This paper presents an integrated study from fracture propagation modeling to gas flow modeling and a correlation analysis to explore the key controlling factors of intensive volume fracturing.The fracture propagation...This paper presents an integrated study from fracture propagation modeling to gas flow modeling and a correlation analysis to explore the key controlling factors of intensive volume fracturing.The fracture propagation model takes into account the interaction between hydraulic fracture and natural fracture by means of the displacement discontinuity method(DDM)and the Picard iterative method.The shale gas flow considers multiple transport mechanisms,and the flow in the fracture network is handled by the embedded discrete fracture model(EDFM).A series of numerical simulations are conducted to analyze the effects of the cluster number,stage spacing,stress difference coefficient,and natural fracture distribution on the stimulated fracture area,fractal dimension,and cumulative gas production,and their correlation coefficients are obtained.The results show that the most influential factors to the stimulated fracture area are the stress difference ratio,stage spacing,and natural fracture density,while those to the cumulative gas production are the stress difference ratio,natural fracture density,and cluster number.This indicates that the stress condition dominates the gas production,and employing intensive volume fracturing(by properly increasing the cluster number)is beneficial for improving the final cumulative gas production.展开更多
To further clarify the proppant transport and placement law in multi-branched fractures induced by volume fracturing, proppant transport simulation experiments were performed with different fracture shapes, sand ratio...To further clarify the proppant transport and placement law in multi-branched fractures induced by volume fracturing, proppant transport simulation experiments were performed with different fracture shapes, sand ratios, branched fracture opening time and injection sequence of proppants in varied particle sizes. The results show that the settled proppant height increases and the placement length decreases in main fractures as the fracturing fluid diverts gradually to the branched fractures at different positions. The flow rate in branched fractures is the main factor affecting their filling. The diverion to branched fractures leads to low flow rate and poor filling of far-wellbore branched fractures. The inclined fracture wall exerts a frictional force on the proppant to slow its settlement, thus enhancing the vertical proppant distribution in the fracture. The increase of sand ratio can improve the filling of near-wellbore main fracture and far-wellbore branched fracture and also increase the settled proppant height in main fracture. Due to the limitation of fracture height, when the sand ratio increases to a certain level, the increment of fracture filling decreases. When branched fracture is always open(or extends continuously), the supporting effect on the branched fractures is the best, but the proppant placement length within the main fractures is shorter. The fractures support effect is better when it is first closed and then opened(or extends in late stage) than when it is first opened and then closed(or extends in early stage). Injecting proppants with different particle sizes in a specific sequence can improve the placement lengths of main fracture and branched fracture. Injection of proppants in an ascending order of particle size improves the near-wellbore fracture filling, to a better extent than that in a descending order of particle size.展开更多
To evaluate the fracturing effect and dynamic change process after volume fracturing with vertical wells in low permeability oil reservoirs, an oil-water two-phase flow model and a well model are built. On this basis,...To evaluate the fracturing effect and dynamic change process after volume fracturing with vertical wells in low permeability oil reservoirs, an oil-water two-phase flow model and a well model are built. On this basis, an evaluation method of fracturing effect based on production data and fracturing fluid backflow data is established, and the method is used to analyze some field cases. The vicinity area of main fracture after fracturing is divided into different stimulated regions. The permeability and area of different regions are used to characterize the stimulation strength and scale of the fracture network. The conductivity of stimulated region is defined as the product of the permeability and area of the stimulated region. Through parameter sensitivity analysis, it is found that half-length of the fracture and the permeability of the core area mainly affect the flow law near the well, that is, the early stage of production;while matrix permeability mainly affects the flow law at the far end of the fracture. Taking a typical old well in Changqing Oilfield as an example, the fracturing effect and its changes after two rounds of volume fracturing in this well are evaluated. It is found that with the increase of production time after the first volume fracturing, the permeability and conductivity of stimulated area gradually decreased, and the fracturing effect gradually decreased until disappeared;after the second volume fracturing, the permeability and conductivity of stimulated area increased significantly again.展开更多
In this paper,a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing.With this system,the effects of seconda...In this paper,a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing.With this system,the effects of secondary fracture angle,fluid displacement,proppant concentration and size,fracturing fluid viscosity and other factors on the migration and distribution of proppant were tested,and the migration and distribution of proppant in primary/secondary fractures were analyzed.The following results were obtained.First,the fluid flow pattern in fractures transforms gradually from laminar flow into turbulent flow with the increase of fracture supporting height.Second,the migration modes of proppant in fractures mainly include suspended migration and gliding migration.Third,the distribution form of proppant in primary fractures before branching is related to secondary fracture angle,fluid displacement and proppant concentration and size,among which the fluid displacement is the most important factor.Fourth,the mass ratio of proppant in primary fractures after branching is proportional to the secondary fracture angle,fluid displacement,fracturing fluid viscosity and proppant concentration and size,and is inversely proportional to the flow ratio between secondary fractures and primary fractures.Fifth,the mass ratio of proppant in secondary fractures after branching is proportional to fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures,and is inversely proportional to secondary fracture angle and proppant concentration and size.Sixth,the angle at the leading edge of proppant bank in the primary fractures after branching is proportional to the proppant concentration and size and the flow ratio between secondary fractures and primary fractures,but is inversely proportional to secondary fracture angle,fluid displacement and fracturing fluid viscosity.Seventh,the angle at the leading edge of proppant bank in the secondary fractures after branching is proportional to the secondary fracture angle and the proppant concentration and size,but is inversely proportional to the fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures.In conclusion,the research results can provide a theoretical support for proppant optimization and program design of shale reservoir volume fracturing.展开更多
