Shale reservoir gas-liquid two-phase output prediction method and system and computer equipment

Abstract

The invention provides a shale reservoir gas-liquid two-phase output prediction method and system and computer equipment, and belongs to the field of oil-gas field development. The shale reservoir gas-liquid two-phase output prediction method comprises the following steps: establishing a gas-liquid two-phase flow model in organic matter pores of a shale reservoir, and determining a gas-liquid two-phase flow equation in the organic matter pores; establishing a gas-liquid two-phase flow model in the inorganic substance pores of the shale reservoir, and determining a gas-liquid two-phase flow equation in the inorganic substance pores; the method comprises the following steps: performing a rock sample test on a shale reservoir, determining the ratio of organic matter pores to inorganic matter pores and pore size distribution of the shale reservoir, and establishing a surface porosity model of the shale reservoir according to the ratio of the organic matter pores to the inorganic matter pores and the pore size distribution; and predicting the gas-liquid two-phase output of the shale reservoir according to the surface porosity model of the shale reservoir, the gas-liquid two-phase flow equation in the organic matter pores and the gas-liquid two-phase flow equation in the inorganic matter pores.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development, specifically to a method for predicting the gas-liquid two-phase production of shale reservoirs, a system for predicting the gas-liquid two-phase production of shale reservoirs, and a computer device. Background Technology

[0002] Shale reservoirs are rich in nanoscale pores, and fluid flow in nanopores differs from that in conventional pores, exhibiting microscale effects. In conventional pores, fluid flow is primarily addressed using the continuum theory, where surface tension and interfacial slip are negligible. However, at the micro- and nanoscale, as the specific surface area of ​​the fluid gradually decreases, inertial forces are no longer the dominant force in fluid flow. Neglecting surface tension and interfacial slip in conventional pores becomes a crucial factor affecting fluid flow.

[0003] When the fluid flow space is reduced to the nanoscale, the intermolecular forces between fluid molecules and wall molecules become significant. Numerous studies have shown that the flow characteristics of fluids at the nanoscale differ greatly from those under macroscopic conditions. As the channel size decreases, the flow properties of fluids in submicron and nanochannels are not only related to the local shear rate but also depend on the channel size. Furthermore, the surface properties of the pipe wall have a significant impact on the flow regime and transport patterns of the two-phase flow. Therefore, current techniques cannot accurately calculate the gas-liquid two-phase production of gas wells. Summary of the Invention

[0004] To address the aforementioned technical deficiencies, this invention provides a method, system, and computer equipment for predicting the gas-liquid two-phase production of shale reservoirs. The method involves dividing the shale reservoir's pores into organic and inorganic pores, and then predicting the gas-liquid two-phase production by region based on the pore characteristics. It establishes gas-liquid two-phase flow equations for organic and inorganic pores based on their characteristics, and further considers the flow characteristics of different pore types to establish flow equations for each pore, resulting in a more accurate calculation method. By using the porosity model of the shale reservoir, the gas-liquid two-phase flow equations for organic and inorganic pores, and other relevant equations, the prediction accuracy is improved, yielding precise prediction results.

[0005] The first aspect of this invention provides a method for predicting the gas-liquid two-phase production of shale reservoirs, comprising:

[0006] A gas-liquid two-phase flow model was established in the organic matter pores of shale reservoirs, and the gas-liquid two-phase flow equations in the organic matter pores were determined based on the gas-liquid two-phase flow model.

[0007] A gas-liquid two-phase flow model in the inorganic pores of shale reservoirs was established, and the gas-liquid two-phase flow equation in the inorganic pores was determined based on the gas-liquid two-phase flow model.

[0008] By conducting rock sample tests on shale reservoirs, the ratio of organic to inorganic porosity and the pore size distribution of shale reservoirs were determined. Based on the ratio of organic to inorganic porosity and the pore size distribution, a porosity model of shale reservoirs was established.

[0009] Predict the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equation in organic matter pores, and the gas-liquid two-phase flow equation in inorganic matter pores.

[0010] In this embodiment of the invention, the method further includes:

[0011] The organic and inorganic porosity of shale reservoirs is determined based on the wettability of the shale reservoir.

[0012] In this embodiment of the invention, establishing a gas-liquid two-phase flow model in the organic matter pores of shale reservoirs includes:

[0013] A two-phase flow model of gas and liquid in organic matter pores is established based on the pore length, pressure difference across the pores, liquid flow velocity, gas flow velocity, slip velocity and slip length on the pore wall.

[0014] In this embodiment of the invention, determining the gas-liquid two-phase flow equation in the organic matter pores based on the gas-liquid two-phase flow model includes:

[0015] Determine the viscous force and pressure driving force of the porous micro-elements in the organic matter pores;

[0016] The boundary conditions of organic matter pores are determined based on the gas-liquid two-phase flow characteristics in the organic matter pores.

[0017] The gas-liquid two-phase flow equation in organic matter pores is determined based on the boundary conditions of the organic matter pores, the viscosity of the pore micro-elements, and the pressure difference driving force of the pore micro-elements.

[0018] In this embodiment of the invention, the boundary conditions of the organic matter pores are: there is velocity slip on the wall of the organic matter pores, the radius of the pore micro-element is equal to the pore radius, and the flow velocity of the pore micro-element is equal to the slip velocity of the gas phase.

[0019] In this embodiment of the invention, establishing a gas-liquid two-phase flow model in the inorganic pores of shale reservoirs includes:

[0020] A two-phase flow model of gas and liquid in inorganic pores is established based on the inorganic pore length, pressure difference across the inorganic pores, liquid phase flow velocity in the inorganic pores, liquid boundary layer thickness and water film thickness, and gas phase flow velocity in the inorganic pores.

[0021] In this embodiment of the invention, determining the gas-liquid two-phase flow equation in the inorganic pores based on the gas-liquid two-phase flow model in the inorganic pores includes:

[0022] Determine the viscous force and pressure driving force of porous micro-elements in inorganic materials;

[0023] The boundary conditions of inorganic pores are determined based on the gas-liquid two-phase flow characteristics in inorganic pores.

[0024] The gas-liquid two-phase flow equation in inorganic pores is determined based on the boundary conditions of inorganic pores, the viscosity of the micro-element, and the pressure difference driving force of the micro-element.

