Rahul Raman, Benjamin J. Spivey, Richard Fink, Stephen Karner
While-drilling pore pressure surveillance enables timely responses to unexpected drilling events, e.g., wellbore instability, or to pressure changes that could impact mud weight requirements or casing depths. The real-time pressure surveillance and analytics (RT-PSA) system described herein aids while-drilling pressure surveillance by highlighting possible pressure trends and detecting pumps-off gas automatically. The system further assists pressure surveillance practitioners by automatically filtering for lithology and providing a visualization dashboard to highlight possible pressure trends. The pressure trending application calculates slopes/trends for LWD and mechanical data and uses these trends to indicate possible pressure trends along the well path using a heat map. A lithology filtering method has been developed using machine learning (ML) clustering algorithms to remove non-shale data, leaving only clay-rich shale lithology for pressure trending. The gas monitoring application aligns the gas curves back to the time and depth at which gas is liberated from the formation by the drill bit, called herein as at-the-bit curves. The application displays modified total gas, gas exponent, and gas ratio curves as at-the-bit curves. The gamma ray and resistivity LWD logs are also shifted back to the time/depth that the bit drilled the measured formations. Aligning the gas and formation log curves to be at-the-bit provides the pressure surveillance personnel with additional context beyond traditional gas surveillance data to classify gas measured at the surface as pumps-off-gas or formation gas. Results demonstrate that the lithology filtering method using machine learning is effective to filter out clay-rich shale. The pressure trending results are consistent with post-drill pore pressure evaluations generated by pressure prediction experts. The shifted total gas and pumps-off gas have been validated versus post-drill pressure analysis. The system is being deployed to mitigate well control events by improving and standardizing pressure surveillance best-practices across a global organization.
{"title":"While-Drilling Pore Pressure Surveillance Using Machine Learning","authors":"Rahul Raman, Benjamin J. Spivey, Richard Fink, Stephen Karner","doi":"10.2118/212502-ms","DOIUrl":"https://doi.org/10.2118/212502-ms","url":null,"abstract":"\u0000 While-drilling pore pressure surveillance enables timely responses to unexpected drilling events, e.g., wellbore instability, or to pressure changes that could impact mud weight requirements or casing depths. The real-time pressure surveillance and analytics (RT-PSA) system described herein aids while-drilling pressure surveillance by highlighting possible pressure trends and detecting pumps-off gas automatically. The system further assists pressure surveillance practitioners by automatically filtering for lithology and providing a visualization dashboard to highlight possible pressure trends.\u0000 The pressure trending application calculates slopes/trends for LWD and mechanical data and uses these trends to indicate possible pressure trends along the well path using a heat map. A lithology filtering method has been developed using machine learning (ML) clustering algorithms to remove non-shale data, leaving only clay-rich shale lithology for pressure trending.\u0000 The gas monitoring application aligns the gas curves back to the time and depth at which gas is liberated from the formation by the drill bit, called herein as at-the-bit curves. The application displays modified total gas, gas exponent, and gas ratio curves as at-the-bit curves. The gamma ray and resistivity LWD logs are also shifted back to the time/depth that the bit drilled the measured formations. Aligning the gas and formation log curves to be at-the-bit provides the pressure surveillance personnel with additional context beyond traditional gas surveillance data to classify gas measured at the surface as pumps-off-gas or formation gas.\u0000 Results demonstrate that the lithology filtering method using machine learning is effective to filter out clay-rich shale. The pressure trending results are consistent with post-drill pore pressure evaluations generated by pressure prediction experts. The shifted total gas and pumps-off gas have been validated versus post-drill pressure analysis. The system is being deployed to mitigate well control events by improving and standardizing pressure surveillance best-practices across a global organization.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116489225","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. Khvostichenko, Greg Skoff, Y. Arevalo, S. Makarychev-Mikhailov
Ensuring a proper apple to apple comparison is a challenge in drilling performance evaluation. When assessing the effect of a particular drilling technology, such as bit, bottomhole assembly (BHA) or mud type, on the rate of penetration (ROP) or other drilling performance criteria, all other factors must be fixed to truly isolate the effect. Traditionally, performance evaluation starts with manual identification of reasonably similar entities, such as drilling runs or well sections by means of numerous selection criteria; e.g., location, depths, inclinations, drilling conditions, tools, etc. The selected drilling performance metrics are then compared using statistical analysis techniques with various extents of thoroughness. Such analyses are laborious and are usually limited to just a handful of cases due to practical reasons and time constraints. Furthermore, the analyses are difficult to apply to large data sets of hundreds or thousands of wells, and there is always a risk of missing an important combination of factors where the effect is important. Therefore, conclusions based on these analyses may well be insufficiently justified or even confirmation biased, leading to suboptimal technical and business decisions. This paper presents a combined machine learning and statistical analysis workflow addressing these challenges. The workflow a) discovers similar entities (wells, intervals, runs) in big datasets; b) extracts subsets of similar entities (i.e., "apples") for evaluation; c) applies rigorous statistical tests to quantify the effect (mud type, BHA type, bit type) on a metric (ROP, success rate) and its statistical significance; and, finally, d) returns information on areas, sets of conditions where the effect is pronounced (or not). In the statistical analysis workflow, the user first specifies the drilling technology of interest and drilling performance metrics, and then defines factors and parameters to be fixed to better isolate the effect of the drilling technology. The historical data on thousands of entities are then preprocessed, and the entities are clustered by similarities in the multitude of factors by the k-means algorithm. Statistical tests are performed automatically on each cluster, quantifying the magnitude of technology effect on performance criteria, and calculating p-values as the measure of statistical significance of the effect. The results are presented in a series of clustering observations that summarize the effects and allow for zooming into the clusters to review drilling parameters and to perform further in-depth analysis, if necessary. All steps of the workflow are presented in this paper, including data processing details, and reasons for selecting specific clustering algorithms and statistical tests. Several examples of the successful applications of the workflow to actual drilling data for thousands of wells are provided, focusing on the effects of BHA, steering tools, and drilling muds on drilling perf