Volume fracturing technology has been widely applied in the development of coalbed methane(CBM)reservoirs.As for the stimulated reservoir volume(SRV)created by volume fracturing,the seepage laws of fluids are describe...Volume fracturing technology has been widely applied in the development of coalbed methane(CBM)reservoirs.As for the stimulated reservoir volume(SRV)created by volume fracturing,the seepage laws of fluids are described more accurately and rationally in the rectangular composite model than in the traditional radial composite model.However,the rectangular composite model considering SRV cannot be solved using the analytical or semi-analytical function method,and its solution from the linear flow model has larger errors.In view of this,SRVareas of CBM reservoirs were described by means of dual-medium model in this paper.The complex CBM migration mechanisms were investigated comprehensively,including adsorption,desorption,diffusion and seepage.A well testing model for rectangular composite fracturing wells in CBM reservoirs based on unsteady-state diffusion was built and solved using the boundary element method combined with Laplace transformation,Stehfest numerical inversion and computer programming technology.Thus,production performance laws of CBM reservoirs were clarified.The flow regimes of typical well testing curves were divided and the effects on change laws of production performance from the boundary size of gas reservoirs,permeability of volume fractured areas,adsorption gas content,reservoir permeability and SRV size were analyzed.Eventually,CBM reservoirs after the volume fracturing stimulation were described more accurately and rationally.This study provides a theoretical basis for a better understanding of the CBM migration laws and an approach to evaluating and developing CBM reservoirs efficiently and rationally.展开更多
Deep shale gas reservoirs buried underground with depth being more than 3500 m are characterized by high in-situ stress,large horizontal stress difference,complex distribution of bedding and natural cracks,and strong ...Deep shale gas reservoirs buried underground with depth being more than 3500 m are characterized by high in-situ stress,large horizontal stress difference,complex distribution of bedding and natural cracks,and strong rock plasticity.Thus,during hydraulic fracturing,these reservoirs often reveal difficult fracture extension,low fracture complexity,low stimulated reservoir volume(SRV),low conductivity and fast decline,which hinder greatly the economic and effective development of deep shale gas.In this paper,a specific and feasible technique of volume fracturing of deep shale gas horizontal wells is presented.In addition to planar perforation,multi-scale fracturing,full-scale fracture filling,and control over extension of high-angle natural fractures,some supporting techniques are proposed,including multi-stage alternate injection(of acid fluid,slick water and gel)and the mixed-and small-grained proppant to be injected with variable viscosity and displacement.These techniques help to increase the effective stimulated reservoir volume(ESRV)for deep gas production.Some of the techniques have been successfully used in the fracturing of deep shale gas horizontal wells in Yongchuan,Weiyuan and southern Jiaoshiba blocks in the Sichuan Basin.As a result,Wells YY1HF and WY1HF yielded initially 14.1×10^(4)m^(3)/d and 17.5×10^(4)m^(3)/d after fracturing.The volume fracturing of deep shale gas horizontal well is meaningful in achieving the productivity of 50×108 m^(3)gas from the interval of 3500e4000 m in Phase II development of Fuling and also in commercial production of huge shale gas resources at a vertical depth of less than 6000 m.展开更多
In order to solve the difficulties in the volume fracturing stimulation of Middle Jurassic Shaximiao Formation tight sandstone reservoirs in the Qiulin Block of Central Sichuan Basin and explore the adaptability of hi...In order to solve the difficulties in the volume fracturing stimulation of Middle Jurassic Shaximiao Formation tight sandstone reservoirs in the Qiulin Block of Central Sichuan Basin and explore the adaptability of high-intensity volumefracturing technology,we selected the outcrop samples of Shaximiao Formation tight sandstone in the Qiulin Block to carry out the physical simulation experiment of true triaxial hydraulic fracturing.On this basis,horizontal well cluster perforation was optimally designed by using the production predictionmodel of staged multi-cluster fracturing horizontal wells.Then,based on the liquid control and proppant increase mode,three rounds of pilot tests were carried out on the tight sandstone reservoirs in this area.Andthe following research resultswere obtained.First,natural fractures in the ShaximiaoFormation tight sandstone reservoir of theQiulin Block are undeveloped,and hydraulic fractures are morphologically dominated by symmetric double-wing fractures,so complex fracture networks can be hardly formed.In addition,the reservoir is of medium to strong water sensitivity,so conventional volume fracturing is not adaptive to the reservoir stimulation in this block.Second,the connotation of high-intensity volume fracturing technology is to carry out multi-cluster perforation in each section to form multiple independent double-wing fractures and to implement the proppant injection mode of liquid control and proppant increase to reduce the inflowfluid while ensuring the high-intensity proppant injection,so as to reduce the damage of inflowfluid to the formation.Third,there are 10 fracturing sections inWell Qiulin 207-5-H2,with 7-12 clusters in each section,and the displacement is in the range of 16-18m^(3)/min.According to the fluid control and proppant increase mode,12146 m^(3) slick water and 4170 t proppant are injected in total.The tested production rate and absolute open flow of natural gas after the fracturing are up to 83.88×10^(4)m^(3)/d and 214.05×10^(4)m^(3)/d,respectively.Fourth,with the decrease of cluster spacing,the cumulative gas production increases gradually,but when the cluster spacing is less than 15 m,the increase amplitude of cumulative gas production decreases.Fifth,when the proppant injection intensity is lower than 6 t/m,the tested gas production per kilometer of stimulated section ina horizontal well overall presents an increasing trend with the increase of proppant injection intensity.When the proppant injection intensity is higher than 6 t/m,however,the tested gas production per kilometer of stimulated section does not increase significantly with the increase of proppant injection intensity.Sixth,as the included angle between the borehole trajectory and the direction ofmaximumhorizontal principal stress increases,the tested gas production per kilometer of stimulated section overall presents an increasing trend.When the hydraulic fracture is nearly perpendicular to the borehole,the effective drainage area is the largest and the tested gas production per kilometer of stimulated section is also the highest.In conclusion,the fracturing mode of high production well has a borehole trajectory of large included angle,perforation cluster spacing of 10 m or so,proppant injection intensity of 5 t/m and large-displacement slick water+continuous injection of combined particle size proppant.展开更多
