Decision making to optimize the drilling operation is based on a variety of factors, among them real-time interpretation of drilled lithology. Because logging while drilling (LWD) tools are placed some meters above the bit, mechanical drilling parameters are the earliest indicators, although they are difficult to interpret accurately. This paper presents a novel deep learning methodology using mechanical drilling parameters for lithology classification. A cascade of deep neural networks (DNNs) are trained on historical data from wells on a field operated by Equinor. Rather than an end-to-end approach, the drilling parameters are used to estimate LWD sensor readings in an intermediate step using the first DNNs. This allows continuous updates of the models during operation using delayed LWD data. The second DNN takes the virtual LWD estimates as input to predict currently drilled lithology, similar to manual expert interpretation of logs. This configuration takes into account case-dependent [mud, bottomhole assembly (BHA), wellbore geometry] and time-varying (bit wear, wellbore friction) relationships between drilling parameters and LWD readings while assuming a constant rule when using LWD data to classify lithology. Upon completion of training and validation, the system is tested on a separate, unseen wellbore, for which results are presented. Visualizations for true lithology alongside the estimates are given, along with confusion matrices and model accuracy. The system achieves high accuracy on the test set and presents low confusion between classes, meaning that it distinguishes well between the lithologies present in the wellbore. It can be seen that the borders between successive layers of lithology are detected rapidly, which is crucial seen from an optimization standpoint, so the driller may immediately adjust accordingly. It shows promise as an advisory system, capable of accurately classifying currently drilled lithology by continuously adapting to changing downhole conditions. Although we cannot expect perfect estimates of lithology purely based on drilling parameters, we can obtain a preliminary map of the subsurface this way. This novel configuration gives a real-time interpretation of the currently drilled lithology. Thus, the drilling operation can be improved through early information and prompt drilling parameter adjustments to accommodate the current drilling environment.
{"title":"Classification of Drilled Lithology in Real-Time Using Deep Learning with Online Calibration","authors":"M. Arnø, John-Morten Godhavn, O. Aamo","doi":"10.2118/204093-pa","DOIUrl":"https://doi.org/10.2118/204093-pa","url":null,"abstract":"\u0000 Decision making to optimize the drilling operation is based on a variety of factors, among them real-time interpretation of drilled lithology. Because logging while drilling (LWD) tools are placed some meters above the bit, mechanical drilling parameters are the earliest indicators, although they are difficult to interpret accurately. This paper presents a novel deep learning methodology using mechanical drilling parameters for lithology classification. A cascade of deep neural networks (DNNs) are trained on historical data from wells on a field operated by Equinor. Rather than an end-to-end approach, the drilling parameters are used to estimate LWD sensor readings in an intermediate step using the first DNNs. This allows continuous updates of the models during operation using delayed LWD data. The second DNN takes the virtual LWD estimates as input to predict currently drilled lithology, similar to manual expert interpretation of logs. This configuration takes into account case-dependent [mud, bottomhole assembly (BHA), wellbore geometry] and time-varying (bit wear, wellbore friction) relationships between drilling parameters and LWD readings while assuming a constant rule when using LWD data to classify lithology. Upon completion of training and validation, the system is tested on a separate, unseen wellbore, for which results are presented. Visualizations for true lithology alongside the estimates are given, along with confusion matrices and model accuracy. The system achieves high accuracy on the test set and presents low confusion between classes, meaning that it distinguishes well between the lithologies present in the wellbore. It can be seen that the borders between successive layers of lithology are detected rapidly, which is crucial seen from an optimization standpoint, so the driller may immediately adjust accordingly. It shows promise as an advisory system, capable of accurately classifying currently drilled lithology by continuously adapting to changing downhole conditions. Although we cannot expect perfect estimates of lithology purely based on drilling parameters, we can obtain a preliminary map of the subsurface this way. This novel configuration gives a real-time interpretation of the currently drilled lithology. Thus, the drilling operation can be improved through early information and prompt drilling parameter adjustments to accommodate the current drilling environment.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48823596","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In certain drilling scenarios, the mud weight required to completely prevent wellbore enlargement can be impractically high. In such cases, what is known as risk-controlled wellbore stability criterion is introduced. This criterion allows for a certain and manageable level of wellbore enlargements to take place. Conventionally, the allowable level of wellbore enlargements in this type of model has always been based on the magnitude of the breakout angle. However, wellbore enlargements, as seen in caliper and image logs, can be highly irregular in terms of their distribution around the wellbore. This means that risk controlling wellbore stability through the breakout angle parameter can be insufficient. Instead, the total volume of cavings is introduced as the risk-control parameter. Unlike the breakout angle, the total volume of cavings can be coupled with a suitable hydraulics model to determine the threshold of manageable enlargement. The volume of cavings is determined using a machine-learning (ML)-assisted 3D elastoplastic finite-element model (FEM). The model implementation is first validated through experimental data. Next, a full data set from offset wells is used to populate and train the model. The trained model is then used to produce estimations of risk-controlled stability mud weights for different drilling scenarios. The model results are compared against those produced by conventional methods. Finally, both the FEM-ML model and the conventional method's results are compared against the drilling experience of the offset wells. The results illustrate how this methodology provides a more comprehensive and new solution to risk controlling wellbore stability.