{"title":"Apples to Apples: Impartial Assessment of Drilling Technologies through Big Data and Machine Learning","authors":"D. Khvostichenko, Greg Skoff, Y. Arevalo, S. Makarychev-Mikhailov","doi":"10.2118/212446-ms","DOIUrl":"https://doi.org/10.2118/212446-ms","url":null,"abstract":"\u0000 Ensuring a proper apple to apple comparison is a challenge in drilling performance evaluation. When assessing the effect of a particular drilling technology, such as bit, bottomhole assembly (BHA) or mud type, on the rate of penetration (ROP) or other drilling performance criteria, all other factors must be fixed to truly isolate the effect. Traditionally, performance evaluation starts with manual identification of reasonably similar entities, such as drilling runs or well sections by means of numerous selection criteria; e.g., location, depths, inclinations, drilling conditions, tools, etc. The selected drilling performance metrics are then compared using statistical analysis techniques with various extents of thoroughness. Such analyses are laborious and are usually limited to just a handful of cases due to practical reasons and time constraints. Furthermore, the analyses are difficult to apply to large data sets of hundreds or thousands of wells, and there is always a risk of missing an important combination of factors where the effect is important. Therefore, conclusions based on these analyses may well be insufficiently justified or even confirmation biased, leading to suboptimal technical and business decisions.\u0000 This paper presents a combined machine learning and statistical analysis workflow addressing these challenges. The workflow a) discovers similar entities (wells, intervals, runs) in big datasets; b) extracts subsets of similar entities (i.e., \"apples\") for evaluation; c) applies rigorous statistical tests to quantify the effect (mud type, BHA type, bit type) on a metric (ROP, success rate) and its statistical significance; and, finally, d) returns information on areas, sets of conditions where the effect is pronounced (or not). In the statistical analysis workflow, the user first specifies the drilling technology of interest and drilling performance metrics, and then defines factors and parameters to be fixed to better isolate the effect of the drilling technology. The historical data on thousands of entities are then preprocessed, and the entities are clustered by similarities in the multitude of factors by the k-means algorithm. Statistical tests are performed automatically on each cluster, quantifying the magnitude of technology effect on performance criteria, and calculating p-values as the measure of statistical significance of the effect. The results are presented in a series of clustering observations that summarize the effects and allow for zooming into the clusters to review drilling parameters and to perform further in-depth analysis, if necessary.\u0000 All steps of the workflow are presented in this paper, including data processing details, and reasons for selecting specific clustering algorithms and statistical tests. Several examples of the successful applications of the workflow to actual drilling data for thousands of wells are provided, focusing on the effects of BHA, steering tools, and drilling muds on drilling perf","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131015908","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. Khaled, Ningyu Wang, P. Ashok, Dongmei Chen, E. van Oort
High bottom hole temperature can lead to decreased downhole tool life in geothermal and high temperature / high pressure (HPHT) oil and gas wells. The temperature increase is exacerbated when circulation stops, e.g., during connection, tripping, well control situations, etc. While continuous circulation technology is an appropriate solution for managing temperature, it is not yet widely adopted in HPHT and geothermal drilling practices. This work investigates factors that impact downhole temperature and recommends strategies to better manage the temperature when continuous circulation is not available. An integrated thermo-hydraulic model was developed to capture the transient behavior of downhole temperature and was applied here to study the transient temperature profile when there is no fluid circulation. The model was validated using the open-source FORGE field dataset, with the mean absolute percentage error (MAPE) between 1-4%. In addition, hundreds of case scenarios were numerically studied to investigate the impact of several key factors on the downhole temperature. The evaluated factors include the pump-off time, type and physical properties of the drilling fluid, wellbore hydraulic diameter, reservoir temperature, geothermal gradient, total wellbore depth and profile, and operational parameters prior to stopping the circulation. The cooling effects of different drilling parameters were compared to a benchmark case of continuous circulation. A correlation map was generated to visualize the impact of those parameters on the downhole temperature distribution when circulation stops. A logarithmic relationship between the pump stop time and the downhole temperature was observed. For the FORGE case scenario, the downhole temperature increases by 27 °C and 48 °C after the pump stops for 30 and 60 minutes, respectively. It was observed that water-based mud with a high viscosity increases fluid convection heat resistance between the formation and wellbore. Also, drilling with a higher flow rate before stopping the pump can cool the near-wellbore formation faster and reduces the downhole temperature even after circulation ceases. Wells with high geothermal gradients, like FORGE wells, have higher temperature build-up during circulation stoppage than wells with low geothermal gradients targeting the same reservoir (formation) in-situ temperature. This study investigates the efficacy of different cooling strategies to avoid downhole temperature build-up when there is no circulation. It thereby facilitates the optimization of geothermal and HPHT well design and construction to prevent downhole tool failures. The developed correlation map can aid drilling engineers understand the impact of different drilling conditions on the downhole temperature.
