The Montney reservoir is one of the most prolific unconventional multi-stacked dry and liquid-rich gas plays in North America. The type of fracturing method and fluid has a significant impact on water-phase trapping, casing deformation, and well performance in the Montney. Different fracturing methods (plug and perf/plug and perf with ball/ball and seat/single-entry pinpoint) and fluids (slickwater/hybrid/oil-based/energized/foam) have been tested in 4000+ Montney wells to find optimal fracturing method and fluid for different reservoir qualities and fluid windows and to minimize water-phase trapping and casing deformation. The previous studies reviewing the performance of fracturing methods in Montney do not represent a holistic evaluation of these methods, due to some limitations, including: (1) Using a small sample size, (2) Having a limited scope by focusing on a specific aspect of fracturing (method/fluid), (3) Relying on data analytics approaches that offer limited subsurface insight, and (4) Generating misleading results (e.g., on optimum fracturing method/fluid) through using disparate data that are unstructured and untrustworthy due to significant regional variation in true vertical depth (TVD), geological properties, fluid windows, completed lateral length, fracturing method/fluid/date, and drawdown rate management strategy. The present study eliminates these limitations by rigorously clustering the 4000+ Montney wells based on the TVD, geological properties, fluid window, completed lateral length, fracturing method/fluid/date, and drawdown strategy. This clustering technique allows for isolating the effect of each fracturing method by comparing each well's production (normalized by proppant tonnage, fluid volume, and completed length) to that of its offsets that use different fracturing methods but possess similar geology and fluid window. With similar TVD and fracturing fluid/date, wells completed with pinpoint fracturing outperform their offsets completed with ball and seat and plug and perf fracturing. However, wells completed with ball and seat and plug and perf methods that outperform their offset pinpoint wells have either: (1) Been fractured 1 to 4 years earlier than pinpoint wells and/or (2) Used energized oil-based fluid, hybrid fluid, and energized slickwater versus slickwater used in pinpoint offsets, suggesting that the water-phase trapping is more severe in these pinpoint wells due to the use of slickwater. Previous studies often favored one specific fracturing method or fluid without highlighting these complex interplays between the type of fracturing method/fluid, completion date (regional depletion), and the reservoir properties and hydrodynamics. This clustering technique shows how proper data structuring in disparate datasets containing thousands of wells with significant variations in geological properties, fluid windows, fracturing method/fluid, regional depletion, and drawdown strategy permits a consistent wel
{"title":"A Play-Wide Performance Review of Plug and Perf, Ball and Seat, and Pinpoint Fracturing Methods in the Montney Tight Siltstone Reservoir","authors":"B. Yadali Jamaloei, Robert T. Burstall, A. Nakhwa","doi":"10.2118/205298-ms","DOIUrl":"https://doi.org/10.2118/205298-ms","url":null,"abstract":"\u0000 The Montney reservoir is one of the most prolific unconventional multi-stacked dry and liquid-rich gas plays in North America. The type of fracturing method and fluid has a significant impact on water-phase trapping, casing deformation, and well performance in the Montney. Different fracturing methods (plug and perf/plug and perf with ball/ball and seat/single-entry pinpoint) and fluids (slickwater/hybrid/oil-based/energized/foam) have been tested in 4000+ Montney wells to find optimal fracturing method and fluid for different reservoir qualities and fluid windows and to minimize water-phase trapping and casing deformation.\u0000 The previous studies reviewing the performance of fracturing methods in Montney do not represent a holistic evaluation of these methods, due to some limitations, including: (1) Using a small sample size, (2) Having a limited scope by focusing on a specific aspect of fracturing (method/fluid), (3) Relying on data analytics approaches that offer limited subsurface insight, and (4) Generating misleading results (e.g., on optimum fracturing method/fluid) through using disparate data that are unstructured and untrustworthy due to significant regional variation in true vertical depth (TVD), geological properties, fluid windows, completed lateral length, fracturing method/fluid/date, and drawdown rate management strategy. The present study eliminates these limitations by rigorously clustering the 4000+ Montney wells based on the TVD, geological properties, fluid window, completed lateral length, fracturing method/fluid/date, and drawdown strategy. This clustering technique allows for isolating the effect of each fracturing method by comparing each well's production (normalized by proppant tonnage, fluid volume, and completed length) to that of its offsets that use different fracturing methods but possess similar geology and fluid window.\u0000 With similar TVD and fracturing fluid/date, wells completed with pinpoint fracturing outperform their offsets completed with ball and seat and plug and perf fracturing. However, wells completed with ball and seat and plug and perf methods that outperform their offset pinpoint wells have either: (1) Been fractured 1 to 4 years earlier than pinpoint wells and/or (2) Used energized oil-based fluid, hybrid fluid, and energized slickwater versus slickwater used in pinpoint offsets, suggesting that the water-phase trapping is more severe in these pinpoint wells due to the use of slickwater. Previous studies often favored one specific fracturing method or fluid without highlighting these complex interplays between the type of fracturing method/fluid, completion date (regional depletion), and the reservoir properties and hydrodynamics.\u0000 This clustering technique shows how proper data structuring in disparate datasets containing thousands of wells with significant variations in geological properties, fluid windows, fracturing method/fluid, regional depletion, and drawdown strategy permits a consistent wel","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74919399","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}
