Enbridge Comparison of Crack Detection In-Line Inspection Tools

2002 ◽  
Author(s):  
Garrett H. Wilkie ◽  
Tanis J. Elm ◽  
Don L. Engen
Keyword(s):  
Power Systems ◽  
Elastic Wave ◽  
Crack Detection ◽  
Management Program ◽  
Metal Loss ◽  
Integrity Management ◽  
Magnetic Inspection ◽  
Extensive Program ◽  
Inspection Data ◽  
Geometry Inspection

Enbridge Pipelines Inc. operates the world’s longest and most complex liquids pipeline network. As part of Enbridge’s Integrity Management Program In-Line Inspections have been and will continue to be conducted on more than 15,000 km of pipeline. This extensive program is comprised of a mature metal loss and geometry inspection component as well as a crack inspection program utilizing the most sophisticated In-Line Inspection (ILI) tools available. Enbridge conducted its first ultrasonic crack inspection with the British Gas Elastic Wave Vehicle (Now GE Power Systems – Oil & Gas – PII Pipeline Solutions) in September 1993 on a Canadian portion of it’s 864–mm (34”) diameter line. The Elastic Wave Vehicle was also used for crack detection on additional segments of this same 864–mm (34”) diameter line during the following years, 1994, 1995 and 1996. Enbridge then conducted its first crack inspection with the Pipetronix UltraScan CD tool (Now also GE Power Systems – Oil & Gas – PII Pipeline Solutions) in November 1997 on a segment of this 864–mm (34”) diameter line that was previously inspected with the Elastic Wave Vehicle. The UltraScan CD tool was then utilized again in 1999, 2000 and 2001 completing crack inspection of the Canadian portion of this 864–mm (34”) diameter line. Enbridge conducted its first magnetic crack inspection with the PII TranScan (TFI) Circumferential Magnetic inspection tool in December 1998 on a United States portion of another 864–mm (34”) diameter line. This same section of line was subsequently inspected with the PII UltraScan CD tool in July 2001. This paper discusses the comparison of results from overlapping crack inspection data analysis from these three PII crack detection tools. Specifically, the overlap of the UltraScan CD and Elastic Wave Vehicle along with the overlap of the UltraScan CD and TranScan (TFI) tool. The relative performance of each crack detection tool will be explored and conclusions drawn.

Post Assessment of Ultrasonic Crack Detection Inline Inspection Data

2008 ◽  
Author(s):  
Lisa Barkdull ◽  
Herbert Willems
Keyword(s):  
Data Analysis ◽  
Crack Detection ◽  
Expert Knowledge ◽  
Effective Area ◽  
Management Program ◽  
Metal Loss ◽  
Analysis Techniques ◽  
Advanced Analysis ◽  
Inspection Data ◽  
Post Assessment

The information supplied from inline inspection data is often used by pipeline operators to make mitigation and/or remediation decisions based on integrity management program requirements. It is common practice to apply industry accepted remaining strength pressure calculations (i.e. B31G, 0.85 dl, effective area) to the data analysis results from an inline inspection survey used for the detection and characterization of metal loss. Similar assessments of data analysis results from an ultrasonic crack detection survey require expert knowledge in the field of fracture mechanics and, just as importantly, require knowledge to understand the limitations of shear wave ultrasonic technology as applied to an inline inspection tool. Traditionally, crack-like and crack-field features have been classified with a maximum depth distributed over the entire length of the feature; crack-field features also have width reported. In an effort to provide further prioritization, techniques such as “longest length” or “interlinked length” [1] have been employed. More recently, an effort has been made to provide a depth profile of the crack-like or crack-field feature using the ultrasonic crack detection data analysis results. This presentation will discuss the advantages of post assessment of ultrasonic crack detection data analysis results to aid in the evaluation of pipeline integrity and discuss the limitations of advanced analysis techniques. Additionally, the potential for new inline inspection ultrasonic technologies which lend themselves to more accurate data analysis techniques will be reviewed.

