A method and device for numerical simulation of low permeability reservoirs

Abstract

The present application discloses a method and device for numerical simulation of low permeability reservoirs. The method divides the low permeability reservoir into multiple small units, establishes a mathematical model suitable for numerical simulation of low permeability reservoirs, and solves the flow of fluids. During the solution process, the pressure and fluid saturation of the grid nodes are continuously updated until the convergence condition is met. Considering the change of permeability with pressure, an appropriate formula is selected to calculate the permeability according to the difference between the current and initial pressures of the grid nodes. A seepage model considering the starting pressure gradient is introduced, and a starting pressure gradient threshold is set to determine whether the fluid starts to flow, and the flow rate is calculated accordingly. The improved mass conservation equation is solved by combining the permeability and flow rate. The pressure equation and the saturation equation are solved to determine the saturation of the fluid. The problem of how to establish a model that can accurately describe the flow law of fluids in low permeability reservoirs is solved, thereby effectively promoting the development and utilization of low permeability reservoirs.

Description

Technical Field

[0001] The present application relates to the technical field of oil and gas exploitation, and in particular to a method and device for numerical simulation of low permeability reservoirs. Background Art

[0002] Low permeability reservoirs refer to oil and gas reservoirs with low permeability, small pore throats, large seepage resistance, and difficult fluid flow. This type of reservoir usually has the characteristics of "one bad and three lows", namely, poor reservoir properties, low water content, low oil recovery rate, and low recovery degree.

[0003] The pore throats of low permeability reservoirs are small, resulting in great resistance to the flow of fluids in them. Compared with traditional medium and high permeability reservoirs, the fluid flow in low permeability reservoirs needs to overcome a higher starting pressure gradient to occur. In addition, the stress sensitivity of the reservoir is also an important aspect of the seepage characteristics of low permeability reservoirs, which makes the permeability change significantly with the change of pressure, further exacerbating the nonlinear characteristics of the seepage.

[0004] Traditional reservoir numerical simulation methods are mostly based on Darcy's linear seepage law, which has achieved remarkable results in describing fluid flow in medium and high permeability reservoirs. However, when faced with low permeability reservoirs, the applicability of these methods is seriously challenged. Due to the inability to accurately describe the nonlinear seepage characteristics in low permeability reservoirs, such as the influence of the starting pressure gradient and stress sensitivity, traditional methods often cannot provide accurate and reliable prediction results.

[0005] Therefore, how to establish a model that can accurately describe the fluid flow laws in low permeability reservoirs, so as to effectively promote the development and utilization of low permeability reservoirs, has become a problem that needs to be solved urgently. Summary of the invention

[0006] In the embodiments of the present application, by providing a low permeability reservoir numerical simulation method, the problem of how to establish a model that can accurately describe the fluid flow laws in the low permeability reservoir is solved, thereby effectively promoting the development and utilization of the low permeability reservoir.

[0007] In a first aspect, an embodiment of the present application provides a method for numerical simulation of a low permeability reservoir, the method comprising: dividing the low permeability reservoir into a plurality of small units by dividing a grid, and solving the fluid flow in each small unit by establishing a mathematical model suitable for numerical simulation of the low permeability reservoir; wherein the fluid comprises an oil phase, a water phase and a gas phase; during the solution process, continuously updating the pressure of the grid node and the saturation of the fluid until a convergence condition is reached; selecting a corresponding formula to calculate the permeability of the grid node based on a comparison between the current pressure of the grid node and the initial pressure; using a seepage model that takes into account a starting pressure gradient to describe the relationship between the flow velocity and the pressure gradient of the grid node, setting a starting pressure gradient threshold, judging whether the fluid starts to flow based on a comparison between the pressure gradient of the grid node and the starting pressure gradient threshold, and calculating the flow velocity based on the seepage model; wherein the flow velocity is the speed at which the fluid flows between the grid nodes; solving the mathematical model suitable for numerical simulation of the low permeability reservoir in combination with the calculated permeability and flow velocity of the grid node to obtain an improved mass conservation equation; solving the oil phase saturation, water phase saturation and gas phase saturation by solving the pressure equation and the saturation equation in the auxiliary equation.

[0008] In a possible implementation, the establishment of a mathematical model suitable for numerical simulation of low permeability reservoirs includes: deriving a mass conservation equation for the fluid under formation and ground conditions based on the law of conservation of mass; wherein the mass conservation equation is used to describe the mass change of the fluid in a unit volume of rock; using Darcy's law to describe the seepage velocity of the gas phase, and introducing a modified Darcy's law to describe the seepage velocity of the oil phase and the water phase, so as to obtain the motion equation of each phase; wherein the modified Darcy's law takes into account the influence of the starting pressure gradient on the seepage velocity; substituting the motion equation into the mass conservation equation to obtain the continuity equation, and defining a boundary condition to solve the continuity equation; the boundary condition includes a closure condition of the outer boundary, a constant production condition of the inner boundary, a constant bottom hole pressure condition of the inner boundary, and the pressure distribution and saturation distribution at the initial moment; introducing an auxiliary equation as a constraint condition to establish a mathematical model suitable for numerical simulation of low permeability reservoirs.

[0009] In a possible implementation, the method selects a corresponding formula to calculate the permeability of the grid node based on a comparison between the current pressure of the grid node and the initial pressure, including: when the current pressure of the grid node is lower than the initial pressure, using a first permeability calculation formula to calculate the permeability of the grid node, and updating the current pressure of the grid node to the initial pressure; when the current pressure of the grid node is higher than or equal to the initial pressure, using a second permeability calculation formula to calculate the permeability of the grid node, and keeping the initial pressure of the grid node unchanged.

[0010] In a possible implementation, the first permeability calculation formula is: ;in, is the permeability of the current grid node, is the initial permeability of the grid node, is the sensitivity of the permeability of the grid nodes to the pressure change during the pressure reduction process, is the initial pressure of the grid node, is the current pressure of the grid node; the second permeability calculation formula is: ;in, is the permeability of the current grid node, is the previous permeability of the grid node, is the sensitivity of the permeability of the grid node to the pressure change when the pressure recovers or increases, is the previous pressure at the grid node, is the current pressure at the mesh node.

[0011] In a possible implementation, the starting pressure gradient threshold is set as follows: within the range where the water saturation is greater than the irreducible water saturation and less than the critical residual oil saturation, the starting pressure gradient value of the oil-water two-phase is calculated using the linear relationship between the water saturation and the minimum pressure gradient required for the fluid to start flowing, and the starting pressure gradient value of the oil-water two-phase is used as the starting pressure gradient threshold.

[0012] In a possible implementation, the method of judging whether the fluid starts to flow based on the comparison between the pressure gradient of the grid node and the starting pressure gradient threshold, and calculating the flow rate based on the seepage model, includes: if the pressure gradient of the grid node is less than or equal to the starting pressure gradient threshold, the fluid does not flow; if the pressure gradient of the grid node is greater than the starting pressure gradient threshold, the fluid starts to flow at the grid node, and the flow rate is calculated based on the seepage model.

[0013] In a possible implementation, the method of solving the oil phase saturation, water phase saturation and gas phase saturation by solving the pressure equation and the saturation equation in the auxiliary equation includes: converting the improved mass conservation equation into a pressure equation containing only fluid pressure; converting the pressure equation containing only fluid pressure into an equation containing only oil phase pressure; performing implicit difference processing on the equation containing only oil phase pressure to obtain an implicit pressure difference equation group, and obtaining the oil phase pressure by solving the equation group; substituting the oil phase pressure into the auxiliary equation to obtain the water phase pressure and the gas phase pressure; obtaining the saturation equations of the oil phase and the water phase by difference processing of the improved mass conservation equations of the oil phase and the water phase, and solving the oil phase saturation and the water phase saturation by pressure and production parameters; and calculating the gas phase saturation according to the principle that the sum of the saturations is 1.

[0014] In a second aspect, an embodiment of the present application provides a low permeability reservoir numerical simulation device, and an establishment module is used to divide the low permeability reservoir into multiple small units by dividing the grid, and the fluid flow in each small unit is solved by establishing a mathematical model suitable for the numerical simulation of the low permeability reservoir; wherein the fluid includes an oil phase, a water phase and a gas phase; during the solution process, the pressure of the grid node and the saturation of the fluid are continuously updated until the convergence condition is reached; a permeability calculation module is used to select a corresponding formula to calculate the permeability of the grid node based on the comparison between the current pressure of the grid node and the initial pressure; a flow rate calculation module is used to use a consideration The seepage model of the starting pressure gradient describes the relationship between the flow velocity and the pressure gradient of the grid node, sets the starting pressure gradient threshold, determines whether the fluid starts to flow based on the comparison between the pressure gradient of the grid node and the starting pressure gradient threshold, and calculates the flow velocity based on the seepage model; wherein the flow velocity is the speed at which the fluid flows between the grid nodes; a solution module is used to solve a mathematical model suitable for numerical simulation of low permeability reservoirs by combining the calculated permeability and flow velocity of the grid nodes, and obtain an improved mass conservation equation; by solving the pressure equation and the saturation equation in the auxiliary equation, the oil phase saturation, water phase saturation and gas phase saturation are solved.

[0015] In a third aspect, an embodiment of the present application provides a low permeability reservoir numerical simulation server, comprising a memory and a processor; the memory is used to store computer executable instructions; the processor is used to execute the computer executable instructions to implement the method described in the first aspect or any possible implementation method of the first aspect.

[0016] In a fourth aspect, an embodiment of the present application provides a computer-readable storage medium, wherein the computer-readable storage medium stores executable instructions, and when a computer executes the executable instructions, the method described in the first aspect or any possible implementation method of the first aspect can be implemented.