[0025] In this embodiment of the invention, the boundary conditions of the inorganic pores are as follows: when the radius of the pore element is equal to the pore radius minus the thickness of the liquid phase boundary layer, the flow velocity of the liquid phase is 0; when the radius of the pore element is equal to the pore radius minus the thickness of the water film, the flow velocity of the liquid phase is equal to the flow velocity of the gas phase.

[0026] In this embodiment of the invention, the step of predicting the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equation in the organic matter pores of shale reservoirs, and the gas-liquid two-phase flow equation in the inorganic matter pores of shale reservoirs includes:

[0027] Based on the porosity model of shale reservoirs, organic matter pores of the same pore size are grouped to obtain multiple combinations of organic matter pores with different pore sizes. The combined gas-liquid two-phase production of each organic matter pore combination is calculated according to the gas-liquid two-phase flow equation in the organic matter pores of shale reservoirs. The total gas-liquid two-phase production of organic matter pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each organic matter pore combination.

[0028] Based on the porosity model of shale reservoirs, inorganic pores of different pore sizes are grouped to obtain multiple combinations of inorganic pores with different pore sizes. The combined gas-liquid two-phase production of each inorganic pore combination is calculated based on the gas-liquid two-phase flow equation in the organic pores of shale reservoirs. The total gas-liquid two-phase production of inorganic pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each inorganic pore combination.

[0029] The gas-liquid two-phase production of shale reservoirs is obtained based on the actual reservoir stimulation area, the total gas-liquid two-phase production of organic matter pores in shale reservoirs, and the total gas-liquid two-phase production of inorganic matter pores in shale reservoirs.

[0030] A second aspect of the present invention provides a shale reservoir gas-liquid two-phase production prediction system, comprising:

[0031] A gas-liquid two-phase flow model in organic matter pores is used to determine the gas-liquid two-phase flow equations in organic matter pores of shale reservoirs;

[0032] A gas-liquid two-phase flow model in inorganic pores is used to determine the gas-liquid two-phase flow equations in inorganic pores of shale reservoirs.

[0033] The porosity model is established based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution, which are determined by testing rock samples from shale reservoirs.

[0034] The prediction module is used to predict the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equations in organic matter pores, and the gas-liquid two-phase flow equations in inorganic matter pores.

[0035] A third aspect of the present invention provides a computer device, comprising:

[0036] Memory;

[0037] Processor; and

[0038] Computer programs;

[0039] The computer program is stored in a memory and configured to be executed by a processor to implement the shale reservoir gas-liquid two-phase production prediction method as described above.

[0040] The proposed method for predicting the gas-liquid two-phase production of shale reservoirs divides the pores of the shale reservoir into organic and inorganic pores. Based on the pore characteristics of the shale reservoir, gas-liquid two-phase prediction is performed in separate zones. Flow equations for the gas-liquid two-phase production of organic and inorganic pores in the shale reservoir are established based on their respective characteristics. The flow characteristics of different pores are considered, and flow equations are established for each pore based on its flow characteristics, resulting in a more accurate calculation method. By using the porosity model of the shale reservoir, the gas-liquid two-phase flow equations for the organic and inorganic pores of the shale reservoir, the prediction accuracy is improved, yielding precise prediction results.

[0041] Other features and advantages of the technical solution of the present invention will be described in detail in the following detailed embodiments section. Attached Figure Description

[0042] The accompanying drawings, which are included to provide a further understanding of the invention and form part of this invention, illustrate exemplary embodiments of the invention and are used to explain the invention, but do not constitute an undue limitation of the invention. In the drawings:

[0043] Figure 1 This is a flowchart of the method for predicting the gas-liquid two-phase production of shale reservoirs provided in this embodiment of the invention;

[0044] Figure 2 This is a gas-liquid two-phase flow model of organic matter pores in shale reservoirs provided in this embodiment of the invention;

[0045] Figure 3 This is a gas-liquid two-phase flow model of inorganic pores in shale reservoirs provided in this embodiment of the invention;

[0046] Figure 4 This is a schematic diagram of the face rate model provided in an embodiment of the present invention;

[0047] Figure 5 This is an aperture distribution diagram provided in an embodiment of the present invention;

[0048] Figure 6 This is a structural block diagram of the shale reservoir gas-liquid two-phase production prediction system provided in an embodiment of the present invention. Detailed Implementation

[0049] To make the technical solutions and advantages of the embodiments of the present invention clearer, the exemplary embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of the present invention, and not an exhaustive list of all embodiments. It should be noted that, unless otherwise specified, the embodiments and features in the embodiments of the present invention can be combined with each other.

[0050] In the description of this invention, it should be understood that the terms "center," "longitudinal," "lateral," "length," "width," "thickness," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0051] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Thus, a feature defined as "first" or "second" may explicitly or implicitly include one or more of that feature. In the description of this invention, "a plurality of" means at least two, such as two, three, etc., unless otherwise explicitly specified.

[0052] In this invention, unless otherwise explicitly specified and limited, terms such as "installation," "connection," "linking," and "fixing" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a connection that allows communication between them; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0053] In developing this invention, the inventors discovered that shale reservoirs are rich in nanoscale pores. Fluid flow in nanoscale pores differs from flow in conventional pores, exhibiting microscale effects. In conventional pores, fluid flow is primarily addressed using the continuum theory, where surface tension and interfacial slip are negligible. However, at the micro- and nanoscale, as the specific surface area of ​​the fluid gradually decreases, inertial forces are no longer the dominant force in fluid flow. Neglecting surface tension and interfacial slip in conventional pores becomes a crucial factor affecting fluid flow.

[0054] When the fluid flow space is reduced to the nanoscale, the intermolecular forces between fluid molecules and wall molecules become significant. Numerous studies have shown that the flow characteristics of fluids at the nanoscale differ greatly from those under macroscopic conditions. As the channel size decreases, the flow properties of fluids in submicron and nanochannels are not only related to the local shear rate but also depend on the channel size. Furthermore, the surface properties of the pipe wall have a significant impact on the flow regime and transport patterns of the two-phase flow. Therefore, current techniques cannot accurately calculate the gas-liquid two-phase production of gas wells.

