Having sufficient depth of cover ensures pipeline protection and is a regulatory requirement. Confirming the pipeline depth of cover on dry land is generally easy and produces accurate results. However, determining the pipeline depth of cover at a river crossing can be problematic because of accessibility difficulties and the increased measurement errors from aboveground surveys. The difficulty of determining the pipeline depth of cover at river crossings can be resolved by integrating both the aboveground survey data and the inline inspection data. By comparing both sets of data, errors from both above survey data and inline inspection data can be detected. This paper describes watercourse management, aboveground DOC surveys, and a spreadsheet based tool developed for both the quick verification of aboveground survey results, and the calculation of the true DOC at water crossings without needing to set new GPS tie-points on both banks of the crossing and running a new ILI.
{"title":"Determining Pipeline Depth of Cover at River Crossings by Data Integration","authors":"Pete Chan, J. Wei","doi":"10.1115/IPC2018-78731","DOIUrl":"https://doi.org/10.1115/IPC2018-78731","url":null,"abstract":"Having sufficient depth of cover ensures pipeline protection and is a regulatory requirement. Confirming the pipeline depth of cover on dry land is generally easy and produces accurate results. However, determining the pipeline depth of cover at a river crossing can be problematic because of accessibility difficulties and the increased measurement errors from aboveground surveys.\u0000 The difficulty of determining the pipeline depth of cover at river crossings can be resolved by integrating both the aboveground survey data and the inline inspection data. By comparing both sets of data, errors from both above survey data and inline inspection data can be detected.\u0000 This paper describes watercourse management, aboveground DOC surveys, and a spreadsheet based tool developed for both the quick verification of aboveground survey results, and the calculation of the true DOC at water crossings without needing to set new GPS tie-points on both banks of the crossing and running a new ILI.","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":"114278068","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}
Amanda Kulhawy, Alex Nemeth, Garry Sommer, S. Hassanien
Integrity reliability science plays a major role in the integrity management of transmission piping, which is piping that traverses long distances across the continent, at high pressures, and can experience high pressure cycling. This science can be applied to non-transmission piping such as lateral piping, which traverses between a transmission line and a facility, or between two facilities, at lower pressures and with lower pressure cycling. Laterals are susceptible to the same threats as transmission lines (internal corrosion, external corrosion, cracking, geotechnical hazards, etc.). However, due to their operation, laterals are only highly susceptible to internal and external corrosion. While site specific conditions may result in a high susceptibility of a geotechnical hazard, this threat is outside of the scope of this paper. On transmission piping, corrosion is generally managed with In-Line Inspection (ILI), Non-Destructive Examination (NDE), and corresponding repairs (e.g. sleeving) to assess and mitigate. With laterals, there can be limited ILI and NDE data. As such, the data used in the quantitative reliability framework for these threats is not available and this creates a gap in the process. This paper addresses this gap through the application of semi-quantitative reliability analysis for internal and external corrosion on laterals along with a risk-based integrity decision making framework. The proposed approach is designed to enable pipeline and facility operators to make effective decisions around lateral integrity programs given the available data, and to better understand the limitations of integrity decision making. Moreover, the paper expands the discussion around the difference between risk-informed and risk-based integrity decision making in order to provide a guideline for optimal and safe integrity management programs considering different criteria. Case studies that include limited or no ILI or NDE information are used to demonstrate the application of semi-quantitative and quantitative reliability assessment of laterals along with the exploration of challenges in calibrating the two assessment methods to provide an example of how reliability science can be applied to laterals and how this can be used in effective decision making given such limitations.