{"title":"Strategies for Prevention of Downhole Tool Failure Caused by High Bottomhole Temperature in Geothermal and HPHT Oil and Gas Wells","authors":"M. Khaled, Ningyu Wang, P. Ashok, Dongmei Chen, E. van Oort","doi":"10.2118/212550-ms","DOIUrl":"https://doi.org/10.2118/212550-ms","url":null,"abstract":"\u0000 High bottom hole temperature can lead to decreased downhole tool life in geothermal and high temperature / high pressure (HPHT) oil and gas wells. The temperature increase is exacerbated when circulation stops, e.g., during connection, tripping, well control situations, etc. While continuous circulation technology is an appropriate solution for managing temperature, it is not yet widely adopted in HPHT and geothermal drilling practices. This work investigates factors that impact downhole temperature and recommends strategies to better manage the temperature when continuous circulation is not available.\u0000 An integrated thermo-hydraulic model was developed to capture the transient behavior of downhole temperature and was applied here to study the transient temperature profile when there is no fluid circulation. The model was validated using the open-source FORGE field dataset, with the mean absolute percentage error (MAPE) between 1-4%. In addition, hundreds of case scenarios were numerically studied to investigate the impact of several key factors on the downhole temperature.\u0000 The evaluated factors include the pump-off time, type and physical properties of the drilling fluid, wellbore hydraulic diameter, reservoir temperature, geothermal gradient, total wellbore depth and profile, and operational parameters prior to stopping the circulation. The cooling effects of different drilling parameters were compared to a benchmark case of continuous circulation. A correlation map was generated to visualize the impact of those parameters on the downhole temperature distribution when circulation stops. A logarithmic relationship between the pump stop time and the downhole temperature was observed. For the FORGE case scenario, the downhole temperature increases by 27 °C and 48 °C after the pump stops for 30 and 60 minutes, respectively. It was observed that water-based mud with a high viscosity increases fluid convection heat resistance between the formation and wellbore. Also, drilling with a higher flow rate before stopping the pump can cool the near-wellbore formation faster and reduces the downhole temperature even after circulation ceases. Wells with high geothermal gradients, like FORGE wells, have higher temperature build-up during circulation stoppage than wells with low geothermal gradients targeting the same reservoir (formation) in-situ temperature.\u0000 This study investigates the efficacy of different cooling strategies to avoid downhole temperature build-up when there is no circulation. It thereby facilitates the optimization of geothermal and HPHT well design and construction to prevent downhole tool failures. The developed correlation map can aid drilling engineers understand the impact of different drilling conditions on the downhole temperature.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131842612","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}
Greg Skoff, F. Mahfoudh, C. Jeong, S. Makarychev-Mikhailov, O. Petryshak, V. Vesselinov, Crispin Chatar, Vijay Bondale, M. Devadas
The energy industry is undergoing a digital transformation, whose goals include increased operational efficiency and reduced energy extraction costs. Data science and machine learning (ML) are enabling the drilling engineering community to contribute to the success of these goals. An ML-based digital solution has been developed to assist the drilling engineer select an optimum bottomhole assembly (BHA) and drilling fluid technology during the well design phase. Traditionally, these selections depended on offset well analysis, which is a manual and time-consuming undertaking. As an alternative, the new digital solution, launched in the form of a web app, automatically selects similar offset wells, and evaluates the available BHA and drilling fluid options from those similar wells. The web app displays these options to the drilling engineer, who is now empowered to make fully informed data-driven decisions. To power the new digital solution, an extensive effort was made to gather, clean, and prepare global operational data into a new database. This operational database includes the selection decisions and performance results of drill bits, motor power sections, rotary steerable systems, BHA configurations, and drilling fluids. After the drilling engineer defines the parameters of the planned drilling run, a multidimensional distance-based approach is used to automatically select the most similar previous drilling runs within the context of the technology selection. The drilling engineer can also fine tune the offset selection based on experience using filters in the web app. Once the most similar offset runs are determined, the technology selection decisions are scored for numerous key performance indicators (KPIs). These KPIs, along with user-defined weights, drive the overall scores. Finally, technology selection recommendations are based on the overall scores and other contextual data such as local availability and cost. The new digital solution has been deployed to a global group of drilling engineers. Feedback sessions are held regularly, and the development team uses this feedback to rapidly iterate and improve user experience. While today's drilling engineers have access to a vast amount of data and information, it often cannot be used in a practical and efficient way. The new solution places all previous drilling system technology selection choices and results into the hands of the drilling engineers, allowing them to make their best decisions. This approach demonstrates how ML and innovative software deployment methods can truly assist the human decision-making process and succeed in accomplishing the goals of digital transformation. To our knowledge, this is a unique approach to drilling system design optimization. Not only is the approach unique, but the database developed as a portion of this effort is likely the largest drilling operations database within the industry. This paper presents all phases of the project, including the d