{"title":"Risk-Controlled Wellbore Stability Criterion Based on a Machine-Learning-Assisted Finite-Element Model","authors":"H. Albahrani, Nobuo Morita","doi":"10.2118/204101-pa","DOIUrl":"https://doi.org/10.2118/204101-pa","url":null,"abstract":"\u0000 In certain drilling scenarios, the mud weight required to completely prevent wellbore enlargement can be impractically high. In such cases, what is known as risk-controlled wellbore stability criterion is introduced. This criterion allows for a certain and manageable level of wellbore enlargements to take place. Conventionally, the allowable level of wellbore enlargements in this type of model has always been based on the magnitude of the breakout angle. However, wellbore enlargements, as seen in caliper and image logs, can be highly irregular in terms of their distribution around the wellbore. This means that risk controlling wellbore stability through the breakout angle parameter can be insufficient. Instead, the total volume of cavings is introduced as the risk-control parameter. Unlike the breakout angle, the total volume of cavings can be coupled with a suitable hydraulics model to determine the threshold of manageable enlargement. The volume of cavings is determined using a machine-learning (ML)-assisted 3D elastoplastic finite-element model (FEM). The model implementation is first validated through experimental data. Next, a full data set from offset wells is used to populate and train the model. The trained model is then used to produce estimations of risk-controlled stability mud weights for different drilling scenarios. The model results are compared against those produced by conventional methods. Finally, both the FEM-ML model and the conventional method's results are compared against the drilling experience of the offset wells. The results illustrate how this methodology provides a more comprehensive and new solution to risk controlling wellbore stability.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42725700","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Steven Johannesen, T. Lagarigue, Gordon Shearer, K. Owen, Grant Wood, W. Hendry
A review of the use of measurement while drilling (MWD), logging while drilling (LWD), and directional drilling (DD) tools mobilized to offshore drilling units in the North Sea highlighted an opportunity to lower operational cost for the operator and reduce capital used for the oilfield services company. An objective was set to develop a risk-based probability model that would assess the positive and negative financial impacts of reducing, or perhaps entirely removing, backup tools in this historically risk-averse basin. The scope of the initial analysis was a drilling campaign on a single rig contracted by the operator (Rig A). This analysis was then extended to review scenarios in which several operations in close proximity would share backup tools. The last 3 years of MWD/LWD/DD tool reliability data from North Sea operations, recorded by the oilfield services company, were used as an input. To assess the probability of failure, a binomial model was developed to create a binomial distribution for each tool to calculate the probability of having zero to X failures for a selected tool or bottomhole assembly (BHA) for a given number of runs. Three binomial models were developed to study the effect of “easy,” “moderate,” and “challenging” drilling environments on tool reliability. A financial risk model was designed to balance the probability-weighted cost of failure for the operator against the lower costs resulting from reduced tool provision by the oilfield services company. To better estimate risks and financial impacts on the project, a sensitivity analysis was performed on the financial risk model using the three binomial models. As a result of the analysis, it was demonstrated that recent improvements in tool reliability support a reduction in the provision of backup MWD/LWD/DD drilling tools for the majority of North Sea drilling scenarios.
