Simulation method and device for quantitatively characterizing shale component and physical property synergic evolution process

Abstract

The application provides a simulation method and device for quantitatively characterizing a shale component and a physical property synergic evolution process, and relates to the technical field of unconventional oil and gas reservoir evaluation. The method comprises the following steps: determining shale components and physical property parameters, and determining a shale reservoir performance comprehensive index according to the shale components and the physical property parameters; determining a shale evolution coefficient according to a preset empirical constant, shale reservoir performance comprehensive indexes corresponding to initial experimental conditions and current experimental conditions, temperatures and pressures; and determining a shale pore characteristic factor according to a preset empirical coefficient, temperature differences and pressure differences between the current experimental conditions and the initial experimental conditions, and shale pore physical parameters of a shale sample. The device executes the above method. The method and device provided in the embodiments of the application can provide more accurate technical support for the development of shale oil and gas reservoirs.

Description

Technical Field

[0001] This invention relates to the field of unconventional oil and gas reservoir evaluation technology, specifically to a simulation method and apparatus for quantitatively characterizing the synergistic evolution of shale components and physical properties. Background Technology

[0002] Shale oil and gas, as an important unconventional oil and gas resource, has attracted widespread attention for its development and utilization. The extraction efficiency of shale oil and gas reservoirs is closely related to their composition and physical properties; therefore, studying the composition and physical properties of shale is fundamental to exploration and development. However, existing technologies such as laboratory testing, geological analysis, and numerical simulation have significant limitations in rapid evaluation, real-time monitoring, and quantitative characterization of the co-evolution of shale composition and physical properties. They often cannot simultaneously obtain the composition and physical property parameters during the sample evolution process, making it difficult to meet the needs of efficient exploration and development of shale oil and gas reservoirs.

[0003] In existing technologies such as CN106908371A, the saturated fluid method for measuring the reservoir performance of shale only considers the porosity and permeability of shale samples, without taking into account the influence of components such as organic carbon content and maturity on the reservoir performance of shale, and does not involve the synergistic changes of components and physical properties during the evolution process.

[0004] In existing technologies such as CN112147696A, the expression for the reservoir performance index only involves the porosity and organic carbon content of shale, without considering factors such as permeability, maturity, and mineral content, and without taking into account the dynamic changes in composition and physical properties during shale evolution. The reservoir performance characterization parameters are relatively singular and cannot comprehensively characterize the reservoir performance of shale.

[0005] In the existing technology CN113552146A, reservoir evaluation is based on porosity and permeability evaluation factors. However, it does not take into account the characteristics of shale, such as strong heterogeneity and complex pore structure. It only considers the physical property parameters of shale and does not involve the synergistic changes of reservoir physical properties and components during shale evolution. Summary of the Invention

[0006] To address the problems in the prior art, embodiments of the present invention provide a simulation method and apparatus for quantitatively characterizing the synergistic evolution of shale components and physical properties, which can at least partially solve the problems existing in the prior art.

[0007] On the one hand, this invention proposes a simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties, including:

[0008] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0009] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0010] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0011] The determination of the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters includes:

[0012] The comprehensive index of shale reservoir performance is calculated based on the weights corresponding to the porosity, permeability, organic carbon content, brittleness index, and maturity, respectively.

[0013] The simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties further includes:

[0014] The weights corresponding to the porosity, permeability, organic carbon content, brittleness index, and maturity were calculated using a principal component analysis model.

[0015] The step of determining the shale evolution coefficient based on preset empirical constants and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, respectively, includes:

[0016] The shale evolution coefficient S is calculated according to the following first expression:

[0017]

[0018] Wherein, I0, T0, and P0 are the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions, I, T, and P are the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the current experimental conditions, and α, β, γ, and δ are all the preset empirical constants.

[0019] The shale pore physical parameters include the volume of a single pore, the total pore volume of the shale sample, the cross-sectional area of ​​a single pore, the perimeter of a single pore, and the pore diameter of a single pore. Correspondingly, the determination of shale pore characteristic factors based on preset empirical coefficients, the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, and the shale pore physical parameters of the shale sample, includes:

[0020] The shale porosity characteristic factor N is calculated according to the following second expression:

[0021]

[0022] Where m is the total number of pores in the shale sample, and V i V is the volume of a single pore. T Let A be the total pore volume of the shale sample, and C be the cross-sectional area of ​​a single pore. i D is the perimeter of a single pore. i ΔT is the pore diameter of a single pore, ΔT is the temperature difference, ΔP is the pressure difference, and a and b are both preset empirical coefficients.

[0023] The simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties further includes:

[0024] The preset empirical constants and preset empirical coefficients are calculated using the least squares method.

[0025] On the one hand, this invention proposes a simulation device for quantitatively characterizing the co-evolution process of shale components and physical properties, comprising:

[0026] The first determining unit is used to determine the shale composition and physical property parameters, and to determine the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters; the shale composition and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0027] The second determining unit is used to determine the shale evolution coefficient based on preset empirical constants and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, respectively.

[0028] The third determining unit is used to determine the shale porosity characteristic factor based on the temperature difference and pressure difference between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample, according to a preset empirical coefficient.