Multi-stage volume fracturing of horizontal wells is the main means to develop tight gas reservoirs.Complex fracture networks of various shapes are generated around the wellbore after volume fracturing.At present,howe...Multi-stage volume fracturing of horizontal wells is the main means to develop tight gas reservoirs.Complex fracture networks of various shapes are generated around the wellbore after volume fracturing.At present,however,most of the well test models suitable for fracturing horizontal wells take all hydraulic fractures as single main fractures,which results in a large error between well test interpretation result and actual situation.As a result,the fracture network characteristic parameters of the stimulated areas cannot be obtained accurately.To this end,a well test model for complex fracture networks in tight-gas fracturing horizontal wells was established on the basis of the non-structural discrete fracture model.Then,this model was solved by using thefinite element method with combined triangular elements and linear elements.And accordingly,the well test type curves of a horizontal well under different fracture network patterns(rectangular,elliptical and hyperbolic)were prepared.Based on this,well test type curves were analyzed from the aspects of characteristics and influential factors and were compared with those obtained from the conventional single-fracture model.Finally,the new model was applied in well test interpretation of one multi-stage volume fracturing horizontal well in the gas reservoir of Permian Shan 1 formation in the Qingyang Gas Field of the Ordos Basin.And the following research results were obtained.First,the biggest difference of well test type curve between the fracture network model and the conventional single-fracture model occurs in the early stage,the characteristics offirst linearflow regime are replaced with the characteristics of pseudo-radialflow regime in the stimulated area.Second,the end time of the pseudo-radialflow regime in the stimulated area is mainly dominated by the size and shape of the stimulated area.The larger the stimulated area is,the longer the pseudo-radialflow regime lasts.As the shape of the stimulated area approaches to be elongated,the characteristics of the well test type curve obtained by the new model are more consistent with those by the single-fracture model.Third,the pressure derivative value of the pseudo-radialflow regime in the stimulated area is mainly dependent on the conductivity and density of the fracture network.The higher the density or the conductivity of fracture network in the stimulated area is,the earlier the wellbore storage effect regime ends,the lower the pressure derivative value of the pseudo-radialflow regime in the stimulated area is and the more obvious the characteristics of the horizontal line are.In conclusion,case study results confirm that the new model is reliable and practical and can provide accurate reservoir parameters as well as the size of the effectively stimulated area by volume fracturing and the conductivity of fracture network,which is conducive to evaluating the stimulation effect of volume fracturing and predicting the postfrac production performance.展开更多
There are abundant natural gas resources in the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin,which is an important resource base for PetroChina Changqing Oilfield Company to in...There are abundant natural gas resources in the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin,which is an important resource base for PetroChina Changqing Oilfield Company to increase the reserves and production of oil and gas.Compared with the other shale gas reservoirs at home and aboard,however,the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin has a lower formation pressure coefficient and poorer reservoir physical properties and gas-bearing property,so its production increase difficulty is higher.In this paper,horizontal-well volume fracturing was studied and tested based on the earlier vertical well tests.According to the technical idea of the staged multi-cluster massive fracturing of long horizontal section,the propagation mechanisms and morphological characteristics of fractures were studied and analyzed based on the fracturing geological characteristics of the shale gas reservoir in the Ordos Basin.On this basis,a full three-dimensional fracture model was optimally established for parameter optimization.The fracturing of the test well ZP1 was carried out with 15 stages and 103 clusters.After the fracturing,a more complex fracture network was formed with a fracture complexity index of 0.4-0.6.The microseismic monitoring zone is 579 m long and 266 m wide and the fracture is 146 m high.To address the drainage difficulty after large-volume fracturing of low-pressure shale gas in the Ordos Basin,this paper carries out a gas energized fracturing test.Considering the characteristics of reservoir physical properties,gas-bearing property and segmented fractures,805 m3 liquid nitrogen was injected in stages during the fracturing of the test horizontal well.The formation pressure coefficient measured from pressure buildup data is increased from 0.7 to 0.8 to 1.88.The wellbore gaseliquid flow model was established and the parameters of long-period controlpressure drainage were optimized.The critical surface equipment was upgraded to achieve accurate measurement,safety and environmental protection.And the following research and practice results were obtained.First,based on the technological innovation and optimization,continuous gaseliquid two-phase flow is realized in the test well ZP1 and its production rate and pressure during the test are stable with the tested daily shale gas production at the wellhead of 6.42×10^(4)m^(3).Second,after fracturing,the absolute open flow of the test well reaches 26.4×10^(4)m^(3)/d,which is more than 10 times higher than the production rate of the vertical well in the same block during the test.Thus,a significant breakthrough is realized in the exploration of marine shale gas in North China.展开更多
An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example.The characteristic curves of capillary pressure and relative permeability were ob...An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example.The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing.The optimization of the stimulated reservoir volume(SRV)fracturing fluid volume strength should meet the requirements of estimated ultimate recovery(EUR),increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount.Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed,above which the single-well EUR increase rate kept decreasing.An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production.Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.展开更多