{"title":"Reduction in Backup Tool Requirements: Risks vs. Benefits, a Probability Analysis","authors":"Steven Johannesen, T. Lagarigue, Gordon Shearer, K. Owen, Grant Wood, W. Hendry","doi":"10.2118/204021-pa","DOIUrl":"https://doi.org/10.2118/204021-pa","url":null,"abstract":"\u0000 A review of the use of measurement while drilling (MWD), logging while drilling (LWD), and directional drilling (DD) tools mobilized to offshore drilling units in the North Sea highlighted an opportunity to lower operational cost for the operator and reduce capital used for the oilfield services company. An objective was set to develop a risk-based probability model that would assess the positive and negative financial impacts of reducing, or perhaps entirely removing, backup tools in this historically risk-averse basin. The scope of the initial analysis was a drilling campaign on a single rig contracted by the operator (Rig A). This analysis was then extended to review scenarios in which several operations in close proximity would share backup tools.\u0000 The last 3 years of MWD/LWD/DD tool reliability data from North Sea operations, recorded by the oilfield services company, were used as an input. To assess the probability of failure, a binomial model was developed to create a binomial distribution for each tool to calculate the probability of having zero to X failures for a selected tool or bottomhole assembly (BHA) for a given number of runs. Three binomial models were developed to study the effect of “easy,” “moderate,” and “challenging” drilling environments on tool reliability. A financial risk model was designed to balance the probability-weighted cost of failure for the operator against the lower costs resulting from reduced tool provision by the oilfield services company. To better estimate risks and financial impacts on the project, a sensitivity analysis was performed on the financial risk model using the three binomial models.\u0000 As a result of the analysis, it was demonstrated that recent improvements in tool reliability support a reduction in the provision of backup MWD/LWD/DD drilling tools for the majority of North Sea drilling scenarios.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44009299","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Improved numerical efficiency in simulating wellbore gas-influx behaviors is essential for realizing real-time model-prediction-based gas-influx management in wells equipped with managed-pressure-drilling (MPD) systems. Currently, most solution algorithms for high-fidelitymultiphase-flow models are highly time consuming and are not suitable for real-time decision making and control. In the application of model-predictive controllers (MPCs), long calculation time can lead to large overshoots and low control efficiency. This paper presents a drift-flux-model (DFM)-based gas-influx simulator with a novel numerical scheme for improved computational efficiency. The solution algorithm to a Robertson problem as differential algebraic equations (DAEs) was used as the numerical scheme to solve the control equations of the DFM in this study. The numerical stability and computational efficiency of this numerical scheme and the widely used flux-splitting methods are compared and analyzed. Results show that the Robertson DAE problem approach significantly reduces the total number of arithmetic operations and the computational time compared with the hybrid advection-upstream-splitting method (AUSMV) while maintaining the same prediction accuracy. According to the “Big-O notation” analysis, the Robertson DAE approach shows a lower-order growth of computational complexity, proving its good potential in enhancing numerical efficiency, especially when handling simulations with larger scales. The validation of both the numerical schemes for the solution of the DFM was performed using measured data from a test well drilled with water-based mud (WBM). This study offers a novel numerical solution to the DFM that can significantly reduce the computational time required for gas-kick simulation while maintaining high prediction accuracy. This approach enables the application of high-fidelity two-phase-flow models in model-prediction-based decision making and automated influx management with MPD systems.
{"title":"On Improving Algorithm Efficiency of Gas-Kick Simulations toward Automated Influx Management: A Robertson Differential-Algebraic-Equation Problem Approach","authors":"Chen Wei, Yuanhang Chen","doi":"10.2118/206747-pa","DOIUrl":"https://doi.org/10.2118/206747-pa","url":null,"abstract":"\u0000 Improved numerical efficiency in simulating wellbore gas-influx behaviors is essential for realizing real-time model-prediction-based gas-influx management in wells equipped with managed-pressure-drilling (MPD) systems. Currently, most solution algorithms for high-fidelitymultiphase-flow models are highly time consuming and are not suitable for real-time decision making and control. In the application of model-predictive controllers (MPCs), long calculation time can lead to large overshoots and low control efficiency.\u0000 This paper presents a drift-flux-model (DFM)-based gas-influx simulator with a novel numerical scheme for improved computational efficiency. The solution algorithm to a Robertson problem as differential algebraic equations (DAEs) was used as the numerical scheme to solve the control equations of the DFM in this study. The numerical stability and computational efficiency of this numerical scheme and the widely used flux-splitting methods are compared and analyzed. Results show that the Robertson DAE problem approach significantly reduces the total number of arithmetic operations and the computational time compared with the hybrid advection-upstream-splitting method (AUSMV) while maintaining the same prediction accuracy. According to the “Big-O notation” analysis, the Robertson DAE approach shows a lower-order growth of computational complexity, proving its good potential in enhancing numerical efficiency, especially when handling simulations with larger scales. The validation of both the numerical schemes for the solution of the DFM was performed using measured data from a test well drilled with water-based mud (WBM).\u0000 This study offers a novel numerical solution to the DFM that can significantly reduce the computational time required for gas-kick simulation while maintaining high prediction accuracy. This approach enables the application of high-fidelity two-phase-flow models in model-prediction-based decision making and automated influx management with MPD systems.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47929428","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Santos, W. Williams, Jyotsna Sharma, M. Almeida, Mahendra Kunju, Charles E. Taylor