[0017] One or more technical solutions provided in the embodiments of the present application have at least the following technical effects:

[0018] The embodiment of the present application provides a method for numerical simulation of low permeability reservoirs. By dividing the grid, the low permeability reservoir is divided into multiple small units, and a mathematical model suitable for low permeability characteristics is established for each small unit, which can more accurately capture the complex flow behavior of fluids in low permeability media. This includes the interaction and dynamic changes between the three-phase fluids of oil phase, water phase and gas phase, thereby significantly improving the accuracy of the simulation results. During the simulation process, the permeability is updated in real time according to the pressure changes of the grid nodes, reflecting the nonlinear characteristics of the permeability changing with pressure in the low permeability reservoir. This dynamic adjustment mechanism makes the simulation closer to the actual geological conditions and helps to more accurately predict the fluid flow law during the reservoir development process. The introduction of a seepage model that considers the start-up pressure gradient and the setting of the start-up pressure gradient threshold can accurately determine when the fluid starts to flow. This improvement is particularly important for low permeability reservoirs, because the fluid flow in low permeability media is often significantly affected by the start-up pressure gradient. Through this mechanism, the start-up and evolution process of fluid flow can be more accurately simulated. By solving the improved mass conservation equation, the accurate tracking of the distribution of oil phase, water phase and gas phase in the reservoir is achieved. This helps to understand the dynamic changes of each phase during the development process and provides a scientific basis for optimizing the production strategy. It solves the problem of how to establish a model that can accurately describe the fluid flow law in low permeability reservoirs, thereby effectively promoting the development and utilization of low permeability reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0019] In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings required for use in the embodiments of the present application or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0020] Figure 1 A flow chart of a low permeability reservoir numerical simulation method provided in an embodiment of the present application;

[0021] Figure 2 A schematic diagram of the variation of permeability with pressure in a deformable medium provided in an embodiment of the present application;

[0022] Figure 3 A schematic diagram of the variation of permeability with pressure in the first stage provided in the embodiment of the present application;

[0023] Figure 4 A schematic diagram of the variation of permeability with pressure in the second stage provided in the embodiment of the present application;

[0024] Figure 5 A schematic diagram of formation permeability changing with pressure provided in an embodiment of the present application;

[0025] Figure 6 A schematic diagram of a well after fracture addition provided in an embodiment of the present application;

[0026] Figure 7 A schematic diagram of the results of daily oil production, daily liquid production, cumulative oil production and water content calculated by simulation considering the startup pressure gradient provided in an embodiment of the present application;

[0027] Figure 8 The average formation pressure distribution diagram of each layer of the reservoir after 1000 days at the start-up pressure G=0.05MPa / m and the oil saturation distribution diagram of the first two layers provided in the embodiment of the present application;

[0028] Fig. 9 The average formation pressure distribution diagram of each layer of the reservoir after 2000 days at the start-up pressure G=0.05MPa / m and the oil saturation distribution diagram of the first two layers provided in the embodiment of the present application;

[0029] Fig.10 The average formation pressure distribution diagram of each layer of the reservoir after 3650 days at the start-up pressure G=0.05MPa / m and the oil saturation distribution diagram of the first two layers provided in the embodiment of the present application;

[0030] Fig.11 A schematic diagram of the results of daily oil production, daily liquid production, and cumulative oil production calculated by simulation taking into account stress sensitivity factors provided in an embodiment of the present application;

[0031] Fig.12 The stress sensitivity coefficient provided in the embodiment of the present application The average formation pressure distribution map of each layer of the reservoir after 1000 days and the oil saturation distribution map of the first two layers;

[0032] Fig.13 The stress sensitivity coefficient provided in the embodiment of the present application is The average formation pressure distribution map of each layer of the reservoir after 2000 days and the oil saturation distribution map of the first two layers;

[0033] Fig.14 The stress sensitivity coefficient provided in the embodiment of the present application The average formation pressure distribution map of each layer of the reservoir after 3650 days and the oil saturation distribution map of the first two layers;

[0034] Fig.15 A schematic diagram of the results of daily oil production, daily liquid production, and cumulative oil production calculated by simulating and calculating the start-up pressure and stress sensitivity factors provided in an embodiment of the present application;

[0035] Fig.16 The embodiment of the present application provides a starting pressure gradient G = 0.05MPa / m, and a stress sensitivity coefficient The average formation pressure distribution map of each layer of the reservoir after 1000 days and the oil saturation distribution map of the first two layers;

[0036] Fig.17 The embodiment of the present application provides a starting pressure gradient G = 0.05MPa / m, and a stress sensitivity coefficient The average formation pressure distribution map of each layer of the reservoir after 2000 days and the oil saturation distribution map of the first two layers;

[0037] Fig.18 The embodiment of the present application provides a starting pressure gradient G = 0.05MPa / m, and a stress sensitivity coefficient The average formation pressure distribution map of each layer of the reservoir after 3650 days and the oil saturation distribution map of the first two layers;

[0038] Fig.19 A schematic diagram of a low permeability reservoir numerical simulation device provided in an embodiment of the present application;

[0039] Fig. 20 A schematic diagram of a low permeability reservoir numerical simulation server provided in an embodiment of the present application. DETAILED DESCRIPTION

[0040] The technical solutions in the embodiments of the present application will be described clearly and completely below in conjunction with the drawings in the embodiments of the present application. Obviously, the described embodiments are part of the embodiments of the present application, rather than all of the embodiments. Based on the embodiments in the present application, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of this application.

[0041] The following describes some of the techniques involved in the embodiments of the present application to facilitate understanding, and they should be considered as merely exemplary. Therefore, it should be appreciated by those of ordinary skill in the art that various changes and modifications may be made to the embodiments described herein without departing from the scope and spirit of the present application. Similarly, for the sake of clarity and conciseness, some descriptions of well-known functions and structures are omitted in the following description.

[0042] The present application embodiment provides a method for numerical simulation of low permeability reservoirs, such as Figure 1 As shown, the method includes steps S101 to S106. Among them, Figure 1 This is only an execution order shown in the embodiment of the present application, and does not represent the only execution order of a low permeability reservoir numerical simulation method. In the case that the final result can be achieved, Figure 1 The steps shown may be performed in parallel or reversed.

[0043] S101: The low permeability reservoir is divided into multiple small units by dividing the grid, and the fluid flow in each small unit is solved by establishing a mathematical model suitable for numerical simulation of low permeability reservoirs. The fluid includes oil phase, water phase and gas phase.

[0044] Specifically, the entire low permeability reservoir area is divided into multiple closely connected and independent small units through fine grid division technology. The purpose of this step is to simulate and analyze the complex fluid flow behavior inside the reservoir more accurately and meticulously. In each divided small unit, the flow behavior of the fluid is considered as a local system. In order to accurately describe and predict the flow of these fluids, it is necessary to establish a special numerical simulation mathematical model suitable for the characteristics of low permeability reservoirs. This model usually takes into account the physical properties of the fluid and the geological characteristics of the reservoir. By establishing such a mathematical model and performing numerical solutions, the flow state of the fluid in each small unit, such as flow velocity, pressure distribution and saturation, can be obtained, and then the fluid flow of the entire reservoir can be comprehensively simulated and analyzed.

[0045] Establishing a mathematical model suitable for numerical simulation of low permeability reservoirs includes the following steps.

[0046] The basic assumptions for establishing a mathematical model suitable for numerical simulation of low permeability reservoirs are: the model considers three-phase fluids of oil, gas and water and their respective corresponding phases. This means that the states and dynamic changes of these three phases need to be tracked separately. It is assumed that the gas phase can dissolve in the oil phase and the water phase when the pressure increases to a certain extent to form dissolved gas. On the contrary, when the pressure decreases, the gas can quickly separate from the oil phase and the water phase and become free gas. The dissolution and overflow in this process are considered to be completed instantly. It is assumed that there is no mass exchange between the water phase and the oil phase, that is, they each maintain independent flow and state changes. The seepage of the gas phase follows Darcy's law, that is, the flow rate is proportional to the pressure gradient. The seepage of the oil phase and the water phase follows the modified Darcy's law, which takes into account special effects in low permeability reservoirs, such as the starting pressure gradient. In addition, it is assumed that the oil phase and the water phase have the same starting pressure gradient. The permeability change caused by pressure change, that is, the pressure-sensitive effect, is considered in the model. During the simulation process, the effects of capillary force and gravity are considered, which have an important influence on the fluid flow in low permeability reservoirs. The compressibility of rock, oil, gas, and water is taken into account in the model, which means that their volume and density change when the pressure changes. To simplify the model, the temperature of the reservoir is assumed to remain constant throughout the simulation.

[0047] 1. Based on the law of conservation of mass, the mass conservation equation of the fluid under formation and ground conditions is derived. The mass conservation equation is used to describe the mass change of the fluid in a unit volume of rock.

[0048] Specifically, in reservoir simulation, in order to describe the mass change of fluid in unit volume of rock, a mass conservation model is established based on the law of mass conservation. This model analyzes the seepage of each phase in any unit volume by applying the law of mass conservation to them.

