A method, apparatus, electronic equipment, and storage medium for determining the oil recovery potential of an oil reservoir via gas drive.

Abstract

This application provides a method, apparatus, electronic device, and storage medium for determining the gas-driven oil recovery potential of an oil reservoir. The method includes: obtaining experimental data on the relationship between oil recovery rate and gas injection rate under different pressures; obtaining a first mixing factor under different pressures using given values ​​of various fitting parameters; obtaining first relationship data between oil recovery rate and gas injection rate under different pressures based on a one-dimensional displacement numerical simulation grid model, various first mixing factors, and a modified black oil numerical simulator; if the relative error between the first relationship data and the experimental relationship data is less than a preset threshold, obtaining a second mixing factor under different pressures using the standard fitting parameter values ​​corresponding to the first mixing factor; and obtaining second relationship data between oil recovery rate and gas injection rate under different pressures based on a three-dimensional displacement numerical simulation grid model, various second mixing factors, and a modified black oil numerical simulator. This method can quickly and accurately determine the gas-driven oil recovery potential of an oil reservoir.

Description

Technical Field

[0001] This invention belongs to the field of information processing technology, and in particular relates to a method, apparatus, electronic device and storage medium for determining the oil reservoir gas drive potential. Background Technology

[0002] Currently, the main methods for evaluating the oil recovery potential of reservoirs via gas drive in related technologies include long core displacement experiments and component numerical simulation. Long core displacement experiments are complex, costly, and time-consuming, and essentially evaluate one-dimensional gas drive efficiency, which is significantly higher than the actual oil recovery potential in the field. Component numerical simulation requires dedicated component numerical simulators. Commercial component numerical simulators are expensive to purchase and require setting numerous fluid and rock parameters, which are generally obtained through extensive experiments, resulting in high economic and time costs. Therefore, to overcome the problems of these technologies, a new method for determining the oil recovery potential of reservoirs via gas drive is urgently needed. Summary of the Invention

[0003] To address the problems existing in the prior art, this invention provides a method, apparatus, electronic device, and storage medium for determining the oil reservoir's gas drive potential. This method can make full use of a small amount of conventional experimental test data to achieve a simple, fast, and accurate determination of gas drive potential, significantly improving evaluation efficiency and time, and reducing related economic costs.

[0004] The first aspect of this application provides a method for determining the oil reservoir gas drive potential, including: Experimental data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions were obtained; By using the given values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions is obtained; Based on a one-dimensional displacement numerical simulation grid model, each of the first mixing factors is sequentially input into the modified black oil numerical simulator to obtain the first relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The modified black oil numerical simulator uses mixing factors to represent the influence of injected gas on crude oil properties and flow parameters. When the relative error between the first relational data and the experimental relational data is less than a preset threshold, the values ​​of each parameter to be fitted corresponding to the first mixing factor are determined as standard parameter values ​​to be fitted. The second mixing factor under different pressure conditions is obtained by using the standard parameters to be fitted. Based on the three-dimensional displacement numerical simulation grid model, each of the second mixing factors is input into the modified black oil numerical simulator to obtain the second relationship data between crude oil recovery rate and gas injection volume under different pressure conditions.

[0005] Alternatively, the mixing factor can be calculated using the following formula:

[0006] in, denoted as mixing factor, a, b, c, and d are different parameters to be fitted, MMP is the minimum miscibility pressure of oil and gas determined by capillary experiments, P is the system pressure, and e is the natural index.

[0007] Optionally, the modified black oil numerical simulator is obtained by modifying the three-component black oil model of oil-gas-water using a pseudo-miscible method. During the modification process, it is assumed that the injected gas and oil are miscible but insoluble in the aqueous phase. The density of the crude oil in the modified black oil numerical simulator is calculated using the following formula:

[0008]

[0009]

[0010] in, This is the corrected crude oil density. The original density of the oil phase. The density of crude oil after complete miscibility. To achieve the saturation of the injected gas, S o S represents the saturation level of crude oil. or Residual oil saturation, Indicates the density of the gas phase; The viscosity of crude oil in the revised black oil numerical simulator is calculated using the following formula:

[0011]

[0012] in, This indicates the corrected crude oil viscosity. The viscosity of crude oil in a completely miscible state. The viscosity is the viscosity of crude oil in its immiscible state. The viscosity of the injected gas; The relative permeability in the modified black oil numerical simulator is calculated using the following formula:

[0013] Where, k rp This represents the relative permeability of the p-phase. This represents the relative permeability of the p-phase under miscible conditions. ω represents the relative permeability of the p-phase under immiscible conditions. omax This represents the maximum value of the mixing factor.

