A method and apparatus for predicting recovery of fractured shale reservoirs

Abstract

The present application relates to a kind of prediction method and device of recovery efficiency of fractured shale reservoir, belong to the technical field of oil and gas exploration and development, the method includes the following steps: respectively constructing the mathematical model of fluid imbibition position in single organic nanometer hole, single inorganic nanometer hole and single microfracture;Scale upgrading is carried out to single nanometer hole and single microfracture using fractal theory, respectively obtain the total number of pore of nanometer hole and the total number of microfracture of core of fractured shale reservoir;Respectively calculate the imbibition oil production in all nanometer holes and the imbibition oil production in all microfractures;The recovery efficiency in the process of spontaneous imbibition and forced imbibition of fractured shale reservoir is calculated respectively.The prediction method and device of recovery efficiency of fractured shale reservoir disclosed in the present application can simply, quickly and efficiently predict the imbibition oil displacement rate, production and recovery efficiency in the process of shale reservoir fracturing and well killing, and have great significance for realizing effective development of shale reservoir.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas exploration and development technology, specifically relating to a method and apparatus for predicting the recovery rate of fractured shale oil reservoirs. Background Technology

[0002] Since the beginning of the 21st century, with the increasing global demand for energy, oil and gas development has entered the unconventional oil and gas stage. The exploration and development of unconventional oil and gas reservoirs has developed rapidly worldwide and has become an important part of the oil and gas supply system.

[0003] Predicting the recovery rate of shale oil reservoirs is crucial in oilfield development. Accurate recovery rate prediction not only helps in selecting optimal production enhancement measures but also aids in formulating and adjusting reasonable development plans. Currently, recovery rate prediction methods in the early stages of conventional oilfield development mainly rely on static geological data, such as analogy methods, empirical formulas, and core experiments. Mid-stage recovery rate prediction methods primarily rely on the large amounts of data accumulated during development, such as waterdrive characteristic curves, production decline curves, Tong's charts, BP neural networks, and reservoir numerical simulations. However, for shale oil reservoirs, due to their unique nonlinear flow characteristics, research on recovery rate prediction methods is relatively limited. Existing recovery rate prediction methods are insufficient for accurately predicting shale oil reservoir recovery rates. Therefore, the ability to accurately predict shale oil reservoir recovery rates is of great significance for guiding shale oilfield development. Summary of the Invention

[0004] To address the aforementioned problems, the present invention aims to provide a method and apparatus for predicting the recovery rate of fractured shale oil reservoirs, thereby solving the problem that existing recovery rate prediction methods cannot predict the recovery rate of shale oil reservoirs.

[0005] To achieve the above objectives, the present invention adopts the following technical solution: This invention discloses a method for predicting the recovery rate of fractured shale oil reservoirs, including... Based on the different pore types, pore types are divided into single nanopores and single microcracks. Single nanopores are further divided into single organic nanopores and single inorganic nanopores. Mathematical models of fluid permeation sites in single organic nanopores, single inorganic nanopores and single microcracks are constructed respectively. Fractal theory was used to scale up the individual nanopores and individual microfractures, respectively, to obtain the total number of nanopores in the core of fractured shale oil reservoirs. and the total number of microcracks ; Based on mathematical models of fluid permeation sites in single organic or inorganic nanopores and the total number of nanopores in fractured shale reservoirs... Calculate the percolation production in all nanopores of a fractured shale reservoir core; and calculate the percolation production based on a mathematical model of the fluid percolation location in a single microfracture and the total number of microfractures. Calculate the amount of oil produced by percolation in all microfractures of a core sample from a fractured shale reservoir; Based on the oil production from all nanopores in the core of the fractured shale reservoir and the oil production from all microfractures in the core of the fractured shale reservoir, as well as the total oil-bearing volume of the core, the recovery rate of the fractured shale reservoir during spontaneous and forced adsorption processes is calculated respectively.

[0006] Specifically, the mathematical model for the fluid permeation sites within the single organic nanopore is as follows: (1) In the formula, Indicates that at time The time radius is The location of fluid permeation at the oil-water front interface in organic nanopores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0007] Specifically, the inorganic nanopores include brittle mineral pores and clay mineral pores, and the mathematical models for the fluid permeation sites in a single inorganic nanopore include mathematical models for the fluid permeation sites in a single brittle mineral pore and mathematical models for the fluid permeation sites in a single clay mineral pore. The mathematical model for the fluid permeation location in a single brittle mineral pore is as follows: (2) In the formula, Indicates that at time The time radius is The location of fluid seepage at the oil-water front interface in the brittle mineral pores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the thickness of the immovable boundary layer; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core; The mathematical model for the fluid seepage location in a single clay mineral pore is as follows: (3) In the formula, Indicates that at time The time radius is The location of fluid seepage at the oil-water front interface in the pores of clay minerals; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the osmotic pressure of water absorption by shale; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0008] Specifically, the mathematical model for the fluid absorption location in the single microcrack is as follows: (4) In the formula, Indicates that at time Opening degree is The location of fluid seepage at the oil-water front interface in microcracks; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the external displacement pressure difference; It refers to the opening of the microcracks; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the location of seepage and absorption at the oil-water front interface; It is the dip angle of the rock core; No. j -1 corresponds to the oil-water front interface seepage location.

[0010] Furthermore, the total number of nanopores in the core of the fractured shale oil reservoir The expression is: (20) In the formula, It is the total number of nanopores in the core of a fractured shale oil reservoir; It is the fractal dimension of the pores; It refers to the porosity of the nanopore core. It is the diameter of the rock core; It is the pore radius of the nanopore; It is the maximum pore radius of the nanopore; The total number of microfractures in the core of the fractured shale reservoir. The expression is: (twenty one) In the formula, It is the total number of microfractures in the core of a fractured shale reservoir; It refers to the porosity of the rock core with micro-fractures; It is the diameter of the rock core; It is the ratio of the length to the aperture of the microcrack; It refers to the tortuosity of the microcracks; It is the fractal dimension of the microcrack; It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack.

[0011] Furthermore, the expression for the percolation oil production in all nanopores of the core of the fractured shale oil reservoir is as follows: (25) In the formula, It is the amount of oil produced by percolation in all nanopores of the core of a fractured shale oil reservoir; It is the minimum pore radius of the nanopore; It is the maximum pore radius of the nanopore; It is the pore radius of the nanopore; It is in time The time radius is The location of fluid permeation at the oil-water front interface in the nanopore; It is the total number of nanopores in the core of a fractured shale oil reservoir; It is the fractal dimension of the pores; It refers to the porosity of the nanopore core. It is the diameter of the rock core; It is the pore radius of the nanopore; The expression for the oil production from all microfractures in the core of the fractured shale reservoir is as follows: (26) In the formula, It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the length of the microcrack; It is in time Opening degree is The location of oil-water front interface seepage in microcracks; It is the total number of microfractures in the core of a fractured shale oil reservoir.