{"title":"Risk-Based Integrity Decision Making for Lateral Piping","authors":"Amanda Kulhawy, Alex Nemeth, Garry Sommer, S. Hassanien","doi":"10.1115/IPC2018-78379","DOIUrl":"https://doi.org/10.1115/IPC2018-78379","url":null,"abstract":"Integrity reliability science plays a major role in the integrity management of transmission piping, which is piping that traverses long distances across the continent, at high pressures, and can experience high pressure cycling. This science can be applied to non-transmission piping such as lateral piping, which traverses between a transmission line and a facility, or between two facilities, at lower pressures and with lower pressure cycling. Laterals are susceptible to the same threats as transmission lines (internal corrosion, external corrosion, cracking, geotechnical hazards, etc.). However, due to their operation, laterals are only highly susceptible to internal and external corrosion. While site specific conditions may result in a high susceptibility of a geotechnical hazard, this threat is outside of the scope of this paper. On transmission piping, corrosion is generally managed with In-Line Inspection (ILI), Non-Destructive Examination (NDE), and corresponding repairs (e.g. sleeving) to assess and mitigate. With laterals, there can be limited ILI and NDE data. As such, the data used in the quantitative reliability framework for these threats is not available and this creates a gap in the process. This paper addresses this gap through the application of semi-quantitative reliability analysis for internal and external corrosion on laterals along with a risk-based integrity decision making framework. The proposed approach is designed to enable pipeline and facility operators to make effective decisions around lateral integrity programs given the available data, and to better understand the limitations of integrity decision making. Moreover, the paper expands the discussion around the difference between risk-informed and risk-based integrity decision making in order to provide a guideline for optimal and safe integrity management programs considering different criteria. Case studies that include limited or no ILI or NDE information are used to demonstrate the application of semi-quantitative and quantitative reliability assessment of laterals along with the exploration of challenges in calibrating the two assessment methods to provide an example of how reliability science can be applied to laterals and how this can be used in effective decision making given such limitations.","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":"128443575","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}
Jing Ma, M. Rosenfeld, P. Veloo, Troy Rovella, P. Martín
Hydrostatic pressure testing is the most widely accepted approach to verify the integrity of assets used for the transportation of natural gas. It is required by Federal Regulations 49 CFR §192 to substantiate the intended maximum allowable operating pressure (MAOP) of new gas transmission pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM) with Docket No. PHMSA-2011-0023 [1], proposes an additional requirement for MAOP verification of existing pipelines that: i) do not have reliable, traceable, verifiable, or complete records of a pressure test; or ii) were grandfathered into present service via 49 CFR §192.619(c). To meet this requirement, the NPRM proposes that an Engineering Critical Assessment (ECA) can be considered as an alternative to pressure testing if the operator establishes and develops an inline inspection (ILI) program. The ECA must analyze cracks or crack-like defects remaining or that could remain in the pipe, and must perform both predicted failure pressure (PFP) and crack growth calculations using established fracture mechanics techniques. For assets that cannot be assessed by ILI, however, the implementation of an ECA is hindered by the lack of defect size information. This work documents a statistical approach to determine the most probable PFP and remaining life for assets that cannot be assessed by ILI. The first step is to infer a distribution of initial defect size accumulated through multiple ILI and in-ditch programs. The initial defect size distribution is established according to the as-identified seam type, e.g. low-frequency electric resistance weld (LF-ERW), high-frequency electric resistance weld (HF-ERW), flash weld (FW), single submerged arc weld (SSAW), or seamless (SMLS). The second step is to perform fracture mechanics assessment to generate a probabilistic distribution of PFPs for the asset. In conjunction with the defect size distribution, inputs into the calculation also include the variations of mechanical strength and toughness properties informed by the operator’s materials verification program. Corresponding to a target reliability level, a nominal PFP is selected through its statistical distribution. Subsequently applying the appropriate class location factor to the nominal PFP gives the operator a basis to verify their current MAOP. The last step is to perform probabilistic fatigue life calculations to derive the remaining life distribution, which drives reassessment intervals and integrity management decisions for the asset. This paper will present some case studies as a demonstration of the methodology developed and details of calculation and establishment of database.