[0055] To address the aforementioned problems, this invention provides a method for predicting the gas-liquid two-phase production of shale reservoirs, comprising: establishing a gas-liquid two-phase flow model in the organic matter pores of the shale reservoir; determining the gas-liquid two-phase flow equation in the organic matter pores based on the gas-liquid two-phase flow model in the organic matter pores; establishing a gas-liquid two-phase flow model in the inorganic matter pores of the shale reservoir; determining the gas-liquid two-phase flow equation in the inorganic matter pores based on the gas-liquid two-phase flow model in the inorganic matter pores; determining the ratio and pore size distribution of organic matter pores to inorganic matter pores by conducting rock sample tests on the shale reservoir; establishing a porosity model of the shale reservoir based on the ratio and pore size distribution of organic matter pores to inorganic matter pores; and predicting the gas-liquid two-phase production of the shale reservoir based on the porosity model, the gas-liquid two-phase flow equation in the organic matter pores, and the gas-liquid two-phase flow equation in the inorganic matter pores. The proposed method for predicting the gas-liquid two-phase production of shale reservoirs divides the pores of the shale reservoir into organic and inorganic pores. Based on the pore characteristics of the shale reservoir, gas-liquid two-phase prediction is performed in separate zones. Flow equations for the gas-liquid two-phase production of organic and inorganic pores in the shale reservoir are established based on their respective characteristics. The flow characteristics of different pores are considered, and flow equations are established for each pore based on its flow characteristics, resulting in a more accurate calculation method. By using the porosity model of the shale reservoir, the gas-liquid two-phase flow equations for the organic and inorganic pores of the shale reservoir, the prediction accuracy is improved, yielding precise prediction results.

[0056] Figure 1 This is a flowchart of the method for predicting the gas-liquid two-phase production of shale reservoirs provided in an embodiment of the present invention. Figure 1 As shown in the figure, the method for predicting the gas-liquid two-phase production of shale reservoirs provided in this embodiment includes the following steps:

[0057] S1. Establish a gas-liquid two-phase flow model in the organic matter pores of shale reservoirs, and determine the gas-liquid two-phase flow equations in the organic matter pores based on the gas-liquid two-phase flow model.

[0058] S2. Establish a gas-liquid two-phase flow model in the inorganic pores of shale reservoirs, and determine the gas-liquid two-phase flow equations in the inorganic pores based on the gas-liquid two-phase flow model.

[0059] S3. By conducting rock sample tests on shale reservoirs, the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution of shale reservoirs are determined. Based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution, a porosity model of shale reservoirs is established.

[0060] S4. Predict the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equation in organic matter pores, and the gas-liquid two-phase flow equation in inorganic matter pores.

[0061] The method further includes:

[0062] S5. The organic and inorganic porosity of shale reservoirs is determined based on the wettability of the shale reservoir. According to the wettability, the porosity of shale reservoirs is divided into organic porosity and inorganic porosity.

[0063] In step S1, establishing a gas-liquid two-phase flow model in the organic matter pores of the shale reservoir includes:

[0064] A two-phase flow model of gas and liquid in organic matter pores is established based on the pore length, pressure difference across the pores, liquid flow velocity, gas flow velocity, slip velocity and slip length on the pore wall.

[0065] In step S1, determining the gas-liquid two-phase flow equation in the organic matter pores based on the gas-liquid two-phase flow model includes:

[0066] Determine the viscous force and pressure driving force of the porous micro-elements in the organic matter pores;

[0067] The boundary conditions of organic matter pores are determined based on the gas-liquid two-phase flow characteristics in the organic matter pores.

[0068] The gas-liquid two-phase flow equation in organic matter pores is determined based on the boundary conditions of the organic matter pores, the viscosity of the pore micro-elements, and the pressure difference driving force of the pore micro-elements.

[0069] The gas-liquid two-phase flow characteristics in the organic matter pores of the shale reservoir are as follows: the organic matter pores are hydrophobic.

[0070] The boundary conditions of the organic matter pores are: there is velocity slip on the wall of the organic matter pores, the radius of the pore element is equal to the pore radius, and the flow velocity of the pore element is equal to the slip velocity of the gas phase.

[0071] Specifically, Figure 2 This is a gas-liquid two-phase flow model of organic matter pores in shale reservoirs provided in this embodiment of the invention, such as... Figure 2As shown, in organic matter pores, due to the hydrophobicity of the pores, the gas-liquid two-phase flow pattern is water-preferred. After all the water is expelled, the gas flows rapidly, exhibiting gas-driven water characteristics. Velocity slip occurs at the gas interface, resulting in increased gas flow capacity and a flow rate greater than predicted by classical theory. Assumptions: the length of the organic matter pore is L, the pressure difference between the two ends is ΔP, the liquid phase content in the organic matter pore is low and flows out rapidly, the gas phase is subsequently produced, and the liquid phase is negligible; the gas is compressible, the water is incompressible; the gas is insoluble in water, and the temperature remains constant throughout the process; the pores are horizontal, and gravity is negligible; the gas phase has the maximum velocity, V, at the center of the pore. max There is velocity slip on the wall, which is V. s The slip length is L s .

[0072] The viscosity of the pore micro-elements in the organic matter pores of shale reservoirs is:

[0073]

[0074] Where, μ g ρ is the gas viscosity, in Pa·s; L is the pore length, in meters; r is the radius of the pore element in the organic matter pores; and v is the flow velocity at the pore element in the organic matter pores.

[0075] The pressure difference driving force of the pore micro-elements in the organic matter pores of shale reservoirs is:

[0076] F=πr 2 ΔP; Formula 2

[0077] Where ΔP is the pressure difference across the organic matter pores, in Pa.

[0078] By balancing the viscous force and the pressure difference driving force of the porous micro-element, we can obtain:

[0079]

[0080] The result of the transformation is:

[0081] Therefore, the flow velocity of the porous micro-elements in the organic matter pores can be obtained as follows:

[0082]

[0083] The flow velocity of the organic matter pores is obtained by integrating the flow velocity of the pore micro-elements. The specific calculation is as follows:

[0084]

[0085] Based on the obtained boundary conditions—namely, velocity slip exists on the walls of the organic pores, the radius of the pore element is equal to the pore radius, and the flow velocity of the pore element is equal to the slip velocity of the gas phase—we can obtain:

[0086]

[0087] Where r0 is the pore radius, the value of the constant C can be obtained from the boundary conditions.