Asif Hoq, Yann Caline, Erik Jakobsen, N. Wood, R. Stolpman, Aurelien Thirion, W. Giffin
The Valhall field, operated by AkerBP, has been a major hub in the North Sea, on stream for thirty-eight years and recently passed one billion barrels of oil produced. The field requires stimulation for economical production. Mechanically strong formations are acid stimulated, while weaker formations require large tip-screenout design proppant fractures. Fracture deployment methods on Valhall have remained relatively unchanged since the nineties and are currently referred to as "conventional". Those consist in a sequence of placing a proppant frac, cleaning out the well with coiled tubing, opening a sleeve or shooting perforations, then coil pulling out of hole pumping the proppant frac. For the past few years, AkerBP and their service partners have worked on qualifying an adapted version of the annular coiled tubing fracturing practice for the offshore infrastructure - a first for the industry, which has been a strategic priority for the operator as it significantly reduces execution time and accelerates production. As with all technology trials, the implementation of this practice on Valhall had to begin on a learning curve through various forms of challenges. Whilst investigating the cause and frequency of premature screenouts during the initial implementation of annular fracturing, the team decided to challenge the conventional standards for fluid testing and quality control. Carefully engineered adjustments were made with regards to high shear testing conditions, temperature modelling, and mixing sequences, these did not only identify the root cause for the unexpected screenouts, but also helped create the current blueprint for engineering a robust fluid. Since the deployment of the redefined recipe, adjusted testing procedures and changes made to the stimulation vessel, there have not been any cases of fluid induced screenouts during the executions. The fewer types of additives now required for the recipe have lowered the cost of treatments and the lower gel loading leads to reduced damage in the fractures, thereby contributing to enhanced production over the lifetime of the wells. This paper describes the investigation, findings and the resulting changes made to the fluid formulation and quality control procedures to accommodate for high shear and dynamic wellbore temperature conditions. It discusses the rationale behind the "reality" testing model and, proves that significant value is created from investing time in thoroughly understanding fluid behaviour in the lab, prior to pumping it on large-scale capital-intensive operations. The study demonstrated that there is always value in innovating or challenging pre-conceived practices, and the learnings from this investigation significantly improved the track record for annular fracturing on Valhall, redefined fluid engineering for the North Sea and will inform future annular fracturing deployments on other offshore assets around the world.
{"title":"Enhancements in Fracturing Fluid Engineering Reawakens a North Sea Giant","authors":"Asif Hoq, Yann Caline, Erik Jakobsen, N. Wood, R. Stolpman, Aurelien Thirion, W. Giffin","doi":"10.2118/205256-ms","DOIUrl":"https://doi.org/10.2118/205256-ms","url":null,"abstract":"\u0000 The Valhall field, operated by AkerBP, has been a major hub in the North Sea, on stream for thirty-eight years and recently passed one billion barrels of oil produced. The field requires stimulation for economical production. Mechanically strong formations are acid stimulated, while weaker formations require large tip-screenout design proppant fractures. Fracture deployment methods on Valhall have remained relatively unchanged since the nineties and are currently referred to as \"conventional\". Those consist in a sequence of placing a proppant frac, cleaning out the well with coiled tubing, opening a sleeve or shooting perforations, then coil pulling out of hole pumping the proppant frac. For the past few years, AkerBP and their service partners have worked on qualifying an adapted version of the annular coiled tubing fracturing practice for the offshore infrastructure - a first for the industry, which has been a strategic priority for the operator as it significantly reduces execution time and accelerates production.\u0000 As with all technology trials, the implementation of this practice on Valhall had to begin on a learning curve through various forms of challenges. Whilst investigating the cause and frequency of premature screenouts during the initial implementation of annular fracturing, the team decided to challenge the conventional standards for fluid testing and quality control. Carefully engineered adjustments were made with regards to high shear testing conditions, temperature modelling, and mixing sequences, these did not only identify the root cause for the unexpected screenouts, but also helped create the current blueprint for engineering a robust fluid.