[0029] In another aspect, embodiments of the present invention provide a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the following method:

[0030] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0031] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0032] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0033] This invention provides a computer-readable storage medium, comprising:

[0034] The computer-readable storage medium stores a computer program that, when executed by a processor, implements the following method:

[0035] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0036] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0037] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0038] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the following method:

[0039] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0040] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0041] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0042] The present invention provides a simulation method and apparatus for quantitatively characterizing the synergistic evolution of shale components and physical properties. This method determines shale components and physical property parameters, and then determines a comprehensive index of shale reservoir performance based on these parameters. The shale components and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity. Based on preset empirical constants, the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial and current experimental conditions are used to determine the shale evolution coefficient. Based on preset empirical coefficients, the temperature and pressure differences between the current and initial experimental conditions, and the shale pore physical parameters of the shale sample, the method determines shale pore characteristic factors. This approach not only comprehensively considers factors affecting shale reservoir performance but also quantitatively reveals the dynamic changes in components and physical properties during the evolution process, thereby providing more precise technical support for the development of shale oil and gas reservoirs. Attached Figure Description

[0043] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. In the drawings:

[0044] Figure 1 This is a schematic diagram of the structure of a simulation system for quantitatively characterizing the co-evolution process of shale components and physical properties, provided in an embodiment of the present invention.

[0045] Figure 2 This is a schematic diagram of the shale sample preparation equipment provided in an embodiment of the present invention.

[0046] Figure 3 This is a schematic flowchart of a simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties, provided by an embodiment of the present invention.

[0047] Figure 4 This is a schematic diagram of the structure of a simulation device for quantitatively characterizing the co-evolution process of shale components and physical properties, provided in an embodiment of the present invention.

[0048] Figure 5 This is a schematic diagram of the physical structure of a computer device provided in an embodiment of the present invention. Detailed Implementation

[0049] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. Here, the illustrative embodiments and descriptions of the present invention are used to explain the present invention, but are not intended to limit the present invention. It should be noted that, unless otherwise specified, the embodiments and features in the embodiments of this application can be arbitrarily combined with each other.

[0050] Figure 1 This is a schematic diagram of a simulation system for quantitatively characterizing the co-evolution process of shale components and physical properties, provided by an embodiment of the present invention. The simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties is applied in the above-mentioned simulation system, such as... Figure 1 As shown, compared to existing systems, the simulation system of this invention adds a heating coil and a temperature and pressure sensor to simulate the heating and pressurization of the experimental environment.

[0051] like Figure 2 As shown, shale samples can be prepared based on this method. A typical shale sample of any shape can be selected and cut into three plunger samples (two with a diameter of 2 cm and a height of 4 cm, and one with a diameter of 2 mm and a height of 3 mm), two powder samples (both with a mesh size of 400 mesh), and a thin section (2 cm long, 6 cm wide, and 30 micrometers thick) using a sample cutter. These samples are then conveyed to the measurement module. The plunger with a diameter of 2 cm and a height of 4 cm is used to measure the horizontal and vertical permeability of the sample and to observe the micron-scale porosity and pore structure using micron-CT. The plunger with a diameter of 2 mm and a height of 3 mm is used for nano-CT to measure the nano-scale porosity and pore structure. One powder sample is placed in an X-ray diffractometer to measure the mineral content of the sample, and another powder sample is placed in a rock pyrolysis apparatus to measure the organic carbon content. The thin section is placed in an optical microscope to measure vitrinite reflectance, observe fluorescence positions, fluid inclusions, etc. All sample movement is carried out via conveyor belt.

[0052] Subsequently, the temperature and pressure control valves in the temperature and pressure control system were opened to simultaneously heat and pressurize the sample to simulate the evolution process of shale, and relevant parameters were measured in real time. To quantitatively study the synergistic evolution of shale components and properties, five shale component and property parameters—porosity, permeability, organic carbon content, brittleness index, and maturity—were selected to first quantitatively characterize the reservoir performance of shale. Then, based on the reservoir performance index, temperature, and pressure changes, a shale evolution coefficient was defined to quantitatively characterize the synergistic evolution of shale components and properties. Simultaneously, during this process, the shale pore structure could be monitored using nano-CT and micro-CT, and its pore structure was quantified into shale pore characteristic factors. These parameters comprehensively reflect the changes in pore volume, shape, and cross-sectional area during shale evolution, aiming to better guide production practices.

[0053] The experimental equipment system is described as follows:

[0054] It mainly includes a sample cutting module, a parameter measurement module, a temperature and pressure control module, and a data processing and display module; among which:

[0055] The sample cutting module mainly includes a sample stage, a telescopic drill bit, diamond cutting blades, an infrared sensor, a waste collection tank, and a robotic arm. The sample stage is used to hold the shale sample, and its 1mm×1mm grid is used to measure the sample's dimensions. The telescopic drill bit is used to drill for the plunger sample and grinding powder required for the experiment. Two horizontally and vertically movable diamond cutting blades are used to cut the rock sample to obtain thin sections. The infrared sensor is used to identify typical areas of the sample for cutting. The waste collection tank is used to collect residual waste during the cutting process. The robotic arm is used to move the sample.