[0012] Furthermore, the recovery rate of spontaneous adsorption in the fractured shale reservoir... The expression is: (31) In the formula, This represents the total oil production during the spontaneous adsorption process; This represents the total oil-bearing volume of the core. The total oil production during the spontaneous adsorption process. The expression is: (28) In the formula, It is the total oil production from the pores of clay minerals; It is the total oil production from the pores of brittle minerals; It is the total oil production from microcracks; Forced absorption recovery rate of fractured shale reservoirs The expression is: (33) In the formula, To force the absorption of total oil production; This represents the total oil-bearing volume of the core. The total oil production from forced permeation The expression is:

[0013] In the formula, It is the total oil production of organic nanopores; It is the total oil production from the pores of clay minerals; It is the total oil production from the pores of brittle minerals; It is the total oil production from microcracks; The total oil-bearing volume of the core The expression is: (30) In the formula, Indicates when The corresponding volumes of organic nanopores, brittle mineral pores, and clay mineral pores, respectively; It is the diameter of the rock core; Indicates when The porosity of the core samples corresponding to organic nanopores, brittle mineral pores, and clay mineral pores, respectively; It refers to the porosity of the rock core with micro-fractures; , ,in, It refers to the tortuosity of the microcracks. When The tortuosity of the nanopores corresponding to each time period. It is the core length.

[0014] This invention also discloses a device for predicting the recovery rate of fractured shale oil reservoirs, including... The first processing unit is used to classify pore types into single nanopores and single microcracks according to different pore types. The single nanopores are further divided into organic nanopores and inorganic nanopores. Mathematical models of fluid permeation sites in single organic nanopores, single inorganic nanopores and single microcracks are constructed respectively. The second processing unit is used to scale up the individual nanopores and individual microfractures using fractal theory, thereby obtaining the total number of nanopores in the core of the fractured shale oil reservoir. and the total number of microcracks ; The third processing unit is used to calculate the fluid permeation location in a single organic or inorganic nanopore based on a mathematical model and the total number of nanopores in fractured shale reservoirs. Calculate the percolation production in all nanopores of a fractured shale reservoir core; and calculate the percolation production based on a mathematical model of the fluid percolation location in a single microfracture and the total number of microfractures. Calculate the amount of oil produced by percolation in all microfractures of a core sample from a fractured shale reservoir; The fourth processing unit is used to calculate the recovery rate of the fractured shale oil reservoir during the spontaneous and forced adsorption processes based on the amount of oil produced by percolation in all nanopores of the core, the amount of oil produced by percolation in all microfractures of the core, and the total oil-bearing volume of the core.

[0015] The present invention also discloses a computer-readable storage medium having a computer program stored thereon, wherein the computer program, when executed by a processor, implements the steps of the above-described method.

[0016] The present invention also discloses a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the steps of the method described above.

[0017] The present invention has the following advantages due to the adoption of the above technical solutions: (I) This invention discloses a method and apparatus for predicting the recovery rate of fractured shale oil reservoirs. The method first classifies pore types into single nanopores and single microfractures based on their pore type. Single nanopores are further divided into single organic nanopores and single inorganic nanopores. Mathematical models are constructed for the fluid absorption locations in single organic nanopores, single inorganic nanopores, and single microfractures, respectively. These mathematical models fully consider micro- and nanoscale constraint effects, such as slip, boundary layer thickness, and osmotic pressure, improving the accuracy of the mathematical models. They can also be used to describe the characteristics of simultaneous fluid seepage in shale pores and fractures. Secondly, fractal theory is used to scale up the single nanopores and single microfractures, obtaining the total number of nanopores in the core of the fractured shale oil reservoir. and the total number of microcracks Furthermore, based on the mathematical model of the fluid permeation location in a single organic nanopore or a single inorganic nanopore and the total number of pores in the nanopores of fractured shale oil reservoirs... The study calculated the percolation production in all nanopores of a fractured shale oil reservoir core, and used a mathematical model of the fluid percolation location in a single microfracture and the total number of microfractures. This study calculates the oil production from all microfractures in the core of fractured shale oil reservoirs. This method, which calculates seepage in parallel across shale pores and fractures to form a generalized oil production figure, more closely approximates engineering practice. Finally, based on the oil production from all nanopores and microfractures in the core of fractured shale oil reservoirs, as well as the total oil-bearing volume of the core, the recovery rate is calculated for both spontaneous and forced seepage processes in fractured shale oil reservoirs. (II) This invention discloses a method and apparatus for predicting the recovery rate of fractured shale oil reservoirs. This method starts from the actual seepage laws of shale oil reservoirs, fully considers the differences in seepage characteristics of different pore types, and takes into account the constraint effect and gravity buoyancy effect in nanotubes. Finally, it constructs a generalized displacement-absorption mathematical model that can simultaneously describe the seepage characteristics of shale pores and fractures, achieving a mathematical characterization of the seepage mechanism. This invention's method and apparatus for predicting the recovery rate of fractured shale oil reservoirs can simulate not only the spontaneous absorption process dominated by capillary force, but also the forced absorption process under external displacement pressure. It can simply, quickly, and efficiently predict the absorption displacement rate, production, and recovery rate at any moment during the fracturing and shut-in process of shale oil reservoirs, which is of great significance for the effective development of shale oil reservoirs.

[0018] (III) The present invention discloses a method and apparatus for predicting the recovery rate of fractured shale oil reservoirs. This method fully considers the complex porous media types in shale reservoirs, the mixed wettability of organic and inorganic nanopores, the micro- and nanoscale confinement effects, external displacement pressure gradients, capillary forces, viscous resistance, gravity, buoyancy, etc., and the distribution characteristics of different pores and fractures. Among them, the slip phenomenon is considered for organic nanopores, and an equivalent slip length is introduced. Boundary layer effects were considered in inorganic nanopores, and the boundary layer thickness was introduced. Osmotic pressure was considered in the pores of clay minerals. The study combines the capillary bundle model with Poiseuille's equation and the flat plate bundle model with Newton's second law to establish an effective, convenient, and rapid mathematical characterization of the seepage mechanism and recovery prediction during the development of fractured wells in shale oil reservoirs. This method can be used to predict the seepage displacement rate, production, or recovery rate at any point during the fracturing and sump-forming process of shale oil reservoirs. It is not only applicable to engineering practice but also to the study of seepage mechanisms in porous media of shale oil reservoirs and to accurately predict their recovery rates, which is of great significance for the development of fractured and sump-forming wells in shale oil reservoirs. Attached Figure Description