A precise diagnosis of the complex post-fracturing characteristics and parameter variations in tight gas reservoirs is essential for optimizing fracturing technology,enhancing treatment effectiveness,and assessing pos...A precise diagnosis of the complex post-fracturing characteristics and parameter variations in tight gas reservoirs is essential for optimizing fracturing technology,enhancing treatment effectiveness,and assessing post-fracturing production capacity.Tight gas reservoirs face challenges due to the interaction between natural fractures and induced fractures.To address these issues,a theoretical model for diagnosing fractures under varying leak-off mechanisms has been developed,incorporating the closure behavior of natural fractures.This model,grounded in material balance theory,also accounts for shut-in pressure.The study derived and plotted typical G-function charts,which capture fracture behavior during closure.By superimposing the G-function in the closure phase of natural fractures with pressure derivative curves,the study explored how fracture parameters—including leak-off coefficient,fracture area,closure pressure,and closure time—impact these diagnostic charts.Findings show that variations in natural fracture flexibility,fracture area,and controlling factors influence the superimposed G-function pressure derivative curve,resulting in distinctive“concave”or“convex”patterns.Field data from Well Y in a specific tight gas reservoir were used to validate the model,confirming both its reliability and practicality.展开更多
Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for ...Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.展开更多
Due to downhole complexities,shale-gas horizontal well fracturing in the Sichuan Basin suffered from casing deformation and failure to apply the technique of cable-conveyed perforation bridge plug.In view of these pro...Due to downhole complexities,shale-gas horizontal well fracturing in the Sichuan Basin suffered from casing deformation and failure to apply the technique of cable-conveyed perforation bridge plug.In view of these problems,a new technique of staged volume fracturing with temporary plugging by sand filling is employed.Based on theoretical analyses and field tests,a design of optimized parameters of coiled tubingconveyed multi-cluster sand-blasting perforation and temporary plugging by sand filling was proposed.It was applied in the horizontalWell ZJ-1 in which casing deformation occurred.The following results are achieved in field operations.First,this technique enables selective staged fracturing in horizontal sections.Second,this technique can realize massive staged fracturing credibly without mechanical plugging,with the operating efficiency equivalent to the conventional bridge plug staged fracturing.Third,full-hole is preserved after fracturing,thus it is possible to directly conduct an open flow test without time consumption of a wiper trip.The staged volume fracturing with temporary plugging by sand filling facilitated the 14-stage fracturing in Well ZJ-1,with similar SRV to that achieved by conventional bridge plug staged fracturing and higher gas yield than neighboring wells on the same well pad.Thus,a new and effective technique is presented in multi-cluster staged volume fracturing of shale gas horizontal wells.展开更多
By introducing the coupling flow expressions of main fracture-matrix, secondary fracture-matrix and main fracture-secondary fracture into the traditional main fracture material balance equation, the “main fracture-se...By introducing the coupling flow expressions of main fracture-matrix, secondary fracture-matrix and main fracture-secondary fracture into the traditional main fracture material balance equation, the “main fracture-secondary fracture-matrix” leak-off coupling flow model is established. The pressure-dependent fracture width equation and the wellbore injection volume equation are coupled to solve the pressure-rate continuity problem. The simulation and calculation of the bottomhole pressure drop and fracture network closure after the pump stopping in slickwater volumetric fracturing treatment are realized. The research results show that the log-log curve of pump-stopping bottomhole pressure drop derivative presents five characteristic slope segments, reflecting four dominant stages, i.e. inter-fracture crossflow, fracture network leak-off, fracture network closure and residual leak-off, after pump shutdown. At the initial time of pump shutdown for volumetric fracturing treatment of horizontal well, the crossflow between main and secondary fractures is obvious, and then the leak-off becomes dominant. The leak-off of main and secondary fractures shows a non-uniform decreasing trend. Specifically, the leak-off of main fractures is slow, while that of secondary fractures is fast;the fracture network as a whole presents the leak-off law of fast first, then slow, until close to zero. The influence of fracture network conductivity on the shape of pressure decline curve is relatively weaker than that of fracture network size. The fracture network conductivity is positively correlated with leak-off volume and fracture closure. The secondary fracture size is positively correlated with leakoff volume and closure of the secondary fracture, but negatively correlated with closure of the main fracture. Field data validation proves that the proposed model and simulation results can effectively reflect the closure characteristics of the fracture network, and the interpretation results are reliable and can reflect the non-uniform stimulation performance of each fracturing stage of an actual horizontal well.展开更多
基金supported by the National Natural Science Foundation of China(Nos.52274038,5203401042174143)+1 种基金the Taishan Scholars Project(No.tsqnz20221140)the Open Fund of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation(Southwest Petroleum University)of China(No.PLN2020-5)。
文摘This paper presents an integrated study from fracture propagation modeling to gas flow modeling and a correlation analysis to explore the key controlling factors of intensive volume fracturing.The fracture propagation model takes into account the interaction between hydraulic fracture and natural fracture by means of the displacement discontinuity method(DDM)and the Picard iterative method.The shale gas flow considers multiple transport mechanisms,and the flow in the fracture network is handled by the embedded discrete fracture model(EDFM).A series of numerical simulations are conducted to analyze the effects of the cluster number,stage spacing,stress difference coefficient,and natural fracture distribution on the stimulated fracture area,fractal dimension,and cumulative gas production,and their correlation coefficients are obtained.The results show that the most influential factors to the stimulated fracture area are the stress difference ratio,stage spacing,and natural fracture density,while those to the cumulative gas production are the stress difference ratio,natural fracture density,and cluster number.This indicates that the stress condition dominates the gas production,and employing intensive volume fracturing(by properly increasing the cluster number)is beneficial for improving the final cumulative gas production.