\u0000 Since the deployment of the redefined recipe, adjusted testing procedures and changes made to the stimulation vessel, there have not been any cases of fluid induced screenouts during the executions. The fewer types of additives now required for the recipe have lowered the cost of treatments and the lower gel loading leads to reduced damage in the fractures, thereby contributing to enhanced production over the lifetime of the wells.\u0000 This paper describes the investigation, findings and the resulting changes made to the fluid formulation and quality control procedures to accommodate for high shear and dynamic wellbore temperature conditions. It discusses the rationale behind the \"reality\" testing model and, proves that significant value is created from investing time in thoroughly understanding fluid behaviour in the lab, prior to pumping it on large-scale capital-intensive operations. The study demonstrated that there is always value in innovating or challenging pre-conceived practices, and the learnings from this investigation significantly improved the track record for annular fracturing on Valhall, redefined fluid engineering for the North Sea and will inform future annular fracturing deployments on other offshore assets around the world.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91003896","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. Klimov, R. Ramazanov, Nadir Husein, Vishwajit Upadhye, A. Drobot, Igor Novikov, A.Y. Bydzan, R. Gazizov, A. Buyanov
The proportion of hard-to-recover reserves is currently increasing and reached more than 65% of total conventional hydrocarbon reserves. This results in an increasing number of horizontal wells put into operation. When evaluating the resource recovery efficiency in horizontal wells, and, consequently, the effectiveness of the development of gas condensate field, the key task is to evaluate the well productivity. To accomplish this task, it is necessary to obtain the reservoir fluid production profile for each interval. Conventional well logging methods with proven efficiency in vertical wells, in case of horizontal wells, will require costly asset-heavy applications such as coiled tubing, downhole tractors conveying well logging tools, and Y-tool bypass systems if pump is used. In addition, the logging data interpretation in the case of horizontal wells is less reliable due to the multiphase flow and variations of the fluid flow rate. The fluorescent-based nanomaterial production profiling surveillance technology can be used as a viable solution to this problem, which enables cheaper and more effective means of the development of hard-to-recover reserves. This technology assumes that tracers are placed downhole in various forms, such as marker tapes for lower completions, markers in the polymer coating of the proppant used for multi-stage hydraulic fracturing, and markers placed as fluid in fracturing fluid during hydraulic fracturing or acid stimulation during bottom-hole treatment. The fundamental difference between nanomaterial tracers production profiling and traditional logging methods is that the former offers the possibility to monitor the production at frac ports in the well for a long period of time with far less equipment and manpower, reduced costs, and improved HSE.
{"title":"Fluorescent Microspheres Method Efficiency in Horizontal Wells with Gas Condensate Liquid","authors":"M. Klimov, R. Ramazanov, Nadir Husein, Vishwajit Upadhye, A. Drobot, Igor Novikov, A.Y. Bydzan, R. Gazizov, A. Buyanov","doi":"10.2118/205248-ms","DOIUrl":"https://doi.org/10.2118/205248-ms","url":null,"abstract":"\u0000 The proportion of hard-to-recover reserves is currently increasing and reached more than 65% of total conventional hydrocarbon reserves. This results in an increasing number of horizontal wells put into operation. When evaluating the resource recovery efficiency in horizontal wells, and, consequently, the effectiveness of the development of gas condensate field, the key task is to evaluate the well productivity. To accomplish this task, it is necessary to obtain the reservoir fluid production profile for each interval. Conventional well logging methods with proven efficiency in vertical wells, in case of horizontal wells, will require costly asset-heavy applications such as coiled tubing, downhole tractors conveying well logging tools, and Y-tool bypass systems if pump is used. In addition, the logging data interpretation in the case of horizontal wells is less reliable due to the multiphase flow and variations of the fluid flow rate.\u0000 The fluorescent-based nanomaterial production profiling surveillance technology can be used as a viable solution to this problem, which enables cheaper and more effective means of the development of hard-to-recover reserves. This technology assumes that tracers are placed downhole in various forms, such as marker tapes for lower completions, markers in the polymer coating of the proppant used for multi-stage hydraulic fracturing, and markers placed as fluid in fracturing fluid during hydraulic fracturing or acid stimulation during bottom-hole treatment.\u0000 The fundamental difference between nanomaterial tracers production profiling and traditional logging methods is that the former offers the possibility to monitor the production at frac ports in the well for a long period of time with far less equipment and manpower, reduced costs, and improved HSE.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89364022","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}
Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve. Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors. The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells. This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.