[0014] Optionally, experimental data on the relationship between oil recovery rate and gas injection rate under different pressure conditions can be obtained, including: Through gas-driven oil capillary experiments, experimental data on the relationship between oil recovery rate and gas injection volume in sand-filled capillary under different pressure conditions were obtained. Before sequentially inputting each of the first mixing factors into the corrected black oil numerical simulator, the method further includes: A one-dimensional displacement numerical simulation grid model is established based on the capillary parameters used in the gas-driven oil capillary experiment. The capillary parameters include at least the capillary inner diameter, capillary length, porosity, and permeability. The one-dimensional displacement numerical simulation grid model is established using a rectangular coordinate system or a radial coordinate system. The cross-sectional area of ​​the grid in the flow direction is consistent with the cross-sectional area of ​​the thin tube, and the length of a single grid in the flow direction is not less than a preset length.

[0015] Optionally, before inputting each of the second mixing factors into the corrected black oil numerical simulator, the method further includes: Based on the geological and development characteristics of the actual block, a three-dimensional displacement numerical simulation grid model is established. The geological characteristics include at least formation dip angle, thickness, porosity, permeability, and permeability variation coefficient. The development characteristics include at least remaining oil saturation, reservoir pressure, well pattern, and well spacing.

[0016] Optionally, the method is used to determine the oil enhancement potential of a reservoir through gas drive, wherein the reservoir includes at least: conventional sandstone / clastic / carbonate reservoirs and tight oil / shale reservoirs; the gas drive medium includes at least one or more mixed gases selected from nitrogen, deoxygenated air, hydrocarbon gas, and carbon dioxide.

[0017] Optionally, the method further includes: Through water drive simulation experiments, third-party relationship data between crude oil recovery rate and gas injection volume under different pressure conditions were obtained; The gas-driven oil production potential of the reservoir is determined based on the second relationship data and the third relationship data.

[0018] Optionally, when the relative error between the first relational data and the experimental relational data is not less than a preset threshold, the method further includes: The values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions, and the first relationship data are obtained again until the relative error between the first relationship data and the experimental relationship data is less than a preset threshold.

[0019] The second aspect of this application provides an apparatus for measuring the oil reservoir gas drive potential, comprising: The first acquisition module is used to obtain experimental data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions; The second acquisition module is used to obtain the first mixing factor under different pressure conditions by using the given values ​​of each parameter to be fitted; The third acquisition module is used to sequentially input each of the first mixing factors into the modified black oil numerical simulator based on the one-dimensional displacement numerical simulation grid model, and obtain the first relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The modified black oil numerical simulator uses mixing factors to represent the influence of injected gas on crude oil properties and flow parameters. The first determining module is used to determine the values ​​of each parameter to be fitted corresponding to the first mixing factor as standard parameter values ​​when the relative error between the first relation data and the experimental relation data is less than a preset threshold. The fourth module is used to obtain a second mixing factor under different pressure conditions using the standard parameter values ​​to be fitted. The fifth module is used to input each of the second mixing factors into the modified black oil numerical simulator based on the three-dimensional displacement numerical simulation grid model to obtain the second relationship data between crude oil recovery rate and gas injection volume under different pressure conditions.

[0020] Alternatively, the mixing factor can be calculated using the following formula:

[0021] in, denoted as mixing factor, a, b, c, and d are different parameters to be fitted, MMP is the minimum miscibility pressure of oil and gas determined by capillary experiments, P is the system pressure, and e is the natural index.

[0022] Optionally, the modified black oil numerical simulator is obtained by modifying the three-component black oil model of oil-gas-water using a pseudo-miscible method. During the modification process, it is assumed that the injected gas and oil are miscible but insoluble in the aqueous phase. The density of the crude oil in the modified black oil numerical simulator is calculated using the following formula:

[0023]

[0024]

[0025] in, This is the corrected crude oil density. The original density of the oil phase. The density of crude oil after complete miscibility. To achieve the saturation of the injected gas, S o S represents the saturation level of crude oil. or Residual oil saturation, Indicates the density of the gas phase; The viscosity of crude oil in the revised black oil numerical simulator is calculated using the following formula:

[0026]

[0027] in, This indicates the corrected crude oil viscosity. The viscosity of crude oil in a completely miscible state. The viscosity is the viscosity of crude oil in its immiscible state. The viscosity of the injected gas; The relative permeability in the modified black oil numerical simulator is calculated using the following formula:

[0028] Where, k rp This represents the relative permeability of the p-phase. This represents the relative permeability of the p-phase under miscible conditions. ω represents the relative permeability of the p-phase under immiscible conditions. omax This represents the maximum value of the mixing factor.