[0056] The parameter measurement module mainly includes a permeability meter with a temperature and pressure modification device, a nano-CT, a micro-CT, an optical microscope, an X-ray diffractometer, a rock pyrolysis apparatus, and conveyor belts. The permeability meter measures the sample's permeability by measuring pressure changes during fluid injection, and measures it again after rotating the sample 90 degrees to dry it; the final permeability is the average of the two measurements. The nano-CT and micro-CT are used to measure the porosity and pore structure characteristics of the plunger samples. The optical microscope can automatically identify multiple vitrinite bodies via computer, and the average of their reflectance is used to reflect the sample's maturity. The X-ray diffractometer is used to measure the mineral composition of the samples. The rock pyrolysis apparatus is used to measure the organic carbon content of the samples. Conveyor belt 1 is connected to the sample stage of the sample preparation machine at one end and to the nano-CT at the other, with the permeability meter in the middle. This allows for the automatic transport of plunger samples of different models into the corresponding measurement modules via a precise positioning system. Conveyor belt 2 is connected to the nano-CT at one end and to conveyor belt 1 at the other, enabling the transport of plunger samples of corresponding specifications to the nano-CT. One end of conveyor belt No. 3 is connected to the sample stage of the sample preparation machine, and the other end is connected to the sample chamber of the rock pyrolysis instrument. It passes through the sample stage of the optical microscope and the sample chamber of the X-ray diffractometer in the middle. It can automatically transport thin section samples into the optical microscope sample stage and transport two powder samples into the X-ray diffractometer and the rock pyrolysis instrument respectively.

[0057] The temperature and pressure control module mainly includes a precisely temperature-adjustable heating coil, a nitrogen tank, connecting pipes, temperature and pressure sensors, and a diamond anvil cell. The precisely temperature-adjustable heating coil is used to raise the temperature of the sample chambers for the permeameter, nano-CT, micro-CT, optical microscope, and X-ray diffractometer. The nitrogen tank is connected to the sample chambers of the nano-CT, micro-CT, optical microscope, and rock pyrolysis apparatus via connecting pipes to change the pressure within the sample chambers. The permeameter and X-ray diffractometer pressurize the samples through mechanical pressure (the permeameter pressurizes through a knob on the core holder, while the X-ray diffractometer pressurizes through a diamond anvil cell). The temperature and pressure sensors uniformly calibrate the required temperature and pressure of each device's sample chamber. The sample chambers of each device can withstand high temperatures and pressures effectively and are well-sealed.

[0058] The data processing and display module mainly includes a computer. The computer can synchronously acquire data from various measuring instruments via a high-speed data acquisition card, process the acquired signals through filtering and amplification, run algorithms to convert the raw data into physical property parameters, and in particular, automatically identify vitrinite in rock thin sections, measure the reflectivity of vitrinite, and obtain the sample maturity. Simultaneously, it can display the measurement results in real time, store these compositional and physical property parameters, calculate the shale reservoir performance index (I), shale evolution coefficient (S), and shale porosity characteristic factor (N) using these parameters, plot their variation curves with temperature and pressure, and set up a network communication unit to support remote data transmission and control system operation. Ultimately, it achieves automated quantitative characterization of shale composition, physical properties, and their co-evolution process.

[0059] Shale samples can be prepared before implementing the method, mainly including:

[0060] At least five typical shale samples of arbitrary shapes were selected. Each sample underwent the following procedures: A typical portion was identified using an infrared sensor on a sample cutter. A telescopic drill bit was used to drill three plungers into the sample on a grid-scaled sample stage. Two plungers, each 2 cm in diameter and 4 cm in height, were used to measure the sample's horizontal and vertical permeability, respectively, and to measure the sample's micron-scale porosity and pore structure using micron-CT. A third plunger, 2 mm in diameter and 3 mm in height, was used for nano-CT to measure the sample's nanon-scale porosity and pore structure. The remaining portion was returned to the sample stage via a robotic arm and cut into thin slices using two perpendicularly oriented diamond blades for vitrinite reflectance measurement. These slices were 2 cm long, 6 cm wide, and 30 micrometers thick. The remaining typical portion was then ground into two 400-mesh powders using a telescopic drill bit. One powder was placed in an X-ray diffractometer to measure the sample's mineral content, and the other powder was placed in a rock pyrolysis apparatus to measure the organic carbon content. Finally, the remaining waste material was disposed of in a waste collection tank. The cutting position and sample size are precisely determined by infrared sensors and a grid ruler on the sample stage.

[0061] Figure 3 This is a schematic flowchart of a simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties, provided by an embodiment of the present invention. Figure 3 As shown in the embodiments of the present invention, the simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties includes:

[0062] Step S1: Determine the shale composition and physical property parameters, and determine the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters; the shale composition and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0063] Step S2: Determine the shale evolution coefficient based on the preset empirical constants and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions.

[0064] Step S3: Based on preset empirical coefficients, the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale pore physical parameters of the shale sample, determine the shale pore characteristic factor.

[0065] In step S1 above, the device determines the shale composition and physical property parameters, and determines the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters; the shale composition and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity. The device can be a computer device, such as a server, that performs the method. The acquisition, storage, use, and processing of data in the technical solution of this application all comply with relevant regulations.