{"title":"Connecting the Dots: Multistage Fracturing in Horizontal Wells with Multilayered Reservoirs - Lessons Learned","authors":"A. Al Shueili, M. Jaboob, Hussain Al Salmi","doi":"10.2118/205302-ms","DOIUrl":"https://doi.org/10.2118/205302-ms","url":null,"abstract":"\u0000 Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve.\u0000 Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors.\u0000 The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells.\u0000 This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75211425","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}
Khalid Fahad Almulhem, Ataur R. Malik, Mustafa Ghazwi
Acid Fracturing has been one of the most effective stimulation technique applied in the carbonate formations to enhance oil and gas production. The traditional approach to stimulate the carbonate reservoir has been to pump crosslinked gel and acid blends such as plain 28% HCL, emulsified acid (EA) and in-situ gelled acid at fracture rates in order to maximize stimulated reservoir volume with desired conductivity. With the common challenges encountered in fracturing carbonate formations, including high leak-off and fast acid reaction rates, the conventional practice of acid fracturing involves complex pumping schemes of pad, acid and viscous diverter fluid cycles to achieve fracture length and conductivity targets. A new generation of Acid-Based Crosslinked (ABC) fluid system has been deployed to stimulate high temperature carbonate formations in three separate field trials aiming to provide rock-breaking viscosity, acid retardation and effective leak-off control. The ABC fluid system has been progressively introduced, initially starting as diverter / leak off control cycles of pad and acid stages. Later it was used as main acid-based fluid system for enhancing live acid penetration, diverting and reducing leakoff as well as keeping the rock open during hydraulic fracturing operation. Unlike in-situ crosslinked acid based system that uses acid reaction by products to start crosslinking process, the ABC fluid system uses a unique crosslinker/breaker combination independent of acid reaction. The system is prepared with 20% hydrochloric acid and an acrylamide polymer along with zirconium metal for delayed crosslinking in unspent acid. The ABC fluid system is aimed to reduced three fluid requirements to one by eliminating the need for an intricate pumping schedule that otherwise would include: a non-acid fracturing pad stage to breakdown the formation and generate the targeted fracture geometry; a retarded emulsified acid system to achieve deep penetrating, differently etched fractures, and a self-diverting agent to minimize fluid leak-off. This paper describes all efforts behind the introduction of this novel Acid-Based Crossliked fluid system in different field trials. Details of the fluid design optimization are included to illustrate how a single system can replace the need for multiple fluids. The ABC fluid was formulated to meet challenging bottom-hole formation conditions that resulted in encouraging post treatment well performance.
{"title":"The Evaluation and Introduction of Novel Acid-Based Crosslinked Gel for HPHT Acid Fracturing Applications in Carbonate Formations","authors":"Khalid Fahad Almulhem, Ataur R. Malik, Mustafa Ghazwi","doi":"10.2118/205318-ms","DOIUrl":"https://doi.org/10.2118/205318-ms","url":null,"abstract":"\u0000 Acid Fracturing has been one of the most effective stimulation technique applied in the carbonate formations to enhance oil and gas production. The traditional approach to stimulate the carbonate reservoir has been to pump crosslinked gel and acid blends such as plain 28% HCL, emulsified acid (EA) and in-situ gelled acid at fracture rates in order to maximize stimulated reservoir volume with desired conductivity.\u0000 With the common challenges encountered in fracturing carbonate formations, including high leak-off and fast acid reaction rates, the conventional practice of acid fracturing involves complex pumping schemes of pad, acid and viscous diverter fluid cycles to achieve fracture length and conductivity targets. A new generation of Acid-Based Crosslinked (ABC) fluid system has been deployed to stimulate high temperature carbonate formations in three separate field trials aiming to provide rock-breaking viscosity, acid retardation and effective leak-off control.\u0000 The ABC fluid system has been progressively introduced, initially starting as diverter / leak off control cycles of pad and acid stages. Later it was used as main acid-based fluid system for enhancing live acid penetration, diverting and reducing leakoff as well as keeping the rock open during hydraulic fracturing operation. Unlike in-situ crosslinked acid based system that uses acid reaction by products to start crosslinking process, the ABC fluid system uses a unique crosslinker/breaker combination independent of acid reaction. The system is prepared with 20% hydrochloric acid and an acrylamide polymer along with zirconium metal for delayed crosslinking in unspent acid. The ABC fluid system is aimed to reduced three fluid requirements to one by eliminating the need for an intricate pumping schedule that otherwise would include: a non-acid fracturing pad stage to breakdown the formation and generate the targeted fracture geometry; a retarded emulsified acid system to achieve deep penetrating, differently etched fractures, and a self-diverting agent to minimize fluid leak-off.\u0000 This paper describes all efforts behind the introduction of this novel Acid-Based Crossliked fluid system in different field trials. Details of the fluid design optimization are included to illustrate how a single system can replace the need for multiple fluids. The ABC fluid was formulated to meet challenging bottom-hole formation conditions that resulted in encouraging post treatment well performance.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78630210","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}