A potential application of optical fiber technologies in the well control domain is to detect the presence of gas and to unfold the gas dynamics inside marine risers (gas-in-riser). Detecting and monitoring gas-in-riser has become more relevant now when considering the application of managed pressure drilling operations in deep and ultradeep waters that may allow for a controlled amount of gas inside the riser. This application of distributed fiber-optic sensing (DFOS) is currently being evaluated at Louisiana State University (LSU) as part of a gas-in-riser research project granted by the National Academies of Sciences, the Gulf Research Program (GRP). Thus, the main objective of this paper is to present and discuss the use of DFOS and downhole pressure sensors to detect and track the gas position inside a full-scale test well during experimental runs conducted at LSU. The other objectives of this work are to show experimental findings of gas migration in the closed test well and to present the adequacy of a mathematical model experimentally validated to match the data obtained in the experimental trials. As a part of this research effort, an existing test well at the LSU Petroleum Engineering Research and Technology Transfer Laboratory (PERTT Lab) was recompleted and instrumented with fiber-optic sensors to continuously collect data along the wellbore and with four pressure and temperature downhole gauges to record those parameters at four discrete depths. A 2⅞-in. tubing string, with its lower end at a depth of 5,026 ft, and a chemical line to inject nitrogen at the bottom of the hole were also installed in the well. Seven experimental runs were performed in this full-scale apparatus using fresh water and nitrogen to calibrate the installed pieces of equipment, to train the crew of researchers to run the tests, to check experimental repeatability, and to obtain experimental results under very controlled conditions because water and nitrogen have well-defined and constant properties. In five runs, the injected gas was circulated out of the well, whereas in two others, the gas was left inside the closed test well to migrate without circulation. This paper presents and discusses the results of four selected runs. The experimental runs showed that fiber-optic information can be used to detect and track the gas position and consequently its velocity inside the marine riser. The fiber-optic data presented a very good agreement with those measured by the four downhole pressure gauges, particularly the gas velocity. The gas migration experiments produced very interesting results. With respect to the mathematical model based on the unsteady-state flow of a two-phase mixture, the simulated results produced a remarkable agreement with the fiber-optic, surface acquisition system and the downhole pressure sensors data gathered from the experimental runs.
{"title":"Use of Fiber-Optic Information To Detect and Investigate the Gas-in-Riser Phenomenon","authors":"O. Santos, W. Williams, Jyotsna Sharma, M. Almeida, Mahendra Kunju, Charles E. Taylor","doi":"10.2118/204115-pa","DOIUrl":"https://doi.org/10.2118/204115-pa","url":null,"abstract":"\u0000 A potential application of optical fiber technologies in the well control domain is to detect the presence of gas and to unfold the gas dynamics inside marine risers (gas-in-riser). Detecting and monitoring gas-in-riser has become more relevant now when considering the application of managed pressure drilling operations in deep and ultradeep waters that may allow for a controlled amount of gas inside the riser. This application of distributed fiber-optic sensing (DFOS) is currently being evaluated at Louisiana State University (LSU) as part of a gas-in-riser research project granted by the National Academies of Sciences, the Gulf Research Program (GRP).\u0000 Thus, the main objective of this paper is to present and discuss the use of DFOS and downhole pressure sensors to detect and track the gas position inside a full-scale test well during experimental runs conducted at LSU. The other objectives of this work are to show experimental findings of gas migration in the closed test well and to present the adequacy of a mathematical model experimentally validated to match the data obtained in the experimental trials.\u0000 As a part of this research effort, an existing test well at the LSU Petroleum Engineering Research and Technology Transfer Laboratory (PERTT Lab) was recompleted and instrumented with fiber-optic sensors to continuously collect data along the wellbore and with four pressure and temperature downhole gauges to record those parameters at four discrete depths. A 2⅞-in. tubing string, with its lower end at a depth of 5,026 ft, and a chemical line to inject nitrogen at the bottom of the hole were also installed in the well.\u0000 Seven experimental runs were performed in this full-scale apparatus using fresh water and nitrogen to calibrate the installed pieces of equipment, to train the crew of researchers to run the tests, to check experimental repeatability, and to obtain experimental results under very controlled conditions because water and nitrogen have well-defined and constant properties. In five runs, the injected gas was circulated out of the well, whereas in two others, the gas was left inside the closed test well to migrate without circulation. This paper presents and discusses the results of four selected runs.\u0000 The experimental runs showed that fiber-optic information can be used to detect and track the gas position and consequently its velocity inside the marine riser. The fiber-optic data presented a very good agreement with those measured by the four downhole pressure gauges, particularly the gas velocity. The gas migration experiments produced very interesting results. With respect to the mathematical model based on the unsteady-state flow of a two-phase mixture, the simulated results produced a remarkable agreement with the fiber-optic, surface acquisition system and the downhole pressure sensors data gathered from the experimental runs.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43980900","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Du, Ke Li, F. Song, Haoming Li, David L. Smith, W. Blackman