[0066] The co-evolution of shale components and properties under temperature and pressure variations is a complex geological process involving multiple physicochemical reactions. To quantitatively study this co-evolution, five shale component and property parameters—porosity, permeability, organic carbon content, brittleness index, and maturity—were selected to first quantitatively characterize the reservoir performance of shale. Then, based on the reservoir performance index, temperature, and pressure variations, a shale evolution coefficient was defined to quantitatively characterize the co-evolution of shale components and properties. Simultaneously, during this process, nano-CT and micro-CT can be used to monitor the shale pore structure and quantify it into shale pore characteristic factors. These parameters comprehensively reflect changes in pore volume, shape, and cross-sectional area during shale evolution.

[0067] The determination of the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters includes:

[0068] The comprehensive index of shale reservoir performance is calculated based on the weights corresponding to the porosity, permeability, organic carbon content, brittleness index, and maturity, respectively. Shale reservoir performance is influenced by multiple factors. To comprehensively characterize shale reservoir performance, five shale components and physical property parameters—porosity, permeability, organic carbon content, brittleness index, and maturity—are selected for quantitative characterization of shale reservoir performance.

[0069] A parameter is defined to comprehensively characterize the shale reservoir performance: the Shale Reservoir Performance Comprehensive Index I. I is a multi-dimensional parameter that combines the physical, chemical, and mechanical properties of shale to evaluate the overall performance of shale reservoirs. The calculation formula is as follows:

[0070]

[0071] in, Porosity, reflecting the size of the reservoir space; K, permeability, reflecting the fluid flow capacity; BI, brittleness index, reflecting the fracturing ability of shale; T, organic carbon content, reflecting the hydrocarbon generation potential of shale; R0, maturity, reflecting the degree of thermal evolution of shale. w1, w2, w3, w4, w5 are the weights of each parameter, and the sum of the weights should be 1.

[0072] The simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties also includes:

[0073] The weights corresponding to the porosity, permeability, organic carbon content, brittleness index, and maturity were calculated using a principal component analysis model.

[0074] The comprehensive evaluation index I for shale reservoir performance consists of five indicators: porosity, permeability, brittleness index, organic carbon content, and maturity, denoted as x1, x2, x3, x4, x5 respectively. Sample i is represented by i = 1, 2, 3, ..., n. The measurement results of the reservoir performance evaluation indicators x1, x2, x3, x4, x5 for sample i are denoted as [a...]. i1 ,a i2 ,a i3 ,a i4 ,a i5 The matrix representation is as follows:

[0075] A = (aij) n×5 .

[0076] The measured sample parameters were standardized, and the standard value z was obtained. ij The implementation process satisfies:

[0077]

[0078] in, That is, μ j s j Let Z be the sample mean and sample standard deviation of the j-th indicator. After standardization, the standardized matrix Z = (zij)ij. ij ) n×5 .

[0079] Calculate the correlation coefficient matrix R, where R = (r ij ) 5×5 ,satisfy:

[0080]

[0081] in, and These are the standardized mean values ​​of the i-th and j-th columns, respectively. When i = j, r ij =1.

[0082] Calculate the eigenvalues ​​and eigenvectors, solve the characteristic equation |R-λI|=0, and obtain the eigenvalues ​​of R: λ1≥λ2≥λ3≥λ4≥λ5≥0. Simultaneously, for each eigenvalue λ... i Solve the corresponding homogeneous linear system of equations (R-λ) i I)u i = 0, obtaining the corresponding eigenvectors u1, u2, u3, u4, u5, and normalizing the eigenvectors so that |u i |=1.

[0083] Calculate the eigenvalue λ j The principal component contribution rate and cumulative contribution rate of (j=1,2,3,4,5) are called b. jThe contribution rate of the principal components is expressed as follows:

[0084]

[0085] B m The cumulative contribution rate is expressed as follows:

[0086]

[0087] Where m represents the number of principal components selected, which is usually determined based on the cumulative contribution rate. Generally, principal components with a cumulative contribution rate of 85% or higher are selected. Assume that the cumulative contribution rate of the first m principal components meets the requirement (m≤5).

[0088] Principal component F j The relationship with the original variables after standardization is as follows: Among them, u jl It is the j-th eigenvector u j The l-th component, z l It is the l-th variable after standardization.

[0089] Calculate F for each principal component j Correlation coefficient with the standardized original variables The calculation method is as follows:

[0090]

[0091] Among them, F ji It is the score of the i-th sample on the j-th principal component. z is the mean score of the j-th principal component. il It is the value of the l-th variable after standardization of the i-th sample. Same as the above explanation.

[0092] Calculate each original variable x l weight w l :

[0093]

[0094] By using principal component analysis (PCA) models to calculate the contribution rates of various parameters, the reservoir performance of shale can be quantitatively characterized based on its porosity, permeability, brittleness index, organic carbon content, and maturity. Simultaneously, through a temperature and pressure control system, the changes in various parameters and reservoir performance indices with temperature and pressure can be observed in real time, simulating the synergistic evolution of shale components and physical properties to better guide production practices.