Recent diagnostic fracture injection test (DFIT) data presented on a Bourdet log-log diagnostic plot showed derivative slope of 0 in the before closure (BC) portion of the DFIT response. Some works qualitatively describe it as radial flow. This behavior has not been quantitatively analyzed, modeled and matched. The present work disagrees with the hypothesis of radial flow and successfully matches the relatively flat trend in the Bourdet derivative with a model dominated by friction dissipation coupled with tip extension. The flat trend in Bourdet derivative occurs shortly after shut-in during the before closure period. Because a flat derivative trend suggests diffusive radial flow, our first approach was to consider the possibility that an open crack at a layer interface stopped the fracture propagation and caused the apparent radial flow behavior observed in falloff data. However, a model that coupled pressure falloff from diffusive flow into a layer interface crack with pressure falloff from closure of a fracture that propagated up to the layer interface failed to reproduce the observed response. Subsequently, we discovered that existing models could match the data without considering the layer interface crack. We found that data processing is very important to what is observed in derivative trends and can mislead the behavior diagnosis. We succeeded to match one field DFIT case showing an obvious early flat trend. The presence and dominance of geomechanics, coupled with diffusive flow, disqualify the description of the flat trend in Bourdet derivative as radial flow. Instead, flow friction coupled with tip extension can completely match the observed behavior. Based on our model, cases with a long flat trend have large magnitude near-wellbore tortuosity friction loss and relatively long tip extension distance. Further, we match the near wellbore tortuosity behavior with rate raised to a power lower than the usually assumed 0.5. The significance of these analyses relates to two key factors. First, large magnitude near wellbore tortuosity friction loss increases the pressure required for fracture propagation during pumping. Second, tip extension is a way to dissipate high pumping pressure when very low formation permeability impedes leakoff. Matching transient behavior subject to the presence of both of these factors requires lowering the near-wellbore tortuosity exponent.
{"title":"Modeling of Before Closure Zero Slope Pressure Derivative in a Diagnostic Fracture Injection Test DFIT","authors":"Guoqing Liu, Jie Wang, C. Ehlig-Economides","doi":"10.2118/205317-ms","DOIUrl":"https://doi.org/10.2118/205317-ms","url":null,"abstract":"\u0000 Recent diagnostic fracture injection test (DFIT) data presented on a Bourdet log-log diagnostic plot showed derivative slope of 0 in the before closure (BC) portion of the DFIT response. Some works qualitatively describe it as radial flow. This behavior has not been quantitatively analyzed, modeled and matched. The present work disagrees with the hypothesis of radial flow and successfully matches the relatively flat trend in the Bourdet derivative with a model dominated by friction dissipation coupled with tip extension.\u0000 The flat trend in Bourdet derivative occurs shortly after shut-in during the before closure period. Because a flat derivative trend suggests diffusive radial flow, our first approach was to consider the possibility that an open crack at a layer interface stopped the fracture propagation and caused the apparent radial flow behavior observed in falloff data. However, a model that coupled pressure falloff from diffusive flow into a layer interface crack with pressure falloff from closure of a fracture that propagated up to the layer interface failed to reproduce the observed response. Subsequently, we discovered that existing models could match the data without considering the layer interface crack.\u0000 We found that data processing is very important to what is observed in derivative trends and can mislead the behavior diagnosis. We succeeded to match one field DFIT case showing an obvious early flat trend. The presence and dominance of geomechanics, coupled with diffusive flow, disqualify the description of the flat trend in Bourdet derivative as radial flow. Instead, flow friction coupled with tip extension can completely match the observed behavior. Based on our model, cases with a long flat trend have large magnitude near-wellbore tortuosity friction loss and relatively long tip extension distance. Further, we match the near wellbore tortuosity behavior with rate raised to a power lower than the usually assumed 0.5.\u0000 The significance of these analyses relates to two key factors. First, large magnitude near wellbore tortuosity friction loss increases the pressure required for fracture propagation during pumping. Second, tip extension is a way to dissipate high pumping pressure when very low formation permeability impedes leakoff. Matching transient behavior subject to the presence of both of these factors requires lowering the near-wellbore tortuosity exponent.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"595 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74720597","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Shaoul, Jason Park, A. Boucher, I. Tkachuk, C. Veeken, Suleiman Salmi, Khalfan Bahri, M. Rashdi, Dariusz Nazaruk
The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.