[0049] The mass conservation equations of each phase under formation conditions are as follows. Oil phase: . Aqueous phase: . Gas phase: .in, represents the seepage velocity of the oil phase, represents the percolation velocity of the gas phase, represents the seepage velocity of the water phase, It indicates the mass flow rate of oil injected or produced per unit volume of rock under formation conditions. It indicates the mass flow rate of gas injected or produced per unit volume of rock under formation conditions. It indicates the mass flow rate of water injected or extracted into or out of a unit volume of rock under formation conditions. Indicates the saturation of the oil phase, represents the saturation of the gas phase, represents the saturation of the water phase, represents the volume coefficient of the oil phase, represents the volume coefficient of the gas phase, represents the volume coefficient of the water phase, Indicates the dissolved gas-oil ratio, represents the dissolved gas-water ratio, represents the porosity, Indicates the density of oil under surface conditions, represents the density of air at ground level. represents the density of water at ground conditions, Indicates the density of gas under formation conditions.

[0050] The mass conservation equations for each phase under ground conditions are as follows. Oil phase: . Aqueous phase: . Gas phase: .in, It indicates the mass flow rate of oil injected or produced per unit volume of rock under ground conditions. It indicates the mass flow rate of gas injected or produced per unit volume of rock under ground conditions. It expresses the mass flow rate of water injected or produced into or out of a unit volume of rock under ground conditions.

[0051] It should be noted that the unit of seepage velocity in this application is cm / s. The mass flow rate injected into a unit volume of rock is a positive number, and the mass flow rate extracted from a unit volume of rock is a negative number. The unit of porosity and saturation of each phase is percentage ( The volume coefficient is dimensionless, the dissolved gas-oil ratio and dissolved gas-water ratio are dimensionless, and the unit of all densities is g / cm 3 .

[0052] For the oil phase, the seepage velocity of the oil phase and the mass flow rate of oil injected or produced per unit volume of rock under formation conditions and surface conditions are considered. By combining these factors with the saturation, volume coefficient and density of the oil phase, equation (1) for the oil phase under formation conditions and equation (4) for surface conditions are obtained. Similarly, for the water phase and gas phase, their mass conservation equations under formation conditions and surface conditions are established respectively. Equations (2) and (5) of the water phase consider the seepage velocity of the water phase and the mass flow rate of water injected or produced per unit volume of rock under formation conditions, and combine the saturation, volume coefficient and density of the water phase. The equation of the gas phase is more complicated because it also needs to consider the influence of dissolved gas, that is, the dissolved gas-oil ratio and the dissolved gas-water ratio. Equations (3) and (6) describe the mass changes of the gas phase under formation conditions and surface conditions respectively.

[0053] 2. Use Darcy's law to describe the seepage velocity of the gas phase, and introduce the modified Darcy's law to describe the seepage velocity of the oil phase and the water phase to obtain the motion equation of each phase. Among them, the modified Darcy's law takes into account the influence of the starting pressure gradient on the seepage velocity.

[0054] Specifically, Darcy's law is a basic law that describes the seepage velocity of fluid in porous media. For the gas phase, Darcy's law is directly used to describe its seepage velocity without considering the influence of the starting pressure gradient. For the oil phase and the water phase, since they have a starting pressure gradient, the modified Darcy's law needs to be used to describe their seepage velocity. The modified Darcy's law adds a starting pressure gradient term on the basis of Darcy's law.

[0055] For the oil phase, its seepage velocity can be expressed as: For the water phase, its seepage velocity can be expressed as: For the gas phase, the percolation velocity can be expressed as: .in, represents the absolute permeability of the formation, represents the relative permeability of the oil phase, represents the relative permeability of the gas phase, represents the relative permeability of the water phase, Indicates the viscosity of the oil phase, represents the viscosity of the gas phase, represents the viscosity of the water phase, represents the oil phase starting pressure gradient, represents the water phase starting pressure gradient, Indicates the oil phase pressure, represents the gas phase pressure, represents the water phase pressure, Represents gravity. Indicates the density of oil under formation conditions, Indicates the density of water under formation conditions, Indicates the density of gas under formation conditions.

[0056] It should be noted that the unit of absolute permeability of the formation in this application is μm 2 , relative permeability is a dimensionless quantity, the unit of viscosity is mPa·s, the unit of starting pressure gradient is 0.1MPa / cm, the unit of pressure is MPa, and the unit of gravity is MPa.

[0057] In summary, the motion equations of oil, gas and water in porous media are obtained. These equations take into account the effects of fluid viscosity, relative permeability, pressure gradient, gravity and starting pressure gradient on the seepage velocity.

[0058] 3. Substitute the equation of motion into the mass conservation equation to obtain the continuity equation, and define the boundary conditions to solve the continuity equation. The boundary conditions include the closure condition of the outer boundary, the constant production condition of the inner boundary, the constant bottom hole pressure condition of the inner boundary, and the pressure distribution and saturation distribution at the initial time.

[0059] Specifically, the continuity equation is obtained by substituting the equation of motion into the mass conservation equation. This equation describes the flow of fluid in the reservoir and takes into account the physical properties of the fluid and the characteristics of the reservoir. The continuity equation for the oil phase is: The continuity equation of the water phase is: The continuity equation for the gas phase is: .

[0060] In order to solve the above continuity equation, it is necessary to define the solution conditions, which include the closure condition of the outer boundary, the constant production condition of the inner boundary, the constant bottom hole pressure condition of the inner boundary, and the pressure distribution and saturation distribution at the initial moment.

[0061] The specific explanation of the closed condition of the outer boundary is as follows. The outer boundary condition mainly refers to the pressure condition at the reservoir boundary. Since the outer boundary is similar to an impermeable closed boundary and has little effect on the fluid seepage process, in the reservoir simulation process, in order to simplify the calculation, it is treated as an impermeable closed boundary, that is, the closed condition of the outer boundary. This means that on the outer boundary G of the reservoir, the pressure gradient perpendicular to the outer normal direction of the outer boundary of the reservoir is zero, that is, the condition is satisfied: Where n is the direction of the outer normal of the reservoir outer boundary G, and p is the pressure.

[0062] The specific explanation of the constant production condition of the inner boundary is as follows. In the process of reservoir development, the inner boundary condition refers to the fluid flow characteristics on the internal boundary of the reservoir. Since the geometric dimensions of oil wells and water wells are very small compared to the overall size of the reservoir, these wells are regarded as point sinks or point sources in actual simulations and analyses. The constant production of the inner boundary means that the oil well or water well produces or injects at a constant flow rate at a specific location. It can be expressed as: .in, Indicates flow rate, which can be oil production, water production or water injection, etc. represents the spatial coordinates in the reservoir, Indicates time, It is the specific location coordinate of the oil well or water well. c. The fixed bottom hole pressure condition of the inner boundary.

[0063] The specific explanation of the fixed bottom hole pressure condition of the inner boundary is as follows. At a specific location of an oil well or water well, i.e., the bottom hole, the bottom hole pressure is set as a function that changes with time, and at this location, no matter how the pressure and saturation at other locations inside the reservoir change, the bottom hole pressure remains at this set value. It can be expressed as: .in, Indicates pressure, represents the spatial coordinates in the reservoir, Indicates time, It is the specific location coordinates of an oil or water well. Indicates that over time Variable bottom hole pressure setpoints. By setting the bottom hole pressure, the production or injection rate of an oil or water well can be controlled, thereby affecting the flow and distribution of fluids inside the reservoir.

[0064] The specific explanations of the pressure distribution and saturation distribution at the initial moment are as follows. The expressions of the pressure distribution and saturation distribution at the initial moment are: The pressure distribution at the initial moment describes the reservoir The pressure value at each point at the moment. It can be expressed as: .in, Indicates pressure, Indicates time, is the uniform pressure value of the reservoir at the initial time. The saturation distribution at the initial time describes the The fluid saturation value at each point in time. For multiphase fluids, the saturation of each fluid needs to be given separately. In this application, special attention needs to be paid to the water saturation because it is crucial for the development of low permeability reservoirs. It can be expressed as: .in, represents the saturation of the water phase, is the average water saturation value of the reservoir at the initial time.

[0065] 4. Auxiliary equations are introduced as constraints to establish a mathematical model suitable for numerical simulation of low permeability reservoirs.

[0066] Specifically, when establishing a mathematical model suitable for numerical simulation of low permeability reservoirs, since the number of undetermined parameters may be greater than the number of equations, it is necessary to introduce auxiliary equations as constraints to ensure the integrity and solvability of the model.

[0067] The sum of the fluid saturations at any point in a reservoir must equal 1. Therefore, the saturation equation is: .

[0068] In low permeability reservoirs, capillary pressure has an important influence on fluid flow. Capillary pressure is the pressure difference on both sides of the oil, water or gas interface, which determines the distribution of fluid in the pores. There are two equations to describe the capillary pressure at the oil-gas interface and the oil-water interface. . .in, is the capillary pressure at the oil-gas interface, is the capillary pressure at the oil-water interface.

[0069] The equation of state describes the relationship between fluid properties such as relative permeability, capillary pressure, permeability, porosity, density and viscosity and parameters such as pressure and saturation. These equations are essential to understanding the behavior of fluids in a reservoir. The equation for relative permeability is: The equation for capillary pressure is: The equation for permeability is: The equation for porosity is: .in, is the current formation pressure, indicating that both permeability and porosity change with pressure. The equation for density is: The equation for viscosity is: .in, is the bubble point pressure. S102: During the solution process, the pressure of the grid nodes and the saturation of the fluid are continuously updated until the convergence condition is reached.

[0070] The convergence condition is defined as that in two consecutive calculations, the difference in pressure of all grid nodes and the difference in fluid saturation are both less than a preset threshold value, and the preset threshold value may be 0.01, or adjusted to other appropriate values ​​according to actual needs.

[0071] S103: According to the comparison between the current pressure of the grid node and the initial pressure, a corresponding formula is selected to calculate the permeability of the grid node.