[0095] In step S2 above, the device determines the shale evolution coefficient based on preset empirical constants and the comprehensive shale reservoir performance index, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, respectively. The determination of the shale evolution coefficient based on preset empirical constants and the comprehensive shale reservoir performance index, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions includes:

[0096] The shale evolution coefficient S is calculated according to the following first expression:

[0097]

[0098] Wherein, I0, T0, and P0 are the comprehensive shale reservoir performance indices, temperature, and pressure corresponding to the initial experimental conditions; I, T, and P are the comprehensive shale reservoir performance indices, temperature, and pressure corresponding to the current experimental conditions; and α, β, γ, and δ are the preset empirical constants. The shale evolution coefficient S is a parameter characterizing the co-evolution of shale composition and physical properties. The larger the value of S, the more significant the changes in composition and physical properties of the shale during the evolution process.

[0099] α, β, γ, and δ are obtained using the least squares method, and the specific process is as follows:

[0100] First, transform the nonlinear equation into a linear equation by taking the logarithm of both sides of the formula for S:

[0101]

[0102] make The above formula can then be written as:

[0103] Y = ln(α) + βX1 + γX2 + δX3

[0104] This gives us the form of a linear equation:

[0105] Y = β0 + β1X1 + β2X2 + β3X3

[0106] Among them, β0=ln(α), β1=β, β2=γ, β3=δ.

[0107] Construct a matrix M containing the observed values ​​of all independent variables and a column of all 1s to represent the intercept term β0:

[0108]

[0109] Finally, the least squares method is used to solve for the parameter β:

[0110] β=(M T M) -1 M T Y

[0111] Where Y is a vector of ln(S). Therefore, the original data can be calculated from the parameter β obtained from the linear model:

[0112] β=β1, γ=β2, δ=β3

[0113] In step S3 above, the device determines shale porosity characteristic factors based on preset empirical coefficients, the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, and the shale porosity physical parameters of the shale sample. The shale porosity physical parameters include the volume of a single pore, the total pore volume of the shale sample, the cross-sectional area of ​​a single pore, the perimeter of a single pore, and the pore diameter of a single pore. Correspondingly, determining the shale porosity characteristic factors based on preset empirical coefficients, the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, and the shale porosity physical parameters of the shale sample, includes:

[0114] The shale porosity characteristic factor N is calculated according to the following second expression:

[0115]

[0116] Where m is the total number of pores in the shale sample, and V i V is the volume of a single pore. T Let A be the total pore volume of the shale sample, and C be the cross-sectional area of ​​a single pore. i D is the perimeter of a single pore. i Let ΔT be the pore diameter of a single pore, ΔP be the temperature difference, ΔP be the pressure difference, and a and b be preset empirical coefficients. Shale pores are important reservoir spaces; their pore structure constantly changes under varying temperature and pressure. To quantitatively study the characteristics of shale pores, combining information such as pore number, volume, pore diameter, perimeter, and cross-sectional area obtained from nano-CT and micro-CT, a parameter comprehensively reflecting the shale pore structure is defined: the shale pore characteristic factor N.

[0117] N is used to quantitatively characterize the pore structure of shale. The larger the value, the more favorable the pore characteristics of the shale are for fluid storage and flow. The pore structure changes with increasing temperature and pressure; therefore, this value reflects how the pore structure changes with temperature and pressure.

[0118] The methods for determining a and b are as follows:

[0119] Let the parameter part of a single pore be a new parameter. Then the formula for N becomes:

[0120]

[0121] Taking the logarithm of both sides of the formula, we get

[0122] Consider two distinct data points j and k, and construct the following system of equations:

[0123]

[0124] Now, construct a system of linear equations using a sufficient number of data point pairs (j,k), and solve for a and b using the least squares method. Rewrite the above equations as:

[0125]

[0126] Among them, y jk =ln(N) j )-ln(N k ),

[0127] For each pair of data points, there is such an equation. Combining these equations forms a system of linear equations. Solving for a and b using the least squares method, the specific calculation formula is as follows:

[0128]

[0129] The effects of temperature and pressure on composition and physical properties are analyzed as follows:

[0130] In the parameter measurement module, each instrument's sample chamber is designed to withstand high temperature and pressure and is highly sealed. Heating coils are wound around the outside to heat the sample. The sample chambers of the nano-CT, micro-CT, optical microscope, and rock pyrolysis apparatus are pressurized via connected nitrogen tanks. The permeability meter is pressurized via a knob on the core holder, and the X-ray diffractometer increases sample pressure via a diamond anvil. Each device is equipped with temperature and pressure sensors to ensure that multiple devices apply the same temperature and pressure, simulating the sample evolution process. Each instrument can automatically heat and pressurize the sample. This device, controlled by power supply and valves, can heat and pressurize the sample chamber of a single instrument individually or simultaneously on multiple instruments.

