Udayasankar Arumugam, M. Gao, R. Krishnamurthy, Rick Wang, R. Kania
Pipelines passing through hilly-terrain potentially have numerous rock dents. Some of them require further in-ditch investigation. However, in-ditch experience revealed elastic rebounding and re-rounding due to internal pressure that could cause cracking on dent outside surface when rock is removed even after following the commonly used pressure reduction by industry. Such OD-surface cracking in rock dent could pose safety issues to excavation crew and immediate integrity threat due to gas release. A preliminary research was performed to determine the required safe dig pressure level for rock dent excavation and address if there is a gap between the common industry practice for pressure reduction. This research could assist pipeline operators with setting a safe dig pressure level for rock dent excavation. The research consists of four components. First, detail review of rock dents cracking experience during excavation has been performed and identified relevant parameters that contributed to OD-cracking. Then, performed several rock dent case studies with different dent depths, indenter sizes, internal pressures and developed criterion for OD cracking using Finite Element Analysis. Thirdly, a decision chart was developed for safe rock dent excavation and presented. Finally, full-scale denting tests with internal pressure was conducted to corroborate the safe dig pressure criterion and compared against FEA results. In this paper, all above components are presented with summary of findings and recommendations for future research.
{"title":"Study of Safe Dig Pressure Level for Rock Dents in Gas Pipelines","authors":"Udayasankar Arumugam, M. Gao, R. Krishnamurthy, Rick Wang, R. Kania","doi":"10.1115/IPC2018-78616","DOIUrl":"https://doi.org/10.1115/IPC2018-78616","url":null,"abstract":"Pipelines passing through hilly-terrain potentially have numerous rock dents. Some of them require further in-ditch investigation. However, in-ditch experience revealed elastic rebounding and re-rounding due to internal pressure that could cause cracking on dent outside surface when rock is removed even after following the commonly used pressure reduction by industry. Such OD-surface cracking in rock dent could pose safety issues to excavation crew and immediate integrity threat due to gas release. A preliminary research was performed to determine the required safe dig pressure level for rock dent excavation and address if there is a gap between the common industry practice for pressure reduction. This research could assist pipeline operators with setting a safe dig pressure level for rock dent excavation.\u0000 The research consists of four components. First, detail review of rock dents cracking experience during excavation has been performed and identified relevant parameters that contributed to OD-cracking. Then, performed several rock dent case studies with different dent depths, indenter sizes, internal pressures and developed criterion for OD cracking using Finite Element Analysis. Thirdly, a decision chart was developed for safe rock dent excavation and presented. Finally, full-scale denting tests with internal pressure was conducted to corroborate the safe dig pressure criterion and compared against FEA results. In this paper, all above components are presented with summary of findings and recommendations for future research.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114200194","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mexico’s Energy Reform has opened up various interesting and unique opportunities for energy infrastructure. A CO2 pipeline project that was recently completed in southern Mexico provides a perfect example of how to breathe new life to deteriorated pipeline infrastructure — infrastructure that would have typically been written off. By coupling a unique pipeline inspection method with a novel lining system, two 28-kilometer (17 mile) pipelines were rehabilitated in record time and in a cost-effective manner. The project consisted of two 12 and 18-inch (300 and 450 millimeters) CO2 transport pipelines that had been out of service for 22 years and that are a central component for a high-profile fertilizer project. Replacing these deteriorated assets with a new transport pipeline was not an option due to time, environmental, permitting and budgetary constraints. The rehabilitated system had to offer a minimum 25-year service life required by the owner. To put this aging infrastructure back into service, it was essential to assess the condition of the pipelines with a high level of accuracy and precision which would allow for the rehabilitation of the pipeline and installation of an interactive liner to extend the system’s serviceable life for a minimum of 25 years. The challenge, however, was that these pipelines were non-piggable by traditional methods. By using a tethered MFL and Caliper ILI solution, the pipelines were each inspected in 13 separate sections with the level of detail necessary to assess the condition and suitability of the rehabilitation strategy selected for the project. Fast-track scheduling constraints required 24-hour data analysis turnaround of reports identifying and discriminating areas of modest and significant corrosion as well as deformations including areas of significant weld slag which could complicate the installation of the liners. Once high-quality data was available, pinpoint repairs were possible with a combination of carbon fiber reinforcement and steel pipe replacement. Afterwards, the pipelines were internally lined with a patented process that effectively provides a double containment system. A grooved liner and the host steel pipe create an annular space that is pressurized with air and remotely monitored. The system is able to detect even a small pressure drop in the annulus that would occur in case the integrity is breached, or a pinhole develops in the steel pipe. With the grooved liner, external repairs can be conducted while the line continues to operate without interrupting CO2 service to the plant. By applying these novel solutions, the rehabilitated pipelines will transport carbon dioxide to a revitalized fertilizer plant in a safe and efficient manner for the next 25 years.
