Shale gas is an important component of unconventional oil and gas resources.Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery.Recent imbibition studies have focused o...Shale gas is an important component of unconventional oil and gas resources.Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery.Recent imbibition studies have focused on shale matrix,and the pressure conditions discussed were mostly atmospheric.The initial imbibition behavior begins from propped fractures to matrix,but there are few studies working on explaining the imbibition behavior in propped fractures or the phenomenon of many shale wells exhibit higher productivity after a“soaking”period.Therefore,propped fracture samples were designed for imbibition and migration experiments.In order to accurately study the mechanism and main influencing factors of fracturing fluid imbibition and migration in propped and unpropped shale fractures under high temperature and high pressure,a series of experiments based on nuclear magnetic resonance(NMR)were carried out.Results showed that NMR T_(2) spectra of all samples exhibited a bimodal distribution.The final imbibition volume of fracturing fluid was positively related to pressure and fracture width.The imbibition effect of fracturing fluid was more evident in matrix pores under high pressure.In the migration during soaking stage,the fracturing fluid gradually migrated from large pores to small pores and gradually displaced the shale gas from the matrix,thus allowing the water blocking in propped fractures to self-unlock to some extent.Gas permeability decreased in the imbibition stage,while it recovered in the migration stage to some extent.展开更多
Shale gas is an important unconventional resource.The economic recovery of shale gas is only possible when a fracture network with sufficient conductivity is created by hydraulic fracturing,that,if effectively propped...Shale gas is an important unconventional resource.The economic recovery of shale gas is only possible when a fracture network with sufficient conductivity is created by hydraulic fracturing,that,if effectively propped,connects fracturing fractures and natural fractures.Focusing on the Longmaxi shale in the Sichuan Basin,Southwest China,we built an optimization model for conductivity of multi-grade fractures based on equivalent seepage theory.We then experimentally analyzed the conductivity of self-propped and sand-propped fractures,and optimized the propping patterns of multi-grade hydraulic fractures in shale gas reservoirs.We concluded that the propping effectiveness of fracture networks could be improved by using low concentrations of small-sized sands and by focusing on creating a large number of self-propped fractures.By applying this understanding to the optimization of fracturing designs for the Longmaxi shale,we successfully created networks of well-propped fractures.展开更多
Proppant flowback in the post-fracturing flowback period not only reduces the fracture conductivity but also damages equipment.Due to the current lack of experimental or numerical simulation methods for proppant flowb...Proppant flowback in the post-fracturing flowback period not only reduces the fracture conductivity but also damages equipment.Due to the current lack of experimental or numerical simulation methods for proppant flowback in partial closure fracture,the mechanisms and patterns of proppant flowback remain unclear.This makes it difficult to predict the risks of proppant flowback,leaving flowback program design without theoretical guidance and resulting in high uncertainty in prevention effectiveness.This paper has further modified the CFD-DEM(Computational Fluid Dynamics-Discrete Element Method)coupling interface by introducing fracture closure pressure into the particle motion equation.Based on the dynamic mesh,the fracture width in the CFD model is adjusted in real time to establish a numerical simulation method that considers fracture closure and synchronous changes in the flow field.By establishing flow similarity at the perforations,a near-wellbore flow field is created in the scaled model that is representative of field conditions,ensuring the practical value of the experimental results.Based on proppant particle force analysis during flowback,we investigated the impact of closure pressure,friction coefficient,perforation parameters,fracture dip angle,proppant particle size combination on proppant flowback.The research indicates that the existence of a threshold closure pressure arises from the competition between the lateral force(driving flowback)exerted by fracture closure on particles and the frictional force(resisting flowback)acting on particles.Below this threshold,increasing closure pressure enhances near-wellbore proppant flowback;above this threshold,increased closure pressure reduces proppant flowback.This threshold value is determined to be 1 MPa under the simulation conditions of this paper.The friction coefficient between particles and the fracture wall has greater impact on particle flowback than the friction coefficient between particles.In the vertical direction of the fracture,flowback is more probable for particles above the perforation.There is higher risk of particle flowback in horizontal fractures.The lateral distribution of large and small particles is more effective in preventing flowback than the vertical distribution.In the horizontal direction,particles nearer to the perforation have a higher probability of flowback.Strategies for proppant flowback control:the flow rate should be kept low initially,and then increased after the bottomhole pressure has been appropriately reduced;perforations should be placed in the upper part of the reservoir(vertical well);the sand concentration should not be increased in the later stages of fracturing to reduce the accumulation of proppant above the perforations;different size proppants should be injected in smaller sizes followed by larger sizes,with a slug of clean fluid in between to achieve a side-by-side placement of larger and smaller proppant,thereby mitigating proppant flowback.展开更多
基金The authors gratefully acknowledge the support of the National Natural Science Foundation of China(Grant Nos.52174036,51774243,51904257,51874251)the Sichuan Province Science and Technology Program(Grant Nos.2021YJ0345,2022JDJQ0009,2022NSFSC0186).