[0131] To characterize the compositional and physical property changes of shale during its diagenetic evolution, we used this temperature and pressure control device to measure relevant parameters under varying temperature and pressure conditions. During testing, temperature and pressure are controlled by temperature and pressure sensors, and initial and converted parameter data are displayed in real time on a computer. First, the reservoir performance index is calculated. Then, based on the shale's reservoir performance index, temperature, and pressure changes, the shale evolution coefficient is calculated, achieving a quantitative characterization of the synergistic evolution process of shale composition and physical properties. Simultaneously, this device can also quantitatively characterize changes in pore structure during shale evolution and simulate the diagenetic evolution process of shale. This simulation device is multifunctional, enabling real-time measurement and calculation of shale evolution parameters to accurately assess the resource potential of shale oil and gas reservoirs and provide a scientific basis for resource development.

[0132] The simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties provided in this invention addresses the significant shortcomings of existing technologies such as laboratory testing, geological analysis, and numerical simulation in terms of rapid evaluation, real-time monitoring, and quantitative characterization of the co-evolution process of shale components and physical properties. The specific objectives are as follows:

[0133] (1) A comprehensive formula for reservoir performance index is constructed by using five shale components and physical property parameters, namely porosity, permeability, brittleness index, organic carbon content and maturity, to achieve quantitative characterization of shale reservoir performance.

[0134] (2) Define a shale pore characteristic factor that comprehensively reflects the shale pore structure based on the relevant parameters of shale pore structure, so as to quantitatively study the characteristics of shale pores.

[0135] (3) By heating and pressurizing the sample, the composition and physical properties of shale during the thermal evolution of shale can be quantitatively characterized in a coordinated manner, the shale evolution coefficient can be calculated, and the sensitivity of key shale parameters to temperature and pressure changes can be analyzed.

[0136] (4) Provide a simulation system that can automatically and in real time measure the composition and physical property related parameters during the evolution of shale, and calculate its reservoir performance index, shale evolution coefficient and porosity characteristic factor, so as to meet the needs of quantitative characterization of shale reservoir composition and physical properties.

[0137] The simulation method for quantitatively characterizing the synergistic evolution of shale components and properties provided in this invention employs multiple techniques, including a permeability meter, micron-scale CT, nano-scale CT, X-ray diffractometer, rock pyrolysis apparatus, and optical microscope, to measure relevant parameters of shale components and properties. Simultaneously, the sample chambers of each instrument undergo temperature and pressure modification to simulate the shale evolution process. This device enables real-time quantitative monitoring of component and property parameters during shale evolution. By calculating quantitative parameters such as the shale reservoir performance index, shale evolution coefficient, and shale porosity characteristic factor, the synergistic evolution of shale components and properties is reflected, overcoming the shortcomings of existing technologies in the quantitative analysis of components and properties during shale evolution. Furthermore, the method designed in this invention further improves the shale reservoir evaluation technology system, providing new methods and ideas for related research and practice, and contributing to the development of shale reservoir evaluation technology.

[0138] The simulation method for quantitatively characterizing the synergistic evolution of shale components and physical properties provided in this invention determines shale components and physical property parameters, and determines a comprehensive index of shale reservoir performance based on these parameters. The shale components and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity. Based on preset empirical constants, the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial and current experimental conditions are used to determine the shale evolution coefficient. Based on preset empirical coefficients, the temperature and pressure differences between the current and initial experimental conditions, as well as the shale pore physical parameters of the shale sample, are used to determine shale pore characteristic factors. This method not only comprehensively considers factors affecting shale reservoir performance but also quantitatively reveals the dynamic changes in components and physical properties during the evolution process, thereby providing more precise technical support for the development of shale oil and gas reservoirs.

[0139] Furthermore, determining the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters includes:

[0140] The comprehensive index of shale reservoir performance is calculated based on the weights corresponding to the porosity, permeability, organic carbon content, brittleness index, and maturity, respectively. This can be referred to the above embodiments for further explanation and will not be repeated here.

[0141] Furthermore, the simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties also includes:

[0142] The weights corresponding to the porosity, permeability, organic carbon content, brittleness index, and maturity were calculated using a principal component analysis model. This can be referred to the above embodiments for further explanation and will not be repeated here.

[0143] Furthermore, the determination of the shale evolution coefficient based on preset empirical constants and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, respectively, includes:

[0144] The shale evolution coefficient S is calculated according to the following first expression:

[0145]

[0146] Wherein, I0, T0, and P0 are the comprehensive shale reservoir performance index, temperature, and pressure corresponding to the initial experimental conditions; I, T, and P are the comprehensive shale reservoir performance index, temperature, and pressure corresponding to the current experimental conditions; and α, β, γ, and δ are all preset empirical constants. Refer to the above embodiments for further explanation; no further details will be provided.

[0147] Further, the shale pore physical parameters include the volume of a single pore, the total pore volume of the shale sample, the cross-sectional area of ​​a single pore, the perimeter of a single pore, and the pore diameter of a single pore; correspondingly, the determination of shale pore characteristic factors based on preset empirical coefficients, the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, and the shale pore physical parameters of the shale sample, includes:

[0148] The shale porosity characteristic factor N is calculated according to the following second expression:

[0149]

[0150] Where m is the total number of pores in the shale sample, and V i V is the volume of a single pore. T Let A be the total pore volume of the shale sample, and C be the cross-sectional area of ​​a single pore. i D is the perimeter of a single pore. i Here, ΔT is the pore diameter of a single pore, ΔP is the temperature difference, ΔP is the pressure difference, and a and b are both preset empirical coefficients. Refer to the above embodiments for further explanation; details will not be repeated here.