[0088] According to the Navier slip model, the equation can be obtained as follows:

[0089]

[0090] Combining formulas four and seven, we can obtain the equation:

[0091]

[0092] Substituting the boundary condition that the radius of the porous element is equal to the pore radius (i.e., r = r0) into formula eight, we can obtain:

[0093]

[0094] Combining formulas six and nine, we can obtain the equation:

[0095]

[0096] Substituting formula ten into formula five yields the following equation:

[0097]

[0098] The formula for calculating the flow rate at the pore element dr is:

[0099] dq=2vπrdr; Formula Twelve

[0100] Substituting Equation 11 into Equation 12 and integrating, we can obtain the gas-liquid two-phase flow equation in the pores of organic matter:

[0101]

[0102] Where, μ g r0 is the gas viscosity, Pa·s; r0 is the pore radius, m; L s L is the slip length, in meters; L is the pore length, in meters; ΔP is the pressure difference across the pore, in Pa. The pressure gradient within the pores can be derived from... express.

[0103] In step S2, establishing a gas-liquid two-phase flow model in the inorganic pores of the shale reservoir includes:

[0104] A two-phase flow model of gas and liquid in inorganic pores is established based on the inorganic pore length, pressure difference across the inorganic pores, liquid phase flow velocity in the inorganic pores, liquid boundary layer thickness and water film thickness, and gas phase flow velocity in the inorganic pores.

[0105] Furthermore, in step S2, determining the gas-liquid two-phase flow equation in the inorganic pores based on the gas-liquid two-phase flow model in the inorganic pores includes:

[0106] Determine the viscous force and pressure driving force of porous micro-elements in inorganic materials;

[0107] The boundary conditions of inorganic pores are determined based on the gas-liquid two-phase flow characteristics in inorganic pores.

[0108] The gas-liquid two-phase flow equation in inorganic pores is determined based on the boundary conditions of inorganic pores, the viscosity of the micro-element, and the pressure difference driving force of the micro-element.

[0109] Determine the viscous force and differential pressure driving force of pore micro-elements in the inorganic pores of shale reservoirs;

[0110] The boundary conditions of inorganic pores are determined based on the gas-liquid two-phase flow characteristics in the inorganic pores of shale reservoirs.

[0111] The gas-liquid two-phase flow equation in the inorganic pores of shale reservoirs is determined based on the boundary conditions of inorganic pores, the viscosity of micro-elements, and the pressure difference driving force of micro-elements.

[0112] Furthermore, the boundary conditions for the inorganic pores are as follows:

[0113] When the radius of the porous micro-element is equal to the pore radius minus the thickness of the liquid phase boundary layer, the flow velocity of the liquid phase is 0.

[0114] When the radius of the porous micro-element is equal to the pore radius minus the thickness of the water film, the flow velocity of the liquid phase is equal to the flow velocity of the gas phase.

[0115] The gas-liquid two-phase flow characteristics in the inorganic pores of the shale reservoir are as follows: the hydrophilicity of the inorganic pores causes the liquid phase to flow along the walls of the inorganic pores, while the gas flows in the middle of the inorganic pores, and a liquid boundary layer is formed at the liquid phase fluid boundary.

[0116] The boundary conditions for the inorganic pores are as follows: when the radius of the pore element is equal to the pore radius minus the thickness of the liquid phase boundary layer, the flow velocity of the liquid phase is 0; when the radius of the pore element is equal to the pore radius minus the thickness of the water film, the flow velocity of the liquid phase is equal to the flow velocity of the gas phase.

[0117] Specifically, Figure 3This is a gas-liquid two-phase flow model of inorganic pores in shale reservoirs provided in this embodiment of the invention, such as... Figure 3 As shown, in inorganic pores, due to the hydrophilicity of capillaries, when the gas and liquid phases flow in the nanopores, the liquid phase flows along the walls, while the gas flows in the middle of the pores. At the liquid-liquid boundary, the adsorption force between the inorganic pore walls and liquid molecules typically hinders fluid flow near the walls, creating a boundary layer. The presence of this boundary layer reduces the effective pore space of the inorganic pores. Assumptions: The length of the inorganic pore is L, the pressure difference between its two ends is ΔP, and the velocities at the gas and liquid interfaces are the same. The thickness of the liquid boundary layer is δ, and the thickness of the water film is h. w .

[0118] The viscous force acting on the porous element at radius r is the same as the pressure difference driving force on the porous element, resulting in the following equations:

[0119]

[0120] Where, μ g The viscosity of a gas is expressed in Pa·s; μ w ρ is the liquid viscosity, in Pa·s; L is the pore length, in meters; r is the radius of the pore element in the organic matter pores; v is the flow velocity at the pore element in the organic matter pores; ΔP is the pressure difference across the pore, in Pa; h w δ represents the water film thickness in meters (m); δ represents the water boundary layer thickness in meters (m).

[0121] Boundary conditions are set as follows: when the radius of the pore element equals the pore radius minus the thickness of the liquid boundary layer, the liquid phase flow velocity is 0; when the radius of the pore element equals the pore radius minus the thickness of the water film, the liquid phase flow velocity equals the gas phase flow velocity (i.e., r = r0 - δ, v). w =0; r = r0 - h w v g =v w Substituting into Formula Fourteen, we get:

[0122]

[0123] Integrating and solving Equation 15, we obtain the gas-liquid two-phase flow equation in the inorganic pores of shale reservoirs as follows:

[0124]

[0125] Where, μ g The viscosity of a gas is expressed in Pa·s; μ w The viscosity of the liquid is expressed in Pa·s; L is the pore length in meters; r0 is the pore radius of the organic matter; ΔP is the pressure difference across the pore in Pa; h wδ represents the water film thickness in meters (m); δ represents the water boundary layer thickness in meters (m). The pressure gradient within the pores can be derived from... express.

[0126] In step S3, rock samples are tested from the shale reservoir to determine the ratio of organic to inorganic porosity and the pore size distribution. Based on this ratio and distribution, a porosity model for the shale reservoir is established.

[0127] S31. Conduct rock sample testing and analysis on shale reservoirs to obtain the ratio of organic matter porosity to inorganic matter porosity in shale reservoirs and the pore size distribution of shale reservoirs;

[0128] S32. Determine the porosity model of shale reservoirs based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution of shale reservoirs.