A Hybrid Topside Structural Approach to the Management of Aging Fleet

2021 ◽  
Author(s):  
Biramarta Isnadi ◽  
Luong Ann Lee ◽  
Sok Mooi Ng ◽  
Ave Suhendra Suhaili ◽  
Quailid Rezza M Nasir ◽  
...  
Keyword(s):  
Structural Integrity ◽  
Metal Loss ◽  
Web Based ◽  
Strong Basis ◽  
Asset Risk ◽  
Risk Ranking ◽  
Design Life ◽  
Industry Standards ◽  
Integrity Management ◽  
Inspection Data

Abstract The objective of this paper is to demonstrate the best practices of Topside Structural Integrity Management for an aging fleet of more than 200 platforms with about 60% of which has exceeded the design life. PETRONAS as the operator, has established a Topside Structural Integrity Management (SIM) strategy to demonstrate fitness of the offshore topside structures through a hybrid philosophy of time-based inspection with risk-based maintenance, which is in compliance to API RP2SIM (2014) inspection requirements. This paper shares the data management, methodology, challenges and value creation of this strategy. The SIM process adopted in this work is in compliance with industry standards API RP2SIM, focusing on Data-Evaluation-Strategy-Program processes. The operator HSE Risk Matrix is adopted in risk ranking of the topside structures. The main elements considered in developing the risk ranking of the topside structures are the design and assessment compliance, inspection compliance and maintenance compliance. Effective methodology to register asset and inspection data capture was developed to expedite the readiness of Topside SIM for a large aging fleet. The Topside SIM is being codified in the operator web-based tool, Structural Integrity Compliance System (SICS). Identifying major hazards for topside structures were primarily achieved via data trending post implementation of Topside SIM. It was then concluded that metal loss as the major threat. Further study on effect of metal loss provides a strong basis to move from time-based maintenance towards risk-based maintenance. Risk ranking of the assets allow the operator to prioritize resources while managing the risk within ALARP level. Current technologies such as drone and mobile inspection tools are deployed to expedite inspection findings and reporting processes. The data from the mobile inspection tool is directly fed into the web based SICS to allow reclassification of asset risk and anomalies management.

Probability of Exceedance (POE) Methodology for Developing Integrity Programs Based on Pipeline Operator-Specific Technical and Economic Factors

2002 ◽  
Author(s):  
Rafael G. Mora ◽  
Curtis Parker ◽  
Patrick H. Vieth ◽  
Burke Delanty
Keyword(s):  
Decision Making ◽  
Probabilistic Models ◽  
Cost Benefit Analysis ◽  
Management Program ◽  
Metal Loss ◽  
Decision Making Process ◽  
Pipeline System ◽  
Probability Of Exceedance ◽  
Integrity Verification ◽  
Inspection Data

With the availability of in-line inspection data, pipeline operators have additional information to develop the technical and economic justification for integrity verification programs (i.e. Fitness-for-Purpose) across an entire pipeline system. The Probability of Exceedance (POE) methodology described herein provides a defensible decision making process for addressing immediate corrosion threats identified through metal loss in-line inspection (ILI) and the use of sub-critical in-line inspection data to develop a long term integrity management program. In addition, this paper describes the process used to develop a Corrosion In-line Inspection POE-based Assessment for one of the systems operated by TransGas Limited (Saskatchewan, Canada). In 2001, TransGas Limited and CC Technologies undertook an integrity verification program of the Loomis to Herbert gas pipeline system to develop an appropriate scope and schedule maintenance activities along this pipeline system. This methodology customizes Probability of Exceedance (POE) results with a deterministic corrosion growth model to determine pipeline specific excavation/repair and re-inspection interval alternatives. Consequently, feature repairs can be scheduled based on severity, operational and financial conditions while maintaining safety as first priority. The merging of deterministic and probabilistic models identified the Loomis to Herbert pipeline system’s worst predicted metal loss depth and the lowest safety factor per each repair/reinspection interval alternative, which when combined with the cost/benefit analysis provided a simplified and safe decision-making process.