[0151] Furthermore, the simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties also includes:

[0152] The preset empirical constants and preset empirical coefficients are calculated using the least squares method. This can be referred to the above embodiments for further explanation, and will not be repeated here.

[0153] Figure 4 This is a schematic diagram of the structure of a simulation device for quantitatively characterizing the co-evolution process of shale components and physical properties, provided in an embodiment of the present invention. Figure 4As shown, the simulation device for quantitatively characterizing the co-evolution process of shale components and physical properties provided in this embodiment of the invention includes a first determining unit 401, a second determining unit 402, and a third determining unit 403, wherein:

[0154] The first determining unit 401 is used to determine the shale composition and physical property parameters, and to determine the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters; the shale composition and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity; the second determining unit 402 is used to determine the shale evolution coefficient based on preset empirical constants, the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, respectively; the third determining unit 403 is used to determine the shale porosity characteristic factor based on preset empirical coefficients, the temperature difference and pressure difference between the current experimental conditions and the initial experimental conditions, and the shale pore physical parameters of the shale sample.

[0155] Specifically, the first determining unit 401 in the device is used to determine the shale composition and physical property parameters, and to determine the comprehensive index of shale reservoir performance based on the shale composition and physical property parameters; the shale composition and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity; the second determining unit 402 is used to determine the shale evolution coefficient based on preset empirical constants, the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, respectively; the third determining unit 403 is used to determine the shale porosity characteristic factor based on preset empirical coefficients, the temperature difference and pressure difference between the current experimental conditions and the initial experimental conditions, and the shale pore physical parameters of the shale sample.

[0156] The simulation device provided in this invention, which quantitatively characterizes the synergistic evolution of shale components and physical properties, determines shale components and physical property parameters, and determines a comprehensive index of shale reservoir performance based on these parameters. The shale components and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity. Based on preset empirical constants, the shale reservoir performance comprehensive index, temperature, and pressure corresponding to the initial and current experimental conditions are used to determine the shale evolution coefficient. Based on preset empirical coefficients, the temperature and pressure differences between the current and initial experimental conditions, as well as the shale pore physical parameters of the shale sample, are used to determine shale pore characteristic factors. This device not only comprehensively considers factors affecting shale reservoir performance but also quantitatively reveals the dynamic changes in components and physical properties during the evolution process, thereby providing more precise technical support for the development of shale oil and gas reservoirs.

[0157] The embodiments of the present invention provide a simulation device for quantitatively characterizing the co-evolution process of shale components and physical properties. Specifically, it can be used to execute the processing flow of the above-described method embodiments. Its functions will not be repeated here, but can be referred to the detailed description of the above-described method embodiments.

[0158] Figure 5 This is a schematic diagram of the physical structure of a computer device provided in an embodiment of the present invention, such as... Figure 5 As shown, the computer device includes: a memory 501, a processor 502, and a computer program stored in the memory 501 and executable on the processor 502. When the processor 502 executes the computer program, it implements the following method:

[0159] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0160] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0161] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0162] This embodiment discloses a computer program product, which includes a computer program that, when executed by a processor, implements the following method:

[0163] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0164] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0165] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0166] This embodiment provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the following method:

[0167] The shale composition and physical properties are determined, and a comprehensive index of shale reservoir performance is determined based on the shale composition and physical properties; the shale composition and physical properties include porosity, permeability, organic carbon content, brittleness index, and maturity.

[0168] Based on preset empirical constants, and the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial experimental conditions and the current experimental conditions, the shale evolution coefficient is determined.

[0169] Based on preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current experimental conditions and the initial experimental conditions, as well as the shale porosity physical parameters of the shale sample.

[0170] Compared with existing technologies, the present invention provides a simulation method for quantitatively characterizing the synergistic evolution of shale components and physical properties. This method determines shale components and physical property parameters, and then determines a comprehensive index of shale reservoir performance based on these parameters. The shale components and physical property parameters include porosity, permeability, organic carbon content, brittleness index, and maturity. Based on preset empirical constants, the shale evolution coefficient is determined using the comprehensive index of shale reservoir performance, temperature, and pressure corresponding to the initial and current experimental conditions, respectively. Based on these preset empirical coefficients, the shale porosity characteristic factors are determined using the temperature and pressure differences between the current and initial experimental conditions, as well as the shale porosity physical parameters of the shale sample. This method not only comprehensively considers factors affecting shale reservoir performance but also quantitatively reveals the dynamic changes in components and physical properties during the evolution process, thus providing more precise technical support for the development of shale oil and gas reservoirs.

[0171] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0172] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0173] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0174] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0175] In the description of this specification, the references to terms such as "an embodiment," "a specific embodiment," "some embodiments," "for example," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples.

