estimates (QPE) from the United States National Oceanic and Atmospheric Administration (NOAA). The geologic classifications are based on slope, susceptible geologic formations, and the locations of historic or known landslide occurrences. Currently the model is calibrated using qualitative measures. Various scientists have developed large landslide databases with associated rainfall statistics to determine rainfall thresholds that trigger landslides. With a sufficient number of landslides, we can more precisely determine minimum rainfall thresholds using similar methods.

Data Analysis and Model Validation of Natural Gas Transmission Pipeline With Compressor Station

2019 ◽  
Vol 4 (3) ◽  
Author(s):  
David Cheng
Keyword(s):  
Performance Analysis ◽  
Natural Gas ◽  
Model Validation ◽  
Measurement Data ◽  
Gas Pipeline ◽  
Pipeline System ◽  
Actual System ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Performance Analysis Tools

Abstract Data from the distributed control system (DCS) or supervisory control and data acquisition (SCADA) system provide useful information critical to the evaluation of the performance and transportation efficiency of a gas pipeline system with compressor stations. The pipeline performance data provide correction factors for compressors as part of the operation optimization of natural gas transmission pipelines. This paper presents methods, procedures, and an example of model validation-based performance analysis of a gas pipeline based on actual system operational data. An analysis approach based on statistical methods is demonstrated with actual DCS gas pipeline measurement data. These methods offer practical ways to validate the pipeline hydraulics model using the DCS data. The validated models are then used as performance analysis tools in assessing the pipeline hydraulics parameters that influence the pressure drop in the pipeline such as corrosion (inside diameter change), roughness changes, or basic sediment and water deposition.

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