Advanced drill-collar connections have been developed with 10 times extended fatigue life compared with the corresponding replaced connections. More than 4,000 advanced connections have been run in North America. Although these connections have demonstrated substantial fatigue-strength improvement in operation, some failures have occurred. Multiple failed connection samples have been retrieved and analyzed for their failure modes and the root causes. In the failure analyses, manufacturing data were reviewed to identify any possible discrepancies between design specifications and manufactured components. The field run data were analyzed for the loading histories of the connections. The downhole fluid properties were also reviewed to identify their possible effects on the connection performances. The bottomhole assemblies (BHAs) were numerically analyzed to determine the loading distributions. The failed connection samples were physically processed and inspected in a metallurgical laboratory. Based on the combined numerical and testing analyses, the conclusions on the failure modes and the root causes were drawn. It was found that the primary failure mode for these connections was fatigue. The root causes for the fatigue failures can be divided into two categories: manufacturing causes and operational causes. Among the manufacturing failure causes, incorrect cold rolling is the primary one. The operation-related failures were mainly caused by overloading. Through failure mode and root-cause analyses, the manufacturing and operational related risks for the advanced drill-collar connections were mitigated accordingly. It therefore greatly improved the quality assurance of the advanced connections.
{"title":"Failure Modes and Root-Cause Analyses of Advanced Drill-Collar Connections","authors":"M. Du, Ke Li, F. Song, Haoming Li, David L. Smith, W. Blackman","doi":"10.2118/204048-pa","DOIUrl":"https://doi.org/10.2118/204048-pa","url":null,"abstract":"\u0000 Advanced drill-collar connections have been developed with 10 times extended fatigue life compared with the corresponding replaced connections. More than 4,000 advanced connections have been run in North America. Although these connections have demonstrated substantial fatigue-strength improvement in operation, some failures have occurred. Multiple failed connection samples have been retrieved and analyzed for their failure modes and the root causes.\u0000 In the failure analyses, manufacturing data were reviewed to identify any possible discrepancies between design specifications and manufactured components. The field run data were analyzed for the loading histories of the connections. The downhole fluid properties were also reviewed to identify their possible effects on the connection performances. The bottomhole assemblies (BHAs) were numerically analyzed to determine the loading distributions. The failed connection samples were physically processed and inspected in a metallurgical laboratory. Based on the combined numerical and testing analyses, the conclusions on the failure modes and the root causes were drawn.\u0000 It was found that the primary failure mode for these connections was fatigue. The root causes for the fatigue failures can be divided into two categories: manufacturing causes and operational causes. Among the manufacturing failure causes, incorrect cold rolling is the primary one. The operation-related failures were mainly caused by overloading.\u0000 Through failure mode and root-cause analyses, the manufacturing and operational related risks for the advanced drill-collar connections were mitigated accordingly. It therefore greatly improved the quality assurance of the advanced connections.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42061317","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Amit Govil, Harald Nevøy, L. Hovda, G. O. Obando Palacio, Geir Kjeldaas
As part of plug and abandonment (P&A) operations, several acceptance criteria need to be considered by operators to qualify barrier elements. In casing annuli, highly bonded material is occasionally found far above the theoretical top of cement. This paper aims to describe how the highly bonded material can be identified using a combination of ultrasonic logging data, validated with measurements in laboratory experiments using reference cells and how this, in combination with data from the well construction records, can contribute to lowering the costly toll of P&A operations. Ultrasonic and sonic log data were acquired in several wells to assess the bond quality behind multiple casing sizes in an abandonment campaign. Data obtained from pulse-echo and flexural sensors were interactively analyzed with a crossplotting technique to distinguish gas, liquid, barite, cement, and formation in the annular space. Within the methodology used, historical data on each well were considered as an integral part of the analysis. During the original well construction, either water-based mud (WBM) or synthetic oil-based mud (OBM) was used for drilling and cementing operations, and some formation intervals consistently showed high bonding signatures under specific conditions, giving clear evidence of formation creep. Log data from multiple wells confirm that formation behavior is influenced by the type of mud used during well construction. The log data provided information of annulus material with a detailed map of the axial and azimuthal variations of the annulus contents. In some cases, log response showed a clear indication of formation creep, evidenced by a high bond quality around the production casing where cement cannot be present. Based on observations from multiple fields in the Norwegian continental shelf, a crossplot workflow has been designed to distinguish formation from cement as the potential barrier element. NORSOK Standard D-010 (2013) has initial verification acceptance criteria both for annulus cement and creeping formation as a well barrier element, both involving bond logs; however, in the case of creeping formation, it is more stringent stating that “two independent logging measurements/tools shall be applied.” This paper aims to demonstrate how this can be done with confidence using ultrasonic and sonic log data, validated against reference barrier cells (Govil et al. 2020). Logging responses like those gathered during full-scale experiments of reference barrier cells with known defects were observed in multiple wells in the field. Understanding the phenomenon of formation creep and its associated casing bond signature could have a massive impact on P&A operations. With a successful qualification of formation as an annulus barrier, significant cost and time savings can be achieved.