基金Supported by the National Natural Science Foundation of China (52074332,52204024)Outstanding Youth Foundation of Shandong Province (ZR2020YQ36)China Postdoctoral Science Foundation (M710225)。
文摘To further clarify the proppant transport and placement law in multi-branched fractures induced by volume fracturing, proppant transport simulation experiments were performed with different fracture shapes, sand ratios, branched fracture opening time and injection sequence of proppants in varied particle sizes. The results show that the settled proppant height increases and the placement length decreases in main fractures as the fracturing fluid diverts gradually to the branched fractures at different positions. The flow rate in branched fractures is the main factor affecting their filling. The diverion to branched fractures leads to low flow rate and poor filling of far-wellbore branched fractures. The inclined fracture wall exerts a frictional force on the proppant to slow its settlement, thus enhancing the vertical proppant distribution in the fracture. The increase of sand ratio can improve the filling of near-wellbore main fracture and far-wellbore branched fracture and also increase the settled proppant height in main fracture. Due to the limitation of fracture height, when the sand ratio increases to a certain level, the increment of fracture filling decreases. When branched fracture is always open(or extends continuously), the supporting effect on the branched fractures is the best, but the proppant placement length within the main fractures is shorter. The fractures support effect is better when it is first closed and then opened(or extends in late stage) than when it is first opened and then closed(or extends in early stage). Injecting proppants with different particle sizes in a specific sequence can improve the placement lengths of main fracture and branched fracture. Injection of proppants in an ascending order of particle size improves the near-wellbore fracture filling, to a better extent than that in a descending order of particle size.
基金Supported by the China National Science and Technology Major Project (2017ZX05013-001)CNPC Science and Technology Major Research Project (2018B-4907)
文摘To evaluate the fracturing effect and dynamic change process after volume fracturing with vertical wells in low permeability oil reservoirs, an oil-water two-phase flow model and a well model are built. On this basis, an evaluation method of fracturing effect based on production data and fracturing fluid backflow data is established, and the method is used to analyze some field cases. The vicinity area of main fracture after fracturing is divided into different stimulated regions. The permeability and area of different regions are used to characterize the stimulation strength and scale of the fracture network. The conductivity of stimulated region is defined as the product of the permeability and area of the stimulated region. Through parameter sensitivity analysis, it is found that half-length of the fracture and the permeability of the core area mainly affect the flow law near the well, that is, the early stage of production;while matrix permeability mainly affects the flow law at the far end of the fracture. Taking a typical old well in Changqing Oilfield as an example, the fracturing effect and its changes after two rounds of volume fracturing in this well are evaluated. It is found that with the increase of production time after the first volume fracturing, the permeability and conductivity of stimulated area gradually decreased, and the fracturing effect gradually decreased until disappeared;after the second volume fracturing, the permeability and conductivity of stimulated area increased significantly again.
基金supported by the Science Foundation for Young Scientists of National Natural Science Foundation of China,“Study on the Diversion and Distribution Mechanisms of Proppant for“Multi-Stage And Multi-Cluster”Fracturing by Shale Horizontal Well”(Grant No.51604050)the Chongqing Science and Technology Innovation Project for People's Livelihood,“Research&Development of Instruments for Evaluating the Migration and Distribution of Proppant for“Multi-Stage And Multi-Cluster”Fracturing by Shale Horizontal Well”(Grant No.cstc2016shmszx90003).
文摘In this paper,a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing.With this system,the effects of secondary fracture angle,fluid displacement,proppant concentration and size,fracturing fluid viscosity and other factors on the migration and distribution of proppant were tested,and the migration and distribution of proppant in primary/secondary fractures were analyzed.The following results were obtained.First,the fluid flow pattern in fractures transforms gradually from laminar flow into turbulent flow with the increase of fracture supporting height.Second,the migration modes of proppant in fractures mainly include suspended migration and gliding migration.Third,the distribution form of proppant in primary fractures before branching is related to secondary fracture angle,fluid displacement and proppant concentration and size,among which the fluid displacement is the most important factor.Fourth,the mass ratio of proppant in primary fractures after branching is proportional to the secondary fracture angle,fluid displacement,fracturing fluid viscosity and proppant concentration and size,and is inversely proportional to the flow ratio between secondary fractures and primary fractures.Fifth,the mass ratio of proppant in secondary fractures after branching is proportional to fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures,and is inversely proportional to secondary fracture angle and proppant concentration and size.Sixth,the angle at the leading edge of proppant bank in the primary fractures after branching is proportional to the proppant concentration and size and the flow ratio between secondary fractures and primary fractures,but is inversely proportional to secondary fracture angle,fluid displacement and fracturing fluid viscosity.Seventh,the angle at the leading edge of proppant bank in the secondary fractures after branching is proportional to the secondary fracture angle and the proppant concentration and size,but is inversely proportional to the fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures.In conclusion,the research results can provide a theoretical support for proppant optimization and program design of shale reservoir volume fracturing.