[0072] Specifically, for low permeability reservoirs, there are many microcracks inside, which make porous media easy to deform when subjected to stress, especially elastic-plastic deformation. As the formation pressure changes, the physical properties of the matrix, pores and other materials in the rock will also change accordingly. In particular, when the pressure changes, the pores in the rock will deform, and when the pressure is restored, although some pores can return to their original shape, not all pores can be completely restored, and the deformation of some pores will always remain permanently. This pore deformation has a significant impact on permeability. During the pressure change process, the permeability will change accordingly, and after the pressure is restored, the permeability will rise, but it usually cannot return to the level before deformation. In order to describe the relationship between permeability and pressure, studies have tried a variety of mathematical relationships, including linear, exponential, power and logarithmic relationships. After comparison, it is found that both the power relationship and the exponential relationship have a certain degree of fit when describing this relationship. However, there is a problem with the power relationship when the effective stress is close to zero, that is, the value of the permeability tends to infinity, which is obviously inconsistent with the actual situation. Therefore, in the actual oilfield development process, the choice of which relationship should not only consider its fitting effect, but also its practicality and simplicity. In this case, the exponential form of the relationship is widely used because of its simplicity and good fitting effect. Specifically, the relationship between the effective stress and porosity of the formation and the permeability of the deformable medium can be expressed by the following exponential form of the relationship: .in, represents the permeability, represents the initial permeability, is the sensitivity coefficient of permeability to pressure change, is the current formation pressure, is the initial formation pressure. This relationship can better describe the characteristics of permeability changing with pressure in low permeability reservoirs.

[0073] Figure 2 This is a schematic diagram of the change in permeability with pressure in a deformable medium provided in an embodiment of the present application. Figure 2 As shown in Figure 1, the first stage is the pressure drop stage. In this stage, the formation pressure drops from Down to As the formation pressure decreases, the absolute permeability of the formation also gradually decreases. This is because the pores and cracks in the formation will deform when the pressure decreases, resulting in a decrease in permeability. At this time, the permeability calculation formula is: .in, is the initial permeability, is the stress sensitivity coefficient of the first stage, that is, the sensitivity of the permeability of the grid node to the pressure change during the pressure reduction process, is the current formation pressure, is the initial formation pressure. The second stage is the pressure recovery stage. In this stage, the formation pressure increases from Rise to Although the formation pressure can be fully restored, the absolute permeability of the formation can only be restored to level, and cannot be fully restored to This is because the deformation of some pores and cracks is permanent and cannot be completely restored. At this time, the permeability calculation formula is: ,in The pressure drops to The permeability at is the stress sensitivity coefficient of the second stage, that is, the sensitivity of the permeability of the grid node to the pressure change when the pressure recovers or increases. is the current formation pressure, The pressure drops to The formation pressure at that time. , and Corresponding to , and The penetration rate at .

[0074] Since elastic plasticity will cause changes in absolute permeability when considering the absolute permeability of the formation, it is necessary to take this into account in the numerical simulation program. In actual operation, it is not possible to simply judge whether the pressure is rising or falling by comparing the pressure value at the current moment with the pressure value at the previous moment, and choose to use formula (27) or formula (28) to calculate the permeability accordingly. Because in the actual process of formation pressure change, the pressure values ​​before and after the moment may fluctuate or repeat. If the calculation formula is blindly selected based on the simple direction of pressure change, the formation permeability may be excessively reduced in the simulation.

[0075] Figure 3 The schematic diagram of the first stage permeability variation with pressure provided in the embodiment of the present application. Figure 3 As shown in Figure 2, during this stage, the pressure may fluctuate, that is, the pressure value may temporarily increase during the decrease process, and the permeability will be affected accordingly. Specifically, if the pressure at a certain moment is Compared with the previous moment, The penetration rate rises at a certain point, but then continues to decline. The value corresponding to the point will be This is because repeated pressure causes more severe deformation of pores and cracks, further reducing permeability.

[0076] Figure 4 The schematic diagram of the second stage permeability variation with pressure provided in the embodiment of the present application. Figure 4 As shown in the figure, in this stage, although the formation pressure can be restored, the permeability cannot be fully restored to the initial level. This is because the deformation of some pores and cracks is permanent. Similar to the first stage, the second stage may also experience repeated pressure fluctuations. This repetition will also lead to a further decrease in permeability. However, in this stage, it is not possible to determine which formula should be used to calculate the permeability simply by comparing it with the initial pressure value. This is because the pressure value at this time may have exceeded the initial pressure value or decreased during the recovery process. Therefore, it is necessary to compare the pressure value at the current moment with the pressure value at the previous moment or the initial moment to select the appropriate formula.

[0077] According to the comparison between the current pressure and the initial pressure of the grid node, a corresponding formula is selected to calculate the permeability of the grid node, including: when the current pressure of the grid node is lower than the initial pressure, the first permeability calculation formula is used to calculate the permeability of the grid node, and the current pressure of the grid node is updated to the initial pressure. When the current pressure of the grid node is higher than or equal to the initial pressure, the second permeability calculation formula is used to calculate the permeability of the grid node, and the initial pressure of the grid node is kept unchanged. The first permeability calculation formula is: .in, is the permeability of the current grid node, is the initial permeability, is the sensitivity of the permeability of the grid nodes to the pressure change during the pressure reduction process, is the initial formation pressure, is the current pressure of the grid node. The second permeability calculation formula is: .in, is the permeability of the current grid node, is the previous permeability of the grid node, is the sensitivity of the permeability of the grid node to the pressure change when the pressure recovers or increases, is the previous pressure at the grid node, is the current pressure at the mesh node.

[0078] Figure 5 This is a schematic diagram of the change of formation permeability with pressure provided in the embodiment of the present application. Figure 5 As shown in Figure 2, the sensitivity of the permeability at the grid node to the pressure change is In the case of Reduce to Although there is , and The sensitivity of the absolute permeability of the formation to the pressure change at the grid node is , but the overall trend of the absolute permeability of the formation is to decrease with the decrease in pressure. Using the new calculation method, namely the first permeability calculation formula and the second permeability calculation formula, the absolute permeability of the formation shows a steady change trend under the change of formation pressure, avoiding the situation where the absolute permeability drops too low or cannot be reasonably restored with the change of formation pressure. For low permeability reservoirs, porous media will deform with the change of effective stress. Therefore, the permeability of the formation is not only related to the spatial coordinates, but also to time (stress change). Since the permeability and reservoir pressure are in a power function relationship, this is one of the important nonlinear factors affecting the equation. In the numerical calculation process, in order to deal with this nonlinear relationship, a self-correction function is added to each step of the calculation, that is, the maximum change range of pressure and saturation allowed for each grid node in two adjacent steps is limited. Therefore, when calculating the node permeability at time n+1, formula (29) and formula (30) are used for calculation. It should be noted that the n+1 moment in this application is the current moment. At this time, the updated judgment value is stored in the initial pressure at any time, and and They represent the sensitivity of the permeability of the grid nodes to pressure changes in the case of pressure reduction and pressure recovery or increase. This calculation method can more accurately reflect the actual situation of formation permeability changes with pressure.

[0079] S104: using a seepage model that takes into account the start-up pressure gradient to describe the relationship between the flow velocity and the pressure gradient of the grid node, setting a start-up pressure gradient threshold, judging whether the fluid starts to flow based on the comparison between the pressure gradient of the grid node and the start-up pressure gradient threshold, and calculating the flow velocity based on the seepage model, wherein the flow velocity is the speed at which the fluid flows between the grid nodes.

[0080] The starting pressure gradient threshold is set as follows: within the range where the water saturation is greater than the irreducible water saturation and less than the critical residual oil saturation, the starting pressure gradient value of the oil-water two-phase is calculated using the linear relationship between the water saturation and the minimum pressure gradient required for the fluid to start flowing, and the starting pressure gradient value of the oil-water two-phase is used as the starting pressure gradient threshold.

[0081] According to the comparison between the pressure gradient of the grid node and the starting pressure gradient threshold, it is judged whether the fluid starts to flow, and the flow rate is calculated according to the seepage model, including: if the pressure gradient of the grid node is less than or equal to the starting pressure gradient threshold, the fluid does not flow. If the pressure gradient of the grid node is greater than the starting pressure gradient threshold, the fluid starts to flow at the grid node, and the flow rate is calculated according to the seepage model.

[0082] Specifically, when dealing with the seepage problem in low permeability reservoirs, the start-up pressure gradient is a crucial consideration. This seepage process exhibits obvious discontinuity. The expression of the seepage model is: .in, is the flow rate, is the pressure gradient, is the starting pressure gradient threshold, is the permeability, is the fluid viscosity. The pressure gradient of a grid node is the pressure difference between the node and its adjacent nodes divided by the distance, that is, if the pressure gradient of a grid node is less than or equal to the start pressure gradient threshold, the fluid does not flow, and the coefficient term and the production constant term associated with the node should be assigned a zero value.

[0083] Furthermore, since there is a good linear relationship between the start-up pressure gradient of oil-water two-phase seepage and water saturation, the start-up pressure gradients of the oil phase and the water phase are the same even at different water saturations. Therefore, in this application, formula (32) is used to process the start-up pressure gradient term: .in, is the starting pressure gradient threshold, is the water saturation, is the bound water saturation, is the residual oil saturation, a is the slope of the linear relationship, and b is the intercept of the linear relationship. The critical residual oil saturation is .

[0084] When dealing with the seepage problem of low permeability reservoirs, except for the starting pressure gradient, the processing methods of other parameters such as conductivity coefficient, phase permeability curve, fluid volume coefficient, viscosity, bubble point treatment, well flow index and production term are the same as those of the conventional three-dimensional three-phase black oil model.