[0029] Optionally, the first obtaining module includes: The submodule is used to obtain experimental data on the relationship between oil recovery rate and gas injection volume under different pressure conditions through gas-driven oil capillary experiments. The device further includes: The first module is used to establish a one-dimensional displacement numerical simulation grid model based on the capillary parameters used in the gas-driven oil capillary experiment. The capillary parameters include at least the capillary inner diameter, capillary length, porosity, and permeability. The one-dimensional displacement numerical simulation grid model is established using a rectangular coordinate system or a radial coordinate system. The cross-sectional area of ​​the grid in the flow direction is consistent with the cross-sectional area of ​​the capillary, and the length of a single grid in the flow direction is not less than a preset length.

[0030] Optionally, the device further includes: The second module is used to establish a three-dimensional displacement numerical simulation grid model based on the geological and development characteristics of the actual block. The geological characteristics include at least formation dip angle, thickness, porosity, permeability, and permeability variation coefficient. The development characteristics include at least remaining oil saturation, reservoir pressure, well pattern, and well spacing.

[0031] Optionally, the method is used to determine the oil enhancement potential of a reservoir through gas drive, wherein the reservoir includes at least: conventional sandstone / clastic / carbonate reservoirs and tight oil / shale reservoirs; the gas drive medium includes at least one or more mixed gases selected from nitrogen, deoxygenated air, hydrocarbon gas, and carbon dioxide.

[0032] Optionally, the device further includes: The sixth module is used to obtain the third relationship data between oil recovery rate and gas injection volume under different pressure conditions through water drive simulation experiments; The second determining module is used to determine the gas-driven oil enhancement potential of the reservoir based on the second relationship data and the third relationship data.

[0033] Optionally, the device further includes: The seventh acquisition module is used to reacquire the values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions, and the first relationship data until the relative error between the first relationship data and the experimental relationship data is less than a preset threshold.

[0034] A third aspect of this application provides an electronic device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the steps of the method for determining the oil reservoir gas drive potential described in the first aspect of this application.

[0035] The fourth aspect of this application provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the steps in the method for determining the oil reservoir gas drive potential as described in the first aspect of this application.

[0036] The method for determining the oil recovery potential of reservoirs using the method described in this application first obtains experimental data on the relationship between oil recovery rate and gas injection volume under different pressure conditions. Next, based on the given values ​​of various fitting parameters, a first mixing factor between injected gas and oil under different pressure conditions is calculated using a mixing factor calculation formula. Then, each of the first mixing factors is input into a modified black oil numerical simulator, which, based on a one-dimensional displacement numerical simulation grid model, outputs the first relationship data between oil recovery rate and gas injection volume under different pressure conditions. When the relative error between the first relationship data and the experimental relationship data is less than a preset threshold, the values ​​of each fitting parameter corresponding to the first mixing factor are determined as standard fitting parameter values. A second mixing factor under different pressure conditions is calculated based on the standard fitting parameter values. Finally, each of the second mixing factors is input into the modified black oil numerical simulator, which, based on a three-dimensional displacement numerical simulation grid model, outputs the second relationship data between oil recovery rate and gas injection volume under different pressure conditions. Since the second relationship data can reflect the relationship between oil recovery rate and gas injection volume under different pressure conditions in a real environment, the potential for gas-driven oil enhancement can be determined through this data. The method described in this application allows for the efficient, rapid, and accurate determination of gas-driven potential by making full use of limited conventional experimental test data, significantly improving evaluation efficiency and reducing related economic costs. Attached Figure Description

[0037] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the embodiments of the present invention 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.