基金supported by the National Natural Science Foundation of China“Basic Research on Reservoir Anhydration and Gas Flow Capacity Improvement in Tight Gas Reservoir”(No.:51534006)the Scientific Research Starting Project of Southwest Petroleum University(No.:2015QHZ003)the Development Fund for Young Scholars of Southwest Petroleum University(No.:201599010088).
文摘Volume fracturing technology has been widely applied in the development of coalbed methane(CBM)reservoirs.As for the stimulated reservoir volume(SRV)created by volume fracturing,the seepage laws of fluids are described more accurately and rationally in the rectangular composite model than in the traditional radial composite model.However,the rectangular composite model considering SRV cannot be solved using the analytical or semi-analytical function method,and its solution from the linear flow model has larger errors.In view of this,SRVareas of CBM reservoirs were described by means of dual-medium model in this paper.The complex CBM migration mechanisms were investigated comprehensively,including adsorption,desorption,diffusion and seepage.A well testing model for rectangular composite fracturing wells in CBM reservoirs based on unsteady-state diffusion was built and solved using the boundary element method combined with Laplace transformation,Stehfest numerical inversion and computer programming technology.Thus,production performance laws of CBM reservoirs were clarified.The flow regimes of typical well testing curves were divided and the effects on change laws of production performance from the boundary size of gas reservoirs,permeability of volume fractured areas,adsorption gas content,reservoir permeability and SRV size were analyzed.Eventually,CBM reservoirs after the volume fracturing stimulation were described more accurately and rationally.This study provides a theoretical basis for a better understanding of the CBM migration laws and an approach to evaluating and developing CBM reservoirs efficiently and rationally.
基金Supported by the Foundation of State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms Effective Development.
文摘Deep shale gas reservoirs buried underground with depth being more than 3500 m are characterized by high in-situ stress,large horizontal stress difference,complex distribution of bedding and natural cracks,and strong rock plasticity.Thus,during hydraulic fracturing,these reservoirs often reveal difficult fracture extension,low fracture complexity,low stimulated reservoir volume(SRV),low conductivity and fast decline,which hinder greatly the economic and effective development of deep shale gas.In this paper,a specific and feasible technique of volume fracturing of deep shale gas horizontal wells is presented.In addition to planar perforation,multi-scale fracturing,full-scale fracture filling,and control over extension of high-angle natural fractures,some supporting techniques are proposed,including multi-stage alternate injection(of acid fluid,slick water and gel)and the mixed-and small-grained proppant to be injected with variable viscosity and displacement.These techniques help to increase the effective stimulated reservoir volume(ESRV)for deep gas production.Some of the techniques have been successfully used in the fracturing of deep shale gas horizontal wells in Yongchuan,Weiyuan and southern Jiaoshiba blocks in the Sichuan Basin.As a result,Wells YY1HF and WY1HF yielded initially 14.1×10^(4)m^(3)/d and 17.5×10^(4)m^(3)/d after fracturing.The volume fracturing of deep shale gas horizontal well is meaningful in achieving the productivity of 50×108 m^(3)gas from the interval of 3500e4000 m in Phase II development of Fuling and also in commercial production of huge shale gas resources at a vertical depth of less than 6000 m.
基金Project supported by the Scientific Research and Technical Development Project of Postdoctoral Workstation of PetroChina Southwest Oil and Gas Field Company“Research on fracture morphology control and reconstruction technology of tight sandstone gas reservoir in Jinhua-Zhongtaishan ShaximiaoFormation”(No:20190302-15).