[0019] Figure 1 This is a schematic diagram of the slip phenomenon in organic nanopores and the boundary layer effect in inorganic nanopores provided in Embodiment 1 of the present invention; Figure 2 This is an equivalent schematic diagram of different fracture types in shale provided in Embodiment 1 of the present invention; Figure 3 This is a stress analysis of different pore types during the fracturing fluid seepage process provided in Embodiment 1 of the present invention; wherein in Figure 3 middle, It is capillary force. It's osmotic pressure. It's buoyancy. It is gravity. It is viscous resistance. It is external displacement pressure; Figure 4 This is a schematic diagram of the organic nanoporous oil-water two-phase permeation and adsorption provided in Embodiment 1 of the present invention; Figure 5 This is a schematic diagram of the oil-water two-phase permeation of inorganic nanopores provided in Embodiment 1 of the present invention, wherein, Figure 5 (a) is a schematic diagram of oil-water two-phase percolation in the pores of brittle minerals. Figure 5 (b) is a schematic diagram of oil-water two-phase percolation in clay mineral pores; Figure 6 This is a schematic diagram of the oil-water two-phase percolation in the pores of inorganic shale clay minerals provided in Embodiment 1 of the present invention, wherein, Figure 6(a) is a schematic diagram of the oil-water two-phase permeation mechanism in the mineral pores of shale clay. Figure 6 (b) is a schematic diagram of fracturing fluid transport in the mineral pores of shale clay under osmotic pressure; Figure 7 This is a schematic diagram of the percolation and absorption of oil and water phases in microcracks provided in Embodiment 1 of the present invention; Figure 8 (a) The relationship between the oil-water interface and time during spontaneous absorption in a single pore and crack provided in Embodiment 1 of the present invention; Figure 8 (b) The relationship between the oil-water interface and time under forced permeation with a pressure gradient of 25 MPa / m provided in Embodiment 1 of the present invention; Figure 9 (a) is a schematic diagram of a shale porous media model with fractal characteristics provided in Embodiment 1 of the present invention; Figure 9 (b) is a schematic diagram of the simplified model provided in Embodiment 1 of the present invention; Figure 10 This is the relationship between the oil production rate and time during spontaneous or forced adsorption at the core scale, as provided in Embodiment 1 of the present invention. Figure 11 This is the relationship between spontaneous or forced seepage recovery rate and time at any point in the core at the time specified in Example 1 of the present invention. Figure 12 This is the relationship between the spontaneous or forced oil production per cubic meter of rock sample and time, as provided in Example 1 of the present invention. Detailed Implementation

[0020] Exemplary embodiments of the invention will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the invention are shown in the drawings, it should be understood that the invention can be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided to enable a more thorough understanding of the invention and to fully convey the scope of the invention to those skilled in the art.

[0021] This invention discloses a method and apparatus for predicting the recovery rate of fractured shale oil reservoirs. Addressing the characteristics of shale reservoirs—diverse mineral compositions, complex pore structures, and widespread microfractures—the core samples of fractured shale oil reservoirs mainly contain three types of porous media: organic nanopores, inorganic nanopores, and microfractures. Inorganic nanopores can be further divided into brittle mineral pores and clay mineral pores based on their mineral composition. Microfractures can be classified into natural bedding fractures and tectonic fractures formed after hydraulic fracturing, depending on their formation method. Due to the different wettability of different pore types and the fact that pore sizes are mostly at the micro-nano level, the solid-liquid molecular forces within the confined micro-nano pores create complex fluid properties and wall-side liquid-solid flow characteristics. Numerous studies have shown that significant slip and adsorption phenomena exist within individual nanopores. Both organic and inorganic nanopores are at the micro-nano level; the difference lies in that organic nanopores are oleophilic, while inorganic nanopores are hydrophilic. Furthermore, organic nanopores are typically smaller than inorganic nanopores, resulting in a more pronounced confinement effect. This makes the slip length of fluids in organic nanopores much greater than that in inorganic nanopores.

[0022] Example 1 Example 1 provides a method for predicting the recovery rate of fractured shale oil reservoirs, applied to the process of fracturing oil displacement and well-to-well seepage, including the following steps: Step A: Based on the different pore types, the pore types are divided into single nanopores and single microcracks. Single nanopores are further divided into single organic nanopores and single inorganic nanopores. Mathematical models of fluid permeation sites in single organic nanopores, single inorganic nanopores and single microcracks are constructed respectively.

[0023] It should be noted that nanopores refer to shale nanopores, which are typically spherical pores with pore radii ranging from a few nanometers to several hundred nanometers. Organic nanopores are mainly concentrated in the tens of nanometers, while inorganic nanopores are mainly concentrated in the hundreds of nanometers. Microcracks refer to cracks that are perceptible to the naked eye, usually referring to the aperture of the crack. The crack aperture ranges from several hundred nanometers to several hundred micrometers. Also known as crack width.

[0024] The mathematical model for the fluid permeation sites in a single organic nanopore is as follows: (1) In the formula, Indicates that at time The time radius is The location of fluid permeation at the oil-water front interface in organic nanopores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0025] The inorganic nanopores include brittle mineral pores and clay mineral pores, and the mathematical models for the fluid permeation sites in a single inorganic nanopore include mathematical models for the fluid permeation sites in a single brittle mineral pore and mathematical models for the fluid permeation sites in a single clay mineral pore.

[0026] The mathematical model for the fluid seepage location in a single brittle mineral pore is as follows: (2) In the formula, Indicates that at time The time radius is The location of fluid seepage at the oil-water front interface in the brittle mineral pores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the thickness of the immovable boundary layer; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0028] The mathematical model for the fluid seepage location in a single clay mineral pore is as follows: (3) In the formula, Indicates that at time The time radius is The location of fluid seepage at the oil-water front interface in the pores of clay minerals; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the osmotic pressure of water absorption by shale; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No.j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0030] The mathematical model for the fluid absorption location in a single microcrack is as follows: (4) In the formula, Indicates that at time Opening degree is The location of fluid seepage at the oil-water front interface in microcracks; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the external displacement pressure difference; It refers to the opening of the microcracks; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the location of seepage and absorption at the oil-water front interface; It is the dip angle of the rock core; No. j -1 corresponds to the oil-water front interface seepage location.

[0031] In step A, to investigate the different seepage patterns of shale oil in pores and fractures, the constructed mathematical model of seepage is required to describe the seepage patterns in both pores and microfractures simultaneously, such as... Figure 1 As shown. In this model, the internal pores of the rock are equivalent to capillary bundles, and the cracks are equivalent to flat plate bundles, as shown below. Figure 2 As shown.

[0032] To obtain the time-varying relationship of the fracturing fluid infiltration front position for different pore types, the Poiseuille equation considering the micro-nano scale constraint effect was used to describe the flow in the pores. Then, Newton's second law was applied to obtain the time-varying relationship of the fracture infiltration front. The stress conditions in different pore types during fracturing fluid infiltration are as follows: Figure 3 As shown. Since the transport of fluid media is taken into account, the constructed percolation mathematical model should be a generalized displacement percolation mathematical model.

[0033] The following sections describe the derivation of mathematical models for fluid permeation sites in single organic nanopores, single inorganic nanopores, and single microcracks.