{"title":"Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman","authors":"J. Shaoul, Jason Park, A. Boucher, I. Tkachuk, C. Veeken, Suleiman Salmi, Khalfan Bahri, M. Rashdi, Dariusz Nazaruk","doi":"10.2118/205328-ms","DOIUrl":"https://doi.org/10.2118/205328-ms","url":null,"abstract":"\u0000 The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020.\u0000 The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity.\u0000 Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel.\u0000 Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73490848","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}
Ruqaiya Al Zadjali, Sandeep Mahaja, Mathieu M. Molenaar
Hydraulic Fracturing (HF) is widely used in PDO in low permeability tight gas formations to enhance production. The application of HF has been expanded to the Oil South as conventional practice in enhancing the recovery and production at lower cost. HF stimulation is used in a number of prospects in the south Oman, targeting sandstone formations such as Gharif, Al Khlata, Karim and Khaleel, most of which have undergone depletion. Fracture dimension are influenced by a combination of operational, well design and subsurface parameters such as injected fluid properties, injection rate, well inclination and azimuth, rock mechanical properties, formation stresses (i.e. fracture pressures) etc. Accurate fracture pressure estimate in HF design and modeling improves reliability of HF placement, which is the key for improved production performance of HF. HF treatments in the studied fields provide large volumes of valuable data. Developing standardized tables and charts can streamline the process to generate input parameters for HF modeling and design in an efficient and consistent manner. Results of the study can assist with developing guidelines and workflow and for HF operations. Field HF data from more than 100 wells in south Oman fields were analyzed to derive the magnitude of breakdown pressure (BP), Fracture Breakdown Pressure (FBP), Instantaneous Shut-In Pressure (ISIP) pressure, and Fracture Closure Pressure (FCP) and develop input correlations for HF design. Estimated initial FCP (in-situ pore pressure conditions) is in the range of 15.6 - 16 kPa/mTVD at reservoir formation pressure gradient of about 10.8 kPa/m TVD bdf. However, most of the fields have undergone variable degree of depletion prior to the HF operation. Horizontal stresses in the reservoir decrease with depletion, it is therefore important to assess the reduction of FCP with reduction in pore pressure (stress depletion). Depletion stress path coefficient (i.e. change on FCP as a fraction of change in pore pressure) was derived based on historic field data and used to predict reduction of FCP as a function of future depletion. Data from this field indicates that the magnitude of decrease in fracture pressure is about 50% of the pore pressure change. Based on the data analysis of available HF data, standardized charts and tables were developed to estimate FCP, FBP, and ISIP values. Ratios of FBP and ISIP to FCP were computed to establish trend with depth to provide inputs to HF planning and design. Results indicate FBP/FCP ratio ranges between 1.24-1.35 and ISIP/FCP ratio ranges between 1.1 to 1.2. Developed workflow and standardized tables, charts and trends provide reliable predictions inputs for HF modeling and design. Incorporating these data can be leveraged to optimize parameters for HF design and modeling for future wells.
{"title":"Improved Efficiency and Reliability of Hydraulic Fracture Modeling and Design with Standardized Stress Inputs for South Oil Fields in Sultanate of Oman","authors":"Ruqaiya Al Zadjali, Sandeep Mahaja, Mathieu M. Molenaar","doi":"10.2118/205283-ms","DOIUrl":"https://doi.org/10.2118/205283-ms","url":null,"abstract":"\u0000 Hydraulic Fracturing (HF) is widely used in PDO in low permeability tight gas formations to enhance production. The application of HF has been expanded to the Oil South as conventional practice in enhancing the recovery and production at lower cost.\u0000 HF stimulation is used in a number of prospects in the south Oman, targeting sandstone formations such as Gharif, Al Khlata, Karim and Khaleel, most of which have undergone depletion.\u0000 Fracture dimension are influenced by a combination of operational, well design and subsurface parameters such as injected fluid properties, injection rate, well inclination and azimuth, rock mechanical properties, formation stresses (i.e. fracture pressures) etc. Accurate fracture pressure estimate in HF design and modeling improves reliability of HF placement, which is the key for improved production performance of HF. HF treatments in the studied fields provide large volumes of valuable data.\u0000 Developing standardized tables and charts can streamline the process to generate input parameters for HF modeling and design in an efficient and consistent manner. Results of the study can assist with developing guidelines and workflow and for HF operations.\u0000 Field HF data from more than 100 wells in south Oman fields were analyzed to derive the magnitude of breakdown pressure (BP), Fracture Breakdown Pressure (FBP), Instantaneous Shut-In Pressure (ISIP) pressure, and Fracture Closure Pressure (FCP) and develop input correlations for HF design. Estimated initial FCP (in-situ pore pressure conditions) is in the range of 15.6 - 16 kPa/mTVD at reservoir formation pressure gradient of about 10.8 kPa/m TVD bdf. However, most of the fields have undergone variable degree of depletion prior to the HF operation. Horizontal stresses in the reservoir decrease with depletion, it is therefore important to assess the reduction of FCP with reduction in pore pressure (stress depletion). Depletion stress path coefficient (i.e. change on FCP as a fraction of change in pore pressure) was derived based on historic field data and used to predict reduction of FCP as a function of future depletion. Data from this field indicates that the magnitude of decrease in fracture pressure is about 50% of the pore pressure change.