[0129] Specifically, analysis of shale reservoir samples revealed that the proportion of organic matter pore volume to the total pore volume is w, and the proportion of inorganic matter pore volume to the total pore volume is (1-w). Based on NMR spectroscopy, a pore size distribution map was obtained, from which the proportion of pores with pore radius r1 is n1; the proportion of pores with pore radius r2 is n2…

[0130] A porosity model for shale reservoirs is determined based on the ratio of organic to inorganic porosity and the pore size distribution of the shale reservoirs. Figure 4 This is a schematic diagram of the face rate model provided in an embodiment of the present invention.

[0131] In step S4, predicting the gas-liquid two-phase production of the shale reservoir based on the porosity model of the shale reservoir, the gas-liquid two-phase flow equation in the organic matter pores, and the gas-liquid two-phase flow equation in the inorganic matter pores includes:

[0132] S41. Based on the porosity model of shale reservoirs, organic matter pores of the same pore size are grouped to obtain multiple combinations of organic matter pores with different pore sizes. The combined gas-liquid two-phase production of each organic matter pore combination is calculated based on the gas-liquid two-phase flow equation in the organic matter pores of shale reservoirs. The total gas-liquid two-phase production of organic matter pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each organic matter pore combination.

[0133] S42. Based on the porosity model of shale reservoirs, inorganic pores of different pore sizes are grouped to obtain multiple combinations of inorganic pores with different pore sizes. The combined gas-liquid two-phase production of each inorganic pore combination is calculated based on the gas-liquid two-phase flow equation in the organic pores of shale reservoirs. The total gas-liquid two-phase production of inorganic pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each inorganic pore combination.

[0134] S43. The gas-liquid two-phase production of the shale reservoir is obtained based on the actual reservoir stimulation area, the total gas-liquid two-phase production of the organic matter pores in the shale reservoir, and the total gas-liquid two-phase production of the inorganic matter pores in the shale reservoir.

[0135] Specifically, according to Formula Thirteen, the formula for the gas production rate of an organic capillary with a single pore radius of r is as follows:

[0136]

[0137] Where, μ g Where is the gas viscosity, Pa·s; r is the pore radius, m; L s L is the slip length, in meters; L is the pore length, in meters; ΔP is the pressure difference across the pore, in Pa. The pressure gradient within the pores can be derived from... express.

[0138] According to Formula 16, the formulas for gas and water production of an inorganic capillary with a single pore radius of r are as follows:

[0139]

[0140] Where, μ g The viscosity of a gas is expressed in Pa·s; μ w The viscosity of the liquid is expressed in Pa·s; L is the pore length in meters (m); r is the pore radius of the organic matter; ΔP is the pressure difference across the pore in Pa; h w δ represents the water film thickness in meters (m); δ represents the water boundary layer thickness in meters (m). The pressure gradient within the pores can be derived from... express.

[0141] N o (r) represents the number of capillaries in organic matter pores with radius r per unit pore area (i.e., the combination of each organic matter pore combination), N i (r) represents the number of capillaries of inorganic pores with radius r per unit pore area (i.e., the combination of each inorganic pore combination), and the specific calculation formula is as follows:

[0142]

[0143] Where w is the proportion of organic matter pore volume to total pore volume, which is dimensionless.

[0144] Taking any unit cross-section in the reservoir, porosity represents the ratio of pore area to cross-sectional area per unit area. Assuming the pores are capillaries of equal length, porosity equals porosity. The proportion of pores in the porosity model is the same as the proportion of pores in the reservoir, i.e., the proportion of organic matter pore volume to total pore volume is w, and the proportions of pore radii r1, r2, r3… are n1, n2, n3… Then, according to formulas 17, 18, and 19, the gas-liquid two-phase production equation for a unit area shale reservoir can be obtained, as shown below:

[0145]

[0146] in, Porosity is dimensionless; n1, n2, n3... represent the proportion of pore radii r1, r2, r3... respectively, which are also dimensionless.

[0147] The actual gas and water production of the reservoir is then equal to the gas and water production under the surface ratio model multiplied by the actual reservoir modification area.

[0148]

[0149] In the formula, A represents the reservoir stimulation area, in m². 2 .

[0150] This embodiment also provides a calculation and analysis using a well in the Fuling shale gas field as an example. The invention selects the core sample from this gas well for nuclear magnetic resonance analysis, and the pore size distribution is measured as follows: Figure 5 As shown, Figure 5 This is a borehole distribution diagram provided in an embodiment of the present invention. Various parameters of this well are shown in Table 1.

[0151] Table 1 Basic parameters of a well in the Fuling shale gas field

[0152]

[0153]

[0154] Using the data in Table 1 and Figure 4 Based on the pore size distribution ratio, the daily gas and water production of the reservoir were calculated using the gas-liquid two-phase production equation of this invention. The calculated daily gas production of this well was 6.27 × 10⁴ m³, and the daily water production was 0.616 m³. Table 2 shows the logging data of a well in the Fuling shale gas field, which agrees well with the calculation results of this invention, verifying the correctness of the model and formula.

[0155] Table 2. Well logging data from a well in the Fuling shale gas field.

[0156]

[0157] This invention considers fluids adsorbed on the solid surface that do not participate in flow, where the fluid does not flow due to the interaction between the solid and liquid. It also considers boundary slip caused by the tangential relative velocity between fluid molecules and the solid surface at the fluid-solid interface. Shale reservoirs are divided into organic and inorganic pore types based on wettability, and the gas-liquid two-phase flow equations within each type of pore are calculated. By combining the porosity model, the ratio of organic to inorganic pore volume, and the pore size distribution, the gas and water production per unit area can be calculated. Finally, the gas and water production under mineral conditions can be calculated based on the actual reservoir stimulation area. The calculated results match actual production well data with an error within 5%.

[0158] This invention considers the microscale effects of fluid flow in shale nanopores, the boundary layer effect caused by the interaction between fluid molecules and wall molecules, and the velocity slip effect. It establishes a gas-liquid two-phase flow model in organic and inorganic pores of shale, providing a basis for the microscale flow of shale oil and gas.