{"title":"Identifying Formation Creep: Ultrasonic Bond Logging Field Examples","authors":"Amit Govil, Harald Nevøy, L. Hovda, G. O. Obando Palacio, Geir Kjeldaas","doi":"10.2118/204040-pa","DOIUrl":"https://doi.org/10.2118/204040-pa","url":null,"abstract":"\u0000 As part of plug and abandonment (P&A) operations, several acceptance criteria need to be considered by operators to qualify barrier elements. In casing annuli, highly bonded material is occasionally found far above the theoretical top of cement. This paper aims to describe how the highly bonded material can be identified using a combination of ultrasonic logging data, validated with measurements in laboratory experiments using reference cells and how this, in combination with data from the well construction records, can contribute to lowering the costly toll of P&A operations.\u0000 Ultrasonic and sonic log data were acquired in several wells to assess the bond quality behind multiple casing sizes in an abandonment campaign. Data obtained from pulse-echo and flexural sensors were interactively analyzed with a crossplotting technique to distinguish gas, liquid, barite, cement, and formation in the annular space. Within the methodology used, historical data on each well were considered as an integral part of the analysis. During the original well construction, either water-based mud (WBM) or synthetic oil-based mud (OBM) was used for drilling and cementing operations, and some formation intervals consistently showed high bonding signatures under specific conditions, giving clear evidence of formation creep. Log data from multiple wells confirm that formation behavior is influenced by the type of mud used during well construction.\u0000 The log data provided information of annulus material with a detailed map of the axial and azimuthal variations of the annulus contents. In some cases, log response showed a clear indication of formation creep, evidenced by a high bond quality around the production casing where cement cannot be present. Based on observations from multiple fields in the Norwegian continental shelf, a crossplot workflow has been designed to distinguish formation from cement as the potential barrier element. NORSOK Standard D-010 (2013) has initial verification acceptance criteria both for annulus cement and creeping formation as a well barrier element, both involving bond logs; however, in the case of creeping formation, it is more stringent stating that “two independent logging measurements/tools shall be applied.” This paper aims to demonstrate how this can be done with confidence using ultrasonic and sonic log data, validated against reference barrier cells (Govil et al. 2020).\u0000 Logging responses like those gathered during full-scale experiments of reference barrier cells with known defects were observed in multiple wells in the field. Understanding the phenomenon of formation creep and its associated casing bond signature could have a massive impact on P&A operations. With a successful qualification of formation as an annulus barrier, significant cost and time savings can be achieved.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47794295","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sun Xiao-feng, Qiaoying Hu, Jingyu Qu, Wei Li, N. Mao, Guoshuai Ju
The cleanliness of wellbore is a key factor in the drilling speed and quality of an oil field, especially in long horizontal sections of horizontal wells. Therefore, a hydraulic-magnetic rotary hole cleaning tool has been designed that does not rely on the rotary action of the drillpipe and could be used with a downhole motor to improve hole cleaning efficiency. However, the influence of magnet shape on the transmission of magnetic torque has remained unclear, such that the magnetic shaft transmission torque needed to be optimized to ensure efficient tool operation. In this study, magnetic field control equations were established in the region of the permanent magnet and air gap, and the magnetic flux distribution and magnetic torque generated between two magnetic axes in each field were calculated. Also, the influence of various magnetic field parameters on magnetic torque conduction of a strip magnet were compared and analyzed and then confirmed by comparison with experimental results. The results showed that the magnetic torque transmitted by strip magnets varied sinusoidally with magnetic axis deviation angles and that the highest torque was generated in the 12-pole model. However, the rate of increase in magnetic torque with magnet thickness was opposite to that of tile magnets, increasing with increasing magnet thickness. Magnetic torque variation with covered area was specific in the 6-pole model, showing a tendency of increasing and then decreasing. When magnet thickness was 12 mm and magnet coverage area in the effective cross section of the tool was 80%, the highest magnetic torque/unit volume of magnet was generated for achieving economic optimization. The results led to conclusions that, by solving the regional magnetic field, the magnetic torque change characteristics during movement of the magnetic drive mechanism of the hydraulic-magnetic rotary hole cleaning tool were simulated successfully and that these results could be used as an optimization analysis method for the magnetic drive mechanism of such tools.