[0034] (1) Mathematical model of fluid permeation sites in a single organic nanopore For a single organic nanopore, reference Figure 4 In typical percolation processes, the internal forces include capillary force, viscous resistance, gravity, and buoyancy. However, because the crude oil in organic nanopores is mainly attached to kerogen, the wettability of organic nanopores exhibits lipophilicity. In this case, the capillary force, which is the main driving force in spontaneous percolation, becomes percolation resistance, making spontaneous percolation difficult. Therefore, the effective utilization of crude oil in organic nanopores requires external displacement pressure.

[0035] The presence of slip in organic nanopores causes a change in the velocity field. By introducing the slip length, the velocity field distribution was recalculated through integration, yielding the equation for the interfacial migration velocity of a single organic nanopore: (5) in, It is the migration velocity of the oil-water interface in organic nanopores; It is the moment of oil-water interface movement in organic nanopores; These are the oil-water front interface permeation sites of organic nanopores; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the core length; It is the dip angle of the rock core; It is the viscosity of the aqueous phase; It is the viscosity of the oil phase.

[0036] Due to the highly complex fluid transport mechanisms in shale, analytical solutions for the locations of interfacial adsorption cannot be directly obtained. Therefore, numerical solutions for the locations of adsorption at the oil-water front are derived here using the finite difference method.

[0037] The equation for the migration velocity at the organic nanopore interface is transformed as follows: (6) When the absorption time is from Increase to At that time, the location of absorption is from Increase to ,use Replace the right side of the above equation Time interval When the value is sufficiently small, the error caused by this approximation method can be ignored, and the above equation can ultimately be expressed as the following integral form: (7) Integrating the above equation yields an approximate numerical solution for the location of the infiltration. (8) In the formula, Indicates that at time The time radius is The oil-water front interface of organic nanopores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0039] so, The radius of time is The oil production rate through fluid percolation in a single organic nanopore is: (9) In the formula, express The radius of time is The amount of oil produced by fluid permeation in a single organic nanopore; Indicates the first j The radius of the corresponding organic nanopore; Indicates the first j The corresponding oil-water front interface of the organic nanopore is the site of infiltration and adsorption.

[0040] Numerous scholars have studied the flow of single-phase fluids in organic nanopores, revealing that both oil and water phases exhibit slippage within these pores, with equivalent slip lengths... The length of oil transport within the nanopores of mixed-wet shale is expressed as follows: (10) In the formula, δ is the average distance between molecules in adjacent layers, and its value is 0.5 nm; This is the relaxation time of a large number of fluid molecules; It is the equivalent activation energy of fluid molecules; Let be the equivalent relaxation time of the fluid molecules. It is a natural constant.

[0041] (2) Mathematical model of fluid permeation sites in a single inorganic nanopore Slip also exists in inorganic nanopores, but the effect of slip in inorganic nanopores is negligible compared to that in organic nanopores.

[0042] To describe the flow behavior of fluids in inorganic nanopores, refer to Figure 5(a) By reasonably neglecting the slip length in inorganic nanopores, the thickness of the stationary boundary layer is introduced to characterize the immobile fluid in inorganic nanopores. Similar to the derivation process in organic nanopores, the velocity field distribution is redefined to obtain the interface migration velocity equation in a single inorganic nanopore.

[0043] Inorganic nanopores are classified into brittle mineral pores and clay mineral pores. Therefore, the mathematical models for the fluid permeation sites in a single inorganic nanopore include mathematical models for the fluid permeation sites in a single brittle mineral pore and mathematical models for the fluid permeation sites in a single clay mineral pore.

[0044] The following sections describe the derivation of mathematical models for fluid absorption locations in a single brittle mineral pore and a single clay mineral pore.

[0045] Equation for interface migration rate in brittle mineral pores: (11) In the formula, Interfacial velocity of fluid in the pores of brittle minerals; It is the moment of oil-water interface movement in organic nanopores; It is the location of the oil-water front interface of the brittle mineral pores; It is the pore radius of the nanopore; It is the thickness of the immovable boundary layer; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the core length; It is the dip angle of the rock core; It is the viscosity of the aqueous phase; It is the viscosity of the oil phase.

[0046] Assume that a stationary boundary layer is formed in the inorganic nanopores due to mineral adsorption, and the presence of this stationary boundary layer reduces fluid flow. Regarding the stationary boundary layer, what is its thickness? The empirical formula is: (12) In the formula, Where is the pore radius; For pressure gradient; It is the fluid viscosity; , and The value of depends on the fluid type; for deionized water... , , .

[0047] Similarly, based on the finite difference method, a mathematical model for the pore absorption location of brittle minerals can be further obtained: (2) In the formula, Indicates that at time The time radius is The location of the oil-water front interface in the brittle mineral pores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the thickness of the immovable boundary layer; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0048] so, The radius of time is The percolation oil production rate of a single brittle mineral pore is: (13) In the formula, express The radius of time is The percolation oil production from a single brittle mineral pore; Indicates the first j The radius of the pore in the brittle mineral corresponding to the step; Indicates the first j The location of the oil-water front interface of the corresponding brittle mineral pore.

[0049] Taking into account the permeability of clay minerals, refer to Figure 5 (b) The expression for the interfacial velocity in the pores of clay minerals is: (14) In the formula, Interfacial velocity of fluid in the pores of clay minerals; It is the moment of oil-water interface movement in organic nanopores; It is the location of the oil-water front interface of the clay mineral pores; It is the pore radius of the nanopore; It is the thickness of the immovable boundary layer; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the osmotic pressure of water absorption by shale; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the core length; It is the dip angle of the rock core; It is the viscosity of the aqueous phase; It is the viscosity of the oil phase.

[0050] Among them, the osmotic pressure of shale water absorption The expression is: (15) In the formula, This is the efficiency of the permeation membrane, and its value is between 0 and 1; It is the molar volume of water. =1.8×10 -5 m 3 / mol; It is a constant. =8.314 J / K·mol; It is absolute temperature; and These are formation water salinity and fracturing fluid salinity, respectively.

[0051] Shale contains extremely high levels of clay minerals; rich shale formations may contain up to 80% clay. For shale, due to its pore structure and clay content, certain physical or electrochemical forces at the molecular level, such as osmosis, cannot be ignored. Therefore, unlike brittle mineral pores, the influence of osmotic pressure must be additionally considered during the adsorption-displacement process of shale clay mineral pores. Figure 6 As shown in (a), the migration process of formation water and fracturing fluid generates osmotic pressure. The two-phase permeation mechanism of oil and water in shale clay mineral pores is as follows: Figure 6 As shown in (b).