{"title":"An Approach to Engineering Critical Assessment of Assets That Cannot Be Inline Inspected","authors":"Jing Ma, M. Rosenfeld, P. Veloo, Troy Rovella, P. Martín","doi":"10.1115/IPC2018-78132","DOIUrl":"https://doi.org/10.1115/IPC2018-78132","url":null,"abstract":"Hydrostatic pressure testing is the most widely accepted approach to verify the integrity of assets used for the transportation of natural gas. It is required by Federal Regulations 49 CFR §192 to substantiate the intended maximum allowable operating pressure (MAOP) of new gas transmission pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM) with Docket No. PHMSA-2011-0023 [1], proposes an additional requirement for MAOP verification of existing pipelines that: i) do not have reliable, traceable, verifiable, or complete records of a pressure test; or ii) were grandfathered into present service via 49 CFR §192.619(c). To meet this requirement, the NPRM proposes that an Engineering Critical Assessment (ECA) can be considered as an alternative to pressure testing if the operator establishes and develops an inline inspection (ILI) program. The ECA must analyze cracks or crack-like defects remaining or that could remain in the pipe, and must perform both predicted failure pressure (PFP) and crack growth calculations using established fracture mechanics techniques. For assets that cannot be assessed by ILI, however, the implementation of an ECA is hindered by the lack of defect size information.\u0000 This work documents a statistical approach to determine the most probable PFP and remaining life for assets that cannot be assessed by ILI. The first step is to infer a distribution of initial defect size accumulated through multiple ILI and in-ditch programs. The initial defect size distribution is established according to the as-identified seam type, e.g. low-frequency electric resistance weld (LF-ERW), high-frequency electric resistance weld (HF-ERW), flash weld (FW), single submerged arc weld (SSAW), or seamless (SMLS). The second step is to perform fracture mechanics assessment to generate a probabilistic distribution of PFPs for the asset. In conjunction with the defect size distribution, inputs into the calculation also include the variations of mechanical strength and toughness properties informed by the operator’s materials verification program. Corresponding to a target reliability level, a nominal PFP is selected through its statistical distribution. Subsequently applying the appropriate class location factor to the nominal PFP gives the operator a basis to verify their current MAOP. The last step is to perform probabilistic fatigue life calculations to derive the remaining life distribution, which drives reassessment intervals and integrity management decisions for the asset. This paper will present some case studies as a demonstration of the methodology developed and details of calculation and establishment of database.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"51 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":"128794209","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}
In accidental scenarios on subsea pipeline systems, like the collision of two adjacent subsea risers, accidental loads are commonly considered as stationary loads; stationary loads refer to loads that act only normal to the pipe at one location. Hence, the potential considerable effects of moving (sliding) accidental loads are neglected; the term moving load refers to the location with respect to time. Accordingly, recent works for ship hull structures show that the structural resistance mobilized against the moving loads is significantly lower than against the stationary loads of similar magnitude; when the loads incite plastic damage. As such, it is reasonable to study the effects of lateral motion of accidental loads on the response of subsea pipelines. This paper implements finite element analyses to investigate the load carrying capacity of a cylindrical shell subject to moving loads; LS-Dyna software package with explicit time-integration scheme is employed in numerical simulations; only crumpling deformation of the cylinders are studied. This research demonstrates that the capacity of a cylindrical shell subject to a moving load, causing plastic damage, is considerably less than its capacity under a stationary load of similar magnitude.
{"title":"An Investigation of the Load Carrying Capacity of Pipelines Under Accidental and Longitudinal Moving (Sliding) Loads","authors":"Farhad Davaripour, B. Quinton","doi":"10.1115/IPC2018-78316","DOIUrl":"https://doi.org/10.1115/IPC2018-78316","url":null,"abstract":"In accidental scenarios on subsea pipeline systems, like the collision of two adjacent subsea risers, accidental loads are commonly considered as stationary loads; stationary loads refer to loads that act only normal to the pipe at one location. Hence, the potential considerable effects of moving (sliding) accidental loads are neglected; the term moving load refers to the location with respect to time. Accordingly, recent works for ship hull structures show that the structural resistance mobilized against the moving loads is significantly lower than against the stationary loads of similar magnitude; when the loads incite plastic damage. As such, it is reasonable to study the effects of lateral motion of accidental loads on the response of subsea pipelines. This paper implements finite element analyses to investigate the load carrying capacity of a cylindrical shell subject to moving loads; LS-Dyna software package with explicit time-integration scheme is employed in numerical simulations; only crumpling deformation of the cylinders are studied. This research demonstrates that the capacity of a cylindrical shell subject to a moving load, causing plastic damage, is considerably less than its capacity under a stationary load of similar magnitude.","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":"128958037","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. Kemp, Justin J. Gossard, S. Finneran, Joseph P. Bratton
Pipeline in-line-inspections (ILI) are used to assess and track the integrity of pipelines, aiding in identifying a variety of features such as: metal loss, dents, out-of-roundness, cracks, etc. The presence of these features can negatively affect the operation, integrity, and remaining life of a pipeline. Proper interpretation of the impacts these features may have on a pipeline are crucial to maintaining the integrity of a pipeline. Several codes and publications exist to assess the severity of these features under known operating conditions, either through empirical formulations or more detailed analysis, in order to aid the operator in determining a corrective action plan. These empirical formulations are generally applicable to assess a singular defect but require a more detailed assessment to evaluate combined defects (i.e. dent in a bend). These detailed assessments typically require a higher level numerical simulation, such as Finite Element Analysis (FEA). This detailed FEA can be quite costly and time consuming to evaluate each set of combined features in a given ILI run. Thus, engineering judgement is critical in determining a worst-case scenario of a given feature set in order to prioritize assessment and corrective action. This study aims to assess dent features (many associated with metal loss) occurring in a pipe bend to determine a worst-case scenario for prioritization of a given feature listing. FEA was used to simulate a field bend of a given radius and angle in order to account for residual stresses in the pipe bend. A rigid indenter was used to form a dent of the approximate length, width, and depth from the ILI data. Separate models were evaluated considering the dent occurring in the intrados, extrados, and neutral axis of the pipe bend to evaluate the worst-case scenario for further assessment. The resulting stresses in the pipe bend-dent geometry, under proper loading were compared to the same dent scenario in a straight pipe segment to develop a stress concentration factor (SCF). This SCF was used in the API 579-1/ASME FFS-1 Fitness for Service (API 579) [1] methodology to determine the impact on the remaining life of the combined features.