{"title":"Breathing New Life to Aging Pipeline Infrastructure Using Unique Wireline Inspection Techniques and Pipe-Lining Technology","authors":"C. Goudy, Alex Gutiérrez","doi":"10.1115/IPC2018-78594","DOIUrl":"https://doi.org/10.1115/IPC2018-78594","url":null,"abstract":"Mexico’s Energy Reform has opened up various interesting and unique opportunities for energy infrastructure. A CO2 pipeline project that was recently completed in southern Mexico provides a perfect example of how to breathe new life to deteriorated pipeline infrastructure — infrastructure that would have typically been written off. By coupling a unique pipeline inspection method with a novel lining system, two 28-kilometer (17 mile) pipelines were rehabilitated in record time and in a cost-effective manner. The project consisted of two 12 and 18-inch (300 and 450 millimeters) CO2 transport pipelines that had been out of service for 22 years and that are a central component for a high-profile fertilizer project. Replacing these deteriorated assets with a new transport pipeline was not an option due to time, environmental, permitting and budgetary constraints. The rehabilitated system had to offer a minimum 25-year service life required by the owner.\u0000 To put this aging infrastructure back into service, it was essential to assess the condition of the pipelines with a high level of accuracy and precision which would allow for the rehabilitation of the pipeline and installation of an interactive liner to extend the system’s serviceable life for a minimum of 25 years. The challenge, however, was that these pipelines were non-piggable by traditional methods.\u0000 By using a tethered MFL and Caliper ILI solution, the pipelines were each inspected in 13 separate sections with the level of detail necessary to assess the condition and suitability of the rehabilitation strategy selected for the project. Fast-track scheduling constraints required 24-hour data analysis turnaround of reports identifying and discriminating areas of modest and significant corrosion as well as deformations including areas of significant weld slag which could complicate the installation of the liners.\u0000 Once high-quality data was available, pinpoint repairs were possible with a combination of carbon fiber reinforcement and steel pipe replacement. Afterwards, the pipelines were internally lined with a patented process that effectively provides a double containment system. A grooved liner and the host steel pipe create an annular space that is pressurized with air and remotely monitored. The system is able to detect even a small pressure drop in the annulus that would occur in case the integrity is breached, or a pinhole develops in the steel pipe. With the grooved liner, external repairs can be conducted while the line continues to operate without interrupting CO2 service to the plant.\u0000 By applying these novel solutions, the rehabilitated pipelines will transport carbon dioxide to a revitalized fertilizer plant in a safe and efficient manner for the next 25 years.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124615892","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This article presents a complete set of calculations (referred to as Model) PG&E developed to monitor, assess and approve strength tests on insitu (pipelines currently in service) gas transmission pipelines. How the Model is used in the field, 2017 test results, and process improvements that resulted from the implementation of the model are also discussed. In compliance with CPUC directives, the Code of Federal Regulations[1] and PG&E’s internal standards, PGE has performed strength tests on approximately 1,100 miles of insitu pipelines from 2011 through 2017. The model was specifically designed to assess the strength test of a closed section of gas pipeline for both leaks and ruptures. The model was originally designed for strength tests using water as the test medium and updated to accommodate nitrogen as a test medium. A future enhancement will be to incorporate a blend of Nitrogen and Helium as the test medium. The model plots the pressure-temperature and pressure-volume curves over the test duration (field test measurements) and compares them to the theoretically calculated curves. The curves are used to determine if the change in pressure is due to temperature influence or leakage. When water is the test medium, the model calculates the net corrected medium volume change from start to end of the static test period. When nitrogen is the test medium, the model calculates and analyzes net mass change of the medium by considering nitrogen under both the real gas state and the ideal gas state. By calculating restrained (buried) pipeline section and unrestrained (exposed) pipeline section separately, the model gains more accuracy. Accurate temperature measurements play a critical role in the model. The model makes it possible for engineers to monitor, analyze and direct strength tests with real-time test data. The model is also used to evaluate the pipeline fill condition on the day prior to the actual test, which resulted in fewer test restarts due to incomplete fill or temperature stabilization issues. An additional benefit is the tests were typically completed earlier in the day. The model is utilized on all PG&E insitu pipeline strength projects today. Authors also provide improvement suggestions of this model in future application.