[0052] Similarly, the numerical solution for the fluid absorption location in the pores of clay minerals can be obtained based on the finite difference method: (3) In the formula, Indicates that at time The time radius is The location of seepage at the oil-water front interface of clay mineral pores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; The osmotic pressure at which shale absorbs water; It is the interfacial tension between oil and water; It is the wetting angle; It is the osmotic pressure of water absorption by shale; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

[0053] so, The radius of time is The oil production from fluid percolation in a single clay mineral pore is: (16) In the formula, express The radius of time is The amount of oil produced by fluid percolation in a single clay mineral pore; Indicates the first j The radius of the clay mineral pore corresponding to the step; Indicates the first j The location of the oil-water front interface of the clay mineral pore corresponding to the step.

[0054] (3) Mathematical model of fluid absorption location in a single microcrack Shale oil reservoirs have well-developed bedding fractures, typically several hundred micrometers in size. Since the fracture size is much larger than the pore size, it is reasonable to assume that there are no micro- or nano-scale confinement effects within the fractures. The forces acting on fully submerged fractures during the absorption process include: displacement pressure, capillary force, viscous resistance, gravity, and buoyancy.

[0055] Since the size of fractures is much larger than the size of pores, it is reasonable to assume that there is no micro- or nano-scale confinement effect within the fractures. Currently, shale oil development mainly utilizes horizontal well fracturing, which generates a large number of artificial fractures, thereby effectively improving crude oil displacement efficiency. Based on different formation methods, fractures can be classified into bedding fractures and structural fractures, such as… Figure 2 As shown.

[0056] Taking the oil-water two-phase system as the research object, and referring to Figure 7 and Figure 3 According to Newton's second law, the mechanical equation for the seepage process in a single crack can be expressed as: (17) In the formula, It is external displacement pressure; It is capillary force; It is buoyancy; It is viscous resistance; It is gravity; It is acceleration; It refers to fluid mass.

[0057] The equation for the interface migration velocity of a single crack is obtained by integration: (18) In the formula, It is the interfacial migration velocity of the fluid in the crack; It is the moment of oil-water interface movement in organic nanopores; It is the location of oil-water seepage at the oil-water front interface of the microcrack; It is the external displacement pressure difference; It refers to the opening of the microcracks; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the core length; It is the dip angle of the rock core; It is the viscosity of the aqueous phase; It is the viscosity of the oil phase.

[0058] Similarly, the numerical solution for the location of fluid absorption in the crack can be approximately obtained by using the finite difference method for integration: (4) In the formula, Indicates that at time Opening degree is The location of fluid seepage at the oil-water front interface in microcracks; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the external displacement pressure difference; It refers to the opening of the microcracks; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the location of oil-water seepage at the oil-water front interface of the microcrack; It is the dip angle of the rock core; No. j -1 corresponds to the oil-water front interface seepage location.

[0059] so, The opening degree at any time is The oil production from fluid seepage in a single fracture is: (19) In the formula, for The opening degree at any time is Oil production from seepage in a single fracture; To indicate the first j The aperture of the microcrack corresponding to the step; Indicates the first j The length of the microcrack corresponding to the step; Indicates the first j The location of the oil-water front interface in the corresponding microcrack.

[0060] in, This indicates the location of the oil-water front interface for infiltration and adsorption in organic nanopores, brittle mineral pores, clay mineral pores, or microcracks. Indicates the first jThe corresponding oil-water front interface of the nanopores or microcracks is the site of infiltration and absorption.

[0061] Mathematical models for fluid infiltration locations in single organic nanopores, single inorganic nanopores, and single microfractures were constructed using the finite difference method, namely formulas (1), (2), (3), and (4). Substituting these models with core parameters, the oil-water interface locations at any given time for organic nanopores, brittle mineral pores, clay mineral pores, and microfractures can be predicted. The prediction results are shown in the figure. Figure 8 As shown.

[0062] Regarding the test samples, core samples were used, and the core samples had a diameter of [missing information]. The core sample is cylindrical. Specific parameters of the core sample are as follows: total porosity of the core. Core diameter Core length core dip angle .

[0063] The specific parameters of organic nanopores are as follows: porosity of organic nanopores Maximum radius of organic nanopores Minimum radius of organic nanopores Organic nanoporous wetting angle Inorganic nanopores and microcracks wetting angle Organic nanopore fractal dimension Organic nanopore tortuosity .

[0064] The specific parameters of inorganic nanopores are as follows: porosity of brittle mineral pores Clay mineral porosity Maximum radius of pores in brittle minerals Minimum radius of pores in brittle minerals Maximum radius of clay mineral pores Minimum radius of clay mineral pores brittle mineral pore fractal dimension Fractal dimension of clay mineral pores brittle mineral pore tortuosity Clay mineral pore tortuosity .

[0065] The specific parameters of the microcracks are as follows: maximum microcrack aperture Minimum aperture of microcracks fractal dimension of microcracks Microcrack tortuosity The ratio of microcrack length to aperture .

[0066] The specific parameters of the oil-water medium are as follows: oil-water interfacial tension =35mN / m, water phase density =1049.3kg / m 3 oil phase density =900kg / m 3 Water phase viscosity =1 mPa•s, oil phase viscosity =10 mPa•s, formation water salinity 109500 mg / L, fracturing fluid salinity 100000 mg / L, gravitational acceleration .

[0067] Step B: Using fractal theory, the scale of the individual nanopores and individual microfractures is scaled up to obtain the total number of nanopores in the core of the fractured shale oil reservoir. and the total number of microcracks ; Upscaling a single nanopore is essentially equivalent to scaling up a nanopore with a diameter of... and porosity The core sample has a pore size in its cross-section. and The number of pores varies between Obtain the total number of nanopores in fractured shale oil reservoirs. Its expression is: (20) In the formula, It is the total number of nanopores in the core of a fractured shale oil reservoir; It is the fractal dimension of the pores; It refers to the porosity of the nanopore core. It is the diameter of the rock core; It is the pore radius of the nanopore; It is the maximum pore radius of the nanopore.

[0068] Upscale individual microfractures to obtain the total number of microfractures in fractured shale reservoirs. Its expression is: (twenty one) In the formula, It is the total number of microfractures in the core of a fractured shale reservoir; It refers to the porosity of the rock core with micro-fractures; It is the diameter of the rock core; It is the ratio of the length to the aperture of the microcrack, i.e. ; It refers to the tortuosity of the microcracks; It is the fractal dimension of the microcrack; It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack.

[0069] It is the step size of the microcrack opening.

[0070] Numerous studies have demonstrated that porous shale media exhibit fractal characteristics, with its pore structure displaying self-similarity and a fractal distribution. The irregular pore structure in shale can be reasonably simplified into an ideal flow model composed of parallel capillary bundles and plate bundles exhibiting fractal features. Based on fractal theory, the models for single pores and fractures have been scaled up.

[0071] Shale core pore size distribution exhibits fractal characteristics, combined with the total number of nanopores in fractured shale reservoirs. The total number of microfractures in fractured shale reservoirs Based on the different fractal characteristics, the mathematical models of single-tube and single-plate displacement and absorption are upgraded to the core scale, constructing a generalized displacement and absorption mathematical model that can be used to describe the seepage behavior of shale porosity and fractures simultaneously. Shale porous media models with fractal characteristics and ideal simplified models, such as... Figure 9 As shown.