[0085] S105: In combination with the calculated permeability and flow rate of the grid nodes, a mathematical model suitable for numerical simulation of low permeability reservoirs is solved to obtain an improved mass conservation equation.

[0086] Specifically, the expression of the right-hand side term of the continuity equation (10) of the oil phase is: The expression of the right-hand side of the continuity equation (11) of the water phase is: The expression of the right-hand side of the continuity equation (12) of the gas phase is: . Expressions (33), (34) and (35) describe the change rates of oil, water and gas phases over time, respectively. These expressions take into account the fluid saturation, porosity, fluid volume coefficient, pressure and the interaction between them. According to equation (17), we can get To simplify expression (35), equation (36) is used, which expresses the relationship between the rate of change of gas saturation over time and the rate of change of oil and water saturation. Substituting equation (36) into expression (35), we obtain , , Equation (37). Substituting expressions (33) and (34) and equations and (37) into the right-hand side of the continuity equations (10), (11), and (12) yields the improved mass conservation equation. For the oil phase, equation (38) is obtained. For the aqueous phase, equation (39) is obtained. For the gas phase, equation (40) is obtained. Among them, the improved mass conservation equations are the improved mass conservation equation of the oil phase (38), the improved mass conservation equation of the water phase (39) and the improved mass conservation equation of the gas phase (40). The above solution process is obtained by discretizing the continuity equation by the finite difference method.

[0087] S106: Solve the oil phase saturation, water phase saturation and gas phase saturation by solving the pressure equation and the saturation equation in the auxiliary equation.

[0088] The oil phase saturation, water phase saturation and gas phase saturation are solved by solving the pressure equation and the saturation equation in the auxiliary equation, which includes the following steps.

[0089] 1. Convert the improved mass conservation equation into a pressure equation that only contains fluid pressure.

[0090] 2. Convert the pressure equation containing only fluid pressure into an equation containing only oil phase pressure.

[0091] 3. Perform implicit difference processing on the equation containing only the oil phase pressure to obtain an implicit pressure difference equation group, and obtain the oil phase pressure by solving the equation group.

[0092] Starting from the continuity equations (10), (11) and (12), multiply the continuity equation (10) by , multiply the continuity equation (11) by , multiply the continuity equation (12) by , after adding and arranging, we get: .make , , , , Considering the compressibility factor, capillary pressure and saturation equation, equation (41) can be changed to: Where: , , , , .in, is the comprehensive compression factor, is the rock pore compressibility coefficient, is the oil phase compressibility coefficient, is the water phase compressibility coefficient, is the gas phase compressibility coefficient. When writing the difference equation for equation (42), for simplicity, the following differential operator should be considered, where p is the differential variable and A is the coefficient of the differential variable. . . . After implicitly differencing the pressure equation (41), both ends of the equation are multiplied by .make .in, , the following implicit pressure difference equations can be obtained: Where: , , . , , .in, , and There is no actual physical meaning, it is just to simplify the equations.

[0093] According to equation (44), the corresponding difference equations are written for the i, j, k grids. Since there are six adjacent nodes, the difference equations of the seven diagonal coefficient matrices can be formed, which can be written in the general form as shown in equation (45): Where: , , , , , , , , .

[0094] It should be noted that the process of converting the improved mass conservation equation into a pressure equation containing only fluid pressure corresponds to equation (41). The process of converting the pressure equation containing only fluid pressure into an equation containing only oil phase pressure corresponds to using and The derived capillary pressure formula is . . Replace to eliminate and , thus obtaining The implicit pressure difference equations are equation (44).

[0095] Solve the implicit pressure difference equations to obtain The above formula is the final numerical model for implicitly solving the pressure equations using the IMPES method (implicit difference processing method), which is a seven-diagonal, structurally symmetrical equation system.

[0096] 4. Substitute the oil phase pressure into the auxiliary equation to obtain the water phase pressure and gas phase pressure.

[0097] Specifically, the oil phase pressure is obtained above , the water phase pressure can be obtained by substituting the oil phase pressure into the auxiliary equation and gas phase pressure , which is shown in formula (47). .in, is the oil phase pressure obtained by solving the implicit difference equations, is the capillary pressure of the water phase relative to the oil phase, is the capillary pressure of the gas phase relative to the oil phase.

[0098] 5. The saturation equations of the oil phase and the water phase are obtained by differential processing of the improved mass conservation equations of the oil phase and the water phase, and the oil phase saturation and the water phase saturation are solved by the pressure and production parameters.

[0099] 6. Based on the principle that the sum of saturations is 1, calculate the gas phase saturation.

[0100] Specifically, in order to solve the saturation of the oil phase and the water phase during the reservoir simulation, the improved mass conservation equations of the oil phase and the water phase are firstly subjected to differential processing. Through this processing, the saturation equations of the oil phase and the water phase are obtained, as shown in Equations (48) and (49), respectively. . .in, is the coefficient matrix related to oil phase flow, is the pressure difference between adjacent time steps, is the source term related to oil phase flow, and the formula ( ) represents the oil phase saturation at the time step The amount of change within. ) represents the water phase saturation equation, which is similar to the oil phase saturation equation, but with different coefficients and source terms to reflect the characteristics of water phase flow. After obtaining the oil and water phase saturation equations, the pressure equation can be solved by implicit methods to obtain the pressure value of each grid point at the next time step. This step is the core of the IMPES method, which ensures the stability and convergence of the numerical solution. According to the principle that the sum of saturations is 1, the gas phase saturation can be calculated. At the moment, the gas phase saturation of each grid point can be calculated by formula (50): This step uses the constraint that the sum of the saturations of oil, water, and gas is 1, thereby achieving the solution of the gas phase saturation.

[0101] When dealing with special problems in numerical models of low permeability reservoirs, several aspects such as well treatment, production determination, and bottom hole pressure determination need to be considered and calculated in detail.

[0102] The steps for processing wells in the model are as follows. For the grid where the well is located, its outer boundary is regarded as a grid with an equivalent radius of circle, and introduce the capacity index and fluidity .make , ,So . Well production Capacity Index , Fluidity , Bottom hole pressure and formation pressure The relationship between is calculated. is the absolute permeability of the formation, is the relative permeability of the formation, is the thickness of the stratum, is the wellbore radius, is the viscosity of the fluid, bottom hole pressure There are two methods: explicit bottom hole pressure and implicit bottom hole pressure. Explicit bottom hole pressure means that the bottom hole pressure is known, while implicit bottom hole pressure means that the bottom hole pressure is unknown and needs to be solved through iteration.

[0103] When the total oil production When the total oil volume is distributed among the various oil layers, this can be done by calculating the production capacity index of each layer. to achieve. Then, the total oil volume is allocated according to the ratio of the capacity index of each layer to the total capacity index. The specific formula is shown in formula (52). After obtaining the oil production of each layer, the water production of each layer can be calculated by a similar method. Gas production , the specific formulas are shown in Equation (53) and Equation (54). . .in, Indicates the dissolved gas-oil ratio, Indicates the dissolved water-oil ratio, is the fluidity of the oil phase, is the fluidity of the water phase, is the fluidity of the gas phase.

[0104] When the total liquid production is given When calculating the flow rate of each phase, we first need to calculate the flow rate ratio of each phase. The specific formulas are shown in (55), (56) and (57). These flow rates describe the proportion of each phase fluid in the total flow rate. The flow rate ratio of the oil phase is for The mobility ratio of the water phase for The gas phase mobility ratio for The total oil production can be calculated by the mobility ratio , After obtaining the total oil production, equations (52), (53) and (54) can also be used to calculate the oil, water and gas production of each layer.

[0105] When the bottom hole pressure is implicit, it is necessary to obtain the current formation pressure through iterative solution. The production of wells The specific method is to use the pressure difference equations to calculate the current formation pressure , and then use formula (58) to calculate the production of the well . If it is a production well , If it is an injection well , .in, Another form of productivity index is , for the injection well When the bottom hole pressure is explicit, the formation pressure at the current time step can be used directly. To calculate the production of a well , the specific formula is shown in formula (59). Calculate the production of the well Finally, the oil, water and gas production of each layer can be calculated.

[0106] Figure 6Schematic diagram of a well after fracture provided in an embodiment of the present application. Considering the low permeability and low natural productivity of low permeability reservoirs, which require fracturing development, in order to be closer to the actual situation of actual production, the permeability near the well is modified to simulate the fracture, and the fracture equivalent conductivity method is used to process it. The spacing between the horizontal well fracturing sections is set to 120m. The fracture length is set to 80m. The conductivity of the fracture is set to 20D·cm. D is the abbreviation of Darcy unit, which is used to represent permeability. The yellow grid represents the location of the production well. In actual reservoir development, production wells are used to extract underground oil and gas. The blue grid represents the location of the water injection well. Water injection wells are generally used to inject water or other fluids into the reservoir to improve the recovery efficiency of the reservoir. The purple grid represents the location of the fracturing section. Fracturing is a commonly used reservoir production enhancement technology that forms fractures by injecting high-pressure fluids into the formation, thereby increasing the permeability of the formation.