[0176] The specific embodiments described above further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above descriptions are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A simulation method for quantitatively characterizing the co-evolution process of shale components and physical properties, characterized in that, The method comprises the following steps: determining shale component and physical parameters, and determining a comprehensive index of shale reservoir performance according to the shale component and physical parameters; the shale component and physical parameters include porosity, permeability, organic carbon content, brittleness index and maturity; determining a shale evolution coefficient according to a preset empirical constant, a comprehensive index of shale reservoir performance, temperature and pressure corresponding to initial experimental conditions and current experimental conditions respectively; determining a shale pore characteristic factor according to a preset empirical coefficient, a temperature difference and a pressure difference between the current experimental conditions and the initial experimental conditions, and shale pore physical parameters of a shale sample; the method for determining the shale evolution coefficient according to the preset empirical constant, the comprehensive index of shale reservoir performance, the temperature and the pressure corresponding to the initial experimental conditions and the current experimental conditions respectively comprises: the shale evolution coefficient S is calculated according to the following first expression: ； wherein, is a comprehensive index of shale reservoir performance corresponding to the initial experimental conditions, temperature and pressure, is a comprehensive index of shale reservoir performance corresponding to the current experimental conditions, temperature and pressure, are the preset empirical constants; the shale pore physical parameters include volume of a single pore, total pore volume of the shale sample, cross-sectional area of a single pore, circumference of a single pore and pore diameter of a single pore; accordingly, the method for determining the shale pore characteristic factor according to the preset empirical coefficient, the temperature difference and the pressure difference between the current experimental conditions and the initial experimental conditions, and the shale pore physical parameters of the shale sample comprises: the shale pore characteristic factor N is calculated according to the following second expression: ； wherein m is the total pore number of the shale sample, V i is the volume of a single pore, V T is the total pore volume of the shale sample, A i is the cross-sectional area of a single pore, Ci is the circumference of a single pore, and Di is the pore diameter of a single pore, is the temperature difference, is the pressure difference, and a and b are both preset empirical coefficients.

2. The method of simulating the coevolution of shale composition and physical properties according to claim 1, wherein, the method for determining the comprehensive index of shale reservoir performance according to the shale component and physical parameters comprises: the comprehensive index of shale reservoir performance is calculated according to weights corresponding to the porosity, the permeability, the organic carbon content, the brittleness index and the maturity respectively.

3. The method of simulating the coevolution of shale composition and physical properties according to claim 2, wherein, The simulation method for quantitatively characterizing the cooperative evolution process of shale component and physical properties further comprises: weights corresponding to the porosity, the permeability, the organic carbon content, the brittleness index and the maturity are calculated by using a principal component analysis model.

4. The method of simulating the coevolution of shale composition and physical properties according to claim 1, wherein, The simulation method for quantitatively characterizing the cooperative evolution process of shale component and physical properties further comprises: the preset empirical constant and the preset empirical coefficient are calculated by using a least square method.

5. A simulation device for quantitatively characterizing the coevolution process of shale composition and physical properties, characterized in that, The method comprises the following steps: a first determination unit is configured to determine shale component and physical parameters, and determine a comprehensive index of shale reservoir performance according to the shale component and physical parameters; the shale component and physical parameters include porosity, permeability, organic carbon content, brittleness index and maturity; a second determination unit is configured to determine a shale evolution coefficient according to a preset empirical constant, a comprehensive index of shale reservoir performance, temperature and pressure corresponding to initial experimental conditions and current experimental conditions respectively; a third determination unit is configured to determine a shale pore characteristic factor according to a preset empirical coefficient, a temperature difference and a pressure difference between the current experimental conditions and the initial experimental conditions, and shale pore physical parameters of a shale sample; the method for determining the shale evolution coefficient according to the preset empirical constant, the comprehensive index of shale reservoir performance, the temperature and the pressure corresponding to the initial experimental conditions and the current experimental conditions respectively comprises: the shale evolution coefficient S is calculated according to the following first expression: ； wherein, is a comprehensive index of shale reservoir performance corresponding to the initial experimental conditions, temperature and pressure, is a comprehensive index of shale reservoir performance corresponding to the current experimental conditions, temperature and pressure, are the preset empirical constants; The shale pore physical parameters include volume of a single pore, total pore volume of the shale sample, cross-sectional area of a single pore, circumference of a single pore, and pore diameter of a single pore; accordingly, the shale pore characteristic factor is determined according to the preset empirical coefficient, the temperature difference and the pressure difference between the current experimental condition and the initial experimental condition, and the shale pore physical parameters of the shale sample, and includes: The shale pore characteristic factor N is calculated according to a second expression as follows: ； wherein m is the total number of pores of the shale sample, V i is the volume of a single pore, V T is the total pore volume of the shale sample, A i is the cross-sectional area of a single pore, Ci is the circumference of a single pore, and Di is the pore diameter of a single pore, is the temperature difference, is the pressure difference, and a and b are both preset empirical coefficients.

6. A computer device comprising a memory, a processor, and a computer program stored on the memory and executable on the processor, characterized in that, The processor implements the method of any one of claims 1 to 4 when executing the computer program.

7. A computer-readable storage medium, characterized in that, The computer readable storage medium stores a computer program, and the computer program is executed by the processor to implement the method of any one of claims 1 to 4.

8. A computer program product, characterised in that, The computer program product includes a computer program, and the computer program is executed by the processor to implement the method of any one of claims 1 to 4.

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