Hierarchical Bayesian Corrosion Growth Model Based on In-Line Inspection Data

2012 ◽  
Author(s):  
M. Al-Amin ◽  
W. Zhou ◽  
S. Zhang ◽  
S. Kariyawasam ◽  
H. Wang
Keyword(s):  
Growth Model ◽  
Power Law ◽  
Management Program ◽  
Metal Loss ◽  
Hierarchical Bayesian ◽  
Natural Gas Pipelines ◽  
Mcmc Simulation ◽  
Corrosion Defects ◽  
External Corrosion ◽  
Inspection Data

A hierarchical Bayesian growth model is presented in this paper to characterize and predict the growth of individual metal-loss corrosion defects on pipelines. The depth of the corrosion defects is assumed to be a power-law function of time characterized by two power-law coefficients and the corrosion initiation time, and the probabilistic characteristics of the parameters involved in the growth model are evaluated using Markov Chain Monte Carlo (MCMC) simulation technique based on ILI data collected at different times for a given pipeline. The model accounts for the constant and non-constant biases and random scattering errors of the ILI data, as well as the potential correlation between the random scattering errors associated with different ILI tools. The model is validated by comparing the predicted depths with the field-measured depths of two sets of external corrosion defects identified on two real natural gas pipelines. The results suggest that the growth model is able to predict the growth of active corrosion defects with a reasonable degree of accuracy. The developed model can facilitate the pipeline corrosion management program.

scholarly journals Comparison Between In-Line Crack Detection and Hydrostatic Testing in IPL’s Line 3

1998 ◽  
Author(s):  
Michael A. Gardiner ◽  
Clive R. Ward ◽  
Susan E. Miller
Keyword(s):  
Elastic Wave ◽  
Crack Detection ◽  
Rigorous Analysis ◽  
Shrinkage Crack ◽  
Seam Weld ◽  
Pipe Line ◽  
Remedial Work ◽  
Inspection Data ◽  
Line Crack

The BG Elastic Wave in-line crack detection vehicle was used to inspect 213.5 km (133 miles) of Interprovincial Pipe Line Inc’s (IPL’s) Line 3. Rigorous analysis of the inspection data, concentrated on the seam weld and surrounding region, identified 73 sites for excavation. Pressure retaining sleeves were fitted at 17 locations. Of these, the most severe defect noted was a 25 mm (1 inch), 40% through wall long seam shrinkage crack. This was the only feature exceeding a size predicted to possibly fail under hydrotest to 100% SMYS. Twelve other cracks were sleeved, all of which were measured to be between 20% and 35% through wall. Minor imperfections were found at the majority of those reported locations which were not sleeved. Following completion of remedial work, 198 km (124 miles) of Line 3 was hydrostatically tested at pressures up to 100% SMYS, including 156 km (98 miles) that had been inspected by the Elastic Wave vehicle. There were no leaks or ruptures under hydrotest, demonstrating the ability of the tool to reliably detect cracks in the seam weld and surrounding region that were smaller than would have been found by hydrostatic testing alone.

SCC Detection and Mitigation Based on In-Line Inspection Tools

2004 ◽  
Author(s):  
Walter Kresic ◽  
Scott Ironside
Keyword(s):  
High Resolution ◽  
Management System ◽  
Crack Detection ◽  
Fitness For Purpose ◽  
Preventative Maintenance ◽  
Precise Method ◽  
Field Inspection ◽  
Integrity Management ◽  
Inspection Data ◽  
Ongoing Monitoring

The focus of the Enbridge Integrity Management System is to prevent leaks or ruptures caused by all duty-related pipe deterioration including SCC. As with all pipe defect types, ongoing monitoring programs are employed to determine whether SCC has occurred. Where it has, preventative maintenance programs are employed to mitigate the SCC. Where required, Enbridge employs high-resolution crack in-line inspection (ILI) as the most precise method for managing SCC. As a member of the Canadian Energy Pipeline Association (CEPA), Enbridge participated in the development of a basic framework for SCC management programs and has adopted this framework as the basis for the Enbridge program. Ultrasonic crack detection ILI, capable of detecting SCC, has been employed on over 3000 km of Enbridge pipe and several hundred investigative excavations have been conducted in relation to the ILI data. The results gathered from these investigations have been trended to define the effectiveness of crack detection ILI to detect, size, and discriminate SCC defects. This paper and presentation describes Enbridge’s experience utilizing ultrasonic crack detection ILI for SCC management. The Enbridge trends have shown that ILI can be reliably utilized to detect SCC but, additional innovation is required for defect sizing. While ILI sizing is limited, trends developed from field inspection data have provided the ability to categorize ILI signals into general classifications that ensure all relevant SCC features are highlighted. The categorization is accurate but added precision would reduce the number of investigative excavations, which currently, are also conducted on many sub-relevant features. Coincident with SCC activities driven by ILI data, trends were also developed for peripheral aspects such as field NDT technology, fitness-for-purpose equations, and SCC initiation and growth causes. Observations and trends related to these activities are also described herein.

