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.

Geohazard Management Approach Within Safety Case

2018 ◽  
Author(s):  
Dario Zapata ◽  
Ingrid Pederson ◽  
Sean Keane
Keyword(s):  
Case Report ◽  
Performance Metrics ◽  
Maintenance Phase ◽  
Management Program ◽  
Management Approach ◽  
Pipeline System ◽  
Independent Evidence ◽  
System Integrity ◽  
Safety Case ◽  
Integrity Management

Safety case is utilized within the Enbridge Pipeline Integrity Management Program as a means to provide evidence that the risks affecting the system have been effectively mitigated (LeBlanc, et al. 2016). The safety case is an independent, evidence-based assessment based on system integrity management processes applied across all pipelines. This paper describes the process in which safety case methodology was implemented to manage geohazard threats. The benefits of assessing geohazard and other integrity threats will also be discussed. The safety case report documents the opportunities to address the identified problems in addition to the relationship between hazards, implemented controls, and associated susceptibility. To demonstrate that adequate safety controls for geohazard threats have been incorporated into the operational and maintenance phase of the pipeline system, the geohazard management component of the safety case was assessed using a bowtie diagram. The results gave visibility to the geohazard program and its effectiveness. Predefined safety performance metrics with probabilistic and deterministic criteria are evaluated to confirm the geohazard program’s continued effectiveness. Results from the safety case assessment identify opportunities for improvement and provide a basis for revision to maintenance, assurance and verification programs. Ultimately the assessment demonstrates that geohazard threats in the pipeline system are being recognized and assessed. The assessment provides evidence that adequate resources and efforts are allocated to mitigate the risk and identifies continuous improvement activities where needed. The safety case report generated as the final portion of an integrity management framework demonstrates risk is as low as reasonably practicable (ALARP).

A Practical Application to Calculating Corrosion Growth Rates by Comparing Successive ILI Runs From Different ILI Vendors

2010 ◽  
Author(s):  
Kevin Spencer ◽  
Shahani Kariyawasam ◽  
Cathy Tetreault ◽  
Jon Wharf
Keyword(s):  
Growth Rate ◽  
Growth Rates ◽  
Management Program ◽  
Management Decision ◽  
Pipeline System ◽  
Data Sets ◽  
Simple Method ◽  
Integrity Management ◽  
Inspection Data ◽  
Over Time

Corrosion growth rates are an essential input into an Integrity Management Program but they can often be the largest source of uncertainty and error. A relatively simple method to estimate a corrosion growth rate is to compare the size of a corrosion anomaly over time and the most practical way to do this for a whole pipeline system is via the use of In-Line Inspection (ILI). However, the reported depth of the anomaly following an ILI run contains measurement uncertainties, i.e., sizing tolerances that must be accounted for in defining the uncertainty, or error associated with the measured corrosion growth rate. When the same inspection vendor performs the inspections then proven methods exist that enable this growth error to be significantly reduced but these methods include the use of raw inspection data and, specialist software and analysis. Guidelines presently exist to estimate corrosion growth rates using inspection data from different ILI vendors. Although well documented, they are often only applicable to “simple” cases, pipelines containing isolated corrosion features with low feature density counts. As the feature density or the corrosion complexity increases then different reporting specifications, interaction rules, analysis procedures, sizing models, etc can become difficult to account for, ultimately leading to incorrect estimations or larger uncertainties regarding the growth error. This paper will address these issues through the experiences of a North American pipeline operator. Accurately quantifying the reliability of pipeline assets over time requires accurate corrosion growth rates and the case study will demonstrate how the growth error was significantly reduced over existing methodologies. Historical excavation and recoat information was utilized to identify static defects and quantify systemic bias between inspections. To reduce differences in reporting and the analyst interpretation of the recorded magnetic signals, novel analysis techniques were employed to normalize the data sets against each other. The resulting uncertainty of the corrosion growth rates was then further reduced by deriving, and applying a regression model to reduce the effect of the different sizing models and the identified systemic bias. The reduced uncertainty ultimately led to a better understanding of the corrosion activity on the pipeline and facilitated a better integrity management decision process.

