Extending the In-Line Inspection Interval for a Gas Pipeline Using Direct Assessment

2008 ◽  
Author(s):  
Marcus McCallum ◽  
Graham Ford ◽  
Andrew Francis
Keyword(s):  
Natural Gas ◽  
Structural Reliability ◽  
Probabilistic Approach ◽  
Gas Pipeline ◽  
Time Dependent ◽  
Time Interval ◽  
Operating Pressure ◽  
Direct Assessment ◽  
Ground Survey ◽  
External Corrosion

RWE npower own and operate a 12km long 8″ diameter natural gas pipeline that supplies natural gas from the National Transmission System (NTS) to a CHP unit. The pipeline has a nominal wall thickness of 6.35mm, is constructed from API 51 X42 grade steel and has a maximum operating pressure of 75barg. The pipeline was commissioned about 8 years ago and has been operating safely since that time. The pipeline was designed in accordance with BS 8010 Parts 1 and 2, with consideration given to the Institute of Gas Engineers Recommendations, IGE/TD/1, IGE/TD/9 and IGE/TD/12. One of the requirements of IGE/TD/1 is that the time interval between in-line inspections should not normally exceed 10 years. However, IGE/TD/1 Edition 4 allows the time interval to be exceeded if justification can be demonstrated using risk based techniques. For older pipelines it is often possible to determine the required time dependent failure probability based on the results of previous ILIs. This allows the time to next ILI to be determined. This time will depend on what has been found previously and values of other pipeline parameters. However, in the case of this pipeline there are no previous ILI data. In view of the above a probabilistic approach to External Corrosion Direct Assessment (ECDA) was adopted. The method makes use of the results from the above ground surveys rather than ILI data. However, in this instance, rather than being used to determine the time interval to the next above ground survey the method was used to determine the time interval to the next (first) ILI. The method is based on structural reliability analysis (SRA) which is used to determine the time dependent probability of failure based on available data. In view of the quantity and quality of the available above ground survey data it was possible to use the method to extend the time to the next ILL by several years.

Performance Evaluation of Above Ground Surveys for Locating External Corrosion in Pipelines

2002 ◽  
Author(s):  
Clive R. Ward ◽  
Marcus McCallum ◽  
Gary L. Masters ◽  
Andrew Francis
Keyword(s):  
Structural Reliability ◽  
Large Diameter ◽  
Operating Pressure ◽  
Integrity Assessment ◽  
Direct Assessment ◽  
Site Investigations ◽  
Transmission Pipeline ◽  
True Condition ◽  
Using Data ◽  
External Corrosion

Integrity management regulations require operators of high-pressure gas pipelines to consider various threats to pipeline integrity including time-dependent degradation due to corrosion. Depending on factors including age and operating pressure, a pipeline will require periodic integrity assessment. Methods available for assessing external corrosion are in-line inspection, pressure testing, or Direct Assessment, which is the subject of this paper. An analysis was conducted on data from a large diameter gas transmission pipeline built in the 1960’s. A 30Km section was investigated, using data spanning an 18-year period. The records analyzed included above ground surveys, high-resolution in-line inspection surveys, and site investigations. Assuming the in-line inspection represents true condition, it was found that the above ground surveys produced indications at between 80% and 90% of the in-line inspection features. Approximately 35% of the survey indications did not correspond to in-line inspection features. This information should benefit those wishing to implement Direct Assessment programs using Structural Reliability Analysis techniques.

Integrity Assessment of Non-Piggable Pipeline Through Direct Assessment

2013 ◽  
Author(s):  
Jai Prakash Sah ◽  
Mohammad Tanweer Akhter
Keyword(s):  
Hydrostatic Pressure ◽  
Natural Gas ◽  
Stress Corrosion ◽  
Health Assessment ◽  
Assessment Method ◽  
Pipeline System ◽  
Internal Corrosion ◽  
Integrity Assessment ◽  
Direct Assessment ◽  
External Corrosion