\u0000 Based on the data analysis of available HF data, standardized charts and tables were developed to estimate FCP, FBP, and ISIP values. Ratios of FBP and ISIP to FCP were computed to establish trend with depth to provide inputs to HF planning and design. Results indicate FBP/FCP ratio ranges between 1.24-1.35 and ISIP/FCP ratio ranges between 1.1 to 1.2.\u0000 Developed workflow and standardized tables, charts and trends provide reliable predictions inputs for HF modeling and design. Incorporating these data can be leveraged to optimize parameters for HF design and modeling for future wells.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75237895","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 objectives of this investigation were to perform a rock mechanical study to evaluate long term stability of Resin-Coated Proppant (RCP), combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations. Thereby providing a tool for the industry to know exactly the duration of the shut-in time before putting a well back onto production. A new experimental method was developed to monitor the curing process of RCP as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature, while the tested RCP sample was being housed in a pressurized vessel. The pressurized vessel was subjected to a variable temperature profile to mimic the recovery of the reservoir temperature following a propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize the potential for proppant flow back. The study has been performed on various types of RCP samples under a range of reservoir conditions. The role of closure stress, temperature, curing time and carrier fluids in attaining a maximum strength of RCP following a propped hydraulic fracturing treatment have been investigated. Also, the Unconfined Compressive Strength (UCS) of various types of RCP have been measured. The testing methods currently practiced in the industry to qualify proppant for field applications are based on physical characterization of several parameters such as the specific gravity of proppant, absolute volume, solubility, roundness, sphericity and bulk density. The sieve analysis, compressive strength, and API crush testing are also measured and reported. The API Recommended Practices; API RP56, API RP58 and API RP60 are the main procedures used to test the suitability of proppants for hydraulic fracturing treatment. However, there is no published API testing method for RCP; therefore this study introduces a new testing procedure, using acoustic velocity as a function of temperature and compressive strength as a function of time; to qualify a given RCP for a particular reservoir of known stress and temperature. The final outcome of this study is to establish a functional procedure for such measurements, in order to maximize the success of a propped hydraulic fracturing treatment and minimize the occurrence of flow back incidents.
{"title":"A New Laboratory Technique to Enhance Proppant Consolidation During Propped Hydraulic Fracturing Treatment","authors":"M. Alqam, A. H. Al-Makrami, H. Abass","doi":"10.2118/205273-ms","DOIUrl":"https://doi.org/10.2118/205273-ms","url":null,"abstract":"\u0000 The objectives of this investigation were to perform a rock mechanical study to evaluate long term stability of Resin-Coated Proppant (RCP), combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations. Thereby providing a tool for the industry to know exactly the duration of the shut-in time before putting a well back onto production.\u0000 A new experimental method was developed to monitor the curing process of RCP as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature, while the tested RCP sample was being housed in a pressurized vessel. The pressurized vessel was subjected to a variable temperature profile to mimic the recovery of the reservoir temperature following a propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize the potential for proppant flow back. The study has been performed on various types of RCP samples under a range of reservoir conditions. The role of closure stress, temperature, curing time and carrier fluids in attaining a maximum strength of RCP following a propped hydraulic fracturing treatment have been investigated. Also, the Unconfined Compressive Strength (UCS) of various types of RCP have been measured.\u0000 The testing methods currently practiced in the industry to qualify proppant for field applications are based on physical characterization of several parameters such as the specific gravity of proppant, absolute volume, solubility, roundness, sphericity and bulk density. The sieve analysis, compressive strength, and API crush testing are also measured and reported. The API Recommended Practices; API RP56, API RP58 and API RP60 are the main procedures used to test the suitability of proppants for hydraulic fracturing treatment. However, there is no published API testing method for RCP; therefore this study introduces a new testing procedure, using acoustic velocity as a function of temperature and compressive strength as a function of time; to qualify a given RCP for a particular reservoir of known stress and temperature.\u0000 The final outcome of this study is to establish a functional procedure for such measurements, in order to maximize the success of a propped hydraulic fracturing treatment and minimize the occurrence of flow back incidents.","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86592158","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}