[0159] Figure 6 This is a structural block diagram of the shale reservoir gas-liquid two-phase production prediction system provided in an embodiment of the present invention. Figure 6 As shown, the shale reservoir gas-liquid two-phase production prediction system provided in this embodiment includes:

[0160] A gas-liquid two-phase flow model in organic matter pores is used to determine the gas-liquid two-phase flow equations in organic matter pores of shale reservoirs;

[0161] A gas-liquid two-phase flow model in inorganic pores is used to determine the gas-liquid two-phase flow equations in inorganic pores of shale reservoirs.

[0162] The porosity model is established based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution, which are determined by testing rock samples from shale reservoirs.

[0163] The prediction module is used to predict the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equations in organic matter pores, and the gas-liquid two-phase flow equations in inorganic matter pores.

[0164] Furthermore, the system also includes a pore division module, which is specifically used to: divide the pores of the shale reservoir into organic matter pores and inorganic matter pores based on the wettability of the shale reservoir.

[0165] The gas-liquid two-phase flow model in organic matter pores is specifically used for:

[0166] Determine the viscosity and differential pressure driving force of pore micro-elements in the organic matter pores of shale reservoirs;

[0167] The boundary conditions of organic matter pores are determined based on the gas-liquid two-phase flow characteristics in the organic matter pores of shale reservoirs.

[0168] The gas-liquid two-phase flow equation in the organic matter pores of shale reservoirs is determined based on the boundary conditions of the organic matter pores, the viscosity of the pore micro-elements, and the pressure difference driving force of the pore micro-elements.

[0169] The gas-liquid two-phase flow characteristics in the organic matter pores of the shale reservoir are as follows: the organic matter pores are hydrophobic.

[0170] The boundary conditions of the organic matter pores are: there is velocity slip on the wall of the organic matter pores, the radius of the pore element is equal to the pore radius, and the flow velocity of the pore element is equal to the slip velocity of the gas phase.

[0171] Specifically, within organic matter pores, due to the hydrophobicity of these pores, the gas-liquid two-phase flow is preferentially water-driven. After all the water is expelled, the gas flows rapidly, exhibiting gas-driven water characteristics. Velocity slip occurs at the gas interface, resulting in increased gas flow capacity and a flow rate greater than predicted by classical theory. Assumptions: the organic matter pore length is L, the pressure difference between its two ends is ΔP, the liquid phase content in the organic matter pores is low and flows out rapidly, the gas phase is subsequently produced, and the liquid phase is negligible; the gas is compressible, the water is incompressible; the gas is insoluble in water, and the temperature remains constant throughout the process; the pores are horizontal, and gravity is negligible; the gas phase has the highest velocity, V, at the center of the pore. max There is velocity slip on the wall, which is V. s The slip length is L s .

[0172] The viscosity of the pore micro-elements in the organic matter pores of shale reservoirs is:

[0173]

[0174] Where, μ g ρ is the gas viscosity, in Pa·s; L is the pore length, in meters; r is the radius of the pore element in the organic matter pores; and v is the flow velocity at the pore element in the organic matter pores.

[0175] The pressure difference driving force of the pore micro-elements in the organic matter pores of shale reservoirs is:

[0176] F=πr 2 ΔP; Formula 2

[0177] Where ΔP is the pressure difference across the organic matter pores, in Pa.

[0178] By balancing the viscous force and the pressure difference driving force of the porous micro-element, we can obtain:

[0179]

[0180] The result of the transformation is:

[0181] Therefore, the flow velocity of the porous micro-elements in the organic matter pores can be obtained as follows:

[0182]

[0183] The flow velocity of the organic matter pores is obtained by integrating the flow velocity of the pore micro-elements. The specific calculation is as follows:

[0184]

[0185] Based on the obtained boundary conditions, namely: on the walls of the organic pores, the radius of the pore element is equal to the pore radius, and the flow velocity of the pore element is equal to the slip velocity of the gas phase, we can obtain:

[0186]

[0187] Where r0 is the pore radius, the value of the constant C can be obtained from the boundary conditions.

[0188] According to the Navier slip model, the equation can be obtained as follows:

[0189]

[0190] Combining formulas four and seven, we can obtain the equation:

[0191]

[0192] Substituting the boundary condition that the radius of the porous element is equal to the pore radius (i.e., r = r0) into formula eight, we can obtain:

[0193]

[0194] Combining formulas six and nine, we can obtain the equation:

[0195]

[0196] Substituting formula ten into formula five yields the following equation:

[0197]

[0198] The formula for calculating the flow rate at the pore element dr is:

[0199] dq=2vπrdr; Formula Twelve

[0200] Substituting Equation 11 into Equation 12 and integrating, we can obtain the gas-liquid two-phase flow equation in the pores of organic matter:

[0201]

[0202] Where, μ g r0 is the gas viscosity, Pa·s; r0 is the pore radius, m; L s L is the slip length, in meters; L is the pore length, in meters; ΔP is the pressure difference across the pore, in Pa. The pressure gradient within the pores can be derived from... express.

[0203] The gas-liquid two-phase flow model in inorganic pores is specifically used for:

[0204] Determine the viscous force and differential pressure driving force of pore micro-elements in the inorganic pores of shale reservoirs;

[0205] The boundary conditions of inorganic pores are determined based on the gas-liquid two-phase flow characteristics in the inorganic pores of shale reservoirs.

[0206] The gas-liquid two-phase flow equation in the inorganic pores of shale reservoirs is determined based on the boundary conditions of inorganic pores, the viscosity of micro-elements, and the pressure difference driving force of micro-elements.

[0207] The gas-liquid two-phase flow characteristics in the inorganic pores of the shale reservoir are as follows: the hydrophilicity of the inorganic pores causes the liquid phase to flow along the walls of the inorganic pores, while the gas flows in the middle of the inorganic pores, and a liquid boundary layer is formed at the liquid phase fluid boundary.

[0208] The boundary conditions for the inorganic pores are as follows: when the radius of the pore element is equal to the pore radius minus the thickness of the liquid phase boundary layer, the flow velocity of the liquid phase is 0; when the radius of the pore element is equal to the pore radius minus the thickness of the water film, the flow velocity of the liquid phase is equal to the flow velocity of the gas phase.