文摘In order to solve the difficulties in the volume fracturing stimulation of Middle Jurassic Shaximiao Formation tight sandstone reservoirs in the Qiulin Block of Central Sichuan Basin and explore the adaptability of high-intensity volumefracturing technology,we selected the outcrop samples of Shaximiao Formation tight sandstone in the Qiulin Block to carry out the physical simulation experiment of true triaxial hydraulic fracturing.On this basis,horizontal well cluster perforation was optimally designed by using the production predictionmodel of staged multi-cluster fracturing horizontal wells.Then,based on the liquid control and proppant increase mode,three rounds of pilot tests were carried out on the tight sandstone reservoirs in this area.Andthe following research resultswere obtained.First,natural fractures in the ShaximiaoFormation tight sandstone reservoir of theQiulin Block are undeveloped,and hydraulic fractures are morphologically dominated by symmetric double-wing fractures,so complex fracture networks can be hardly formed.In addition,the reservoir is of medium to strong water sensitivity,so conventional volume fracturing is not adaptive to the reservoir stimulation in this block.Second,the connotation of high-intensity volume fracturing technology is to carry out multi-cluster perforation in each section to form multiple independent double-wing fractures and to implement the proppant injection mode of liquid control and proppant increase to reduce the inflowfluid while ensuring the high-intensity proppant injection,so as to reduce the damage of inflowfluid to the formation.Third,there are 10 fracturing sections inWell Qiulin 207-5-H2,with 7-12 clusters in each section,and the displacement is in the range of 16-18m^(3)/min.According to the fluid control and proppant increase mode,12146 m^(3) slick water and 4170 t proppant are injected in total.The tested production rate and absolute open flow of natural gas after the fracturing are up to 83.88×10^(4)m^(3)/d and 214.05×10^(4)m^(3)/d,respectively.Fourth,with the decrease of cluster spacing,the cumulative gas production increases gradually,but when the cluster spacing is less than 15 m,the increase amplitude of cumulative gas production decreases.Fifth,when the proppant injection intensity is lower than 6 t/m,the tested gas production per kilometer of stimulated section ina horizontal well overall presents an increasing trend with the increase of proppant injection intensity.When the proppant injection intensity is higher than 6 t/m,however,the tested gas production per kilometer of stimulated section does not increase significantly with the increase of proppant injection intensity.Sixth,as the included angle between the borehole trajectory and the direction ofmaximumhorizontal principal stress increases,the tested gas production per kilometer of stimulated section overall presents an increasing trend.When the hydraulic fracture is nearly perpendicular to the borehole,the effective drainage area is the largest and the tested gas production per kilometer of stimulated section is also the highest.In conclusion,the fracturing mode of high production well has a borehole trajectory of large included angle,perforation cluster spacing of 10 m or so,proppant injection intensity of 5 t/m and large-displacement slick water+continuous injection of combined particle size proppant.
文摘Multi-stage volume fracturing of horizontal wells is the main means to develop tight gas reservoirs.Complex fracture networks of various shapes are generated around the wellbore after volume fracturing.At present,however,most of the well test models suitable for fracturing horizontal wells take all hydraulic fractures as single main fractures,which results in a large error between well test interpretation result and actual situation.As a result,the fracture network characteristic parameters of the stimulated areas cannot be obtained accurately.To this end,a well test model for complex fracture networks in tight-gas fracturing horizontal wells was established on the basis of the non-structural discrete fracture model.Then,this model was solved by using thefinite element method with combined triangular elements and linear elements.And accordingly,the well test type curves of a horizontal well under different fracture network patterns(rectangular,elliptical and hyperbolic)were prepared.Based on this,well test type curves were analyzed from the aspects of characteristics and influential factors and were compared with those obtained from the conventional single-fracture model.Finally,the new model was applied in well test interpretation of one multi-stage volume fracturing horizontal well in the gas reservoir of Permian Shan 1 formation in the Qingyang Gas Field of the Ordos Basin.And the following research results were obtained.First,the biggest difference of well test type curve between the fracture network model and the conventional single-fracture model occurs in the early stage,the characteristics offirst linearflow regime are replaced with the characteristics of pseudo-radialflow regime in the stimulated area.Second,the end time of the pseudo-radialflow regime in the stimulated area is mainly dominated by the size and shape of the stimulated area.The larger the stimulated area is,the longer the pseudo-radialflow regime lasts.As the shape of the stimulated area approaches to be elongated,the characteristics of the well test type curve obtained by the new model are more consistent with those by the single-fracture model.Third,the pressure derivative value of the pseudo-radialflow regime in the stimulated area is mainly dependent on the conductivity and density of the fracture network.The higher the density or the conductivity of fracture network in the stimulated area is,the earlier the wellbore storage effect regime ends,the lower the pressure derivative value of the pseudo-radialflow regime in the stimulated area is and the more obvious the characteristics of the horizontal line are.In conclusion,case study results confirm that the new model is reliable and practical and can provide accurate reservoir parameters as well as the size of the effectively stimulated area by volume fracturing and the conductivity of fracture network,which is conducive to evaluating the stimulation effect of volume fracturing and predicting the postfrac production performance.
基金Project supported by the National Major Science and Technology Project“Development Demonstration Project of Large-scale Low-permeability Lithologic-Stratigraphic Reservoirs in the Ordos Basin”(No.2016ZX05050)。
文摘There are abundant natural gas resources in the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin,which is an important resource base for PetroChina Changqing Oilfield Company to increase the reserves and production of oil and gas.Compared with the other shale gas reservoirs at home and aboard,however,the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin has a lower formation pressure coefficient and poorer reservoir physical properties and gas-bearing property,so its production increase difficulty is higher.In this paper,horizontal-well volume fracturing was studied and tested based on the earlier vertical well tests.According to the technical idea of the staged multi-cluster massive fracturing of long horizontal section,the propagation mechanisms and morphological characteristics of fractures were studied and analyzed based on the fracturing geological characteristics of the shale gas reservoir in the Ordos Basin.On this basis,a full three-dimensional fracture model was optimally established for parameter optimization.The fracturing of the test well ZP1 was carried out with 15 stages and 103 clusters.After the fracturing,a more complex fracture network was formed with a fracture complexity index of 0.4-0.6.The microseismic monitoring zone is 579 m long and 266 m wide and the fracture is 146 m high.To address the drainage difficulty after large-volume fracturing of low-pressure shale gas in the Ordos Basin,this paper carries out a gas energized fracturing test.Considering the characteristics of reservoir physical properties,gas-bearing property and segmented fractures,805 m3 liquid nitrogen was injected in stages during the fracturing of the test horizontal well.The formation pressure coefficient measured from pressure buildup data is increased from 0.7 to 0.8 to 1.88.The wellbore gaseliquid flow model was established and the parameters of long-period controlpressure drainage were optimized.The critical surface equipment was upgraded to achieve accurate measurement,safety and environmental protection.And the following research and practice results were obtained.First,based on the technological innovation and optimization,continuous gaseliquid two-phase flow is realized in the test well ZP1 and its production rate and pressure during the test are stable with the tested daily shale gas production at the wellhead of 6.42×10^(4)m^(3).Second,after fracturing,the absolute open flow of the test well reaches 26.4×10^(4)m^(3)/d,which is more than 10 times higher than the production rate of the vertical well in the same block during the test.Thus,a significant breakthrough is realized in the exploration of marine shale gas in North China.
