Effective Pipeline Integrity Management in the Magallanes Region of Chile

2010 ◽  
Author(s):  
E. Salinas ◽  
A. Mun˜oz ◽  
A. Wilde ◽  
J. Healy ◽  
M. Bakayeva
Keyword(s):  
Natural Gas ◽  
Crude Oil ◽  
Operational Reliability ◽  
Management Plan ◽  
Pipeline System ◽  
Energy Company ◽  
Exploration And Production ◽  
Integrity Management ◽  
Business Line ◽  
The Impact

Empresa Nacional del Petro´leo (ENAP) is an energy company, wholly owned by the Chilean Government. With regards to overall management, the company comprises of two Business Divisions: Exploration and Production (Up-stream) and Refining and Logistic (Down-stream), complemented by corporate managerial structures. The objective of ENAP’s Exploration and Production (UpStream) business line is the exploration and exploitation of hydrocarbons (oil and natural gas) in the South of Chile (Magallanes) and abroad, as well as geo-thermal energy, in this case, associated with private entities in areas of Northern Chile. Within the Magallanes region ENAP operates approximately 2,200 km of natural gas, crude oil and refined product pipelines. These pipelines range in diameter from 4 to 20 inch and the majority of pipelines are over 30 years old. Due to operational reliability reasons, since 1998 ENAP has been regularly inspecting its pipelines using intelligent in-line inspection tools. Furthermore, since 2006, as part of an overall pipeline integrity management plan ENAP has been conducting Fitness for Service assessments on selected pipelines including a risk-based assessment considering pipeline condition and the impact on the continuity of operation. The Integrity Management Plan implemented by ENAP in the Magallanes region has been applied to all pipelines transporting gas, crude oil and refined products, including those built after 1990. This plan comprises the construction phase, from which invaluable information is gathered for later use. The primary aims of ENAP’s integrity management plan are: - To protect the public; - To protect the surrounding environment by preventing pipeline failures; - To ensure efficient usage of the budget available to conduct maintenance tasks; - To prevent damage to the pipelines, e.g. due to corrosion activity; - To provide clarity of activities being performed by ENAP in order to ensure an efficient, safe and reliable pipeline system. This paper provides a description of the integrity management strategy adopted by ENAP and includes a review of a number of the challenges encountered during its implementation.

SCC Integrity Management Case Study: Kinder Morgan Natural Gas Pipeline of America

2004 ◽  
Author(s):  
J. D. Davis ◽  
J. E. Marr ◽  
D. Venance
Keyword(s):  
Natural Gas ◽  
Management Plan ◽  
Gas Pipeline ◽  
Pipeline System ◽  
Line System ◽  
Neutral Ph ◽  
Natural Gas Pipeline ◽  
Integrity Management ◽  
Using Data ◽  
Management Case Study

Natural Gas Pipeline Company of America (NGPL), a subsidiary of Kinder Morgan, Inc., has been monitoring their pipeline system for the presence and severity of stress corrosion cracking (SCC) for more than thirty years. With the identification of near neutral pH SCC (also called low pH SCC) on this system, over the past five years NGPL has implemented a comprehensive SCC integrity management plan (IMP). Through their SCC IMP, NGPL has been finding and eliminating near critical near neutral pH SCC and other defects from their system, while using data from the program to obtain a better understanding of the relationship of SCC to existing pipe and environmental conditions. NGPL transports commercial quality natural gas to the Chicago area through a multi-line system that originates in various North American supply regions. The system right-of-way encompasses most of the American mid-west and crosses many physiographic areas. The pipelines have varying grades, diameters, and wall thicknesses, and were constructed at different times. Overall there are approximately 10,000 miles (16,000 kilometers) of pipeline that fall within the current NGPL SCC IMP. The primary purpose of this paper is to relate some of our experience with SCC on our system and describe the some of the innovative technical aspects of the existing in-house SCC IMP. This paper outlines some historical examples of the NGPL methodology for detecting near neutral pH SCC in pipeline steels using two or more separate pipeline investigation techniques. The basic steps of SCC direct assessment (DA) are described, as well as the process of integrating the predictive SCC model with in-line inspection (ILI) low level analysis signatures to determine the extent and severity of near neutral pH SCC on the NGPL pipeline system.