[0209] Specifically, in inorganic pores, due to the hydrophilicity of capillaries, when the gas and liquid phases flow in nanopores, the liquid phase flows along the walls, while the gas flows in the middle of the pores. At the liquid-liquid boundary, the adsorption force between the inorganic pore walls and liquid molecules typically hinders fluid flow near the walls, creating a boundary layer. The presence of this boundary layer reduces the effective pore space of the inorganic material. Assumptions: The length of the inorganic pore is L, the pressure difference across it is ΔP, and the velocities at the gas and liquid interfaces are the same. The thickness of the liquid boundary layer is δ, and the thickness of the water film is h. w .

[0210] The viscous force acting on the porous element at radius r is the same as the pressure difference driving force on the porous element, resulting in the following equations:

[0211]

[0212] Where, μ g The viscosity of a gas is expressed in Pa·s; μ w ρ is the liquid viscosity, in Pa·s; L is the pore length, in meters; r is the radius of the pore element in the organic matter pores; v is the flow velocity at the pore element in the organic matter pores; ΔP is the pressure difference across the pore, in Pa; h w δ represents the water film thickness in meters (m); δ represents the water boundary layer thickness in meters (m).

[0213] Boundary conditions are set as follows: when the radius of the pore element equals the pore radius minus the thickness of the liquid boundary layer, the liquid phase flow velocity is 0; when the radius of the pore element equals the pore radius minus the thickness of the water film, the liquid phase flow velocity equals the gas phase flow velocity (i.e., r = r0 - δ, v). w =0; r = r0 - h w v g =v w Substituting into Formula Fourteen, we get:

[0214]

[0215] Integrating and solving Equation 15, we obtain the gas-liquid two-phase flow equation in the inorganic pores of shale reservoirs as follows:

[0216]

[0217] Where, μ g The viscosity of a gas is expressed in Pa·s; μ w The viscosity of the liquid is expressed in Pa·s; L is the pore length in meters; r0 is the pore radius of the organic matter; ΔP is the pressure difference across the pore in Pa; h w δ represents the water film thickness in meters (m); δ represents the water boundary layer thickness in meters (m). The pressure gradient within the pores can be derived from... express.

[0218] The face rate model is specifically used for:

[0219] Rock samples were tested and analyzed to obtain the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution of the shale reservoir.

[0220] The porosity model of shale reservoirs is determined based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution of shale reservoirs.

[0221] Specifically, analysis of shale reservoir samples revealed that the proportion of organic matter pore volume to the total pore volume is w, and the proportion of inorganic matter pore volume to the total pore volume is (1-w). Based on NMR spectroscopy, a pore size distribution map was obtained, from which the proportion of pores with pore radius r1 is n1; the proportion of pores with pore radius r2 is n2…

[0222] The porosity model of shale reservoirs is determined based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution of shale reservoirs.

[0223] The prediction module is specifically used for:

[0224] Based on the porosity model of shale reservoirs, organic matter pores of the same pore size are grouped to obtain multiple combinations of organic matter pores with different pore sizes. The combined gas-liquid two-phase production of each organic matter pore combination is calculated according to the gas-liquid two-phase flow equation in the organic matter pores of shale reservoirs. The total gas-liquid two-phase production of organic matter pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each organic matter pore combination.

[0225] Based on the porosity model of shale reservoirs, inorganic pores of different pore sizes are grouped to obtain multiple combinations of inorganic pores with different pore sizes. The combined gas-liquid two-phase production of each inorganic pore combination is calculated based on the gas-liquid two-phase flow equation in the organic pores of shale reservoirs. The total gas-liquid two-phase production of inorganic pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each inorganic pore combination.

[0226] The gas-liquid two-phase production of shale reservoirs is obtained based on the actual reservoir stimulation area, the total gas-liquid two-phase production of organic matter pores in shale reservoirs, and the total gas-liquid two-phase production of inorganic matter pores in shale reservoirs.

[0227] Specifically, according to Formula Thirteen, the formula for the gas production rate of an organic capillary with a single pore radius of r is as follows:

[0228]

[0229] Where, μ g Where is the gas viscosity, Pa·s; r is the pore radius, m; L s L is the slip length, in meters; L is the pore length, in meters; ΔP is the pressure difference across the pore, in Pa. The pressure gradient within the pores can be derived from... express.

[0230] According to Formula 16, the formulas for gas and water production of an inorganic capillary with a single pore radius of r are as follows:

[0231]

[0232] Where, μ g The viscosity of a gas is expressed in Pa·s; μ w The viscosity of the liquid is expressed in Pa·s; L is the pore length in meters (m); r is the pore radius of the organic matter; ΔP is the pressure difference across the pore in Pa; h w δ represents the water film thickness in meters (m); δ represents the water boundary layer thickness in meters (m). The pressure gradient within the pores can be derived from... express.

[0233] N o (r) represents the number of capillaries in organic matter pores with radius r per unit pore area (i.e., the combination of each organic matter pore combination), N i (r) represents the number of capillaries of inorganic pores with radius r per unit pore area (i.e., the combination of each inorganic pore combination), and the specific calculation formula is as follows:

[0234]

[0235] Where w is the proportion of organic matter pore volume to total pore volume, which is dimensionless.

[0236] Taking any unit cross-section in the reservoir, porosity represents the ratio of pore area to cross-sectional area per unit area. Assuming the pores are capillaries of equal length, porosity equals porosity. The proportion of pores in the porosity model is the same as the proportion of pores in the reservoir, i.e., the proportion of organic matter pore volume to total pore volume is w, and the proportions of pore radii r1, r2, r3… are n1, n2, n3… Then, according to formulas 17, 18, and 19, the gas-liquid two-phase production equation for a unit area shale reservoir can be obtained, as shown below:

[0237]

[0238] in, Porosity is dimensionless; n1, n2, n3... represent the proportion of pore radii r1, r2, r3... respectively, which are also dimensionless.

[0239] The actual gas and water production of the reservoir is then equal to the gas and water production under the surface ratio model multiplied by the actual reservoir modification area.

[0240]

[0241] In the formula, A represents the reservoir stimulation area, in m². 2 .

[0242] The present invention also provides a computer device, including: a memory, a processor, and a computer program, the computer program being stored in the memory and configured to be executed by the processor to implement the above-described method for predicting the gas-liquid two-phase production of shale reservoirs.