{"title":"Using Finite Element Analysis to Prioritize ILI Calls for Combined Features: Dents in Bends","authors":"D. Kemp, Justin J. Gossard, S. Finneran, Joseph P. Bratton","doi":"10.1115/IPC2018-78636","DOIUrl":"https://doi.org/10.1115/IPC2018-78636","url":null,"abstract":"Pipeline in-line-inspections (ILI) are used to assess and track the integrity of pipelines, aiding in identifying a variety of features such as: metal loss, dents, out-of-roundness, cracks, etc. The presence of these features can negatively affect the operation, integrity, and remaining life of a pipeline. Proper interpretation of the impacts these features may have on a pipeline are crucial to maintaining the integrity of a pipeline. Several codes and publications exist to assess the severity of these features under known operating conditions, either through empirical formulations or more detailed analysis, in order to aid the operator in determining a corrective action plan. These empirical formulations are generally applicable to assess a singular defect but require a more detailed assessment to evaluate combined defects (i.e. dent in a bend). These detailed assessments typically require a higher level numerical simulation, such as Finite Element Analysis (FEA). This detailed FEA can be quite costly and time consuming to evaluate each set of combined features in a given ILI run. Thus, engineering judgement is critical in determining a worst-case scenario of a given feature set in order to prioritize assessment and corrective action.\u0000 This study aims to assess dent features (many associated with metal loss) occurring in a pipe bend to determine a worst-case scenario for prioritization of a given feature listing. FEA was used to simulate a field bend of a given radius and angle in order to account for residual stresses in the pipe bend. A rigid indenter was used to form a dent of the approximate length, width, and depth from the ILI data. Separate models were evaluated considering the dent occurring in the intrados, extrados, and neutral axis of the pipe bend to evaluate the worst-case scenario for further assessment. The resulting stresses in the pipe bend-dent geometry, under proper loading were compared to the same dent scenario in a straight pipe segment to develop a stress concentration factor (SCF). This SCF was used in the API 579-1/ASME FFS-1 Fitness for Service (API 579) [1] methodology to determine the impact on the remaining life of the combined features.","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":"129074600","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}
Accurate defect sizing is crucial for maintaining effective pipeline safety and operation. Under growing pressure from local, national and world organizations, pipeline operators demand improved magnetic flux leakage (MFL) metal-loss sizing accuracy and classification from in-line inspection (ILI) tools. The axial MFL field response in pipeline steel near a metal-loss defect is a very complex phenomenon. Although critical for proper sizing model development, the effects of tool speed due to product flow is very difficult to model during finite element analysis (FEA) and therefore is often overlooked. However, understanding the dynamic MFL response is crucial for proper ILI tool design and the development of accurate defect sizing algorithms. T.D. Williamson (TDW) utilizes dynamic computer simulation modeling, paired with laboratory testing, to develop the complex parametric relationships between metal loss geometry, pipeline material and ILI tool speed. The blend of simulation and physical test results allow for TDW to iterate more quickly across multiple physics variables with simulation models, while maintaining a firm footing in reality with physical test validation. Accurately simulating magnetic field responses of metal loss under dynamic conditions produces the data necessary to identify optimal magnetizer design, including optimizing sensor spacing and placement for metal-loss defect sizing and characterization. This paper will provide an overview of advances in the use of computer simulation modeling for predicting dynamic flux leakage field response. Besides increasing accuracy, results from this work will extend specifications beyond optimal speed ranges and provide the basis for general corrosion profilometry predictions from decomposition of the full MFL signal.