{"title":"An Analysis Model and its Practical Applications in PG&E Gas Transmission Pipeline Strength Test Projects","authors":"Chunlei He, E. Stracke","doi":"10.1115/IPC2018-78255","DOIUrl":"https://doi.org/10.1115/IPC2018-78255","url":null,"abstract":"This article presents a complete set of calculations (referred to as Model) PG&E developed to monitor, assess and approve strength tests on insitu (pipelines currently in service) gas transmission pipelines. How the Model is used in the field, 2017 test results, and process improvements that resulted from the implementation of the model are also discussed.\u0000 In compliance with CPUC directives, the Code of Federal Regulations[1] and PG&E’s internal standards, PGE has performed strength tests on approximately 1,100 miles of insitu pipelines from 2011 through 2017. The model was specifically designed to assess the strength test of a closed section of gas pipeline for both leaks and ruptures.\u0000 The model was originally designed for strength tests using water as the test medium and updated to accommodate nitrogen as a test medium. A future enhancement will be to incorporate a blend of Nitrogen and Helium as the test medium. The model plots the pressure-temperature and pressure-volume curves over the test duration (field test measurements) and compares them to the theoretically calculated curves. The curves are used to determine if the change in pressure is due to temperature influence or leakage. When water is the test medium, the model calculates the net corrected medium volume change from start to end of the static test period. When nitrogen is the test medium, the model calculates and analyzes net mass change of the medium by considering nitrogen under both the real gas state and the ideal gas state.\u0000 By calculating restrained (buried) pipeline section and unrestrained (exposed) pipeline section separately, the model gains more accuracy. Accurate temperature measurements play a critical role in the model.\u0000 The model makes it possible for engineers to monitor, analyze and direct strength tests with real-time test data. The model is also used to evaluate the pipeline fill condition on the day prior to the actual test, which resulted in fewer test restarts due to incomplete fill or temperature stabilization issues. An additional benefit is the tests were typically completed earlier in the day. The model is utilized on all PG&E insitu pipeline strength projects today. Authors also provide improvement suggestions of this model in future application.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130202907","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Riccardella, D. Dedhia, Scott Riccardella, T. Manning
Probabilistic fracture mechanics (PFM) analysis can provide insights into the relative benefits of various pipeline integrity management options in reducing the probability of a pipeline failure. For example, a prior analysis (1) showed that In-Line Inspection (ILI) technology can achieve a greater level of safety, at longer reassessment intervals, than other integrity management techniques such as Hydrostatic Pressure Testing in a line subject to an aggressive Stress Corrosion Cracking (SCC) environment in relatively high toughness pipe base material. This paper extends that study to evaluate the effects of different crack growth mechanisms, such as fatigue crack growth (FCG) in gas and liquid pipelines as well as materials with differing fracture toughness levels (i.e. Seam Welds vs. Base Metal). PFM analysis can address these growth mechanisms and toughness distributions and serve as a valuable tool for weighing the effects of different assessment techniques, repair criteria and reassessment intervals on pipeline integrity. The analysis can also be used to study the effects of probability of detection (POD) of the ILI techniques as well as enhanced repair (dig) criteria. This paper presents a series of case studies to illustrate the utility of the PFM approach for comparing integrity management options for pipelines subject to different crack growth mechanisms and fracture toughness properties.