{"title":"Machine Learning-Based Drilling System Recommender: Towards Optimal BHA and Fluid Technology Selection","authors":"Greg Skoff, F. Mahfoudh, C. Jeong, S. Makarychev-Mikhailov, O. Petryshak, V. Vesselinov, Crispin Chatar, Vijay Bondale, M. Devadas","doi":"10.2118/212559-ms","DOIUrl":"https://doi.org/10.2118/212559-ms","url":null,"abstract":"\u0000 The energy industry is undergoing a digital transformation, whose goals include increased operational efficiency and reduced energy extraction costs. Data science and machine learning (ML) are enabling the drilling engineering community to contribute to the success of these goals. An ML-based digital solution has been developed to assist the drilling engineer select an optimum bottomhole assembly (BHA) and drilling fluid technology during the well design phase. Traditionally, these selections depended on offset well analysis, which is a manual and time-consuming undertaking. As an alternative, the new digital solution, launched in the form of a web app, automatically selects similar offset wells, and evaluates the available BHA and drilling fluid options from those similar wells. The web app displays these options to the drilling engineer, who is now empowered to make fully informed data-driven decisions.\u0000 To power the new digital solution, an extensive effort was made to gather, clean, and prepare global operational data into a new database. This operational database includes the selection decisions and performance results of drill bits, motor power sections, rotary steerable systems, BHA configurations, and drilling fluids. After the drilling engineer defines the parameters of the planned drilling run, a multidimensional distance-based approach is used to automatically select the most similar previous drilling runs within the context of the technology selection. The drilling engineer can also fine tune the offset selection based on experience using filters in the web app. Once the most similar offset runs are determined, the technology selection decisions are scored for numerous key performance indicators (KPIs). These KPIs, along with user-defined weights, drive the overall scores. Finally, technology selection recommendations are based on the overall scores and other contextual data such as local availability and cost.\u0000 The new digital solution has been deployed to a global group of drilling engineers. Feedback sessions are held regularly, and the development team uses this feedback to rapidly iterate and improve user experience. While today's drilling engineers have access to a vast amount of data and information, it often cannot be used in a practical and efficient way. The new solution places all previous drilling system technology selection choices and results into the hands of the drilling engineers, allowing them to make their best decisions. This approach demonstrates how ML and innovative software deployment methods can truly assist the human decision-making process and succeed in accomplishing the goals of digital transformation.\u0000 To our knowledge, this is a unique approach to drilling system design optimization. Not only is the approach unique, but the database developed as a portion of this effort is likely the largest drilling operations database within the industry. This paper presents all phases of the project, including the d","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125466469","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}
A major Deepwater operator in the Gulf of Mexico needed to set a 330 ft cross sectional cement barrier in 13 5/8" × 20" casing. This well in over 6, 000 ft+ MD water depth required a cement barrier placed just above the 20" casing shoe in order to meet the qualifications to plug and abandon the well. The 13 5/8" Perf/Wash/Cement system was the best solution to circulate/place cement in a controlled and focused area. The 330 ft long section was planned to be washed and cemented in one run and verified by pressure testing and tagging top of cement. Careful study of Cement Bond Logs and fluid hydraulic calculations was shared in extensive meetings with product experts, engineers, and other 3rd party vendors involved with the job. This novel analysis, great teamwork and a fit for purpose tool helped ensure that the job was successfully completed. The 13 5/8" Perforate, Wash and Cement Tool was successfully deployed for washing and cementing of the interval with even rates at 1200 lpm. After performing the operation the Operator tagged top of cement 6 feet above planned height which proved our analysis and calculations, and a confirmed positive/negative test allowed them to move on with the completion of the plug and abandonment of the well. This was the first operation of its kind in Deepwater Gulf of Mexico and proved to be a viable solution to accurately place an approved and quality cement job behind casing free of unwanted debris that could create micro annuli. This type of operation requires thorough analysis and calculations to ensure the well conditions and tool are fit for purpose and will result in a successful operation. This achievement was the precursor to many more jobs that are suited for this application in the region.
{"title":"Abandonment Barrier Placement with Novel Analysis Spells Success in Deepwater","authors":"Donnie Kehlenbeck II, J. Mcnicol","doi":"10.2118/212444-ms","DOIUrl":"https://doi.org/10.2118/212444-ms","url":null,"abstract":"\u0000 A major Deepwater operator in the Gulf of Mexico needed to set a 330 ft cross sectional cement barrier in 13 5/8\" × 20\" casing. This well in over 6, 000 ft+ MD water depth required a cement barrier placed just above the 20\" casing shoe in order to meet the qualifications to plug and abandon the well. The 13 5/8\" Perf/Wash/Cement system was the best solution to circulate/place cement in a controlled and focused area.\u0000 The 330 ft long section was planned to be washed and cemented in one run and verified by pressure testing and tagging top of cement. Careful study of Cement Bond Logs and fluid hydraulic calculations was shared in extensive meetings with product experts, engineers, and other 3rd party vendors involved with the job. This novel analysis, great teamwork and a fit for purpose tool helped ensure that the job was successfully completed.\u0000 The 13 5/8\" Perforate, Wash and Cement Tool was successfully deployed for washing and cementing of the interval with even rates at 1200 lpm. After performing the operation the Operator tagged top of cement 6 feet above planned height which proved our analysis and calculations, and a confirmed positive/negative test allowed them to move on with the completion of the plug and abandonment of the well.\u0000 This was the first operation of its kind in Deepwater Gulf of Mexico and proved to be a viable solution to accurately place an approved and quality cement job behind casing free of unwanted debris that could create micro annuli. This type of operation requires thorough analysis and calculations to ensure the well conditions and tool are fit for purpose and will result in a successful operation. This achievement was the precursor to many more jobs that are suited for this application in the region.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"88 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130842913","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}
Anan Noel, D. Mendoza, Denis Li, Freddy Perez, G. Andreasen, Kien Tang, O. Buitrago, Ryan Sardjono, S. Oluwadare