Management of Pipeline Dents and Mechanical Damage in Gas Pipelines

2006 ◽  
Author(s):  
David J. Warman ◽  
Dennis Johnston ◽  
John D. Mackenzie ◽  
Steve Rapp ◽  
Bob Travers
Keyword(s):  
High Resolution ◽  
Magnetic Flux ◽  
Mechanical Damage ◽  
Management Plan ◽  
Magnetic Flux Leakage ◽  
Pipeline System ◽  
Channel Geometry ◽  
Channel Deformation ◽  
Integrity Management ◽  
Flux Leakage

This paper describes an approach used by Duke Energy Gas Transmission (DEGT) to manage dents and mechanical damage as part of its overall Integrity Management Plan (IMP). The approach provides guidance in the process for evaluating deformation anomalies that are detected by high resolution magnetic flux leakage (HR-MFL) and multi-channel geometry in-line inspection tools, the process to determine which deformations will be selected for excavation, the process to conduct pipeline field excavations, assessments, and repairs for pipeline integrity purposes. This approach was developed, tested and fully implemented during pipeline integrity work over a two year program involving over 1,100 miles of HR-MFL and 900 miles of geometry in-line inspection. Integration of data from high resolution ILI tools (HR-MFL and multi-channel deformation tools) was used to identify and characterize dents and mechanical damage in the pipeline system. From subsequent field assessments and correlation with ILI results, the processes were refined and field procedures developed. The new guidance provided in the 2003 edition of ASME B31.8 was used as the governing assessment criteria.

scholarly journals Crude oil, natural gas, and economic growth: impact and causality analysis in Caspian Sea region

2018 ◽  
Vol 54 (3) ◽  
pp. 169-184 ◽  
Author(s):  
S M Rashed Jahangir ◽  
Betul Yuce Dural
Keyword(s):  
Economic Growth ◽  
Natural Gas ◽  
Crude Oil ◽  
Caspian Sea ◽  
Oil Price ◽  
Crude Oil Price ◽  
Causality Test ◽  
Oil And Natural Gas ◽  
Gas Price ◽  
The Impact

Abstract The main objective of this study was to investigate the impact and causality of crude oil and natural gas on economic growth in the Caspian Sea region. Here, the study applies ordinary least square (OLS) method and Granger causality test using time series data from 1997 to 2015 to ascertain the impact and causality of crude oil and natural gas on economic growth. The results, according to the OLS method, evince that crude oil and natural gas have a significant impact on economic growth of the region. Alongside, considering causality test, gross domestic product (GDP) does Granger cause (unidirectional) crude oil price and export which denotes that GDP can help to forecast crude oil price and export; however, crude oil price and export cannot help to forecast GDP. Surprisingly, this direction is unlikely for GDP and natural gas. GDP and natural gas have unidirectional, but opposite causal relationship, i.e., natural gas price and export do Granger cause GDP which signify that natural gas price and export can help to forecast GDP; however, GDP cannot help to forecast crude oil price and export.

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.

Pipeline Integrity Management at Kuwait Oil Company

2006 ◽  
Author(s):  
Todd R. Porter ◽  
Emad Al-Nasser
Keyword(s):  
Mechanical Damage ◽  
Management Plan ◽  
Pipeline System ◽  
Fuel Gas ◽  
Water Pipelines ◽  
Integrity Management ◽  
The State Of Kuwait ◽  
External Corrosion ◽  
Project Life ◽  
Oil Company

Kuwait Oil Company (KOC) operates large pipelines system in the State of Kuwait. This pipeline system is comprised of a complex network of high pressure gas, low pressure gas, fuel gas, condensate, crude subsystems as well as water pipelines. A Total Pipeline Integrity Management System (TPIMS) project was initiated in early 2005 to provide KOC with a complete system baseline, integrity management plan and system, and assessments. Periodic re-assessments will be conducted throughout the project life cycle to manage priorities and optimize integrity, repair and maintenance operations. The primary integrity threat of the pipeline system is Internal and External Corrosion, with secondary threats of mechanical damage and Stress Corrosion Cracking (SCC) to be considered as well. This case study will present the design, implementation and execution of a comprehensive approach to pipeline integrity management. Aspects of data management / analysis, integrity (ILI, DA) and risk analysis will be discussed. Kuwait has undergone significant reconstruction since the liberation from Iraqi invasion in 1991 and with mandates to increase production and throughput, system reliability and up-time is essential. KOC is well advanced in the implementation of a TPIMS, a model for the region and worldwide.