{"title":"Optimal Design of Magnetic Torque for a Hydraulic-Magnetic Rotary Hole Cleaning Tool in Horizontal Drilling","authors":"Sun Xiao-feng, Qiaoying Hu, Jingyu Qu, Wei Li, N. Mao, Guoshuai Ju","doi":"10.2118/206752-pa","DOIUrl":"https://doi.org/10.2118/206752-pa","url":null,"abstract":"\u0000 The cleanliness of wellbore is a key factor in the drilling speed and quality of an oil field, especially in long horizontal sections of horizontal wells. Therefore, a hydraulic-magnetic rotary hole cleaning tool has been designed that does not rely on the rotary action of the drillpipe and could be used with a downhole motor to improve hole cleaning efficiency. However, the influence of magnet shape on the transmission of magnetic torque has remained unclear, such that the magnetic shaft transmission torque needed to be optimized to ensure efficient tool operation. In this study, magnetic field control equations were established in the region of the permanent magnet and air gap, and the magnetic flux distribution and magnetic torque generated between two magnetic axes in each field were calculated. Also, the influence of various magnetic field parameters on magnetic torque conduction of a strip magnet were compared and analyzed and then confirmed by comparison with experimental results. The results showed that the magnetic torque transmitted by strip magnets varied sinusoidally with magnetic axis deviation angles and that the highest torque was generated in the 12-pole model. However, the rate of increase in magnetic torque with magnet thickness was opposite to that of tile magnets, increasing with increasing magnet thickness. Magnetic torque variation with covered area was specific in the 6-pole model, showing a tendency of increasing and then decreasing. When magnet thickness was 12 mm and magnet coverage area in the effective cross section of the tool was 80%, the highest magnetic torque/unit volume of magnet was generated for achieving economic optimization. The results led to conclusions that, by solving the regional magnetic field, the magnetic torque change characteristics during movement of the magnetic drive mechanism of the hydraulic-magnetic rotary hole cleaning tool were simulated successfully and that these results could be used as an optimization analysis method for the magnetic drive mechanism of such tools.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49226963","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. J. Skadsem, D. Gardner, Katherine Beltrán Jiménez, Amit Govil, G. O. Palacio, Laurent Delabroy
Important functions of well cement are to provide zonal isolation behind casing strings and to mechanically support and protect the casing. Experience suggests that many wells develop integrity problems related to fluid migration or loss of zonal isolation, which often manifest themselves in sustained casing pressure (SCP) or surface casing vent flows. Because the characteristic sizes of realistic migration paths are typically only on the order of tens of micrometers, detecting, diagnosing, and eventually treating migration paths remain challenging problems for the industry. As part of the recent abandonment operation of an offshore production well, sandwich joints comprising production casing, annulus cement, and intermediate casing were cut and retrieved to surface. Two of these joints were subjected to an extensive test campaign, including surface relogging, chemical analyses, and seepage testing, to better understand the ultrasonic-log response and its potential connection to rates of fluid migration. One of the joints contained an apparently well-defined top of cement (TOC) with settled barite on top. Although the settled material initially provided a complete seal against gas flow, the sealing capability was irreversibly lost as part of subsequent testing. The two joints have effective microannuli sizes in the range of tens of micrometers, in agreement with previous reports on SCP buildup in wells. On a local scale, however, we observed significant variations in cement quality from both the log results and the seepage testing. Further, we found qualitatively very good correlations between seepage-test results and the log results for the bond between cement and casings. The best bonded cement was found directly above a production casing collar, where a short segment of well-bonded cement prevented measurable steady-state seepage of nitrogen. Additional tests involving internal pressurization of the production casing suggested that certain annular-seepage characteristics are well-described by an effective microannulus at the cement/casing interfaces. We consider the two sandwich joints to be highly representative and relevant for similar mature wells that are to be abandoned.