Managing the integrity of pipeline system is the primary goal of every pipeline operator. To ensure the integrity of pipeline system, its health assessment is very important and critical for ensuring safety of environment, human resources and its assets. In long term, managing pipeline integrity is an investment to asset protection which ultimately results in cost saving. Typically, the health assessment to managing the integrity of pipeline system is a function of operational experience and corporate philosophy. There is no single approach that can provide the best solution for all pipeline system. Only a comprehensive, systematic and integrated integrity management program provides the means to improve the safety of pipeline systems. Such programme provides the information for an operator to effectively allocate resources for appropriate prevention, detection and mitigation activities that will result in improved safety and a reduction in the number of incidents. Presently GAIL (INDIA) LTD. is operating & maintaining approximately 10,000Kms of natural gas/RLNG/LPG pipeline and HVJ Pipeline is the largest pipeline network of India which transports more than 50% of total gas being consumed in this country. HVJ pipeline system consists of more than 4500 Kms of pipeline having diameter range from 04” to 48”, which consist of piggable as well as non-piggable pipeline. Though, lengthwise non-piggable pipeline is very less but their importance cannot be ignored in to the totality because of their critical nature. Typically, pipeline with small length & connected to dispatch terminal are non-piggable and these pipelines are used to feed the gas to the consumer. Today pipeline industries are having three different types of inspection techniques available for inspection of the pipeline. 1. Inline inspection 2. Hydrostatic pressure testing 3. Direct assessment (DA) Inline inspection is possible only for piggable pipeline i.e. pipeline with facilities of pig launching & receiving and hydrostatic pressure testing is not possible for the pipeline under continuous operation. Thus we are left with direct assessment method to assess health of the non-piggable pipelines. Basically, direct assessment is a structured multi-step evaluation method to examine and identify the potential problem areas relating to internal corrosion, external corrosion, and stress corrosion cracking using ICDA (Internal Corrosion Direct Assessment), ECDA (External Corrosion Direct Assessment) and SCCDA (Stress Corrosion Direct Assessment). All the above DA is four steps iterative method & consist of following steps; a. Pre assessment b. Indirect assessment c. Direct assessment d. Post assessment Considering the importance of non-piggable pipeline, integrity assessment of following non piggable pipeline has done through direct assessment method. 1. 30 inch dia pipeline of length 0.6 km and handling 18.4 MMSCMD of natural gas 2. 18 inch dia pipeline of length 3.65 km and handling 4.0 MMSCMD of natural gas 3. 12 inch dia pipeline of length 2.08 km and handling 3.4 MMSCMD of natural gas In addition to ICDA, ECDA & SCCDA, Long Range Ultrasonic Thickness (LRUT-a guided wave technology) has also been carried out to detect the metal loss at excavated locations observed by ICDA & ECDA. Direct assessment survey for above pipelines has been conducted and based on the survey; high consequence areas have been identified. All the high consequence area has been excavated and inspected. No appreciable corrosion and thickness loss have observed at any area. However, pipeline segments have been identified which are most vulnerable and may have corrosion in future.

An External Corrosion Direct Assessment Module for a Pipeline Integrity Management System

2006 ◽  
Author(s):  
Menno T. van Os ◽  
Piet van Mastrigt ◽  
Andrew Francis
Keyword(s):  
Management System ◽  
Structural Reliability ◽  
Individual Performance ◽  
Corrosion Activity ◽  
Time Saving ◽  
Survey Techniques ◽  
Direct Assessment ◽  
Integrity Management ◽  
External Corrosion ◽  
The Individual

A significant part of the high pressure gas transport system of Gasunie cannot be examined by in-line inspection techniques. To ensure safe operation of these pipelines, an External Corrosion Direct Assessment (ECDA) module for PIMSLIDER (a pipeline integrity management system) is currently under development. The functional specifications of this module are based on NACE RP0502-2002, a recommended practice for ECDA. In addition to this, a new probabilistic methodology has been adopted, to take account for uncertainties associated with ECDA and to quantify the contributions from aboveground surveys and excavations to the integrity of a pipeline. This methodology, which is based on Structural Reliability Analysis (SRA) and Bayesian updating techniques, is presented in more detail in paper IPC2006-10092 of this conference. The DA module of PIMSLIDER enables computerized storage, retrieval and processing of all appropriate pipeline data and therefore guarantees highly accurate, reproducible and time saving integrity analyses of the Gasunie grid. Another important function of this system is the ability to use the complete database of all pipelines to pre-assess the integrity of a particular pipeline. This automated retrieval of data from pipelines with similar characteristics and/or environmental conditions results in a substantial increase of accessible data and enables Gasunie to improve the reliability of applied statistics throughout the process. As a consequence, the overall cost of inspections and excavations can be greatly reduced. In the Pre-Assessment phase, the DA module assists the integrity manager in gathering and analyzing data necessary to determine the current condition of a pipeline. After collection and visualization of the available data, the user can identify suitable ECDA regions. Furthermore, the gathered data are used to construct prior distributions of parameters relevant to the SRA model, such as the number and size of corrosion defects and pipeline-related parameters. In the Indirect Inspections step, the DA module allows the user to store and analyze the data from aboveground surveys, in order to identify and define the severity of coating faults and areas at which corrosion activity may occur. The probabilistic methodology accounts for the individual performance of each applied survey technique in terms of missed defects and false indications, in general a major source of uncertainty in ECDA. In the Direct Examinations phase, excavations are carried out to collect data to assess possible corrosion activity. Subsequently, the ECDA module uses this information to update, among other things, the parameters concerning the performance of survey techniques, the number of defects and the corrosion rate. As a result, updated failure frequencies are calculated for each ECDA-region (after each excavation if required), which are then used by the DA module to advise the integrity manager if additional mitigating activities are necessary, or by defining a reassessment interval.