{"title":"Evaluation of Crack Growth and Material Toughness Effects on Probability of Pipeline Failure","authors":"P. Riccardella, D. Dedhia, Scott Riccardella, T. Manning","doi":"10.1115/IPC2018-78691","DOIUrl":"https://doi.org/10.1115/IPC2018-78691","url":null,"abstract":"Probabilistic fracture mechanics (PFM) analysis can provide insights into the relative benefits of various pipeline integrity management options in reducing the probability of a pipeline failure. For example, a prior analysis (1) showed that In-Line Inspection (ILI) technology can achieve a greater level of safety, at longer reassessment intervals, than other integrity management techniques such as Hydrostatic Pressure Testing in a line subject to an aggressive Stress Corrosion Cracking (SCC) environment in relatively high toughness pipe base material.\u0000 This paper extends that study to evaluate the effects of different crack growth mechanisms, such as fatigue crack growth (FCG) in gas and liquid pipelines as well as materials with differing fracture toughness levels (i.e. Seam Welds vs. Base Metal). PFM analysis can address these growth mechanisms and toughness distributions and serve as a valuable tool for weighing the effects of different assessment techniques, repair criteria and reassessment intervals on pipeline integrity. The analysis can also be used to study the effects of probability of detection (POD) of the ILI techniques as well as enhanced repair (dig) criteria. This paper presents a series of case studies to illustrate the utility of the PFM approach for comparing integrity management options for pipelines subject to different crack growth mechanisms and fracture toughness properties.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133748631","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Vibration related issues can be a challenging part of pipeline integrity management, because they are frequently difficult to predict, diagnose, and remediate. Often, vibrational issues are not even considered until pipe movement is observed or failures occur. A wide variety of vibration problems are associated with pumps and compressors, and piping at pumping stations are often susceptible to vibration related issues. Excessive piping vibration may result in leaks at connections and flanges, and fatigue failures can occur, leading to leaks that present safety and environmental concerns. The energy responsible for pipeline vibration is usually provided by rotating or reciprocating pumping equipment, and is transmitted to the piping either by direct mechanical contact, pressure pulsations, or turbulence in the pumped fluid. Vibration problems usually occur when a mechanical natural frequency of the piping system, an acoustic natural frequency of the contained fluid, or both, is excited by the driving force. In this paper, a brief overview of vibration issues that occur in pipeline facilities is presented. Next, a selection of case studies is provided to illustrate some of the types of vibration induced failures that have been observed at pipeline facilities, and how they were addressed and resolved. These examples provide some insight into how to potentially avoid such issues, or if they occur, how to identify and mitigate them.
{"title":"Vibration and Fatigue Failures at Pipeline Facilities","authors":"L. Matta, G. Szasz","doi":"10.1115/IPC2018-78176","DOIUrl":"https://doi.org/10.1115/IPC2018-78176","url":null,"abstract":"Vibration related issues can be a challenging part of pipeline integrity management, because they are frequently difficult to predict, diagnose, and remediate. Often, vibrational issues are not even considered until pipe movement is observed or failures occur. A wide variety of vibration problems are associated with pumps and compressors, and piping at pumping stations are often susceptible to vibration related issues. Excessive piping vibration may result in leaks at connections and flanges, and fatigue failures can occur, leading to leaks that present safety and environmental concerns.\u0000 The energy responsible for pipeline vibration is usually provided by rotating or reciprocating pumping equipment, and is transmitted to the piping either by direct mechanical contact, pressure pulsations, or turbulence in the pumped fluid. Vibration problems usually occur when a mechanical natural frequency of the piping system, an acoustic natural frequency of the contained fluid, or both, is excited by the driving force.\u0000 In this paper, a brief overview of vibration issues that occur in pipeline facilities is presented. Next, a selection of case studies is provided to illustrate some of the types of vibration induced failures that have been observed at pipeline facilities, and how they were addressed and resolved. These examples provide some insight into how to potentially avoid such issues, or if they occur, how to identify and mitigate them.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130703148","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Palkovic, S. Bellemare, K. Botros, Xiande Chen, R. Kania