文摘Shale gas is an important component of unconventional oil and gas resources.Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery.Recent imbibition studies have focused on shale matrix,and the pressure conditions discussed were mostly atmospheric.The initial imbibition behavior begins from propped fractures to matrix,but there are few studies working on explaining the imbibition behavior in propped fractures or the phenomenon of many shale wells exhibit higher productivity after a“soaking”period.Therefore,propped fracture samples were designed for imbibition and migration experiments.In order to accurately study the mechanism and main influencing factors of fracturing fluid imbibition and migration in propped and unpropped shale fractures under high temperature and high pressure,a series of experiments based on nuclear magnetic resonance(NMR)were carried out.Results showed that NMR T_(2) spectra of all samples exhibited a bimodal distribution.The final imbibition volume of fracturing fluid was positively related to pressure and fracture width.The imbibition effect of fracturing fluid was more evident in matrix pores under high pressure.In the migration during soaking stage,the fracturing fluid gradually migrated from large pores to small pores and gradually displaced the shale gas from the matrix,thus allowing the water blocking in propped fractures to self-unlock to some extent.Gas permeability decreased in the imbibition stage,while it recovered in the migration stage to some extent.
基金This study was supported by the National Major Science and Technology Project(No.2016ZX05060-004 and 2016ZX05023-001)the Petro China Major Science and Technology Project(No.2016E-0612).
文摘Shale gas is an important unconventional resource.The economic recovery of shale gas is only possible when a fracture network with sufficient conductivity is created by hydraulic fracturing,that,if effectively propped,connects fracturing fractures and natural fractures.Focusing on the Longmaxi shale in the Sichuan Basin,Southwest China,we built an optimization model for conductivity of multi-grade fractures based on equivalent seepage theory.We then experimentally analyzed the conductivity of self-propped and sand-propped fractures,and optimized the propping patterns of multi-grade hydraulic fractures in shale gas reservoirs.We concluded that the propping effectiveness of fracture networks could be improved by using low concentrations of small-sized sands and by focusing on creating a large number of self-propped fractures.By applying this understanding to the optimization of fracturing designs for the Longmaxi shale,we successfully created networks of well-propped fractures.
基金support of the National Natural Science Foundation of China(Grant No.52474069)the National Natural Science Foundation of China(No.52104060).
文摘Proppant flowback in the post-fracturing flowback period not only reduces the fracture conductivity but also damages equipment.Due to the current lack of experimental or numerical simulation methods for proppant flowback in partial closure fracture,the mechanisms and patterns of proppant flowback remain unclear.This makes it difficult to predict the risks of proppant flowback,leaving flowback program design without theoretical guidance and resulting in high uncertainty in prevention effectiveness.This paper has further modified the CFD-DEM(Computational Fluid Dynamics-Discrete Element Method)coupling interface by introducing fracture closure pressure into the particle motion equation.Based on the dynamic mesh,the fracture width in the CFD model is adjusted in real time to establish a numerical simulation method that considers fracture closure and synchronous changes in the flow field.By establishing flow similarity at the perforations,a near-wellbore flow field is created in the scaled model that is representative of field conditions,ensuring the practical value of the experimental results.Based on proppant particle force analysis during flowback,we investigated the impact of closure pressure,friction coefficient,perforation parameters,fracture dip angle,proppant particle size combination on proppant flowback.The research indicates that the existence of a threshold closure pressure arises from the competition between the lateral force(driving flowback)exerted by fracture closure on particles and the frictional force(resisting flowback)acting on particles.Below this threshold,increasing closure pressure enhances near-wellbore proppant flowback;above this threshold,increased closure pressure reduces proppant flowback.This threshold value is determined to be 1 MPa under the simulation conditions of this paper.The friction coefficient between particles and the fracture wall has greater impact on particle flowback than the friction coefficient between particles.In the vertical direction of the fracture,flowback is more probable for particles above the perforation.There is higher risk of particle flowback in horizontal fractures.The lateral distribution of large and small particles is more effective in preventing flowback than the vertical distribution.In the horizontal direction,particles nearer to the perforation have a higher probability of flowback.Strategies for proppant flowback control:the flow rate should be kept low initially,and then increased after the bottomhole pressure has been appropriately reduced;perforations should be placed in the upper part of the reservoir(vertical well);the sand concentration should not be increased in the later stages of fracturing to reduce the accumulation of proppant above the perforations;different size proppants should be injected in smaller sizes followed by larger sizes,with a slug of clean fluid in between to achieve a side-by-side placement of larger and smaller proppant,thereby mitigating proppant flowback.