External Corrosion and Internal Corrosion Direct Assessment Validation Project

2004 ◽  
Author(s):  
Carl A. Mikkola ◽  
Christina L. Case ◽  
Kevin C. Garrity
Keyword(s):  
Natural Gas ◽  
Final Report ◽  
Internal Corrosion ◽  
Assessment Development ◽  
Direct Assessment ◽  
Natural Gas Pipeline ◽  
Assessment Validation ◽  
External Corrosion ◽  
Development And Validation ◽  
To Receive

In January, 2003, Enbridge Midcoast Energy, L.P., a subsidiary of Enbridge Energy Partners, L.P., implemented a comprehensive direct assessment development and validation project for its Natural Gas Business segment; a project intended to demonstrate the validity of External Corrosion and Internal Corrosion Direct Assessment (ECDA and ICDA). The work began in January 2003 and was concluded in June 2003. The primary goal of the project was to demonstrate that External Corrosion Direct Assessment and Internal Corrosion Direct Assessment as performed in compliance with the NACE and INGAA methodologies could be used to effectively verify and manage the integrity of non-piggable and non-interruptible natural gas pipeline segments. The programs were validated by in-line inspection (ILI) using high-resolution magnetic flux leakage tools and field verification digs. The objective of the project was to receive approval from the Texas Railroad Commission to use direct assessment (“DA”), where demonstrated to be appropriate, for integrity verification and management of pipeline systems that are not verifiable through other approved means. The Enbridge DA Validation Project was successfully completed and is considered to be one of the leading DA validation projects undertaken to date in the U.S. A total of 12,000 manhours and over $1MM was expended in performing the pre-assessment to identify a candidate pipeline, develop detailed procedures for DA execution and implementation, perform indirect surveys, modify pipe and complete cleaning pig runs, gauge pig runs, dummy pig runs, intelligent pig runs, perform detailed direct examinations and perform detailed analysis of the results including the preparation of the final report. This paper is intended to describe the steps that Enbridge took in validating DA.

A New Probabilistic Methodology for Undertaking External Corrosion Direct Assessment

2006 ◽  
Author(s):  
Andrew Francis ◽  
Marcus McCallum ◽  
Menno T. Van Os ◽  
Piet van Mastrigt
Keyword(s):  
Surface Characteristics ◽  
Survey Techniques ◽  
Direct Assessment ◽  
Ground Survey ◽  
Pressure Test ◽  
Integrity Management ◽  
Corrosion Defects ◽  
Low Probability ◽  
External Corrosion ◽  
Pipeline Safety

External Corrosion Direct Assessment (ECDA) has now become acknowledged, by the Office of Pipeline Safety (OPS) in North America, as a viable alternative to both in-line inspection (ILI) and the hydrostatic pressure test for the purpose of managing the integrity of high pressure pipelines. Accordingly an ECDA standard is now in existence. The essence of ECDA is to use indirect above ground survey techniques to locate the presence of coating and corrosion defects and then to investigate some of the indications directly by making excavations. However, one of the problems of above ground survey techniques is that they do not locate all defects and are susceptible to false indication. This means that the defects will not be present at all indications and that some defects will be missed. In view of the limitations of above ground survey techniques the ECDA standard requires that at least two complimentary survey techniques should be used. The selected survey techniques will depend on the nature of a particular ‘ECDA segment’, taking account of the surface characteristics. However, in many situations the surveys will include a coating survey and a corrosion survey. In general the outcome from these two surveys will be NH locations at which just the coating survey gives an indication, NC locations at which just the corrosion survey gives an indication and NHC locations at which both surveys give an indication. This paper presents a new probabilistic methodology for estimating the distributions of the actual numbers of coating and corrosion defects, taking account of the outcomes of the surveys and the probabilities of detection and false indication of both techniques. The method also shows how the probabilities of detection and false indication are updated depending on what is found during the excavations and the distributions of the numbers of remaining corrosion and coating defects are subsequently modified. Based on a prescribed repair criterion the analysis is used to determine the probability that at least one remaining corrosion defect will exceed the repair criteria. As excavations are sequentially performed the probability naturally reduces. The attainment of an acceptably low probability is used as a trigger to terminate the excavation programme. A detailed description of the development of the method is given in this paper and the application is illustrated through a simple numerical example. A description of how the method is used to build a Direct Assessment module for a pipeline integrity management system is described in an accompanying paper.