In-ditch/in-service characterization of pipelines using nondestructive evaluation (NDE) can provide valuable data for confirming operating pressure and qualifying pipelines for transporting natural gas of different quality or gas mixture, as well as for determining repair criteria for integrity management programs. This is especially relevant for vintage pipelines that may not have material test reports (MTR) available, and for aging infrastructure that have been subjected to suspected or unknown integrity threats. However, measurement of material fracture toughness currently requires the removal of large samples for laboratory testing, such as compact tension (CT) fracture testing or Charpy impact testing. The present work introduces a new concept, the Nondestructive Toughness Tester (NDTT), that provides a NDE solution for measuring the fracture toughness of pipeline steel in a superficial layer of material (∼0.005 inches). The NDTT uses a specially designed wedge-shaped stylus to generate a Mode I tensile loading that results in a ductile fracture response. NDTT tests are performed in multiple orientations on 8 different pipeline steel samples covering 3 different grades to compare the NDTT material response with the fracture toughness measurements from laboratory CT specimens. Analysis of these results indicate that the height of a fractured ligament that remains on the sample surface after NDTT testing exhibits a linear relationship with traditional CT J-integral measurements normalized by its yield strength. This type of behavior is analogous to the crack-tip-opening-displacement (CTOD) calculated through elastic-plastic fracture mechanics. Tests conducted on the pipe outer diameter and in the longitudinal direction near the pipe mid-wall indicate that the NDTT can measure differences in fracture toughness for different crack orientations. Furthermore, the results show that outer diameter tests provide a conservative estimate of the overall steel fracture toughness. These observations indicate that the NDTT is a viable method for assessing toughness properties of steel materials. Additional research is required to further refine the implementation of the NDTT concept and understand the relationship with laboratory test results on pipe cutouts, but the progress is already a significant step towards obtaining additional material toughness data for integrity management.
{"title":"Calibration of a Nondestructive Toughness Tester (NDTT) for Measuring Fracture Toughness of Pipeline Steel","authors":"S. Palkovic, S. Bellemare, K. Botros, Xiande Chen, R. Kania","doi":"10.1115/IPC2018-78538","DOIUrl":"https://doi.org/10.1115/IPC2018-78538","url":null,"abstract":"In-ditch/in-service characterization of pipelines using nondestructive evaluation (NDE) can provide valuable data for confirming operating pressure and qualifying pipelines for transporting natural gas of different quality or gas mixture, as well as for determining repair criteria for integrity management programs. This is especially relevant for vintage pipelines that may not have material test reports (MTR) available, and for aging infrastructure that have been subjected to suspected or unknown integrity threats. However, measurement of material fracture toughness currently requires the removal of large samples for laboratory testing, such as compact tension (CT) fracture testing or Charpy impact testing. The present work introduces a new concept, the Nondestructive Toughness Tester (NDTT), that provides a NDE solution for measuring the fracture toughness of pipeline steel in a superficial layer of material (∼0.005 inches). The NDTT uses a specially designed wedge-shaped stylus to generate a Mode I tensile loading that results in a ductile fracture response. NDTT tests are performed in multiple orientations on 8 different pipeline steel samples covering 3 different grades to compare the NDTT material response with the fracture toughness measurements from laboratory CT specimens. Analysis of these results indicate that the height of a fractured ligament that remains on the sample surface after NDTT testing exhibits a linear relationship with traditional CT J-integral measurements normalized by its yield strength. This type of behavior is analogous to the crack-tip-opening-displacement (CTOD) calculated through elastic-plastic fracture mechanics. Tests conducted on the pipe outer diameter and in the longitudinal direction near the pipe mid-wall indicate that the NDTT can measure differences in fracture toughness for different crack orientations. Furthermore, the results show that outer diameter tests provide a conservative estimate of the overall steel fracture toughness. These observations indicate that the NDTT is a viable method for assessing toughness properties of steel materials. Additional research is required to further refine the implementation of the NDTT concept and understand the relationship with laboratory test results on pipe cutouts, but the progress is already a significant step towards obtaining additional material toughness data for integrity management.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"400 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130769995","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