文摘An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example.The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing.The optimization of the stimulated reservoir volume(SRV)fracturing fluid volume strength should meet the requirements of estimated ultimate recovery(EUR),increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount.Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed,above which the single-well EUR increase rate kept decreasing.An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production.Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.
文摘A precise diagnosis of the complex post-fracturing characteristics and parameter variations in tight gas reservoirs is essential for optimizing fracturing technology,enhancing treatment effectiveness,and assessing post-fracturing production capacity.Tight gas reservoirs face challenges due to the interaction between natural fractures and induced fractures.To address these issues,a theoretical model for diagnosing fractures under varying leak-off mechanisms has been developed,incorporating the closure behavior of natural fractures.This model,grounded in material balance theory,also accounts for shut-in pressure.The study derived and plotted typical G-function charts,which capture fracture behavior during closure.By superimposing the G-function in the closure phase of natural fractures with pressure derivative curves,the study explored how fracture parameters—including leak-off coefficient,fracture area,closure pressure,and closure time—impact these diagnostic charts.Findings show that variations in natural fracture flexibility,fracture area,and controlling factors influence the superimposed G-function pressure derivative curve,resulting in distinctive“concave”or“convex”patterns.Field data from Well Y in a specific tight gas reservoir were used to validate the model,confirming both its reliability and practicality.
基金Supported by China National Major Project of Science and Technology(2016ZX05046-004)PetroChina Major Project of Science and Technology(2017B-4905)PetroChina Jilin Oilfield Company Major Project of Science and Technology(JY21A2-12).
文摘Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.
基金supported by the National Major Science and Technology Project“Experimental study on shale gas production in Zhaotong County,Yunnan Province”(No.:2012ZX0518-006)Major Project of CNPC“Field test of shale gas drilling and production engineering technology in Zhaotong demonstration zone”(No.:2012F-47-02).
文摘Due to downhole complexities,shale-gas horizontal well fracturing in the Sichuan Basin suffered from casing deformation and failure to apply the technique of cable-conveyed perforation bridge plug.In view of these problems,a new technique of staged volume fracturing with temporary plugging by sand filling is employed.Based on theoretical analyses and field tests,a design of optimized parameters of coiled tubingconveyed multi-cluster sand-blasting perforation and temporary plugging by sand filling was proposed.It was applied in the horizontalWell ZJ-1 in which casing deformation occurred.The following results are achieved in field operations.First,this technique enables selective staged fracturing in horizontal sections.Second,this technique can realize massive staged fracturing credibly without mechanical plugging,with the operating efficiency equivalent to the conventional bridge plug staged fracturing.Third,full-hole is preserved after fracturing,thus it is possible to directly conduct an open flow test without time consumption of a wiper trip.The staged volume fracturing with temporary plugging by sand filling facilitated the 14-stage fracturing in Well ZJ-1,with similar SRV to that achieved by conventional bridge plug staged fracturing and higher gas yield than neighboring wells on the same well pad.Thus,a new and effective technique is presented in multi-cluster staged volume fracturing of shale gas horizontal wells.
基金Supported by the National Natural Science Foundation of China (51974332)。
文摘By introducing the coupling flow expressions of main fracture-matrix, secondary fracture-matrix and main fracture-secondary fracture into the traditional main fracture material balance equation, the “main fracture-secondary fracture-matrix” leak-off coupling flow model is established. The pressure-dependent fracture width equation and the wellbore injection volume equation are coupled to solve the pressure-rate continuity problem. The simulation and calculation of the bottomhole pressure drop and fracture network closure after the pump stopping in slickwater volumetric fracturing treatment are realized. The research results show that the log-log curve of pump-stopping bottomhole pressure drop derivative presents five characteristic slope segments, reflecting four dominant stages, i.e. inter-fracture crossflow, fracture network leak-off, fracture network closure and residual leak-off, after pump shutdown. At the initial time of pump shutdown for volumetric fracturing treatment of horizontal well, the crossflow between main and secondary fractures is obvious, and then the leak-off becomes dominant. The leak-off of main and secondary fractures shows a non-uniform decreasing trend. Specifically, the leak-off of main fractures is slow, while that of secondary fractures is fast;the fracture network as a whole presents the leak-off law of fast first, then slow, until close to zero. The influence of fracture network conductivity on the shape of pressure decline curve is relatively weaker than that of fracture network size. The fracture network conductivity is positively correlated with leak-off volume and fracture closure. The secondary fracture size is positively correlated with leakoff volume and closure of the secondary fracture, but negatively correlated with closure of the main fracture. Field data validation proves that the proposed model and simulation results can effectively reflect the closure characteristics of the fracture network, and the interpretation results are reliable and can reflect the non-uniform stimulation performance of each fracturing stage of an actual horizontal well.