The highly productive Permian Basin requires wells with high dogleg severity (DLS) curve and long lateral sections. After many years of development and participation by all major industry players, most 8.5in size wells are still being drilled using two bottomhole assemblies (BHAs); one for the curve and a second for the extended lateral section. This increases cost, time, and risks. With development of our new solution, curve and lateral sections of Permian wells can now be consistently drilled in one run. Using in-house digital modeling and dynamic drilling simulation software of the complete drilling system and complex lithology profiles, design attributes were evaluated for directional performance before initial prototypes were created. These models increased efficiency and cost savings in the design process. Analysis revealed that shortening the distance from the RSS pad actuators to the bit (L1), increases the build-rate capability, increases the DLS output in the curve section, and provides tight trajectory control in long laterals. The system design also has a proprietary bit box connection and polycrystalline diamond compact (PDC) cutters on the bias unit. Prototype testing was done on high-DLS curve and lateral wells with major operators delivering wells per client requirements. The new solution successfully landed high DLS curve sections in 14 wells. The solution achieved a new milestone of delivering the 8.5-in curve on target and much faster than the conventional motor in the same application. After the curve sections the same BHA drilled into the long lateral section without making a trip between the curve and lateral sections. Several records were broken in some of these 14 wells, including 19% more daily footage than the previous record. Almost all these wells were also drilled using a remote operations center utilizing latest digital capabilities, reducing onsite footprint. Based on the most conservative figures from field test results and projected usage, the increased efficiency and faster well delivery time can significantly impact sustainability, reducing CO2 emissions per well drilled by this new solution.
{"title":"New One BHA Solution for High Dogleg Severity Curve and Lateral Drilling","authors":"Anan Noel, D. Mendoza, Denis Li, Freddy Perez, G. Andreasen, Kien Tang, O. Buitrago, Ryan Sardjono, S. Oluwadare","doi":"10.2118/212567-ms","DOIUrl":"https://doi.org/10.2118/212567-ms","url":null,"abstract":"\u0000 The highly productive Permian Basin requires wells with high dogleg severity (DLS) curve and long lateral sections. After many years of development and participation by all major industry players, most 8.5in size wells are still being drilled using two bottomhole assemblies (BHAs); one for the curve and a second for the extended lateral section. This increases cost, time, and risks. With development of our new solution, curve and lateral sections of Permian wells can now be consistently drilled in one run.\u0000 Using in-house digital modeling and dynamic drilling simulation software of the complete drilling system and complex lithology profiles, design attributes were evaluated for directional performance before initial prototypes were created. These models increased efficiency and cost savings in the design process.\u0000 Analysis revealed that shortening the distance from the RSS pad actuators to the bit (L1), increases the build-rate capability, increases the DLS output in the curve section, and provides tight trajectory control in long laterals. The system design also has a proprietary bit box connection and polycrystalline diamond compact (PDC) cutters on the bias unit.\u0000 Prototype testing was done on high-DLS curve and lateral wells with major operators delivering wells per client requirements. The new solution successfully landed high DLS curve sections in 14 wells. The solution achieved a new milestone of delivering the 8.5-in curve on target and much faster than the conventional motor in the same application. After the curve sections the same BHA drilled into the long lateral section without making a trip between the curve and lateral sections. Several records were broken in some of these 14 wells, including 19% more daily footage than the previous record. Almost all these wells were also drilled using a remote operations center utilizing latest digital capabilities, reducing onsite footprint. Based on the most conservative figures from field test results and projected usage, the increased efficiency and faster well delivery time can significantly impact sustainability, reducing CO2 emissions per well drilled by this new solution.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"33 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133951592","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}
Mohamed El Nadoury, Ola Balbaa, J. Vincent, Todd Eberhardt, M. Moussa, Alaa Galal, S. Elkholy, Joseph Younan, Mohamed Sabra, M. Bogaerts
Setting cement plugs is a critical operation, often not getting the required attention and potentially resulting in lost time. For example, while drilling an exploratory well offshore Egypt in the North Ras el Ash block, special attention was given early in the well's design phase to the wellbore abandonment to be executed after reaching the well target and achieving all well's objectives. As part of the continuous improvement, a detailed after-action review (AAR) took the place of the abandonment of the previous exploration well in the same field ahead of spud. All applicable lessons learned were identified and worked out in easy-to-implement steps to improve the chances of a successful abandonment meeting all company and regulatory requirements. The AAR addressed all aspects of the abandonment, including cement slurry design and laboratory testing, cement plug placement and operational rig procedures, and post-placement activities that could impact the cement plug and, in the worst case, could lead to not meeting abandonment requirements. All plugs to be verified by a positive and negative pressure test were simulated using proprietary software. The simulation results would predict the cement plug bonding to the formation or casing during and after the positive and negative tests. To overcome any damage in the sealing capability of the plug, those plugs were designed so that the slurry would expand during the cement setting phase. In addition, detailed laboratory tests were run to optimize the cement slurry design at actual downhole conditions. Special attention was given to formation pressures and possible losses or influx after cutting and retrieving the intermediate casing. Certain shales are gas-bearing formations but with very low permeability and very low capability to deliver gas to the wellbore. During the drilling phase, this is not considered a high risk and was easily managed with drilling fluids. However, while setting plugs, a small influx of gas can percolate through the cement plug creating a potential leak path. Correct placement in the field is equally important to a good design. The plug placement was simulated to minimize contamination during placement for plugs. Optimum spacer volume, underdisplacement, and the use of mechanical separators were optimized to achieve the plug and abandonment (P&A) objectives. Pull out of hole (POOH) was designed to minimize disturbance of the cement plug and circulation at top of cement (TOC) was performed without disturbing the cement/spacer interface. All the effort placed into the well abandonment during the well design phase paid out during the execution. A total of five cement plugs were planned. The plugs were tagged and tested achieving all the abandonment requirements successfully. No repeat plugs were required.