Testing of Acoustic Emission Technology to Detect Cracks and Corrosion in the Marine Environment

2010 ◽  
Vol 26 (02) ◽  
pp. 106-110
Author(s):  
Ge Wang ◽  
Michael Lee ◽  
Chris Serratella ◽  
Stanley Botten ◽  
Sam Ternowchek ◽  
...  
Keyword(s):  
Acoustic Emission ◽  
Structural Integrity ◽  
Pilot Project ◽  
Development Project ◽  
Management Program ◽  
Pipeline System ◽  
Inspection Planning ◽  
Structural Degradation ◽  
Integrity Management ◽  
Acoustic Emission Technology

Real-time monitoring and detection of structural degradation helps in capturing the structural conditions of ships. The latest nondestructive testing (NDT) and sensor technologies will potentially be integrated into future generations of the structural integrity management program. This paper reports on a joint development project between Alaska Tanker Company, American Bureau of Shipping (ABS), and MISTRAS. The pilot project examined the viability of acoustic emission technology as a screening tool for surveys and inspection planning. Specifically, testing took place on a 32-year-old double-hull Trans Alaska Pipeline System (TAPS) trade tanker. The test demonstrated the possibility of adapting this technology in the identification of critical spots on a tanker in order to target inspections. This targeting will focus surveys and inspections on suspected areas, thus increasing efficiency of detecting structural degradation. The test has the potential to introduce new inspection procedures as the project undertakes the first commercial testing of the latest acoustic emission technology during a tanker's voyage.

Overcoming Technical Limitations in Identifying and Characterizing Critical Complex Corrosion

2012 ◽  
Author(s):  
Shahani Kariyawasam ◽  
Patrick Yeung ◽  
Stuart Clouston ◽  
Geoffrey Hurd
Keyword(s):  
Management Program ◽  
Pipeline System ◽  
Root Cause ◽  
Signal Characteristics ◽  
Key Characteristics ◽  
Critical Defect ◽  
External Corrosion ◽  
Failure Location ◽  
Microbiologically Induced Corrosion ◽  
Technology Processes

In 2009 a pipeline within the TransCanada pipeline system experienced a rupture. As this pipeline was already under a rigorous In Line Inspection (ILI) based corrosion management program this failure led to an extensive root cause analysis. Even though the hazard causing the failure was microbiologically induced corrosion (MIC) under tape coating, the more troubling question was “Why had the severity of this anomaly not been determined by the ILI based corrosion management program?” This led to an investigation of what key characteristics of the ILI signals resulting from areas of “complex corrosion” are more difficult to correctly interpret and size and furthermore where the line condition is such that manual verification is needed. By better understanding the limitations of the technology, processes used, and the critical defect signal characteristics, criteria were developed to ensure that “areas of concern” are consistently identified, manually verified and therefore the sizing is validated at these potentially higher risk locations. These new criteria were applied on ILI data and then validated against in-the-ditch measurements and a hydrotest. This process in conjunction with optimization of ILI sizing algorithms enabled the operator to overcome some of the known challenges in sizing areas of complex corrosion and update its corrosion management process to improve the detection and remediation of critical defects. This paper describes this investigation of the failure location, development of the complex corrosion criteria, and the validation of effectiveness of the criteria. The criteria are focused on external corrosion and have been currently validated on pipelines of concern. Application to other lines should be similarly validated.

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.

Learnings From Data Management and Integration Efforts on the Enbridge Pipeline System

2004 ◽  
Author(s):  
Garry L. Sommer ◽  
Brad S. Smith
Keyword(s):  
Data Management ◽  
Management Program ◽  
Pipeline System ◽  
Data Set ◽  
Data Alignment ◽  
Commercial Market ◽  
History Of ◽  
Integrity Management ◽  
Management Effort ◽  
Analysis System