[0072] The following describes the total number of microfractures in fractured shale reservoirs. The derivation process.

[0073] The distribution of crack aperture follows a fractal distribution function. hour, The expression is as follows: (twenty two) In the formula, It is the minimum aperture of the microcrack; It is the fractal dimension of the microcrack; It refers to the opening of the microcracks; It is the step size of the microcrack opening.

[0074] The total number of microfractures in the core of fractured shale oil reservoirs and fractal distribution function The relationship between them can be represented as: (twenty three) Furthermore, Integrate and convert the fractal distribution function Unfold to obtain the total number of microfractures in the core of the fractured shale reservoir. The expression is: (twenty four) In the formula, It is the total number of microfractures in the core of a fractured shale reservoir; It refers to the porosity of the rock core with micro-fractures; It is the diameter of the rock core; It is the ratio of the length to the aperture of the microcrack, i.e. ; It refers to the tortuosity of the microcracks; It is the fractal dimension of the microcrack; It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack.

[0075] It is the step size of the microcrack opening.

[0076] Step C: Based on the mathematical model of the fluid permeation sites in a single organic nanopore or a single inorganic nanopore, and the total number of pores in the nanopores of fractured shale oil reservoirs... Calculate the percolation production in all nanopores of a fractured shale oil reservoir core; and calculate the fluid percolation location in a single microfracture and the total number of microfractures based on a mathematical model. Calculate the amount of oil produced by percolation in all microfractures of a fractured shale reservoir core.

[0077] Based on the fractal theory of pore distribution, for nanopores, the total oil production of organic or inorganic nanopores is the sum of the oil production of all nanopores. Therefore, the expression for the percolation oil production in all nanopores of the fractured shale reservoir is: (25) In the formula, It is the amount of oil produced by percolation in all the nanopores of the core of a fractured shale oil reservoir; It is the minimum pore radius of the nanopore; It is the maximum pore radius of the nanopore; It is the pore radius of the nanopore; It is in time The time radius is The oil-water front interface of the nanopores is the site of infiltration and adsorption. It is the total number of nanopores in the core of a fractured shale oil reservoir; It is the fractal dimension of the pores; It refers to the porosity of the nanopore core. It is the diameter of the rock core; It is the pore radius of the nanopore.

[0078] Based on the fractal theory of fracture distribution, the total oil production from fractures is the sum of the oil production from all fractures. Therefore, the expression for the percolation oil production from all microfractures in the fractured shale reservoir is: (26) In the formula, It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack; It is the length of the microcrack; = It is in time Opening degree is The location of oil-water front interface seepage in microcracks; It is the total number of microfractures in the core of a fractured shale reservoir; It is the ratio of the crack's length to its opening, i.e. ; It is a fractal distribution function, and its expression is: (27) In the formula, It is the fractal dimension of the pores; It is the minimum aperture of the microcrack; It refers to the opening of the microcracks; It is the step size of the microcrack opening.

[0079] Step D: Based on the oil production from all nanopores in the core of the fractured shale oil reservoir and the oil production from all microfractures in the core of the fractured shale oil reservoir, as well as the total oil-bearing volume of the core, calculate the recovery rate during the spontaneous and forced adsorption processes of the fractured shale oil reservoir.

[0080] For spontaneous infiltration, the infiltration process occurs only in brittle mineral pores, clay mineral pores, and microcracks.

[0081] In this case, the total oil production from spontaneous adsorption is the sum of the oil production from all brittle mineral pores, all clay mineral pores, and all microfractures. Therefore, the expression for the total oil production during spontaneous adsorption is: (28) In the formula, It is the total oil production during the spontaneous adsorption process; It is the total oil production from the pores of clay minerals; It is the total oil production from the pores of brittle minerals; It is the total oil production from microcracks; It is the minimum pore radius of the nanopore; It is the maximum pore radius of the nanopore; It is the pore radius of the nanopore; It is in time The time radius is When The locations of the oil-water front interface infiltration at the corresponding brittle mineral pores and clay mineral pores; Is when The fractal dimensions of the pores in brittle minerals and clay minerals, respectively; Indicates when The porosity of the core samples corresponding to brittle mineral pores and clay mineral pores at different times; Indicates when The minimum pore radii of brittle mineral pores and clay mineral pores, respectively; Indicates when The maximum pore radii of brittle mineral pores and clay mineral pores, respectively; It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack; It is the length of the microcrack; It is the ratio of the crack's length to its opening, i.e. ; It is the total number of microfractures in the core of a fractured shale reservoir; = It is in time Opening degree is The location of oil-water front interface seepage in microcracks; It is the step size of the microcrack opening.

[0082] The total oil production from microfractures The derivation process is as follows: (29) In the formula, It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack; It is the length of the microcrack; It is the ratio of the crack's length to its opening, i.e. ; It is the total number of microfractures in the core of a fractured shale reservoir; = It is in time Opening degree is The location of oil-water front interface seepage in microcracks; It is the step size of the microcrack opening.

[0083] Total oil-bearing volume of the core It equals the sum of the volumes of nanopores and microcracks, and its expression is: (30) In the formula, The volume of the nanopore; The volume of the microcrack; Indicates when The corresponding volumes of organic nanopores, brittle mineral pores, and clay mineral pores; It is the diameter of the rock core; Indicates when The porosity of the core samples corresponding to organic nanopores, brittle mineral pores, and clay mineral pores, respectively; It refers to the porosity of the rock core with micro-fractures; , ,in, It refers to the tortuosity of the microcracks. Is when The tortuosity of the nanopores corresponding to each time period. It is the core length.

[0084] Therefore, the recovery rate of spontaneous adsorption in fractured shale reservoirs is obtained. : (31) In the formula, The recovery rate of spontaneous adsorption in fractured shale reservoirs; This represents the total oil production during the spontaneous adsorption process; This represents the total oil-bearing volume of the core.

[0085] Forced adsorption occurs in all pore types. In this case, the total oil production from forced adsorption is the sum of the cumulative oil production from all pore types; therefore, the expression for the total oil production from forced adsorption is: (32) In the formula, It is the total oil production of organic nanopores; It is the total oil production from the pores of clay minerals; It is the total oil production from the pores of brittle minerals; It is the total oil production from microcracks; It is the minimum pore radius of the nanopore; It is the maximum pore radius of the nanopore; It is the pore radius of the nanopore; It is in time The time radius is When The oil-water front interface permeation sites of organic nanopores, brittle mineral pores, and clay mineral pores, respectively; Is when The fractal dimensions of organic nanopores, brittle mineral pores, and clay mineral pores, respectively; Indicates when The porosity of the core samples corresponding to organic nanopores, brittle mineral pores, and clay mineral pores, respectively; Indicates when The minimum pore radii of organic nanopores, brittle mineral pores, and clay mineral pores, respectively; Indicates when The maximum pore radii of organic nanopores, brittle mineral pores, and clay mineral pores, respectively; It is the diameter of the rock core; It is the pore radius of the nanopore. It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack; It is the length of the microcrack; It is the ratio of the crack's length to its opening, i.e. ; It is the total number of microfractures in the core of a fractured shale reservoir; = It is in time Opening degree is The location of oil-water front interface seepage in microcracks; It is the step size of the microcrack opening.