坐封水泥塞是一项关键的作业，通常没有得到足够的重视，可能会浪费时间。例如，在埃及北部Ras el Ash区块钻探一口勘探井时，在井的设计阶段早期就特别关注了在达到井目标并实现所有井目标后执行的弃井作业。作为持续改进的一部分，详细的事后评估(AAR)取代了在开钻前放弃同一油田的前一口勘探井。所有适用的经验教训都被识别出来，并以易于实施的步骤制定出来，以提高成功放弃的机会，满足所有公司和监管要求。AAR解决了弃井作业的所有方面，包括水泥浆设计和实验室测试、水泥塞放置和钻机操作程序，以及可能影响水泥塞的放置后活动，在最坏的情况下，可能导致无法满足弃井要求。所有需要通过正负压测试验证的桥塞都使用专有软件进行了模拟。模拟结果可以预测水泥塞在测试中和测试后与地层或套管的胶结情况。为了克服桥塞密封能力的任何损害，这些桥塞的设计使得泥浆在固井阶段会膨胀。此外，还进行了详细的实验室测试，以优化实际井下条件下的水泥浆设计。特别要注意的是地层压力以及切割和回收中间套管后可能出现的损失或流入。某些页岩是含气地层，但渗透率非常低，向井筒输送气体的能力非常低。在钻井阶段，这种风险并不高，而且很容易用钻井液进行处理。然而，在坐封桥塞时，少量气体会通过水泥塞渗透，形成潜在的泄漏通道。正确的位置对于一个好的设计来说同样重要。模拟了桥塞的放置过程，以尽量减少桥塞放置过程中的污染。为了实现封隔和弃井(P&A)的目标，优化了最佳的封隔器体积、欠排量和机械分离器的使用。出井(POOH)的设计是为了最大限度地减少水泥塞的干扰，并且在不干扰水泥/隔离剂界面的情况下进行水泥顶部循环(TOC)。在井设计阶段投入的所有弃井工作都在执行过程中得到了回报。总共计划了5个水泥塞。对桥塞进行了标记和测试，成功达到了所有弃井要求。无需重复插入。
{"title":"Continuous Improvement for Offshore Plug and Abandonment, a Case Study from Egypt Offshore","authors":"Mohamed El Nadoury, Ola Balbaa, J. Vincent, Todd Eberhardt, M. Moussa, Alaa Galal, S. Elkholy, Joseph Younan, Mohamed Sabra, M. Bogaerts","doi":"10.2118/212538-ms","DOIUrl":"https://doi.org/10.2118/212538-ms","url":null,"abstract":"\u0000 Setting cement plugs is a critical operation, often not getting the required attention and potentially resulting in lost time. For example, while drilling an exploratory well offshore Egypt in the North Ras el Ash block, special attention was given early in the well's design phase to the wellbore abandonment to be executed after reaching the well target and achieving all well's objectives.\u0000 As part of the continuous improvement, a detailed after-action review (AAR) took the place of the abandonment of the previous exploration well in the same field ahead of spud. All applicable lessons learned were identified and worked out in easy-to-implement steps to improve the chances of a successful abandonment meeting all company and regulatory requirements. The AAR addressed all aspects of the abandonment, including cement slurry design and laboratory testing, cement plug placement and operational rig procedures, and post-placement activities that could impact the cement plug and, in the worst case, could lead to not meeting abandonment requirements.\u0000 All plugs to be verified by a positive and negative pressure test were simulated using proprietary software. The simulation results would predict the cement plug bonding to the formation or casing during and after the positive and negative tests. To overcome any damage in the sealing capability of the plug, those plugs were designed so that the slurry would expand during the cement setting phase. In addition, detailed laboratory tests were run to optimize the cement slurry design at actual downhole conditions.\u0000 Special attention was given to formation pressures and possible losses or influx after cutting and retrieving the intermediate casing. Certain shales are gas-bearing formations but with very low permeability and very low capability to deliver gas to the wellbore. During the drilling phase, this is not considered a high risk and was easily managed with drilling fluids. However, while setting plugs, a small influx of gas can percolate through the cement plug creating a potential leak path.\u0000 Correct placement in the field is equally important to a good design. The plug placement was simulated to minimize contamination during placement for plugs. Optimum spacer volume, underdisplacement, and the use of mechanical separators were optimized to achieve the plug and abandonment (P&A) objectives. Pull out of hole (POOH) was designed to minimize disturbance of the cement plug and circulation at top of cement (TOC) was performed without disturbing the cement/spacer interface.\u0000 All the effort placed into the well abandonment during the well design phase paid out during the execution. A total of five cement plugs were planned. The plugs were tagged and tested achieving all the abandonment requirements successfully. No repeat plugs were required.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"139 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132898481","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}
Mahmoud ElGizawy, R. Lowdon, D. Aklestad, Paul Strain, Fraser Boyce
A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding colliding with other offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying technology individually is not sufficient. This highest level of wellbore positioning accuracy to date is achieved by combing two wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic Measurement-While-Drilling (MWD) Definitive Dynamic Surveys (DDS). The accuracy of the MWD DDS has been enhanced by correcting potential error sources such as misalignment of the survey package from the borehole, drill-string magnetic interference and limited global geomagnetic reference and accelerometer sensor accuracy. Further, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the Rotary Steerable System (RSS). Hence the first position is derived from magnetic MWD DDS after applying In-Field Referencing (IFR), Multi-Station Analysis (MSA), Bottom Hole Assembly (BHA) sag correction (SAG), and Dual-Inclination (DI) corrections. A Second wellbore position is calculated using the latest technology in Gyro-measurement-While-Drilling (GWD). The results and comparisons of multiple runs are presented. The highest accuracy of wellbore positioning had been proven in successful case studies by penetrating a very small reservoir target on an extended reach well that was unfeasible using either the most accurate enhanced MWD DDS or the latest GWD technology. The presented case study shows how the wellbore objectives of penetrating the tight target reservoir had been confirmed by Logging-While-Drilling (LWD) images and interpretation of the subsurface team. This gave the highest accuracy of the wellbore position accuracy to date while drilling assured placing the well with higher confidence to maximize reservoir production without colliding with nearby offset wells. In reservoir sections, the wellbore survey accuracy limits boreholes' lateral and true vertical depth spacing, constraining reservoir production. In the top and intermediate sections, wellbore survey accuracy limits how close the well can be drilled in the proximity of other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. This technique unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy achieved to date when compared to the latest magnetic MWD surveys after correcting all known errors compared to the GWD.