Enbridge Pipelines Inc. operates one of the longest and most complex pipeline systems in the world. A key aspect of the Enbridge Integrity Management Program (IMP) is the trending, analysis, and management of data collected from over 50 years of pipeline operations. This paper/presentation describes Enbridge’s challenges, learnings, processes, and innovations for meeting today’s increased data management/integration demands. While much has been written around the premise of data management/integration, and many software solutions are available in the commercial market, the greatest data management challenge for mature pipeline operators arises from the variability of data (variety of technologies, data capture methods, and data accuracy levels) collected over the operating history of the system. Ability to bring this variable data set together is substantially the most difficult aspect of a coordinated data management effort and is critical to the success of any such project. Failure to do this will result in lack of user confidence and inability to gain “buy-in” to new data management processes. In 2001 Enbridge began a series of initiatives to enhance data management and analysis. Central to this was the commitment to accurate geospatial alignment of integrity data. This paper/presentation describes Enbridge’s experience with development of custom software (Integrated Spatial Analysis System – ISAS) including critical learnings around a.) Data alignment efforts and b.) Significant efforts involved in development of an accurate pipe centreline. The paper/presentation will also describe co-incident data management programs that link to ISAS. This includes enhanced database functionality for excavation data and development of software to enable electronic transfer of data to this database. These tools were built to enable rapid transfer of field data and “real time” tool validation through automated unity plots of tool defect data vs. that measured in the field.

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.

Identification of Repair Coatings on Pipelines Using In-Line Inspection Technologies

2016 ◽  
Author(s):  
Andrew Greig ◽  
Jörg Grillenberger
Keyword(s):  
Cathodic Protection ◽  
Low Cost ◽  
Pipeline System ◽  
Acoustic Transducer ◽  
Coating Type ◽  
History Of ◽  
Electro Magnetic ◽  
External Corrosion ◽  
Weld Area ◽  
Inspection Data

One of the major issues in the pipeline industry is coating disbondment. A very large percentage of external corrosion and SCC is observed under disbonded coatings that shield Cathodic Protection (CP). This has been an ongoing issue with coated and cathodic protected pipelines since the initial use of these two protection methods. The various coating types and their typical failure scenarios, under various harsh environmental conditions, as well as their compatibility with cathodic protection when disbondment occurs, play a major role for recoating programs and selection of the coating type used for repairs and re-coating programs. With the continued development and improvements of the “Electro-Magnetic Acoustic Transducer” (EMAT) in line inspection technology it is possible to locate disbonded coatings, without the need of exposing the pipeline. This way operators can assess the condition of the coatings applied to their pipeline systems at a comparable low cost. Inline inspection tools equipped with the “EMAT” technology are also capable of identifying the various coating types and coating conditions.1 The coating type identification process is not limited to coating types applied to whole joints. Field applied coatings covering the girth weld area or coating changes within a joint such as repairs can be identified as well. In the presented case study, the challenge was the identification of different coating types used as repairs or for re-coating procedures, within the 60 year history of the inspected pipeline system. At the beginning of the project the main coating types and obvious repairs were identified based on EMAT in line inspection data. In a combined effort, operator and in line inspection vendor compared the initially identified coating types with the known repair history of this pipeline system. Based on this shared combined information the coating type analysis could be finetuned and additional areas could be identified as repaired or re-coated. The paper will outline different coating repair methods described by the operator and subsequently identified by the EMAT tool. This paper will also describe for each coating repair method the associated risks for the pipeline integrity.

Hydrostatic Pressure Testing Program for a Liquid Petroleum Products Pipeline

1998 ◽  
Author(s):  
Robert V. Hadden ◽  
Kevin J. De Leenheer
Keyword(s):  
Water Treatment ◽  
Petroleum Products ◽  
Management Program ◽  
Pipeline System ◽  
Sewer System ◽  
Testing Program ◽  
Water Transportation ◽  
Pipe Line ◽  
Integrity Management ◽  
Products Pipeline

As part of its Integrity Management Program, Trans Mountain Pipe Line hydrostatically tests sections of its pipeline system with water transported to test sites through the pipeline. After completion of the testing, the water continues through the pipeline to a water treatment facility where it is treated and discharged to the municipal sewer system. Hydrostatic testing of an operating pipeline, although simple in concept, is a major undertaking. This paper will outline the technical aspects of Trans Mountain’s hydrostatic testing program including: test water transportation, environmental constraints, coordination of test activities and water treatment.

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.

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