[0086] Therefore, the forced adsorption recovery rate of fractured shale reservoirs is obtained. : (33) In the formula, The recovery rate of forced adsorption in fractured shale reservoirs; To force the absorption of total oil production; This represents the total oil-bearing volume of the core.

[0087] Among them, regardless of the recovery rate of spontaneous seepage or forced seepage, the total oil-bearing volume of the core is... It is the same, that is, equal to the sum of the volumes of nanopores and microcracks.

[0088] To verify the prediction of cumulative oil production and oil production rate at any time during spontaneous and forced adsorption processes, existing parameters are substituted into the expressions for total oil production during spontaneous adsorption and total oil production during forced adsorption, respectively. This allows for the prediction of cumulative oil production during spontaneous adsorption at any given time. Forced absorption cumulative oil production Based on the specific parameters of the aforementioned core samples, organic nanopores, inorganic nanopores, and microfractures, the final spontaneous oil production at the core scale was 0.7671 cm³. 3 The final core-scale forced adsorption oil production was 0.7683 cm³. 3 Calculate the total oil-bearing volume of the core. It is 1.6567cm 3 .

[0089] Based on the cumulative oil production at any given time, the relationship between oil production rate and time can be further predicted. The prediction results are as follows: Figure 10 As shown. The recovery rate of spontaneous adsorption in fractured shale reservoirs. Forced adsorption recovery rate of fractured shale reservoirs Over time See the relationship of change Figure 11 .

[0090] Recovery rate of spontaneous adsorption in fractured shale reservoirs The forced adsorption recovery rate of fractured shale reservoirs is 46.3370%. The accuracy rate is 46.3639%, which meets the requirements.

[0091] Step E: Predict the total oil yield per cubic meter of rock sample Assuming the physical properties of the core remain unchanged, the cumulative oil production per cubic meter of core can be equivalently obtained using the core-scale cumulative oil production prediction model. The expression for core oil production is as follows: (34) In the formula, This refers to the oil production from the core. This represents the core volume. This represents the recovery rate of the fractured shale reservoir where the core was located.

[0092] Based on this, the relationship between the cumulative oil production per cubic meter of rock sample and time can be further obtained, such as... Figure 12 As shown. The final predicted cumulative oil production per cubic meter of rock sample through spontaneous seepage is 1.5628 × 10⁻⁶. -3 m 3 The cumulative oil production from forced percolation was 1.5652 × 10⁻⁶. -3 m3 This further proves that the prediction method is simple, quick, and produces accurate and reliable results.

[0093] Example 2 Example 2 provides a device for predicting the recovery rate of fractured shale oil reservoirs, and its structure is described in detail below.

[0094] The recovery prediction device for this fractured shale oil reservoir includes The first processing unit is used to classify pore types into single nanopores and single microcracks according to different pore types. The single nanopores are further divided into organic nanopores and inorganic nanopores, and mathematical models of fluid permeation sites in single organic nanopores, single inorganic nanopores and single microcracks are constructed respectively. The second processing unit is used to scale up the individual nanopores and individual microfractures using fractal theory, thereby obtaining the total number of nanopores in the core of the fractured shale oil reservoir. and the total number of microcracks ; The third processing unit is used to calculate the fluid permeation location in a single organic or inorganic nanopore based on a mathematical model and the total number of nanopores in fractured shale reservoirs. Calculate the percolation production in all nanopores of a fractured shale reservoir core; and calculate the percolation production based on a mathematical model of the fluid percolation location in a single microfracture and the total number of microfractures. Calculate the amount of oil produced by percolation in all microfractures of a core sample from a fractured shale reservoir; The fourth processing unit is used to calculate the recovery rate of the fractured shale oil reservoir during the spontaneous and forced adsorption processes based on the amount of oil produced by percolation in all nanopores of the core, the amount of oil produced by percolation in all microfractures of the core, and the total oil-bearing volume of the core.

[0095] Example 3 Example 3 provides a computer-readable storage medium, which is described in detail below.

[0096] The computer-readable storage medium has a computer program stored thereon, which, when executed by a processor, implements the steps of the method of Embodiment 1.

[0097] Example 4 Example 4 provides a computer device, which is described in detail below.

[0098] The computer device includes a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that the processor executes the computer program to implement the steps of the method of Embodiment 1.

[0099] Based on extensive research by domestic and international scholars on recovery rate prediction during the development of different types of oil reservoirs, this invention compares the results of these studies and finds significant differences between various recovery rate prediction methods. Conventional experimental methods, numerical simulation methods, and production data analysis methods are typically time-consuming, applicable to specific production stages, and most are only suitable for medium- to high-permeability reservoirs. Due to the unique nonlinear flow characteristics of shale reservoirs, these methods are often no longer applicable or their prediction accuracy is unsatisfactory. In addition to the above methods, fluid adsorption into porous media is a common natural phenomenon. Simulating the seepage process using nonlinear flow mathematical models and ultimately predicting development indicators such as production and recovery rate is also a key research area both domestically and internationally. However, existing studies primarily focus on matrix-type tight reservoirs, and the stress analysis is not comprehensive enough to be directly applied to shale.

[0100] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for predicting the recovery rate of fractured shale oil reservoirs, characterized in that, include Based on different pore types, pore types are divided into single nanopores and single microcracks. Single nanopores are further divided into single organic nanopores and single inorganic nanopores. Mathematical models of fluid absorption sites in single organic nanopores, single inorganic nanopores, and single microcracks are constructed respectively. The mathematical model for the fluid absorption site in a single organic nanopore is as follows: (1) In the formula, Indicates that at time The time radius is The location of fluid permeation at the oil-water front interface in organic nanopores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core; Fractal theory was used to scale up the individual nanopores and individual microfractures, respectively, to obtain the total number of nanopores in the core of fractured shale oil reservoirs. and the total number of microcracks ; Based on mathematical models of fluid permeation sites in single organic or inorganic nanopores and the total number of nanopores in fractured shale reservoirs... Calculate the percolation production in all nanopores of a fractured shale reservoir core; and calculate the percolation production based on a mathematical model of the fluid percolation location in a single microfracture and the total number of microfractures. Calculate the amount of oil produced by percolation in all microfractures of a core sample from a fractured shale reservoir; Based on the oil production from all nanopores in the core of the fractured shale reservoir and the oil production from all microfractures in the core of the fractured shale reservoir, as well as the total oil-bearing volume of the core, the recovery rate of the fractured shale reservoir during spontaneous and forced adsorption processes is calculated respectively.