At the forefront of the effort to understand and mitigate pipeline corrosion is the prediction of corrosion growth rates. It is important to understand the effect of corrosion growth estimates on integrity management decisions. An overly conservative approach results in unnecessary digs, while removing conservatism increases the potential for a missed feature to grow to a threatening size. While approaches to feature depth growth have been well-established, there has been less investigation into the growth of feature lengths. A literature review was performed on the methodologies applicable to length growth, and their performance was compared to those that only account for depth growth using a sample analysis. For pipelines with multiple in-line inspection (ILI) runs, feature or signal matching can be used to estimate the change in feature size. These rates can be used directly on individual features, averaged across pipe joints, or compiled into a statistical distribution. Alternatively, only one ILI measurement can be used and an assumption made on the age of the defect. These approaches are more commonly applied to depth growth but could be used to predict length growth as well. To compare the growth methodologies, the study used historical ILI measurements of a liquid pipeline to predict feature sizes and estimated burst pressures determined at the time of the latest ILI. The number of defects correctly predicted to have an insufficient burst pressure safety factor for safe operation was compared to the number of defects that were erroneously predicted to not meet this criterion, and those that were predicted to be safe but later found to not meet the safety factor requirement. The number of erroneously flagged defects was found to vary the most between methodologies. For the assessed data set, using the joint average rate based on feature box-matching was non-conservative on average. It was also found that incorporating length growth did not significantly affect the accuracy of the burst pressure predictions.
{"title":"Evaluation of Corrosion Growth Prediction Methodologies Using Burst Pressure Comparisons From Repeated In-Line Inspections","authors":"Chance Wright, T. Dessein, Yanping Li, S. Ward","doi":"10.1115/IPC2018-78294","DOIUrl":"https://doi.org/10.1115/IPC2018-78294","url":null,"abstract":"At the forefront of the effort to understand and mitigate pipeline corrosion is the prediction of corrosion growth rates. It is important to understand the effect of corrosion growth estimates on integrity management decisions. An overly conservative approach results in unnecessary digs, while removing conservatism increases the potential for a missed feature to grow to a threatening size. While approaches to feature depth growth have been well-established, there has been less investigation into the growth of feature lengths. A literature review was performed on the methodologies applicable to length growth, and their performance was compared to those that only account for depth growth using a sample analysis.\u0000 For pipelines with multiple in-line inspection (ILI) runs, feature or signal matching can be used to estimate the change in feature size. These rates can be used directly on individual features, averaged across pipe joints, or compiled into a statistical distribution. Alternatively, only one ILI measurement can be used and an assumption made on the age of the defect. These approaches are more commonly applied to depth growth but could be used to predict length growth as well.\u0000 To compare the growth methodologies, the study used historical ILI measurements of a liquid pipeline to predict feature sizes and estimated burst pressures determined at the time of the latest ILI. The number of defects correctly predicted to have an insufficient burst pressure safety factor for safe operation was compared to the number of defects that were erroneously predicted to not meet this criterion, and those that were predicted to be safe but later found to not meet the safety factor requirement. The number of erroneously flagged defects was found to vary the most between methodologies. For the assessed data set, using the joint average rate based on feature box-matching was non-conservative on average. It was also found that incorporating length growth did not significantly affect the accuracy of the burst pressure predictions.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"265 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133692576","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Kwon, Jong Hyoung Kim, O. Kwon, Woojoo Kim, Sungki Choi, Seunghun Choi, K. Kim, D. Ro
The instrumented indentation technique (IIT) is a novel method for evaluating mechanical properties such as tensile properties, toughness and residual stress by analyzing the indentation load-depth curve measured during indentation. It can be applied directly on small-scale and localized sections in industrial structures and structural components since specimen preparation is very easy and the experimental procedure is nondestructive. We introduce the principles for measuring mechanical properties with IIT: tensile properties by using a representative stress and strain approach, residual stress by analyzing the stress-free and stressed-state indentation curves, and fracture toughness of metals based on a ductile or brittle model according to the fracture behavior of the material. The experimental results from IIT were verified by comparing results from conventional methods such as uniaxial tensile testing for tensile properties, mechanical saw-cutting and hole-drilling methods for residual stress, and CTOD test for fracture toughness.