{"title":"Modeling Pipeline Metal Loss Defects at Tool Speed","authors":"Matthew Romney, Adrian Belanger","doi":"10.1115/IPC2018-78014","DOIUrl":"https://doi.org/10.1115/IPC2018-78014","url":null,"abstract":"Accurate defect sizing is crucial for maintaining effective pipeline safety and operation. Under growing pressure from local, national and world organizations, pipeline operators demand improved magnetic flux leakage (MFL) metal-loss sizing accuracy and classification from in-line inspection (ILI) tools.\u0000 The axial MFL field response in pipeline steel near a metal-loss defect is a very complex phenomenon. Although critical for proper sizing model development, the effects of tool speed due to product flow is very difficult to model during finite element analysis (FEA) and therefore is often overlooked. However, understanding the dynamic MFL response is crucial for proper ILI tool design and the development of accurate defect sizing algorithms.\u0000 T.D. Williamson (TDW) utilizes dynamic computer simulation modeling, paired with laboratory testing, to develop the complex parametric relationships between metal loss geometry, pipeline material and ILI tool speed. The blend of simulation and physical test results allow for TDW to iterate more quickly across multiple physics variables with simulation models, while maintaining a firm footing in reality with physical test validation. Accurately simulating magnetic field responses of metal loss under dynamic conditions produces the data necessary to identify optimal magnetizer design, including optimizing sensor spacing and placement for metal-loss defect sizing and characterization.\u0000 This paper will provide an overview of advances in the use of computer simulation modeling for predicting dynamic flux leakage field response. Besides increasing accuracy, results from this work will extend specifications beyond optimal speed ranges and provide the basis for general corrosion profilometry predictions from decomposition of the full MFL signal.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"27 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":"130646655","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}
The failure of a corroded pipe is generally controlled by the depth and the longitudinal extent of the metal loss area subjected to hoop stress. However, the failure of metal loss due to its circumferential extent under longitudinal stress is possible if significant longitudinal stress exists in the pipe or the metal loss has considerable circumferential extent and depth. If such circumstances exist, it is prudent to conduct a complementary analysis of pipe integrity to assess the potential for circumferential as well longitudinal failure. Most existing approaches for assessing circumferential metal loss, such as Miller’s equations, were derived by assuming the metal loss to be centered at the extreme stress position around the pipe circumference, i.e., the center of the metal loss is centered at the location of the maximum bending stress in the pipe. The assessment may be over-conservative if the metal loss area deviates from the extreme position related to the bending plane. Described in this paper is a new approach to assess the potential for circumferential failure of metal loss centered at an arbitrary angle from the location of maximum bending stress. The approach results in the same failure stress as existing models when the metal loss is centered at the location of maximum bending stress. The failure stress increases when the metal loss deviates from the location of maximum bending stress and reaches the maximum value when the metal loss is centered at the neutral axis. The equations of the model developed in this paper can be easily implemented into a spreadsheet tool for routine integrity assessment. Other considerations related to the assessment of circumferential metal loss are also discussed, including non-uniform corrosion, negligible corrosion, and the interaction of multiple corrosion areas in the same pipe cross section. The model developed in this paper can also be used to determine the cutoff line for plastic collapse in a failure assessment diagram (FAD) based approach for assessing circumferential cracks, such as API 1104 Appendix A and API 579.