An optimist says the glass is half-full, a pessimist half-empty, whereas a good engineer says that the glass is twice as big as it needs to be. There has been much debate over the years about the relative functionality, application and even necessity of proppant in delivering effective hydraulic fractures. Often these debates have been directly linked to major changes in core frac applications, more recently in the dominant North American onshore unconventional market. However, the debates have all too often used broad or unclear brush strokes to describe shifting fracture requirements. Meanwhile, the developing oilfield in the rest of the world resides in more permeable areas of the resource triangle, great care must be taken to ensure that conventional lessons hard learned are not lost, but also that unconventional understanding develops. Over recent years there have been many debates and publications on the relative value of the use of proppant (and associated conductivity), although the true question was about appropriate fracture design in different rock/matrix qualities and environments. Certainly, the vast majority of fracturing engineers appreciate the difference between continuous proppant-pack conductivity and other techniques, such as infinite conductivity, pillar fracturing or duning designs. However, there is increasing evidence that conventional fracturing is suffering from populist attitudes, leading to ineffective fracturing. Additionally, and just as impactful, that unconventional fracturing continues to rely on the lessons learned and physics derived directly from our conventional experience but applying this in an entirely different environment. Primarily, the main concern is with the transfer of recent lessons learned and techniques utilised in one rock quality and environment, to an entirely different scenario, resulting in the misapplication, reduced IP30, poorer NPV or reduced long term EUR and IRR. Examples will be referenced where appropriate proppant selection and frac design can be the difference between success and failure. Fundamentally, we have not sufficiently developed our understanding of the role of proppant and conductivity, for application in unconventionals and thereby rely far too much on our previous conventional thinking. While at the same time we are exporting often inappropriate unconventional populist practice into very conventional environments, thereby potentially achieving the abhorrence of the worst of both worlds. This paper will describe and address scenarios where appropriate engineering selection, rather than popularity-based decision making, has resulted in a successful outcome. It will also attempt to ensure that we show the importance of studying your rock, in anticipation of engineering design, and that this should be a key consideration. The paper will also suggest that as an industry we urgently need to address our approach to consideration of conductivity, placement and importance and
{"title":"Optimist, Pessimist or Engineer - Conductivity Based on Need Not Fashion","authors":"M. Rylance","doi":"10.2118/205286-ms","DOIUrl":"https://doi.org/10.2118/205286-ms","url":null,"abstract":"\u0000 An optimist says the glass is half-full, a pessimist half-empty, whereas a good engineer says that the glass is twice as big as it needs to be. There has been much debate over the years about the relative functionality, application and even necessity of proppant in delivering effective hydraulic fractures. Often these debates have been directly linked to major changes in core frac applications, more recently in the dominant North American onshore unconventional market. However, the debates have all too often used broad or unclear brush strokes to describe shifting fracture requirements. Meanwhile, the developing oilfield in the rest of the world resides in more permeable areas of the resource triangle, great care must be taken to ensure that conventional lessons hard learned are not lost, but also that unconventional understanding develops.\u0000 Over recent years there have been many debates and publications on the relative value of the use of proppant (and associated conductivity), although the true question was about appropriate fracture design in different rock/matrix qualities and environments. Certainly, the vast majority of fracturing engineers appreciate the difference between continuous proppant-pack conductivity and other techniques, such as infinite conductivity, pillar fracturing or duning designs. However, there is increasing evidence that conventional fracturing is suffering from populist attitudes, leading to ineffective fracturing. Additionally, and just as impactful, that unconventional fracturing continues to rely on the lessons learned and physics derived directly from our conventional experience but applying this in an entirely different environment.\u0000 Primarily, the main concern is with the transfer of recent lessons learned and techniques utilised in one rock quality and environment, to an entirely different scenario, resulting in the misapplication, reduced IP30, poorer NPV or reduced long term EUR and IRR. Examples will be referenced where appropriate proppant selection and frac design can be the difference between success and failure. Fundamentally, we have not sufficiently developed our understanding of the role of proppant and conductivity, for application in unconventionals and thereby rely far too much on our previous conventional thinking. While at the same time we are exporting often inappropriate unconventional populist practice into very conventional environments, thereby potentially achieving the abhorrence of the worst of both worlds.\u0000 This paper will describe and address scenarios where appropriate engineering selection, rather than popularity-based decision making, has resulted in a successful outcome. It will also attempt to ensure that we show the importance of studying your rock, in anticipation of engineering design, and that this should be a key consideration. The paper will also suggest that as an industry we urgently need to address our approach to consideration of conductivity, placement and importance and","PeriodicalId":11171,"journal":{"name":"Day 3 Thu, January 13, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-01-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78125172","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：