Development and Experiences of a Circumferential Stress Corrosion Crack Management Program

2018 ◽  
Author(s):  
Neil Bates ◽  
Mark Brimacombe ◽  
Steven Polasik
Keyword(s):  
Stress Corrosion ◽  
Stress Corrosion Cracking ◽  
Crack Detection ◽  
Circumferential Stress ◽  
Management Program ◽  
Corrosion Cracking ◽  
Pipeline System ◽  
Average Growth ◽  
Proactive Management ◽  
Inspection Data

A pipeline operator set out to assess the risk of circumferential stress corrosion cracking and to develop a proactive management program, which included an in-line inspection and repair program. The first step was to screen the total pipeline inventory based on pipe properties and environmental factors to develop a susceptibility assessment. When a pipeline was found to be susceptible, an inspection plan was developed which often included ultrasonic circumferential crack detection in-line inspection and geotechnical analysis of slopes. Next, a methodology was developed to prioritize the anomalies for investigation based on the likelihood of failure using the provided in-line inspection sizing data, crack severity analysis, and correlation to potential causes of axial or bending stress, combined with a consequence assessment. Excavation programs were then developed to target the anomalies that posed the greatest threat to the pipeline system or environment. This paper summarizes the experiences to date from the operator’s circumferential stress corrosion cracking program and describes how the pipeline properties, geotechnical program, and/or in-line inspection programs were combined to determine the susceptibility of each pipeline and develop excavation programs. In-line inspection reported crack types and sizes compared to field inspection data will be summarized, as well as how the population and severity of circumferential stress corrosion cracking found compares to the susceptible slopes found in the geotechnical program completed. Finally, how the circumferential SCC time-average growth rate distributions were calculated and were used to set future geohazard inspections, in-line inspections, or repair dates will be discussed.

Optimizing the Management of Excavation and Repair Data From Inline Inspection Programs

2020 ◽  
Author(s):  
Miaad Safari ◽  
David Shaw
Keyword(s):  
Condition Monitoring ◽  
Data Gathering ◽  
Management Program ◽  
Data Uncertainty ◽  
Pipeline System ◽  
System Integrity ◽  
Integrity Management ◽  
External Corrosion ◽  
Inspection Data ◽  
Superior Approach

Abstract As integrity programs mature over the life of a pipeline, an increasing number of data points are collected from second, third, or further condition monitoring cycles. Types of data include Inline Inspection (ILI) or External Corrosion Direct Assessment (ECDA) inspection data, validation or remediation dig information, and records of various repairs that have been completed on the pipeline system. The diversity and massive quantity of this gathered data proposes a challenge to pipeline operators in managing and maintaining these data sets and records. The management of integrity data is a key element to a pipeline system Integrity Management Program (IMP) as per the CSA Z662[1]. One of the most critical integrity datasets is the repair information. Incorrect repair assignments on a pipeline can lead to duplicate unnecessary excavations in the best scenario and a pipeline failure in the worst scenario. Operators rely on various approaches to manage and assign repair data to ILIs such as historical records reviews, ILI-based repair assignments, or chainage-based repair assignments. However, these methods have significant gaps in efficiency and/or accuracy. Failure to adequately manage excavation and repair data can lead to increased costs due to repeated excavation of an anomaly, an increase in resources required to match historical information with new data, uncertainty in the effectiveness of previous repairs, and the possibility of incorrect assignment of repairs to unrepaired features. This paper describes the approach adopted by Enbridge Gas to track and maintain repairs, as a part of the Pipeline Risk and Integrity Management (PRIM) platform. This approach was designed to create a robust excavation and repair management framework, providing a robust system of data gathering and automation, while ensuring sufficient oversight by Integrity Engineers. Using this system, repairs are assigned to each feature in an excavation, not only to a certain chainage along the pipeline. Subsequently, when a new ILI results report is received, a process of “Repair Matching” is completed to assign preexisting repairs and assessments to the newly reported features at a feature level. This process is partially automated, whereby pre-determined box-to-box features matched between ILIs can auto-populate repairs for many of the repaired features. The proposed excavation management system would provide operators a superior approach to managing their repair history and projecting historical repairs and assessments onto new ILI reports, prior to assessing the ILI and issuing further digs on the pipeline. This optimized method has many advantages over the conventional repair management methods used in the industry. This method is best suited for operators that are embarking on their second or third condition monitoring cycle, with a moderate number of historical repairs.