{"title":"Study of Ultrasonic Logs and Seepage Potential on Sandwich Sections Retrieved from a North Sea Production Well","authors":"H. J. Skadsem, D. Gardner, Katherine Beltrán Jiménez, Amit Govil, G. O. Palacio, Laurent Delabroy","doi":"10.2118/206727-pa","DOIUrl":"https://doi.org/10.2118/206727-pa","url":null,"abstract":"\u0000 Important functions of well cement are to provide zonal isolation behind casing strings and to mechanically support and protect the casing. Experience suggests that many wells develop integrity problems related to fluid migration or loss of zonal isolation, which often manifest themselves in sustained casing pressure (SCP) or surface casing vent flows. Because the characteristic sizes of realistic migration paths are typically only on the order of tens of micrometers, detecting, diagnosing, and eventually treating migration paths remain challenging problems for the industry. As part of the recent abandonment operation of an offshore production well, sandwich joints comprising production casing, annulus cement, and intermediate casing were cut and retrieved to surface. Two of these joints were subjected to an extensive test campaign, including surface relogging, chemical analyses, and seepage testing, to better understand the ultrasonic-log response and its potential connection to rates of fluid migration. One of the joints contained an apparently well-defined top of cement (TOC) with settled barite on top. Although the settled material initially provided a complete seal against gas flow, the sealing capability was irreversibly lost as part of subsequent testing. The two joints have effective microannuli sizes in the range of tens of micrometers, in agreement with previous reports on SCP buildup in wells. On a local scale, however, we observed significant variations in cement quality from both the log results and the seepage testing. Further, we found qualitatively very good correlations between seepage-test results and the log results for the bond between cement and casings. The best bonded cement was found directly above a production casing collar, where a short segment of well-bonded cement prevented measurable steady-state seepage of nitrogen. Additional tests involving internal pressurization of the production casing suggested that certain annular-seepage characteristics are well-described by an effective microannulus at the cement/casing interfaces. We consider the two sandwich joints to be highly representative and relevant for similar mature wells that are to be abandoned.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47464709","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Antoni Miszewski, Adam Miszewski, R. Stevens, M. Gemignani
A set of five wells were to be drilled with directional coiled tubing drilling (CTD) on the North Slope of Alaska. The particular challenges of these wells were the fact that the desired laterals were targeted to be at least 6,000 ft long, at a shallow depth, almost twice the length of laterals that are regularly drilled at deeper depths. The shallow depth meant that two of the five wells involved a casing exit through three casings, which had never been attempted before. After drilling, the wells were completed with a slotted liner, run on coiled tubing (CT). This required a very smooth and straight wellbore so that the liner could be run as far as the lateral had been drilled. In this paper, we focus on one of the two wells on which triple casing exit was performed. However, the same considerations and results apply to the other wells on which the same technology has been used. Various methods were considered to increase lateral reach, including running an extended reach tool, using a friction reducer, increasing the CT size, and using a drilling bottomhole assembly (BHA) that could drill a very straight well path. All of these options were modeled with tubing forces software, and their relative effectiveness was evaluated. The drilling field results easily exceeded the minimum requirements for success. This project demonstrated record-breaking lateral lengths, a record length of liner run on CT in a single run, and a triple casing exit. The data gained from this project can be used to fine-tune the modeling for future work of a similar nature.
{"title":"Extended Reach Drilling with Coiled Tubing: A Case Study on the Alaskan North Slope That Proves the Benefits of Drilling a Straight Hole","authors":"Antoni Miszewski, Adam Miszewski, R. Stevens, M. Gemignani","doi":"10.2118/204418-pa","DOIUrl":"https://doi.org/10.2118/204418-pa","url":null,"abstract":"\u0000 A set of five wells were to be drilled with directional coiled tubing drilling (CTD) on the North Slope of Alaska. The particular challenges of these wells were the fact that the desired laterals were targeted to be at least 6,000 ft long, at a shallow depth, almost twice the length of laterals that are regularly drilled at deeper depths. The shallow depth meant that two of the five wells involved a casing exit through three casings, which had never been attempted before. After drilling, the wells were completed with a slotted liner, run on coiled tubing (CT). This required a very smooth and straight wellbore so that the liner could be run as far as the lateral had been drilled. In this paper, we focus on one of the two wells on which triple casing exit was performed. However, the same considerations and results apply to the other wells on which the same technology has been used.\u0000 Various methods were considered to increase lateral reach, including running an extended reach tool, using a friction reducer, increasing the CT size, and using a drilling bottomhole assembly (BHA) that could drill a very straight well path. All of these options were modeled with tubing forces software, and their relative effectiveness was evaluated.\u0000 The drilling field results easily exceeded the minimum requirements for success. This project demonstrated record-breaking lateral lengths, a record length of liner run on CT in a single run, and a triple casing exit. The data gained from this project can be used to fine-tune the modeling for future work of a similar nature.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46032077","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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