{"title":"Combining Best-in-Class Surveying Measurements to Provide the Most Accurate Wellbore Position","authors":"Mahmoud ElGizawy, R. Lowdon, D. Aklestad, Paul Strain, Fraser Boyce","doi":"10.2118/212547-ms","DOIUrl":"https://doi.org/10.2118/212547-ms","url":null,"abstract":"\u0000 A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding colliding with other offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying technology individually is not sufficient.\u0000 This highest level of wellbore positioning accuracy to date is achieved by combing two wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic Measurement-While-Drilling (MWD) Definitive Dynamic Surveys (DDS). The accuracy of the MWD DDS has been enhanced by correcting potential error sources such as misalignment of the survey package from the borehole, drill-string magnetic interference and limited global geomagnetic reference and accelerometer sensor accuracy. Further, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the Rotary Steerable System (RSS). Hence the first position is derived from magnetic MWD DDS after applying In-Field Referencing (IFR), Multi-Station Analysis (MSA), Bottom Hole Assembly (BHA) sag correction (SAG), and Dual-Inclination (DI) corrections. A Second wellbore position is calculated using the latest technology in Gyro-measurement-While-Drilling (GWD).\u0000 The results and comparisons of multiple runs are presented. The highest accuracy of wellbore positioning had been proven in successful case studies by penetrating a very small reservoir target on an extended reach well that was unfeasible using either the most accurate enhanced MWD DDS or the latest GWD technology. The presented case study shows how the wellbore objectives of penetrating the tight target reservoir had been confirmed by Logging-While-Drilling (LWD) images and interpretation of the subsurface team. This gave the highest accuracy of the wellbore position accuracy to date while drilling assured placing the well with higher confidence to maximize reservoir production without colliding with nearby offset wells.\u0000 In reservoir sections, the wellbore survey accuracy limits boreholes' lateral and true vertical depth spacing, constraining reservoir production. In the top and intermediate sections, wellbore survey accuracy limits how close the well can be drilled in the proximity of other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. This technique unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy achieved to date when compared to the latest magnetic MWD surveys after correcting all known errors compared to the GWD.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"70 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131661949","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}
Geothermal energy is gaining attention worldwide as an attractive and vastly underutilized renewable energy source due to its abundance, baseload capability, resiliency, and reliability. While there are many types of geothermal energy concepts, the holy grail of geothermal – that would enable geothermal drilling and production in most places in the world – is hard rock or superhot rock concepts. Developing these systems requires drilling into granitic basement formations, often at temperatures exceeding 300º C. There are two main technological challenges associated with hard, hot rock concepts. Firstly, very hard rock, such as granite or basalt, limits the rate of penetration (ROP). Secondly, the temperature of the drilling system exceeds the operational limits of electronic tools like measurement while drilling (MWD) and Rotary Steerable. This paper discusses the modeling, design, and testing of a drilling system that solves both challenges. Our approach to the ROP problem was to optimize the drilling system for drilling cold hard rock from 0º to 175º C and optimize the system for drilling hot hard rock where temperatures exceed 175º C. We will discuss the design and performance of both PDC drill bits and Hybrid Particle Impact/PDC bits in hard rock formations and the best application of the two methodologies moving forward. Our approach to the temperature problem was to model the entire wellbore and drillstring and investigate the effects of, but not limited to, the starting temperature of the fluid, flow rate of the fluid, type of fluid, impact of the thickness, type of insulation on the inside of the drillpipe, the diameter of the pipe, and continuous circulation. The objective of the modeling was to understand the relative impact of changes to the system on the temperature of the drilling fluid and the most cost-effective way to deliver a 150º C fluid to the bottom of the hole. This paper will discuss the results, observations, and conclusions of testing and running PDC drill bits and Particle Impact Drilling/PDC hybrids in hard formations. The results will derive from lab testing and geothermal drilling projects. The paper will also discuss the field testing and running of components of a drilling system optimized to deliver as cool a fluid as possible to the bottom of the wellbore. The results shown in this paper suggest that we have solved, or are very close to solving, two of the major challenges which prevent geothermal energy from being economically viable worldwide and not just restricted to the small geographic areas where you have very high temperature gradients associated with volcanic activity. The results would also have significant benefits for oil and gas wells where the bottom hole temperatures exceed 175º C.