{"title":"Structure Assessment Using Instrumented Indentation: Strength, Toughness and Residual Stress","authors":"D. Kwon, Jong Hyoung Kim, O. Kwon, Woojoo Kim, Sungki Choi, Seunghun Choi, K. Kim, D. Ro","doi":"10.1115/IPC2018-78465","DOIUrl":"https://doi.org/10.1115/IPC2018-78465","url":null,"abstract":"The instrumented indentation technique (IIT) is a novel method for evaluating mechanical properties such as tensile properties, toughness and residual stress by analyzing the indentation load-depth curve measured during indentation. It can be applied directly on small-scale and localized sections in industrial structures and structural components since specimen preparation is very easy and the experimental procedure is nondestructive. We introduce the principles for measuring mechanical properties with IIT: tensile properties by using a representative stress and strain approach, residual stress by analyzing the stress-free and stressed-state indentation curves, and fracture toughness of metals based on a ductile or brittle model according to the fracture behavior of the material. The experimental results from IIT were verified by comparing results from conventional methods such as uniaxial tensile testing for tensile properties, mechanical saw-cutting and hole-drilling methods for residual stress, and CTOD test for fracture toughness.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134527636","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Bao, Shulong Zhang, Wenxing Zhou, Shenwei Zhang
In this paper, three-dimensional finite element models are developed to simulate full-scale burst tests of corroded pipes containing multiple naturally occurring corrosion anomalies. Both the von Mises and Tresca yield criteria and associated flow rules are employed in finite element analysis (FEA). For the Tresca criterion, the corresponding constitutive model subroutine is developed and incorporated in the FEA. The accuracy of FEA is investigated by comparing the burst pressures observed in the tests and corresponding burst pressures predicted using FEA. The implications of using the von Mises and Tresca criteria for the accuracy of the predicted burst pressure are investigated. Sensitivity analyses are also carried out to investigate the impact on the predicted burst pressure due to the mesh density in the corroded region, characterization of the geometry of the corrosion cluster and different types of element (e.g. solid and shell elements) used in FEA. The results suggest that the Tresca criterion always underestimates the burst pressure and the von Mises yield criterion predicts the burst pressure accurately. This study demonstrates the feasibility of using high-fidelity FEA and the Tresca yield criterion to simulate full-scale burst tests of corroded pipes and therefore establish a large database of burst pressure capacities of corroded pipes that can be used to develop an accurate, practical burst pressure capacity model amenable to the pipeline integrity management practice.
{"title":"Evaluation of Burst Pressure of Corroded Pipe Segments Using Three-Dimensional Finite Element Analyses","authors":"J. Bao, Shulong Zhang, Wenxing Zhou, Shenwei Zhang","doi":"10.1115/IPC2018-78130","DOIUrl":"https://doi.org/10.1115/IPC2018-78130","url":null,"abstract":"In this paper, three-dimensional finite element models are developed to simulate full-scale burst tests of corroded pipes containing multiple naturally occurring corrosion anomalies. Both the von Mises and Tresca yield criteria and associated flow rules are employed in finite element analysis (FEA). For the Tresca criterion, the corresponding constitutive model subroutine is developed and incorporated in the FEA. The accuracy of FEA is investigated by comparing the burst pressures observed in the tests and corresponding burst pressures predicted using FEA. The implications of using the von Mises and Tresca criteria for the accuracy of the predicted burst pressure are investigated. Sensitivity analyses are also carried out to investigate the impact on the predicted burst pressure due to the mesh density in the corroded region, characterization of the geometry of the corrosion cluster and different types of element (e.g. solid and shell elements) used in FEA. The results suggest that the Tresca criterion always underestimates the burst pressure and the von Mises yield criterion predicts the burst pressure accurately.\u0000 This study demonstrates the feasibility of using high-fidelity FEA and the Tresca yield criterion to simulate full-scale burst tests of corroded pipes and therefore establish a large database of burst pressure capacities of corroded pipes that can be used to develop an accurate, practical burst pressure capacity model amenable to the pipeline integrity management practice.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"68 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134026151","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Douglas Dewar, G. Boven, M. ElSeify, P. Bjorn, Nick Bruce