[0107] Figure 7 A schematic diagram of the results of daily oil production, daily liquid production, cumulative oil production and water content calculated by simulation considering the startup pressure gradient provided in an embodiment of the present application. Figure 7 (a) in the figure is the daily oil production. Figure 7 (b) in the figure is the daily liquid production. Figure 7 (c) in the figure is the cumulative oil production. Figure 7(d) in the figure is the water content. This application simulates low permeability reservoirs, and specifically considers the impact of the start-up pressure gradient on reservoir development. The start-up pressure gradient is an important parameter in low permeability reservoirs, which reflects the minimum pressure difference required for the fluid to start flowing in the formation. Different start-up pressure gradient values ​​were set in the simulation, namely 0MPa / m, 0.025MPa / m, 0.05MPa / m, 0.075MPa / m and 0.1MPa / m, to study their impact on the reservoir development effect. In the absence of start-up pressure, that is, when the start-up pressure gradient is zero, when the synchronous water injection strategy is used to maintain the formation pressure, the liquid production capacity of the reservoir can be maintained at a relatively stable level. However, as the start-up pressure gradient gradually increases, the period of time during which the liquid production capacity remains stable will be significantly shortened, and the amplitude of its decline will also increase significantly. Furthermore, as the liquid production capacity continues to decline, although the water injection capacity remains unchanged, a small increase in the liquid production capacity was observed in the middle and late stages of production. This rebound may be due to the redistribution of formation pressure, changes in fluid properties, or the combined effect of other complex geological and engineering factors. It is worth noting that oil production capacity also follows a similar law of change as liquid production capacity. From a physical mechanism perspective, as the starting pressure gradient increases, the resistance that the fluid needs to overcome in the formation also increases, which leads to more energy consumption. Therefore, during the production process, the production pressure difference will gradually decrease, thereby gradually reducing the production capacity of the oil well. This reduction in production capacity is not only reflected in the liquid production capacity, but also directly affects the oil production capacity.

[0108] Figure 8 The embodiments of the present application provide a distribution diagram of the average formation pressure of each layer of the reservoir after 1000 days when the starting pressure G=0.05MPa / m and a distribution diagram of the oil saturation of the first two layers. Figure 8 (a) in the figure is the average pressure distribution diagram of the first layer after 1000 days. Figure 8 (b) in the figure is the average pressure distribution diagram of the second layer after 1000 days. Figure 8 (c) in the figure is the average pressure distribution diagram of the third layer after 1000 days. Figure 8 (d) in the figure is the oil saturation distribution map of the first layer after 1000 days. Figure 8 (e) in the figure is the oil saturation distribution map of the second layer after 1000 days.

[0109] Fig. 9 The embodiments of the present application provide a distribution diagram of the average formation pressure of each layer of the reservoir after 2000 days when the starting pressure G=0.05MPa / m and a distribution diagram of the oil saturation of the first two layers. Fig. 9 (a) in the figure is the average pressure distribution diagram of the first layer after 2000 days. Fig. 9 (b) in the figure is the average pressure distribution diagram of the second layer after 2000 days. Fig. 9 (c) in the figure is the average pressure distribution diagram of the third layer after 2000 days. Fig. 9 (d) in the figure is the oil saturation distribution map of the first layer after 2000 days. Fig. 9 (e) in the figure is the oil saturation distribution map of the second layer after 2000 days.

[0110] Fig.10 The embodiments of the present application provide a distribution diagram of the average formation pressure of each layer of the reservoir after 3650 days when the starting pressure G=0.05MPa / m and a distribution diagram of the oil saturation of the first two layers. Fig.10 (a) in the figure is the average pressure distribution diagram of the first layer after 3650 days. Fig.10 (b) in the figure is the average pressure distribution diagram of the second layer after 3650 days. Fig.10 (c) in the figure is the average pressure distribution diagram of the third layer after 3650 days. Fig.10 (d) in the figure is the oil saturation distribution map of the first layer after 3650 days. Fig.10 (e) in the figure is the oil saturation distribution map of the second layer after 3650 days.

[0111] Specifically, during the development of oil reservoirs, there is a close negative correlation between the degree of recovery and the starting pressure gradient. Specifically, as the starting pressure gradient continues to increase, the degree of recovery of the oil reservoir shows a trend of gradually decreasing. This law directly leads to an increase in the remaining oil saturation of the reservoir within the same time span (such as ten years later). In order to reveal this phenomenon more intuitively, the condition of a starting pressure gradient of 0.05MPa / m was specially selected, and the average formation pressure distribution diagram of each layer after 1000 days, 2000 days and 3650 days and the oil saturation distribution diagram of the first two layers were drawn. Figure 8 , Fig. 9 and Fig.10 As shown in the figure, as the production time goes by, it can be clearly observed that the formation pressure near the production well shows a gradual downward trend, while at the same time, the formation pressure near the water injection well gradually increases due to the continuous increase in water injection. This phenomenon is particularly obvious in the second layer, because both the production well and the water injection well are located in this layer. Similarly, the oil saturation of the reservoir has also changed significantly over time. Especially in the second layer, the reduction in oil saturation is particularly significant due to the direct effect of production activities. At the same time, with the increase of the starting pressure gradient, at the same time point, although the overall trend of the formation pressure distribution remains unchanged, the oil saturation shows a gradual increasing trend. The reason for this phenomenon is that the increase in the starting pressure gradient increases the resistance that the fluid needs to overcome in the formation, resulting in a decrease in the amount of crude oil that can be produced under the same formation pressure.

[0112] Fig.11 A schematic diagram of the results of daily oil production, daily liquid production, and cumulative oil production calculated by simulation taking into account stress sensitivity factors provided in an embodiment of the present application. Fig.11 (a) in the figure is the daily oil production comparison curve for different stress sensitivity coefficients. Fig.11 (b) in the figure is the daily fluid production comparison curve for different stress sensitivity coefficients. Fig.11 (c) in the figure is the comparison curve of cumulative oil production at different stress sensitivity coefficients.

[0113] Specifically, in the numerical simulation of low permeability reservoirs considering stress sensitivity factors, special attention is paid to the change of absolute permeability of the reservoir with pressure change. Since the average formation pressure continues to decrease during the production process and has not dropped below the saturation pressure in the final stage of this simulation case, the stress sensitivity coefficient The influence on the calculation of absolute permeability is negligible. The main concern is the stress sensitivity coefficient role.

[0114] In order to further explore the influence of stress sensitivity coefficient on reservoir production dynamics, , , , and The simulation results are shown in Figure 2. Fig.11 The comparison curves of daily oil production, daily liquid production and cumulative oil production are displayed. Fig.11 As shown, in the absence of stress sensitivity In the case of , the synchronous water injection production method can keep the reservoir's liquid production capacity stable. However, when considering the stress sensitivity factor, the permeability will decrease with the change of stress, resulting in an increase in the flow resistance of the fluid and a corresponding decrease in the flow rate. This change makes the fluid's permeability in the reservoir worse, which in turn affects the overall production capacity of the reservoir. As the stress sensitivity coefficient increases, the formation permeability gradually decreases, and the production capacity of the reservoir also decreases. The greater the stress sensitivity coefficient, the more significant the reduction in production capacity. This phenomenon shows that in the development process of low permeability reservoirs, stress sensitivity is an important factor that cannot be ignored, and it will have a significant impact on the production dynamics of the reservoir.

[0115] Fig.12 The stress sensitivity coefficient provided in the embodiment of the present application The average formation pressure distribution map of each layer of the reservoir after 1000 days and the oil saturation distribution map of the first two layers. Fig.12 (a) Average pressure distribution of the first layer after 1000 days. Fig.12 (b) in the figure is the average pressure distribution diagram of the second layer after 1000 days. Fig.12(c) in the figure is the average pressure distribution diagram of the third layer after 1000 days. Fig.12 (d) in the figure is the oil saturation distribution map of the first layer after 1000 days. Fig.12 (e) in the figure is the oil saturation distribution map of the second layer after 1000 days.

[0116] Fig.13 The stress sensitivity coefficient provided in the embodiment of the present application is The average formation pressure distribution map of each layer of the reservoir after 2000 days and the oil saturation distribution map of the first two layers. Fig.13 (a) in the figure is the average pressure distribution diagram of the first layer after 2000 days. Fig.13 (b) in the figure is the average pressure distribution diagram of the second layer after 2000 days. Fig.13 (c) in the figure is the average pressure distribution diagram of the third layer after 2000 days. Fig.13 (d) in the figure is the oil saturation distribution map of the first layer after 2000 days. Fig.13 (e) in the figure is the oil saturation distribution map of the second layer after 2000 days.

[0117] Fig.14 The stress sensitivity coefficient provided in the embodiment of the present application The average formation pressure distribution map of each layer of the reservoir after 3650 days and the oil saturation distribution map of the first two layers. Fig.14 (a) in the figure is the average pressure distribution diagram of the first layer after 3650 days. Fig.14 (b) in the figure is the average pressure distribution diagram of the second layer after 3650 days. Fig.14 (c) in the figure is the average pressure distribution diagram of the third layer after 3650 days. Fig.14 (d) in the figure is the oil saturation distribution map of the first layer after 3650 days. Fig.14 (e) in the figure is the oil saturation distribution map of the second layer after 3650 days.