{"title":"Fitness for Service Analysis of the Circumferential Extent of Corrosion in Pipelines","authors":"Fan Zhang, M. Rosenfeld, J. Gustafson","doi":"10.1115/IPC2018-78338","DOIUrl":"https://doi.org/10.1115/IPC2018-78338","url":null,"abstract":"The failure of a corroded pipe is generally controlled by the depth and the longitudinal extent of the metal loss area subjected to hoop stress. However, the failure of metal loss due to its circumferential extent under longitudinal stress is possible if significant longitudinal stress exists in the pipe or the metal loss has considerable circumferential extent and depth. If such circumstances exist, it is prudent to conduct a complementary analysis of pipe integrity to assess the potential for circumferential as well longitudinal failure. Most existing approaches for assessing circumferential metal loss, such as Miller’s equations, were derived by assuming the metal loss to be centered at the extreme stress position around the pipe circumference, i.e., the center of the metal loss is centered at the location of the maximum bending stress in the pipe. The assessment may be over-conservative if the metal loss area deviates from the extreme position related to the bending plane. Described in this paper is a new approach to assess the potential for circumferential failure of metal loss centered at an arbitrary angle from the location of maximum bending stress. The approach results in the same failure stress as existing models when the metal loss is centered at the location of maximum bending stress. The failure stress increases when the metal loss deviates from the location of maximum bending stress and reaches the maximum value when the metal loss is centered at the neutral axis. The equations of the model developed in this paper can be easily implemented into a spreadsheet tool for routine integrity assessment. Other considerations related to the assessment of circumferential metal loss are also discussed, including non-uniform corrosion, negligible corrosion, and the interaction of multiple corrosion areas in the same pipe cross section. The model developed in this paper can also be used to determine the cutoff line for plastic collapse in a failure assessment diagram (FAD) based approach for assessing circumferential cracks, such as API 1104 Appendix A and API 579.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"17 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":"127995137","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}
M. Piazza, Justin Harkrader, Rogelio Guajardo, T. Henning, M. Urrea, R. Krishnamurthy, S. Tandon, M. Gao
In-line inspection (ILI) systems continue to improve in the detection and characterization of cracks in pipelines, and are relied on substantially by pipeline operators to support Integrity Management Programs for continual assessment of conditions on operating pipelines that are susceptible to cracking as an integrity threat. Recent experience for some forms of cracking have shown that integration of data from multiple ILI systems can improve detection and characterization (depth sizing, crack orientation, and crack feature profile) performance. This paper will describe the approach taken by a liquids pipeline operator to integrate data from multiple ILI systems, namely Ultrasonic axial (UC) and circumferential (UCc) crack detection and Magnetic Flux Leakage (MFL) technologies, to improve detection and characterization of cracks and crack fields on a 42 miles long, 12-inch OD liquid pipeline with a 38-year operating history. ILI data has indicated a large number of crack features, including 4000+ crack features reported by UC, 1000+ crack features by UCc, and 2500+ metal loss features reported by MFL. Initial excavations demonstrated a unique pattern of blended circumferential-, oblique- and axial-orientated cracks along the entire extent of the 42-mile pipeline, requiring advanced methods of data integration and analysis. Applying individual technologies and their analysis approaches showed limitations in performance for identification and characterization of these blended features. The outcome of the study was the development of a feature classification approach to classify the cracks with respect to their orientation, and rank them based on the depth sizing by using multiple datasets. Several sections of the 42-mile pipeline were cut-out and subjected to detailed examination using multiple non-destructive examination (NDE) methods and destructive testing to confirm the crack depths and profiles. These data were used as the basis for confirming the ILI tool performance and providing confirmation on the improvements made to crack detection and sizing through the data integration process.