Axial Strain Inline Inspection has transitioned from an experimental to commercial technology that will develop significantly as the industry requires. Axial strain tool measures total elastic longitudinal strain on a pipeline including: imposed strains due to manufacturing; construction/cold bending; backfilling; and loading associated with abnormal forces such as ground movement and settlement. The technology is based on magnetostriction, which measures the permeability and magnetic induction of ferromagnetic materials. Magnetostriction is well understood, but the application of the technology to active pipelines is relatively recent. Currently, Inertial Measurement Unit (IMU) inline inspections (ILI) effectively identify areas of localized bending strains and can be used for monitoring of pipeline movements run to run, but they do not detect axial strain associated with either tensile or compressive loading. Currently, axial strain modules are mounted behind Magnetic Flux Leakage (MFL) platforms and have either 4 or 8 probes that provide circumferential readings typically at 0.5 to 1 m intervals. Data is either considered “trend” or “calibrated” depending on whether representative test samples are available. Interpretations are provided by the vendor in the form of Axial Strain Variation which is the averaged value of a set of readings with the hoop strain component removed. Additionally, data from each probe is analyzed to establish the maximum and minimal longitudinal strains (εmax/εmin) with locations around the circumference of the pipeline. Given the potential complexity of locked-in strains, simple calculations using sinusoidal bending relationships do not apply. Therefore, curve fitting analysis is required to determine the circumferential strains. This paper includes operational learnings from the analyses of data from eight (8) Axial Strain ILI runs within variable terrain on some natural gas transmission and gathering pipelines in British Columbia by verifying strains due to known abnormal loading as well as identifying previously unknown features (landslides, in particular). In addition, sources of error, data anomalies, current limitations and potential improvements of the technology are discussed.
{"title":"Operational Experiences With Axial Strain Inline Inspection Tools","authors":"Douglas Dewar, G. Boven, M. ElSeify, P. Bjorn, Nick Bruce","doi":"10.1115/IPC2018-78466","DOIUrl":"https://doi.org/10.1115/IPC2018-78466","url":null,"abstract":"Axial Strain Inline Inspection has transitioned from an experimental to commercial technology that will develop significantly as the industry requires. Axial strain tool measures total elastic longitudinal strain on a pipeline including: imposed strains due to manufacturing; construction/cold bending; backfilling; and loading associated with abnormal forces such as ground movement and settlement. The technology is based on magnetostriction, which measures the permeability and magnetic induction of ferromagnetic materials. Magnetostriction is well understood, but the application of the technology to active pipelines is relatively recent. Currently, Inertial Measurement Unit (IMU) inline inspections (ILI) effectively identify areas of localized bending strains and can be used for monitoring of pipeline movements run to run, but they do not detect axial strain associated with either tensile or compressive loading. Currently, axial strain modules are mounted behind Magnetic Flux Leakage (MFL) platforms and have either 4 or 8 probes that provide circumferential readings typically at 0.5 to 1 m intervals. Data is either considered “trend” or “calibrated” depending on whether representative test samples are available. Interpretations are provided by the vendor in the form of Axial Strain Variation which is the averaged value of a set of readings with the hoop strain component removed. Additionally, data from each probe is analyzed to establish the maximum and minimal longitudinal strains (εmax/εmin) with locations around the circumference of the pipeline. Given the potential complexity of locked-in strains, simple calculations using sinusoidal bending relationships do not apply. Therefore, curve fitting analysis is required to determine the circumferential strains. This paper includes operational learnings from the analyses of data from eight (8) Axial Strain ILI runs within variable terrain on some natural gas transmission and gathering pipelines in British Columbia by verifying strains due to known abnormal loading as well as identifying previously unknown features (landslides, in particular). In addition, sources of error, data anomalies, current limitations and potential improvements of the technology are discussed.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132059304","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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