Balancing Pipeline Safety and Cost Integrity Management Through Performance Validation of In-Line Inspection Data

2010 ◽  
Author(s):  
Rick McNealy ◽  
Sergio Limon-Tapia ◽  
Richard Kania ◽  
Martin Fingerhut ◽  
Harvey Haines
Keyword(s):  
Failure Criteria ◽  
Actual Condition ◽  
Metal Loss ◽  
Integrity Management ◽  
Multiple Case ◽  
Multiple Case Studies ◽  
Inspection Data ◽  
Performance Validation ◽  
The Cost ◽  
Pipeline Safety

In-Line Inspection (ILI) surveys are widely employed to identify potential threats by capturing changes in pipe condition such as metal loss, caused by corrosion. The better the performance and interpretation of these survey data, the higher the reliability of being able to predict the actual condition of the pipe and required remediation. Each ILI survey has a certain level of conservatism from the assessment equations such as B31G and sensitivity to ILI performance for measurement uncertainty. Multiple levels of conservatism intended to limit the possibility of a non-conservative assessment can result in a significant economic penalty and excessive digs without improving safety. A study was undertaken to evaluate the reliability of responses to ILI corrosion features through multiple case studies examining the effects of failure criteria and data analysis parameters. This paper discusses the effect of validated ILI performance on safety, and addresses the risk of false acceptance of corrosion indications at a prescribed safety factor. The cost of unnecessary excavations due to falsely rejecting ILI predictions is also discussed.

Assessment of In-Line Inspection Performance and Interpretation of Field Measurements for Characterization of Complex Dents

2016 ◽  
Author(s):  
Luis A. Torres ◽  
Matthew J. Fowler ◽  
Jordan G. Stenerson
Keyword(s):  
Management Strategies ◽  
Mechanical Damage ◽  
Field Measurements ◽  
Management Program ◽  
Metal Loss ◽  
Tool Performance ◽  
Integrity Management ◽  
Technical Specifications ◽  
Shape Complexity

Integrity management of dents on pipelines is currently performed through the interpretation of In-Line Inspection (ILI) data; this includes Caliper, Magnetic Flux Leakage (MFL), and Ultrasonic Testing (UT) tools. Based on the available ILI data, dent features that are recognized as threats from a mechanical damage perspective are excavated and remediated. Federal codes and regulations provide rules and allow inference on what types of dent features may be a result of mechanical damage; nonetheless, there are challenges associated with identifying dents resulting from mechanical damage. One of the difficulties when managing the mechanical damage threat is the lack of information on how MFL and UT ILI tool performance is affected by dented areas in the pipe. ILI vendors do not offer any technical specifications for characterizing and sizing metal loss features in dents. It is generally expected that metal loss tool performance will be affected in dented areas of the pipe, but it is not known to what degree. It is likely that degradation will vary based on feature shape, sensor design, and sensor placement. Because metal loss tool performance is unknown within the limits of the dented pipe, other methods for recognizing mechanical damage have been incorporated into the management strategies of mechanical damage. Some of these methods include strain based assessments and characterization of shape complexity. In order to build a more effective integrity management program for mechanical damage, it is of critical importance to understand how tool technology performance is affected by dented areas in the pipe and what steps can be taken to use ILI information more effectively. In this paper, the effectiveness of MFL and UT wall measurement tools in characterizing and sizing metal loss features within dents is studied by evaluating against field results from non-destructive examinations of mechanical damage indications. In addition, the effectiveness of using shape complexity indicators to identify mechanical damage is evaluated, introducing concepts such as dents in close proximity and multi-apex dents. Finally, the effectiveness of ILI tools in predicting dent association with girth welds is also explored by comparing ILI and field results.

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