scholarly journals Environmental safety in case of accidents on the marine component of a multimodal pipeline system

2020 ◽  
Author(s):  
Д.Ф. Кожевин ◽  
А.С. Поляков ◽  
Д.А. Скороходов ◽  
В.Ю. Каминский ◽  
А.Л. Стариченков
Keyword(s):  
Natural Gas ◽  
Initial Period ◽  
Fire Risk ◽  
Combustion Products ◽  
Environmental Safety ◽  
Sea Surface ◽  
Pipeline System ◽  
Event Tree ◽  
Excessive Pressure ◽  
The Impact

Для трубопроводов, проложенных под водой, опасными являются следующие факторы пожара: тепловое излучение при факельном горении природного газа над поверхностью моря, избыточное давление и импульс волны давления при сгорании газопаровоздушной смеси, а также расширяющиеся продукты сгорания при реализации пожара-вспышки газопаровоздушной смеси. При этом рассмотрены особенности газового конденсата и моноэтиленгликоля. Выполнена оценка пожарных рисков и составлен перечень исходных данных для их расчётов. Описана последовательность развития аварии. При построении дерева событий учтена глубина подводного размещения трубопровода. При проведении анализа риска использованы четыре сценария выхода природного газа на поверхность. Определена величина потенциального пожарного риска в определенной точке трассы трубопровода. Выполнена оценка воздействия поражающих факторов при авариях на шлангокабеле и на трубопроводе. Рассмотрены нестабильные динамические явления, сопровождающие аварию на морском трубопроводе: в начальный период воздействия ударной волны, выбросе воды на палубу судна и пожароопасного воздушного шлейфа над поверхностью моря. For pipelines laid under water, the following fire factors are dangerous: thermal radiation when natural gas flares above the sea surface, excessive pressure and pressure wave momentum when a gas-air mixture is burned, as well as expanding combustion products when a gas-air mixture is flashed. Gorenje The features of gas condensate and monoethylene glycol are considered. Fire risks were assessed and a list of initial data for their calculations was compiled. The sequence of accident development is described. When building the event tree, the depth of the underwater pipeline placement is taken into account. During the risk analysis, four scenarios of natural gas coming to the surface were used. The value of the potential fire risk at a certain point of the pipeline route is determined. An assessment of the impact of damaging factors in accidents on the hose cable and on the pipeline was performed. Unstable dynamic phenomena accompanying an accident on an offshore pipeline are considered: during the initial period of impact of a shock wave, the release of water on the ships deck and a fire-dangerous air plume above the sea surface.

An Integration Method for Assessing the Operational Reliability of Underground Gas Storage in a Depleted Reservoir

2018 ◽  
Vol 140 (3) ◽  
Author(s):  
Weichao Yu ◽  
Yuan Min ◽  
Weihe Huang ◽  
Kai Wen ◽  
Ye Zhang ◽  
...  
Keyword(s):  
Natural Gas ◽  
Integration Method ◽  
Gas Injection ◽  
Gas Storage ◽  
Operational Reliability ◽  
Pipeline System ◽  
Operational Parameters ◽  
Underground Gas Storage ◽  
Surface System ◽  
Process Calculation

Underground gas storage (UGS), a key component of a natural gas pipeline network, can not only be used as an emergency gas source under a pipeline system failure situation but it is also available for seasonal peak shaving under pipeline system normal operation. Therefore, in order to meet the natural gas needs, it is of vital importance to safeguard the security of UGS operation and assess the reliability of UGS. The aim of the overall study is to develop an integration method for assessing operational reliability of UGS in a depleted reservoir under different injection-production scenarios, whereas existing studies only assess a single component or subsystem reliability. According to function zoning, UGS is separated into reservoir, well system, and surface system, and reservoir and surface system are connected through well system. The well system contains multiple injection/production wells. For the first step of the reliability assessment, the hydraulic calculation, including the gas injection process calculation and the gas production process calculation, is adopted to obtain the operational parameters of each component in UGS. Next, the reliability of the reservoir, injection/production well, and equipment in surface system is evaluated using operational parameters and a Monte Carlo approach. The reliability of the subsystem, such as the well system and surface system, is then calculated according to system reliability theory. Finally, operational reliability of UGS is obtained, which reflects the capacity of performing gas injection-production function. Two test cases are given to illustrate the integration method.

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