Use of Structural Reliability Analysis for Uprating Above Ground Installations

2002 ◽  
Author(s):  
A. Francis ◽  
C. S. Jandu ◽  
M. A. McCallum
Keyword(s):  
Reliability Analysis ◽  
Structural Reliability ◽  
Failure Modes ◽  
Time Dependent ◽  
Operating Pressure ◽  
Stress Concentrations ◽  
Safe Operation ◽  
The Uk ◽  
Design Factors ◽  
Increased Pressure

In support of an extensive programme to increase the operating pressure of the UK National Transmission System (NTS) Advantica Technologies Limited have developed a structural reliability based methodology which is used to demonstrate the safe operation of Above Ground Installations (AGIs) at increased pressure levels. The approach is based on Advantica’s methodology for demonstrating the safe operation of pipeline sections at high design factors. It incorporates the effects of stress concentrations occurring at Tees and bends within complex pipework systems, and addresses the credible failure modes, including shakedown, corrosion and fatigue, taking account of pressure and thermal loadings. Particular attention is given to the time-dependent nature of the failure modes and the mitigating effect of the pre-service hydrostatic test and weld inspections is included.

A Model for Sizing High Consequence Areas Associated With Natural Gas Pipelines

2002 ◽  
Author(s):  
Mark J. Stephens ◽  
Keith Leewis ◽  
Daron K. Moore
Keyword(s):  
Natural Gas ◽  
Release Rate ◽  
Gas Pipeline ◽  
Intensity Level ◽  
Operating Pressure ◽  
Worst Case ◽  
Damage Area ◽  
Natural Gas Pipelines ◽  
Failure Event ◽  
Extent Of Damage

The failure of a high-pressure natural gas pipeline can lead to various outcomes, some of which can pose a significant threat to people and property in the immediate vicinity of the failure location. The dominant hazard is thermal radiation from a sustained jet or trench fire. An estimate of the ground area affected by a credible worst-case failure event can be obtained from a model that characterizes the heat intensity associated with rupture failure of the pipe where the escaping gas is assumed to feed a sustained trench fire that ignites very soon after line failure. An equation has been developed that relates the diameter and operating pressure of a pipeline to the size of the area likely to experience high consequences in the event of an ignited rupture failure. The model upon which the hazard area equation is based consists of three parts: 1) a fire model that relates the rate of gas release to the heat intensity of the fire as a function of distance from the fire source; 2) an effective release rate model that provides a representative steady-state approximation to the actual transient release rate; and 3) a heat intensity threshold that establishes the sustained heat intensity level above which the effects on people and property are consistent with the adopted definition of a so-called High Consequence Area. The validity of the proposed model is established by a comparison between the predicted extent of the damage area and the actual extent of damage for significant gas pipeline failure incidents reported in the public domain.

A Robust Approach to Pipeline Integrity Management Using Direct Assessment Based on Structural Reliability Analysis

2004 ◽  
Author(s):  
Marcus McCallum ◽  
Andrew Francis ◽  
Tim Illson ◽  
Mark McQueen ◽  
Mike Scott ◽  
...  
Keyword(s):  
Reliability Analysis ◽  
Structural Reliability ◽  
Voltage Gradient ◽  
Pipeline System ◽  
Pipe Failure ◽  
Internal Corrosion ◽  
Direct Assessment ◽  
Structural Reliability Analysis ◽  
Integrity Management ◽  
External Corrosion

Approximately 1450 km (900 miles) of a 4020-km (2500 mile) natural gas pipeline system operated by Crosstex Energy Service L.P in Texas are subject to the Texas Railroad Commission’s (TRRC) integrity management rules. Consequently, in preparation for the construction of an extensive and robust integrity management program, Crosstex commissioned Advantica to assist in the development and application of a pilot study on a 13.4 km (8.3 mile) section of a 14” pipeline. The purpose of the study, which is based on Structural Reliability Analysis (SRA), was to compare the level of integrity that could be inferred from the use of Direct Assessment (DA) techniques with the level that could be inferred from ILI results. Based on a preliminary assessment of available data, the study identified both external and internal corrosion as potential threats to integrity. SRA was used in conjunction with ‘Bayesian Updating’ to determine the probability of pipe failure due to external corrosion, taking account of results from above-ground measurements and a number of bell-hole excavations. The above-ground survey techniques utilized included Close Interval Survey (CIS) and Direct Current Voltage Gradient (DCVG). A similar approach was adopted to address the threat due to internal corrosion, but hydraulic modelling was substituted for the above-ground measurements. A third study based on SRA was used to determine the combined probability of failure due to both internal and external corrosion taking account of ILI results. The outcome of the analyses demonstrated that the level of integrity that could be inferred from the use of Crosstex’ DA methodology was similar to that which could be inferred from the use of ILI. The results were presented to the TRRC for review and approval. This paper gives a detailed description of the SRA based methodology that was employed by Crosstex and presents the results that clearly demonstrate the comparability of ILI and DA for the purpose of integrity management.