{"title":"Integration of Data From Multiple In-Line Inspection Systems to Improve Crack Detection and Characterization","authors":"M. Piazza, Justin Harkrader, Rogelio Guajardo, T. Henning, M. Urrea, R. Krishnamurthy, S. Tandon, M. Gao","doi":"10.1115/IPC2018-78770","DOIUrl":"https://doi.org/10.1115/IPC2018-78770","url":null,"abstract":"In-line inspection (ILI) systems continue to improve in the detection and characterization of cracks in pipelines, and are relied on substantially by pipeline operators to support Integrity Management Programs for continual assessment of conditions on operating pipelines that are susceptible to cracking as an integrity threat. Recent experience for some forms of cracking have shown that integration of data from multiple ILI systems can improve detection and characterization (depth sizing, crack orientation, and crack feature profile) performance. This paper will describe the approach taken by a liquids pipeline operator to integrate data from multiple ILI systems, namely Ultrasonic axial (UC) and circumferential (UCc) crack detection and Magnetic Flux Leakage (MFL) technologies, to improve detection and characterization of cracks and crack fields on a 42 miles long, 12-inch OD liquid pipeline with a 38-year operating history. ILI data has indicated a large number of crack features, including 4000+ crack features reported by UC, 1000+ crack features by UCc, and 2500+ metal loss features reported by MFL. Initial excavations demonstrated a unique pattern of blended circumferential-, oblique- and axial-orientated cracks along the entire extent of the 42-mile pipeline, requiring advanced methods of data integration and analysis. Applying individual technologies and their analysis approaches showed limitations in performance for identification and characterization of these blended features. The outcome of the study was the development of a feature classification approach to classify the cracks with respect to their orientation, and rank them based on the depth sizing by using multiple datasets.\u0000 Several sections of the 42-mile pipeline were cut-out and subjected to detailed examination using multiple non-destructive examination (NDE) methods and destructive testing to confirm the crack depths and profiles. These data were used as the basis for confirming the ILI tool performance and providing confirmation on the improvements made to crack detection and sizing through the data integration process.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"8 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":"128051437","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}
Pacific Gas and Electric Company owns and operates an extensive network of over 10,700 km (6,700 miles) of gas transmission pipelines, much of which is under 16″ diameter and operates at less than 27.5 bar (400 psig), making them difficult to inspect with free swimming in-line inspection (ILI) tools. Additionally, many piggable pipeline sections are multi-diameter and have numerous 1.5D fittings, some of these in back to back configuration, requiring tools that are not currently available. Following several failed attempts to inspect PG&E’s 12″ × 16″ pipelines in 2015 using existing ILI tools, and after working to modify a 12″ × 18″ tool for lower pressure service in 2016, PG&E and ROSEN decided to collaboratively develop new, specially designed, 12″ × 16″ geometry and axial MFL tools. The goal of this project was to develop tools that could meet both the PG&E pipeline passage requirements and allow for an acceptable speed profile. The need to inspect a total of 16 pipeline sections in the long-term ILI Upgrade Plan, in this size range, justified the investment in these new tools. The service provider embarked on a new ILI tool design process including design, manufacturing, fabrication and testing at their facilities in Germany. Through this process, a number of unique ILI tool design features to lower tool drag and improve ease of collapsibility were implemented, resulting in a tool that far exceeds existing industry capabilities. To confirm the tools’ capabilities before their first use in a live gas transmission pipeline, pump testing in water, as well as in compressed air, was performed. In late 2017, using these tools, PG&E inspected two previously unpiggable 12″ × 16″ low-pressure pipelines successfully. In this paper, the process of developing these tools will be discussed. The test program will be reviewed comparing findings under controlled conditions in water and compressed air with pig run behavior in the live pipelines. The analysis also provides an assessment of the operating conditions that are deemed necessary for the inspection tool to gather a good quality data set.
太平洋天然气和电力公司拥有并运营着一个超过10,700公里(6,700英里)的天然气输送管道网络，其中大部分管道直径低于16″，运行压力低于27.5 bar (400 psig)，这使得它们很难用免费游泳在线检查(ILI)工具进行检查。此外，许多可清管管道段是多直径的，有许多1.5D接头，其中一些是背靠背配置，需要目前无法获得的工具。2015年，PG&E使用现有的ILI工具对12″× 16″管道进行了几次失败的检测，2016年，PG&E和ROSEN决定合作开发专门设计的12″× 16″几何和轴向MFL工具，并对12″× 18″工具进行了改进。该项目的目标是开发既能满足PG&E管道通道要求，又能实现可接受的速度剖面的工具。在ILI长期升级计划中，需要在这个尺寸范围内检查总共16个管道段，这证明了投资这些新工具是合理的。该服务提供商在其位于德国的工厂开始了新的ILI工具设计流程，包括设计、制造、制造和测试。在这一过程中，ILI采用了许多独特的工具设计特点，降低了工具的拖拽，提高了工具的可折叠性，从而使该工具远远超过了现有的行业能力。为了在首次用于天然气输送管道之前确认该工具的性能，在水中和压缩空气中进行了泵测试。2017年底，PG&E使用这些工具成功检查了两条以前无法清管的12″× 16″低压管道。本文将讨论这些工具的开发过程。测试程序将在水和压缩空气的受控条件下与活管道中的清管器运行行为进行比较。分析还提供了对操作条件的评估，这些条件被认为是检测工具收集高质量数据集所必需的。