[0118] Specifically, in the numerical simulation of the effect of stress sensitivity coefficient on the production dynamics of low permeability reservoirs, special attention was paid to the changes in the remaining oil saturation, formation pressure and oil saturation of the reservoir. When the oil saturation increases, it is found that the residual oil saturation of the reservoir shows a gradual increasing trend after ten years. In order to reveal this phenomenon more intuitively, The conditions were analyzed and the average formation pressure distribution of each layer of the reservoir and the oil saturation distribution of the first two layers were plotted after 1000 days, 2000 days and 3650 days. Fig.12 , Fig.13 and Fig.14As shown in the figure, with the passage of production time, the formation pressure near the production well gradually decreases, while the formation pressure near the water injection well gradually increases due to the continuous increase in the amount of water injection. This phenomenon is particularly obvious in the second layer, because both the production well and the water injection well are located in this layer. It is worth noting that under different stress sensitivity coefficients, the formation pressure distribution at the same time point remains basically unchanged. This shows that the stress sensitivity coefficient mainly affects the permeability of the formation, rather than the overall distribution of formation pressure. With the passage of production time, the oil saturation of the reservoir has also changed significantly. Especially in the second layer, due to the direct effect of production activities, the reduction in oil saturation is particularly significant. At the same time, with the increase of the stress sensitivity coefficient, at the same time point, the oil saturation shows a trend of gradual increase. The reason for this phenomenon is that the increase in the stress sensitivity coefficient leads to a decrease in the absolute permeability of the formation, which reduces the amount of oil that can be produced under the same production conditions, thereby increasing the residual oil saturation of the reservoir.

[0119] Fig.15 A schematic diagram of the results of daily oil production, daily liquid production, and cumulative oil production calculated by simulating and calculating both the start-up pressure and stress sensitivity factors provided in an embodiment of the present application. Fig.15 (a) in the figure is the daily oil production comparison curve when two different factors are considered simultaneously. Fig.15 (b) in the figure is the daily fluid production comparison curve when two different factors are considered simultaneously. Fig.15 (c) is the cumulative oil production comparison curve when two different factors are considered simultaneously. Fig.15 As shown in Figure 2, several different starting pressure gradient G values ​​were selected, including 0.025MPa / m, 0.05MPa / m, 0.075MPa / m and 0.1MPa / m, as well as several stress sensitivity coefficients. The model was simulated in detail with different values, namely 0.025, 0.05, 0.075 and 0.1. The simulation results show that both daily oil production, daily liquid production and cumulative oil production are significantly affected by these two factors. However, by comparing the simulation results under different conditions, it can be found that the start-up pressure gradient has a more significant impact on the numerical simulation results of low permeability reservoirs. In contrast, although the stress sensitivity factor also has a certain impact on the simulation results, its impact is relatively small.

[0120] Fig.16 The embodiment of the present application provides a starting pressure gradient G = 0.05MPa / m, and a stress sensitivity coefficient The average formation pressure distribution map of each layer of the reservoir after 1000 days and the oil saturation distribution map of the first two layers. Fig.16 (a) Average pressure distribution of the first layer after 1000 days. Fig.16 (b) in the figure is the average pressure distribution diagram of the second layer after 1000 days. Fig.16 (c) in the figure is the average pressure distribution diagram of the third layer after 1000 days. Fig.16 (d) in the figure is the oil saturation distribution map of the first layer after 1000 days. Fig.16 (e) in the figure is the oil saturation distribution map of the second layer after 1000 days.

[0121] Fig.17 The embodiment of the present application provides a starting pressure gradient G = 0.05MPa / m, and a stress sensitivity coefficient The average formation pressure distribution map of each layer of the reservoir after 2000 days and the oil saturation distribution map of the first two layers. Fig.17 (a) in the figure is the average pressure distribution diagram of the first layer after 2000 days. Fig.17 (b) in the figure is the average pressure distribution diagram of the second layer after 2000 days. Fig.17 (c) in the figure is the average pressure distribution diagram of the third layer after 2000 days. Fig.17 (d) in the figure is the oil saturation distribution map of the first layer after 2000 days. Fig.17 (e) in the figure is the oil saturation distribution map of the second layer after 2000 days.

[0122] Fig.18 The embodiment of the present application provides a starting pressure gradient G = 0.05MPa / m, and a stress sensitivity coefficient The average formation pressure distribution map of each layer of the reservoir after 3650 days and the oil saturation distribution map of the first two layers. Fig.18 (a) in the figure is the average pressure distribution diagram of the first layer after 3650 days. Fig.18 (b) in the figure is the average pressure distribution diagram of the second layer after 3650 days. Fig.18 (c) in the figure is the average pressure distribution diagram of the third layer after 3650 days. Fig.18 (d) in the figure is the oil saturation distribution map of the first layer after 3650 days. Fig.18 (e) in the figure is the oil saturation distribution map of the second layer after 3650 days.

[0123] like Fig.18As shown in the figure, as the production activities continue, the formation pressure around the production wells gradually decreases, which is caused by the continuous extraction of fluids. At the same time, the formation pressure near the water injection wells gradually increases with the increase of water injection volume, because the newly injected fluid provides additional pressure support for the formation. It is worth noting that since both the production wells and the water injection wells are located in the second layer of the reservoir, the oil saturation change of this layer is particularly significant, reflecting the dynamic distribution and flow law of the fluid in the reservoir. In order to deeply explore the reasons behind these phenomena, a comprehensive simulation analysis of the low permeability one-source-one-sink reservoir was carried out using a numerical simulation program. In the simulation process, the starting pressure gradient factor, stress sensitivity factor and the situation of considering these two factors at the same time were considered respectively to evaluate their specific effects on the simulation results. The simulation results show that both the starting pressure gradient and stress sensitivity factors have a significant impact on the productivity of low permeability reservoirs. Specifically, the starting pressure gradient, as a resistance to fluid flow, directly limits the flow speed and range of the fluid, thereby affecting the production of the oil field. The stress sensitivity factor indirectly affects the flow of fluids and the productivity of the reservoir by changing the physical properties of the reservoir such as permeability and porosity. Further comparative analysis found that the impact of the start-up pressure gradient on productivity is greater than that of the stress sensitivity factor. This means that in the numerical simulation of low permeability reservoirs, the key factor of the start-up pressure gradient cannot be ignored. At the same time, considering that the stress sensitivity factor also has a certain impact on productivity, it should also be fully considered in the simulation process.

[0124] In summary, this application reveals the complex laws of fluid flow and distribution in low permeability reservoirs and emphasizes the importance of starting pressure gradient and stress sensitivity factors in numerical simulation. These findings not only provide strong support for a deeper understanding of the exploitation mechanism of low permeability reservoirs, but also provide a useful reference for future reservoir management and optimization work.

[0125] The present application also provides a low permeability reservoir numerical simulation device 1900, such as Fig.19 As shown, the device includes: an establishment module 1901, a permeability calculation module 1902, a flow rate calculation module 1903 and a solution module 1904.

[0126] The establishment module 1901 is used to divide the low permeability reservoir into multiple small units by dividing the grid, and the fluid flow in each small unit is solved by establishing a mathematical model suitable for numerical simulation of the low permeability reservoir. The fluid includes an oil phase, a water phase and a gas phase. During the solution process, the pressure of the grid node and the saturation of the fluid are continuously updated until the convergence condition is reached.

[0127] The permeability calculation module 1902 is used to select a corresponding formula to calculate the permeability of the grid node according to the comparison between the current pressure and the initial pressure of the grid node.

[0128] The flow rate calculation module 1903 is used to describe the relationship between the flow rate and the pressure gradient of the grid node using the seepage model considering the starting pressure gradient, set the starting pressure gradient threshold, judge whether the fluid starts to flow according to the comparison between the pressure gradient of the grid node and the starting pressure gradient threshold, and calculate the flow rate according to the seepage model. The flow rate is the speed at which the fluid flows between the grid nodes.

[0129] The solution module 1904 is used to solve the mathematical model applicable to the numerical simulation of low permeability reservoirs by combining the calculated permeability and flow rate of the grid nodes, and obtain the improved mass conservation equation. The oil phase saturation, water phase saturation and gas phase saturation are solved by solving the pressure equation and the saturation equation in the auxiliary equation.

[0130] Some modules in the apparatus described in the present application can be described in the general context of computer executable instructions executed by a computer, such as program modules. Generally, program modules include routines, programs, objects, components, data structures, classes, etc. that perform specific tasks or implement specific abstract data types. The present application can also be practiced in distributed computing environments, in which tasks are performed by remote processing devices connected through a communication network. In a distributed computing environment, program modules can be located in local and remote computer storage media including storage devices.

[0131] The devices or modules described in the above application embodiments can be implemented by computer chips or entities, or by products with certain functions. For the convenience of description, the above devices are described in various modules according to their functions. When implementing the embodiments of the present application, the functions of each module can be implemented in the same or multiple software and / or hardware. Of course, the module that implements a certain function can also be implemented by combining multiple sub-modules or sub-units.

[0132] The methods, devices or modules described in this application can be implemented in the form of computer-readable program codes. The controller can be implemented in any appropriate manner. For example, the controller can take the form of a microprocessor or processor and a computer-readable medium storing computer-readable program codes (such as software or firmware) that can be executed by the (micro)processor, logic gates, switches, application-specific integrated circuits (English: Application Specific Integrated Circuit, referred to as: ASIC), programmable logic controllers and embedded microcontrollers. Examples of controllers include but are not limited to the following microcontrollers: ARC 625D, Atmel AT91SAM, Microchip PIC18F26K20 and Silicone Labs C8051F320. The memory controller can also be implemented as part of the control logic of the memory. Those skilled in the art also know that in addition to implementing the controller in the form of pure computer-readable program codes, the controller can be implemented in the form of logic gates, switches, application-specific integrated circuits, programmable logic controllers and embedded microcontrollers by logically programming the method steps. Therefore, this controller can be considered as a hardware component, and the devices included in it for implementing various functions can also be regarded as structures within the hardware component. Or even, the means for realizing various functions may be regarded as both a software module for realizing the method and a structure within a hardware component.