scholarly journals Responding to a Northern Pipeline Challenge

2000 ◽  
Author(s):  
Terry J. Klatt
Keyword(s):  
Natural Gas ◽  
Liquefied Natural Gas ◽  
Gas Pipeline ◽  
Operating Pressure ◽  
Pipe Steels ◽  
Line Pipe ◽  
Natural Gas Pipeline ◽  
Construction Methods ◽  
Discontinuous Permafrost ◽  
Future Work

An 800-mile natural gas pipeline is being considered as part of an Alaskan liquefied natural gas (LNG) project. Concepts to maximize the pipeline’s value and minimize its cost are considered. The pipeline’s operating pressure has been synchronized with the LNG plant’s inlet pressure to achieve system efficiencies. Line pipe steels are optimized to address pressure, fracture and geotechnical issues. An advanced approach to designing and operating a gas pipeline in discontinuous permafrost is evaluated. Construction methods and strategies have been developed in areas such as trenching and winter construction. Finally, future work to further develop these concepts is identified.

scholarly journals Regularities of safe control of piston compressor units of mobile compressor stations

2021 ◽  
pp. 76-81
Author(s):  
Z.N Matsuk ◽  
T.V Bunko ◽  
A.S Belikov ◽  
V.A Shalomov
Keyword(s):  
Natural Gas ◽  
Gas Pressure ◽  
Gas Pipeline ◽  
Relative Mass ◽  
Time Interval ◽  
Relative Pressure ◽  
Gas Pipelines ◽  
Mobile Compressor ◽  
Gas Pumping ◽  
Main Gas Pipeline

Purpose. Ensuring the optimal mode of gas transportation from local sections of the main gas trunkline (GT), subject to repair (maintenance) and/or shutdown, to existing main gas trunkline based on the calculation, determination, and establishment of rational values of the operating modes of mobile compressor stations during the entire time of gas pumping. Methodology. The studies are based on existing physical principles and laws that describe the effect of the properties of natural gas and the geometric parameters of pipelines through which gas is pumped on the dynamics of changes in the mass and pressure of the transported gas. The calculation of the change in the mass and pressure of the gas in the gas pipeline from which the gas is pumped is based on a number of existing theoretical and empirical dependencies included in the generally accepted methods for their calculation. Known physical relationships and mathematical models are used to carry out the calculations. Findings. The mass approach to the issue of calculating the gas transportation time is more mathematically accurate than the volumetric one. The ratio of the relative mass to the relative gas pressure in a localized section of the main gas pipeline, during the entire pumping time, is a constant value. The use of the values of the quantities obtained at the point of intersection of the graphs of changes in the relative mass and relative pressure of the gas, in the preliminary calculation of the time for pumping gas, or pressure, or mass, or the volume of gas in each time interval, makes it possible to select the optimal rate of building up/reducing gas pressure by compressor units and optimal modes of gas transportation by operating gas pipelines during the operation of mobile compressor stations. Originality. The proposed approach to calculating and determining the time of gas pumping by mobile compressor stations from local sections of the main gas pipelines subject to repair (maintenance) and/or shutdown to sections of existing main gas pipelines proves that it is advisable to establish stable patterns in the transportation of natural gas using reciprocating compressor units only after modeling in time the change in the mass and pressure of gas in the local section of the main gas pipeline from which the gas is pumped. Practical value. The proposed approach to optimizing the time of gas pumping by mobile compressor stations makes it possible to increase the level of energy and resource efficiency of gas transmission enterprises, as well as to improve the technical and economic indicators of technologies for repairing the main gas pipelines, compressor stations of main gas pipelines associated with the need to bleed gas from sections of the main (technological) pipelines subject to repair (maintenance) and/or shutdown. Optimization of gas pumping time significantly reduces the time spent by employees of gas transmission enterprises under the influence of hazardous and harmful production factors, thereby reducing the level of relevant risks. Gas emissions and associated risks are reduced by 90%.

Sign in / Sign up

Export Citation Format

Share Document