[0243] The present invention also provides a machine-readable storage medium storing computer program instructions thereon, which, when executed by a processor, implement the above-described method for predicting the gas-liquid two-phase production of shale reservoirs.

[0244] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code. The solutions in the embodiments of the present invention can be implemented using various computer languages, such as the object-oriented programming language Java and the interpreted scripting language JavaScript.

[0245] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0246] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0247] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0248] Although preferred embodiments of the invention have been described, those skilled in the art, upon learning the basic inventive concept, can make other changes and modifications to these embodiments. Therefore, the appended claims are intended to be interpreted as including both the preferred embodiments and all changes and modifications falling within the scope of the invention.

[0249] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

Claims

1. A method for predicting the gas-liquid two-phase production of shale reservoirs, characterized in that, include: A gas-liquid two-phase flow model was established in the organic matter pores of shale reservoirs, and the gas-liquid two-phase flow equations in the organic matter pores were determined based on the gas-liquid two-phase flow model. A gas-liquid two-phase flow model in the inorganic pores of shale reservoirs was established, and the gas-liquid two-phase flow equation in the inorganic pores was determined based on the gas-liquid two-phase flow model. By conducting rock sample tests on shale reservoirs, the ratio of organic to inorganic porosity and the pore size distribution of shale reservoirs were determined. Based on the ratio of organic to inorganic porosity and the pore size distribution, a porosity model of shale reservoirs was established. Predict the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equation in organic matter pores, and the gas-liquid two-phase flow equation in inorganic matter pores.

2. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 1, characterized in that, The organic and inorganic porosity of shale reservoirs is determined based on the wettability of the shale reservoir.

3. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 1, characterized in that, The establishment of a gas-liquid two-phase flow model in the organic matter pores of shale reservoirs includes: A two-phase flow model of gas and liquid in organic matter pores is established based on the pore length, pressure difference across the pores, liquid flow velocity, gas flow velocity, slip velocity and slip length on the pore wall.

4. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 3, characterized in that, The determination of the gas-liquid two-phase flow equation in organic matter pores based on the gas-liquid two-phase flow model includes: Determine the viscous force and pressure driving force of the porous micro-elements in the organic matter pores; The boundary conditions of organic matter pores are determined based on the gas-liquid two-phase flow characteristics in the organic matter pores. The gas-liquid two-phase flow equation in organic matter pores is determined based on the boundary conditions of the organic matter pores, the viscosity of the pore micro-elements, and the pressure difference driving force of the pore micro-elements.

5. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 4, characterized in that, The boundary conditions of the organic matter pores are: there is velocity slip on the wall of the organic matter pores, the radius of the pore element is equal to the pore radius, and the flow velocity of the pore element is equal to the slip velocity of the gas phase.

6. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 1, characterized in that, The establishment of the gas-liquid two-phase flow model in the inorganic pores of shale reservoirs includes: A two-phase flow model of gas and liquid in inorganic pores is established based on the inorganic pore length, pressure difference across the inorganic pores, liquid phase flow velocity in the inorganic pores, liquid boundary layer thickness and water film thickness, and gas phase flow velocity in the inorganic pores.

7. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 6, characterized in that, The determination of the gas-liquid two-phase flow equation in inorganic pores based on the gas-liquid two-phase flow model in inorganic pores includes: Determine the viscous force and pressure driving force of porous micro-elements in inorganic materials; The boundary conditions of inorganic pores are determined based on the gas-liquid two-phase flow characteristics in inorganic pores. The gas-liquid two-phase flow equation in inorganic pores is determined based on the boundary conditions of inorganic pores, the viscosity of the micro-element, and the pressure difference driving force of the micro-element.

8. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 7, characterized in that, The boundary conditions for the inorganic pores are as follows: When the radius of the porous micro-element is equal to the pore radius minus the thickness of the liquid phase boundary layer, the flow velocity of the liquid phase is 0. When the radius of the porous micro-element is equal to the pore radius minus the thickness of the water film, the flow velocity of the liquid phase is equal to the flow velocity of the gas phase.

9. The method for predicting the gas-liquid two-phase production of shale reservoirs according to claim 1, characterized in that, The method for predicting the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equation in organic matter pores, and the gas-liquid two-phase flow equation in inorganic matter pores includes: Based on the porosity model of shale reservoirs, organic matter pores of the same pore size are grouped to obtain multiple combinations of organic matter pores with different pore sizes. The combined gas-liquid two-phase production of each organic matter pore combination is calculated according to the gas-liquid two-phase flow equation in the organic matter pores of shale reservoirs. The total gas-liquid two-phase production of organic matter pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each organic matter pore combination. Based on the porosity model of shale reservoirs, inorganic pores of different pore sizes are grouped to obtain multiple combinations of inorganic pores with different pore sizes. The combined gas-liquid two-phase production of each inorganic pore combination is calculated based on the gas-liquid two-phase flow equation in the organic pores of shale reservoirs. The total gas-liquid two-phase production of inorganic pores in shale reservoirs is obtained based on the combined gas-liquid two-phase production of each inorganic pore combination. The gas-liquid two-phase production of shale reservoirs is obtained based on the actual reservoir stimulation area, the total gas-liquid two-phase production of organic matter pores in shale reservoirs, and the total gas-liquid two-phase production of inorganic matter pores in shale reservoirs.

10. A shale reservoir gas-liquid two-phase production prediction system, characterized in that, include: A gas-liquid two-phase flow model in organic matter pores is used to determine the gas-liquid two-phase flow equations in organic matter pores of shale reservoirs; A gas-liquid two-phase flow model in inorganic pores is used to determine the gas-liquid two-phase flow equations in inorganic pores of shale reservoirs. The porosity model is established based on the ratio of organic matter porosity to inorganic matter porosity and the pore size distribution, which are determined by testing rock samples from shale reservoirs. The prediction module is used to predict the gas-liquid two-phase production of shale reservoirs based on the porosity model of shale reservoirs, the gas-liquid two-phase flow equation in organic matter pores, and the gas-liquid two-phase flow equation in inorganic matter pores.

11. A computer device, characterized in that, include: Memory; processor; as well as Computer programs; The computer program is stored in a memory and configured to be executed by a processor to implement the shale reservoir gas-liquid two-phase production prediction method according to any one of claims 1 to 9.

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