{"title":"Overcoming Difficult to Inspect Multi-Diameter, Low Pressure Gas Transmission Pipeline Challenges","authors":"Frank A. Dauby, Stefan Vages","doi":"10.1115/IPC2018-78427","DOIUrl":"https://doi.org/10.1115/IPC2018-78427","url":null,"abstract":"Pacific Gas and Electric Company owns and operates an extensive network of over 10,700 km (6,700 miles) of gas transmission pipelines, much of which is under 16″ diameter and operates at less than 27.5 bar (400 psig), making them difficult to inspect with free swimming in-line inspection (ILI) tools. Additionally, many piggable pipeline sections are multi-diameter and have numerous 1.5D fittings, some of these in back to back configuration, requiring tools that are not currently available. Following several failed attempts to inspect PG&E’s 12″ × 16″ pipelines in 2015 using existing ILI tools, and after working to modify a 12″ × 18″ tool for lower pressure service in 2016, PG&E and ROSEN decided to collaboratively develop new, specially designed, 12″ × 16″ geometry and axial MFL tools.\u0000 The goal of this project was to develop tools that could meet both the PG&E pipeline passage requirements and allow for an acceptable speed profile. The need to inspect a total of 16 pipeline sections in the long-term ILI Upgrade Plan, in this size range, justified the investment in these new tools. The service provider embarked on a new ILI tool design process including design, manufacturing, fabrication and testing at their facilities in Germany. Through this process, a number of unique ILI tool design features to lower tool drag and improve ease of collapsibility were implemented, resulting in a tool that far exceeds existing industry capabilities. To confirm the tools’ capabilities before their first use in a live gas transmission pipeline, pump testing in water, as well as in compressed air, was performed. In late 2017, using these tools, PG&E inspected two previously unpiggable 12″ × 16″ low-pressure pipelines successfully. In this paper, the process of developing these tools will be discussed. The test program will be reviewed comparing findings under controlled conditions in water and compressed air with pig run behavior in the live pipelines. The analysis also provides an assessment of the operating conditions that are deemed necessary for the inspection tool to gather a good quality data set.","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":"115542623","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}
David Katz, S. Potts, T. Beuker, Joerg Grillenberger, Ralf Weber
The integrity of aging assets like gas pipelines are managed by a variety of inspection and validation methods. In the particular case of gas pipelines and their susceptibility to cracking, an ultrasonic inspection methodology has been introduced over the last decade, which is based on an electromagnetic acoustic transducer (EMAT). Meanwhile, a high resolution implementation of the technology has been utilized on in-line inspection (ILI) tools from 10″ to 48″ in diameter. Williams Gas Pipelines have utilized this inspection technology successfully on several pipelines, therefore an overview will be given about this experience. Secondly a case study will be presented, in which a post hydrostatic test ILI service was used to gain additional relevant safety and integrity information from the ILI inspection and to better understand the actual capabilities of a hydrostatic test. The approach taken is in accordance with API 1163 and in consideration of API 1176. As part of this approach the performance of the ILI tool was confirmed based on a set of full scale tests conducted at the PRCI ILI test facility. The results were used to increase the statistical confidence in the capabilities of the technology.
天然气管道等老化资产的完整性通过各种检查和验证方法进行管理。在天然气管道及其易开裂的特殊情况下，在过去十年中引入了一种基于电磁声换能器(EMAT)的超声波检测方法。同时，该技术的高分辨率实现已用于直径为10″至48″的在线检测(ILI)工具。Williams Gas Pipelines已经成功地在几条管道上使用了这种检测技术，因此将对这一经验进行概述。其次，将介绍一个案例研究，其中使用静水测试后的ILI服务，从ILI检查中获得额外的相关安全性和完整性信息，并更好地了解静水测试的实际能力。采用的方法符合API 1163并考虑了API 1176。作为该方法的一部分，ILI工具的性能是根据在PRCI ILI测试设施进行的一组全尺寸测试来确认的。这些结果被用来增加对该技术能力的统计信心。
{"title":"EMAT As a Basis for a Comprehensive System Wide Crack Management Program","authors":"David Katz, S. Potts, T. Beuker, Joerg Grillenberger, Ralf Weber","doi":"10.1115/IPC2018-78346","DOIUrl":"https://doi.org/10.1115/IPC2018-78346","url":null,"abstract":"The integrity of aging assets like gas pipelines are managed by a variety of inspection and validation methods. In the particular case of gas pipelines and their susceptibility to cracking, an ultrasonic inspection methodology has been introduced over the last decade, which is based on an electromagnetic acoustic transducer (EMAT). Meanwhile, a high resolution implementation of the technology has been utilized on in-line inspection (ILI) tools from 10″ to 48″ in diameter. Williams Gas Pipelines have utilized this inspection technology successfully on several pipelines, therefore an overview will be given about this experience. Secondly a case study will be presented, in which a post hydrostatic test ILI service was used to gain additional relevant safety and integrity information from the ILI inspection and to better understand the actual capabilities of a hydrostatic test. The approach taken is in accordance with API 1163 and in consideration of API 1176. As part of this approach the performance of the ILI tool was confirmed based on a set of full scale tests conducted at the PRCI ILI test facility. The results were used to increase the statistical confidence in the capabilities of the technology.","PeriodicalId":273758,"journal":{"name":"Volume 1: Pipeline and Facilities Integrity","volume":"82 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":"115565952","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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