[0133] like Fig. 20 As shown, an embodiment of the present application also provides a low permeability reservoir numerical simulation server, including a memory 2001 and a processor 2002; the memory 2001 is used to store computer executable instructions; the processor 2002 is used to execute computer executable instructions to implement a low permeability reservoir numerical simulation method described above in the embodiment of the present application.

[0134] The embodiment of the present application also provides a computer-readable storage medium, which stores executable instructions. When a computer executes the executable instructions, it can implement the low permeability reservoir numerical simulation method described above in the embodiment of the present application.

[0135] It can be seen from the description of the above implementation methods that those skilled in the art can clearly understand that the present application can be implemented by means of software plus necessary hardware. Based on this understanding, the technical solution of the present application can be essentially or partly contributed to the prior art in the form of a software product, or it can be reflected in the implementation process of data migration. The computer software product can be stored in a storage medium, such as ROM / RAM, a disk, an optical disk, etc., including a number of instructions for a computer device (which can be a personal computer, a mobile terminal, a server, or a network device, etc.) to execute the method described in the embodiment of the present application.

[0136] The various embodiments in this specification are described in a progressive manner, and the same or similar parts between the various embodiments can be referred to each other, and each embodiment focuses on the differences from other embodiments. All or part of this application can be used in many general or special computer system environments or configurations.

[0137] The above embodiments are only used to illustrate the technical solutions of the present application, rather than to limit the present application. Although the present application has been described in detail with reference to the aforementioned embodiments, a person of ordinary skill in the art should understand that the technical solutions described in the aforementioned embodiments may still be modified, or some or all of the technical features thereof may be replaced by equivalents. However, these modifications or replacements do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the present application.

Claims

1. A method for numerical simulation of low permeability reservoirs, characterized in that: include: By dividing the grid, the low permeability reservoir is divided into a plurality of small units, and the fluid flow in each small unit is solved by establishing a mathematical model suitable for numerical simulation of the low permeability reservoir; wherein the fluid includes an oil phase, a water phase and a gas phase; Auxiliary equations are introduced as constraints to establish a mathematical model suitable for numerical simulation of low permeability reservoirs. During the solution process, the pressure of the grid nodes and the saturation of the fluid are continuously updated until the convergence condition is reached; According to the comparison between the current pressure and the initial pressure of the grid node, the corresponding formula is selected to calculate the permeability of the grid node; A seepage model considering the starting pressure gradient is used to describe the relationship between the flow velocity and the pressure gradient of the grid node. A starting pressure gradient threshold is set. Whether the fluid starts to flow is determined by comparing the pressure gradient of the grid node with the starting pressure gradient threshold. The flow velocity is calculated according to the seepage model. The flow velocity is the speed at which the fluid flows between the grid nodes. Combined with the calculated permeability and flow rate of the grid nodes, the mathematical model suitable for numerical simulation of low permeability reservoirs is solved to obtain the improved mass conservation equation; By solving the pressure equation and the saturation equation in the auxiliary equation, the oil phase saturation, water phase saturation and gas phase saturation are solved; The method of solving the oil phase saturation, water phase saturation and gas phase saturation by solving the pressure equation and the saturation equation in the auxiliary equation includes: converting the improved mass conservation equation into a pressure equation containing only fluid pressure; converting the pressure equation containing only fluid pressure into an equation containing only oil phase pressure; performing implicit difference processing on the equation containing only oil phase pressure to obtain an implicit pressure difference equation group, and obtaining the oil phase pressure by solving the equation group; substituting the oil phase pressure into the auxiliary equation to obtain the water phase pressure and the gas phase pressure; obtaining the saturation equations of the oil phase and the water phase by difference processing on the improved mass conservation equations of the oil phase and the water phase, and solving the oil phase saturation and the water phase saturation by pressure and production parameters; and calculating the gas phase saturation according to the principle that the sum of the saturations is 1.

2. The low permeability reservoir numerical simulation method according to claim 1, characterized in that: The mathematical model for numerical simulation of low permeability reservoirs is established, including: According to the law of conservation of mass, the mass conservation equation of the fluid under formation and ground conditions is derived; wherein the mass conservation equation is used to describe the mass change of the fluid in a unit volume of rock; The Darcy's law is used to describe the seepage velocity of the gas phase, and the modified Darcy's law is introduced to describe the seepage velocity of the oil phase and the water phase, so as to obtain the motion equation of each phase; wherein the modified Darcy's law takes into account the influence of the starting pressure gradient on the seepage velocity; Substitute the equation of motion into the mass conservation equation to obtain the continuity equation, and define the boundary conditions to solve the continuity equation; The solution conditions include the closing condition of the outer boundary, the fixed production condition of the inner boundary, the fixed bottom hole pressure condition of the inner boundary, and the pressure distribution and saturation distribution at the initial moment; Auxiliary equations are introduced as constraints to establish a mathematical model suitable for numerical simulation of low permeability reservoirs.

3. The low permeability reservoir numerical simulation method according to claim 1, characterized in that: The method of selecting a corresponding formula to calculate the permeability of a grid node based on the comparison between the current pressure and the initial pressure of the grid node includes: When the current pressure of the grid node is lower than the initial pressure, the permeability of the grid node is calculated using the first permeability calculation formula, and the current pressure of the grid node is updated to the initial pressure; When the current pressure of the grid node is higher than or equal to the initial pressure, the permeability of the grid node is calculated using the second permeability calculation formula, and the initial pressure of the grid node is kept unchanged.

4. The low permeability reservoir numerical simulation method according to claim 3, characterized in that: The first permeability calculation formula is: ;in, is the permeability of the current grid node, is the initial permeability of the grid node, is the sensitivity of the permeability of the grid nodes to the pressure change during the pressure reduction process, is the initial pressure of the grid node, is the current pressure of the grid node; The second permeability calculation formula is: ;in, is the permeability of the current grid node, is the previous permeability of the grid node, is the sensitivity of the permeability of the grid node to the pressure change when the pressure recovers or increases, is the previous pressure at the grid node, is the current pressure at the mesh node.

5. The low permeability reservoir numerical simulation method according to claim 1, characterized in that: The starting pressure gradient threshold is set as follows: within the range where the water saturation is greater than the irreducible water saturation and less than the critical residual oil saturation, the starting pressure gradient value of the oil-water two-phase is calculated using the linear relationship between the water saturation and the minimum pressure gradient required for the fluid to start flowing, and the starting pressure gradient value of the oil-water two-phase is used as the starting pressure gradient threshold.

6. The low permeability reservoir numerical simulation method according to claim 1, characterized in that: The step of judging whether the fluid starts to flow based on the comparison between the pressure gradient of the grid node and the start-up pressure gradient threshold, and calculating the flow rate based on the seepage model, includes: If the pressure gradient of the grid node is less than or equal to the start-up pressure gradient threshold, the fluid does not flow; If the pressure gradient of a grid node is greater than the starting pressure gradient threshold, the fluid starts to flow at the grid node, and the flow velocity is calculated according to the seepage model.

7. A low permeability reservoir numerical simulation device, characterized in that: include: Establishing a module, for dividing a low permeability reservoir into a plurality of small units by dividing a grid, and solving the fluid flow in each small unit by establishing a mathematical model suitable for numerical simulation of low permeability reservoirs; wherein the fluid includes an oil phase, a water phase and a gas phase; introducing an auxiliary equation as a constraint condition to establish a mathematical model suitable for numerical simulation of low permeability reservoirs; in the process of solving the problem, continuously updating the pressure of the grid nodes and the saturation of the fluid until the convergence condition is reached; A permeability calculation module is used to select a corresponding formula to calculate the permeability of a grid node based on a comparison between the current pressure of the grid node and the initial pressure; A flow rate calculation module is used to describe the relationship between the flow rate and the pressure gradient of the grid node using a seepage model that takes into account the starting pressure gradient, set a starting pressure gradient threshold, determine whether the fluid starts to flow based on the comparison between the pressure gradient of the grid node and the starting pressure gradient threshold, and calculate the flow rate based on the seepage model; wherein the flow rate is the speed at which the fluid flows between the grid nodes; A solution module is used to solve a mathematical model suitable for numerical simulation of low permeability reservoirs by combining the calculated permeability and flow rate of the grid nodes to obtain an improved mass conservation equation; by solving the pressure equation and the saturation equation in the auxiliary equation, the oil phase saturation, the water phase saturation and the gas phase saturation are solved; the solution of the oil phase saturation, the water phase saturation and the gas phase saturation by solving the pressure equation and the saturation equation in the auxiliary equation includes: converting the improved mass conservation equation into a pressure equation containing only fluid pressure; converting the improved mass conservation equation into a pressure equation containing only fluid pressure; converting the improved mass conservation equation into a pressure equation containing only fluid pressure; converting the improved mass conservation equation into a pressure equation containing only fluid pressure. The pressure equation is converted into an equation containing only the oil phase pressure; the equation containing only the oil phase pressure is implicitly differentiated to obtain an implicit pressure differential equation group, and the oil phase pressure is obtained by solving the equation group; the oil phase pressure is substituted into the auxiliary equation to obtain the water phase pressure and the gas phase pressure; the saturation equations of the oil phase and the water phase are obtained by differential processing of the improved mass conservation equations of the oil phase and the water phase, and the oil phase saturation and the water phase saturation are solved by the pressure and production parameters; the gas phase saturation is calculated according to the principle that the sum of the saturations is 1.

8. A low permeability reservoir numerical simulation server, characterized in that: including memory and processor; The memory is used to store computer executable instructions; The processor is used to execute the computer executable instructions to implement the method according to any one of claims 1 to 6.

9. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores executable instructions, and when a computer executes the executable instructions, the method according to any one of claims 1 to 6 can be implemented.

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