{"title":"Building a System to Solve the Challenges of Drilling Hot Hard Rock for Geothermal and Oil and Gas","authors":"A. Pink, A. Patterson, Karl Erik Thoresen","doi":"10.2118/212438-ms","DOIUrl":"https://doi.org/10.2118/212438-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Geothermal energy is gaining attention worldwide as an attractive and vastly underutilized renewable energy source due to its abundance, baseload capability, resiliency, and reliability. While there are many types of geothermal energy concepts, the holy grail of geothermal – that would enable geothermal drilling and production in most places in the world – is hard rock or superhot rock concepts. Developing these systems requires drilling into granitic basement formations, often at temperatures exceeding 300º C. There are two main technological challenges associated with hard, hot rock concepts. Firstly, very hard rock, such as granite or basalt, limits the rate of penetration (ROP). Secondly, the temperature of the drilling system exceeds the operational limits of electronic tools like measurement while drilling (MWD) and Rotary Steerable. This paper discusses the modeling, design, and testing of a drilling system that solves both challenges.\u0000 \u0000 \u0000 \u0000 Our approach to the ROP problem was to optimize the drilling system for drilling cold hard rock from 0º to 175º C and optimize the system for drilling hot hard rock where temperatures exceed 175º C. We will discuss the design and performance of both PDC drill bits and Hybrid Particle Impact/PDC bits in hard rock formations and the best application of the two methodologies moving forward. Our approach to the temperature problem was to model the entire wellbore and drillstring and investigate the effects of, but not limited to, the starting temperature of the fluid, flow rate of the fluid, type of fluid, impact of the thickness, type of insulation on the inside of the drillpipe, the diameter of the pipe, and continuous circulation. The objective of the modeling was to understand the relative impact of changes to the system on the temperature of the drilling fluid and the most cost-effective way to deliver a 150º C fluid to the bottom of the hole.\u0000 \u0000 \u0000 \u0000 This paper will discuss the results, observations, and conclusions of testing and running PDC drill bits and Particle Impact Drilling/PDC hybrids in hard formations. The results will derive from lab testing and geothermal drilling projects. The paper will also discuss the field testing and running of components of a drilling system optimized to deliver as cool a fluid as possible to the bottom of the wellbore.\u0000 \u0000 \u0000 \u0000 The results shown in this paper suggest that we have solved, or are very close to solving, two of the major challenges which prevent geothermal energy from being economically viable worldwide and not just restricted to the small geographic areas where you have very high temperature gradients associated with volcanic activity. The results would also have significant benefits for oil and gas wells where the bottom hole temperatures exceed 175º C.\u0000","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124807240","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 bonding properties between a sealant and steel casing are an important component of well barrier. However, there is no consent about how sealing materials should be tested and qualified, and the understandings around the bonding interface and its mechanisms of failure remains uncertain. A custom setup and a systematic interface analysis procedure was established to test the hydraulic bond sealing properties of different sealants, and to investigate their interface with a L80-Cr13 steel casing. The results of hydraulic bond sealability was correlated with macro and microstructural evidence of the bonding interface to understand the behavior and the performance of class G cement and a geopolymer recipes. The geopolymer recipe showed improved sealing performance in relation to class G cement. The interface analysis suggests that, in addition to the mechanical interlocking mechanism, the geopolymer sealant has a strong bond with the coating of the steel casing, as a secondary adhesion mechanism. Understanding the interface and the mechanisms of failure may be the key to further develop current and future sealants, and to reduce risk of leak and to reduce cost with well intervention in P&A operations.
{"title":"Sealing Ability of Barrier Materials for P&A Application: Investigation of Casing-Barrier Interface","authors":"P. Moreira, M. Khalifeh, Amit Govil","doi":"10.2118/212562-ms","DOIUrl":"https://doi.org/10.2118/212562-ms","url":null,"abstract":"\u0000 The bonding properties between a sealant and steel casing are an important component of well barrier. However, there is no consent about how sealing materials should be tested and qualified, and the understandings around the bonding interface and its mechanisms of failure remains uncertain. A custom setup and a systematic interface analysis procedure was established to test the hydraulic bond sealing properties of different sealants, and to investigate their interface with a L80-Cr13 steel casing. The results of hydraulic bond sealability was correlated with macro and microstructural evidence of the bonding interface to understand the behavior and the performance of class G cement and a geopolymer recipes. The geopolymer recipe showed improved sealing performance in relation to class G cement. The interface analysis suggests that, in addition to the mechanical interlocking mechanism, the geopolymer sealant has a strong bond with the coating of the steel casing, as a secondary adhesion mechanism. Understanding the interface and the mechanisms of failure may be the key to further develop current and future sealants, and to reduce risk of leak and to reduce cost with well intervention in P&A operations.","PeriodicalId":255336,"journal":{"name":"Day 3 Thu, March 09, 2023","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127595707","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：