2. The method for predicting the recovery rate of fractured shale oil reservoirs according to claim 1, characterized in that, The inorganic nanopores include brittle mineral pores and clay mineral pores. The mathematical models for the fluid permeation sites in a single inorganic nanopore include mathematical models for the fluid permeation sites in a single brittle mineral pore and mathematical models for the fluid permeation sites in a single clay mineral pore. The mathematical model for the fluid permeation location in a single brittle mineral pore is as follows: (2) In the formula, Indicates that at time The time radius is The location of fluid seepage at the oil-water front interface in the brittle mineral pores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the thickness of the immovable boundary layer; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core; The mathematical model for the fluid seepage location in a single clay mineral pore is as follows: （3） In the formula, Indicates that at time The time radius is The location of fluid seepage at the oil-water front interface in the pores of clay minerals; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the osmotic pressure of water absorption by shale; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core.

3. The method for predicting the recovery rate of fractured shale oil reservoirs according to claim 1, characterized in that, The mathematical model for the fluid absorption location in the single microcrack is as follows: (4) In the formula, Indicates that at time Opening degree is The location of fluid seepage at the oil-water front interface in microcracks; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the external displacement pressure difference; It refers to the opening of the microcracks; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; It is the location of seepage and absorption at the oil-water front interface; It is the dip angle of the rock core; No. j -1 corresponds to the oil-water front interface seepage location.

4. The method for predicting the recovery rate of fractured shale oil reservoirs according to claim 1, characterized in that, The total number of nanopores in the core of the fractured shale reservoir The expression is: (20) In the formula, It is the total number of nanopores in the core of a fractured shale oil reservoir; It is the fractal dimension of the pores; It refers to the porosity of the nanopore core. It is the diameter of the rock core; It is the pore radius of the nanopore; It is the maximum pore radius of the nanopore; The total number of microfractures in the core of the fractured shale reservoir. The expression is: (21) In the formula, It is the total number of microfractures in the core of a fractured shale reservoir; It refers to the porosity of the rock core with micro-fractures; It is the diameter of the rock core; It is the ratio of the length to the aperture of the microcrack; It refers to the tortuosity of the microcracks; It is the fractal dimension of the microcrack; It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the maximum opening of the microcrack.

5. The method for predicting the recovery rate of fractured shale oil reservoirs according to claim 4, characterized in that, The expression for the percolation oil production in all nanopores of the core of the fractured shale oil reservoir is as follows: (25) In the formula, It is the amount of oil produced by percolation in all nanopores of the core of a fractured shale oil reservoir; It is the minimum pore radius of the nanopore; It is the maximum pore radius of the nanopore; It is the pore radius of the nanopore; It is in time The time radius is The location of fluid permeation at the oil-water front interface in the nanopore; It is the total number of nanopores in the core of a fractured shale oil reservoir; It is the fractal dimension of the pores; It refers to the porosity of the nanopore core. It is the diameter of the rock core; It is the pore radius of the nanopore; The expression for the oil production from all microfractures in the core of the fractured shale reservoir is as follows: (26) In the formula, It refers to the opening of the microcracks; It is the minimum aperture of the microcrack; It is the length of the microcrack; It is in time Opening degree is The location of oil-water front interface seepage in microcracks; It is the total number of microfractures in the core of a fractured shale oil reservoir.

6. The method for predicting the recovery rate of fractured shale oil reservoirs according to claim 5, characterized in that, The recovery rate of spontaneous adsorption in the fractured shale reservoir The expression is: (31) In the formula, This represents the total oil production during the spontaneous adsorption process; This represents the total oil-bearing volume of the core. The total oil production during the spontaneous adsorption process. The expression is: (28) In the formula, It is the total oil production from the pores of clay minerals; It is the total oil production from the pores of brittle minerals; It is the total oil production from microcracks; Forced absorption recovery rate of fractured shale reservoirs The expression is: (33) In the formula, To force the absorption of total oil production; This represents the total oil-bearing volume of the core. The total oil production from forced permeation The expression is: In the formula, It is the total oil production of organic nanopores; It is the total oil production from the pores of clay minerals; It is the total oil production from the pores of brittle minerals; It is the total oil production from microcracks; The total oil-bearing volume of the core The expression is: (30) In the formula, Indicates when The corresponding volumes of organic nanopores, brittle mineral pores, and clay mineral pores, respectively; It is the diameter of the rock core; Indicates when The porosity of the core samples corresponding to organic nanopores, brittle mineral pores, and clay mineral pores, respectively; It refers to the porosity of the rock core with micro-fractures; , ,in, It refers to the tortuosity of the microcracks. When The tortuosity of the nanopores corresponding to each time period. It is the core length.

7. A device for predicting the recovery rate of fractured shale oil reservoirs, characterized in that, include The first processing unit is used to classify pore types into single nanopores and single microcracks based on their pore types. Single nanopores are further divided into organic nanopores and inorganic nanopores. Mathematical models are constructed for the fluid absorption locations in single organic nanopores, single inorganic nanopores, and single microcracks, respectively. The mathematical model for the fluid absorption locations in a single organic nanopore is as follows: (1) In the formula, Indicates that at time The time radius is The location of fluid permeation at the oil-water front interface in organic nanopores; It is the viscosity of the oil phase; It is the core length; It is the viscosity of the aqueous phase; It is the first j The time corresponding to each step; It is the first j -1 step corresponds to the time; It is the pore radius of the nanopore; It is the equivalent slip length; It is the external displacement pressure difference; It is the interfacial tension between oil and water; It is the wetting angle; It is the density of the aqueous phase; It is the density of the oil phase; It is gravitational acceleration; No. j -1 corresponds to the oil-water front interface seepage location; It is the dip angle of the rock core; The second processing unit is used to scale up the individual nanopores and individual microfractures using fractal theory, thereby obtaining the total number of nanopores in the core of the fractured shale oil reservoir. and the total number of microcracks ; The third processing unit is used to calculate the fluid permeation location in a single organic or inorganic nanopore based on a mathematical model and the total number of nanopores in fractured shale reservoirs. Calculate the percolation production in all nanopores of a fractured shale reservoir core; and calculate the percolation production based on a mathematical model of the fluid percolation location in a single microfracture and the total number of microfractures. Calculate the amount of oil produced by percolation in all microfractures of a core sample from a fractured shale reservoir; The fourth processing unit is used to calculate the recovery rate of the fractured shale oil reservoir during the spontaneous and forced adsorption processes based on the amount of oil produced by percolation in all nanopores of the core, the amount of oil produced by percolation in all microfractures of the core, and the total oil-bearing volume of the core.

8. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by a processor, it implements the steps of the method according to any one of claims 1 to 6.

9. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the steps of the method according to any one of claims 1 to 6.

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