[0038] Figure 1 This is a flowchart illustrating a method for determining the oil reservoir gas drive potential according to an embodiment of this application; Figure 2a This is a schematic diagram illustrating the relationship between crude oil recovery rate and gas injection volume at 25 MPa, as shown in one embodiment of this application. Figure 2b This is a schematic diagram illustrating the relationship between crude oil recovery rate and gas injection volume at 30 MPa, as shown in one embodiment of this application. Figure 2c This is a schematic diagram illustrating the relationship between crude oil recovery rate and gas injection volume at 35 MPa, as shown in one embodiment of this application. Figure 3 This is a schematic diagram illustrating the relationship between a mixing factor and pressure according to an embodiment of this application; Figure 4This is a schematic diagram showing a comparison between experimental and simulation results of long core displacement, as illustrated in an embodiment of this application. Figure 5 This is a schematic diagram of permeability distribution and well location in a three-dimensional geological model, as shown in one embodiment of this application. Figure 6 This is a schematic diagram showing a comparison of the relationship curves between CO2 and water drive recovery degree and injection volume in one embodiment of this application; Figure 7 This is a structural block diagram of an apparatus for measuring the oil reservoir gas drive potential, as shown in one embodiment of this application. Detailed Implementation

[0039] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to embodiments. It should be understood that the specific embodiments described herein are merely illustrative and not intended to limit the invention.

[0040] Currently, the evaluation of reservoir gas-drive oil enhancement potential mainly relies on core displacement experiments or component numerical simulation methods. Long core displacement experiments primarily include core preparation, saturated oil treatment, water-drive, and gas-drive physical simulation. Core preparation involves complex sample processing steps such as collecting core samples from the target layer, drilling cores, and end-face grinding. For reservoirs with naturally developed fractures, low-permeability reservoirs, or tight-fracturing reservoirs, additional fracture-splitting is required to simulate fractures. After core preparation, sequential processing steps include vacuum saturation, water-drive to create bound water saturation, and oil-drive saturated oil. After core saturation, cores are arranged in a specific pattern according to their permeability to form long cores. These long cores are placed in a long core displacement experiment apparatus. After establishing the initial or remaining oil saturation based on the reservoir's actual conditions, gas-drive is performed at a specific injection rate or pressure until the gas-oil ratio at the production end reaches a certain value, at which point the experiment terminates. Therefore, long core displacement experiments are extremely cumbersome, time-consuming, and costly. Furthermore, since core displacement is a one-dimensional displacement process, the gas drive recovery rate obtained through long core displacement experiments essentially reflects the gas drive oil displacement efficiency. However, actual reservoir gas drive is a three-dimensional displacement process and is affected by factors such as reservoir heterogeneity. Therefore, the gas drive potential evaluated by core displacement experiments is usually significantly higher than the actual value in the field.

[0041] The component numerical simulation method involves establishing a reservoir geological model and using a component numerical simulator to simulate the water-to-gas displacement process, thereby calculating the gas-driven oil enhancement potential. This method mainly includes steps such as geological model construction, setting rock-fluid physical properties, setting injection and production parameters, and numerical simulation calculations. Specific steps can be found in relevant technical documents. The component numerical simulation method requires a specialized component numerical simulator. Currently, commercially available component numerical simulators are expensive to purchase, and the computational workload and efficiency are high. Furthermore, the rock-fluid physical properties required for component numerical simulation generally need to be obtained through extensive physical simulation experiments (including formation fluid component testing experiments, constant-pressure / constant-composition gas injection PVT experiments, and capillary tube experiments) to ensure the reliability of the simulation results. Compared to long core displacement experiments, the component numerical simulation method can consider actual reservoir characteristics, and the gas-driven potential it evaluates is closer to reality. However, the component numerical simulation method also suffers from high economic and time costs.

[0042] Therefore, based on the above analysis, at least the following two problems exist in the relevant technology: First, the long core displacement test process is complex, costly, and time-consuming. Moreover, it essentially evaluates one-dimensional gas-driven oil displacement efficiency. Therefore, the gas drive potential evaluated by the core displacement test is usually significantly higher than the actual value in the mine.

[0043] Second, component numerical simulation requires the use of a dedicated component numerical simulator. Commercial component numerical simulators are expensive to purchase and require setting a large number of fluid and rock parameters. These parameters are generally obtained through a lot of experiments, resulting in high economic and time costs.

[0044] To address the problems existing in related technologies, this application provides a method for evaluating the potential of low-permeability fracturing water-drive reservoirs to gas drive based on modified black oil numerical simulation. This method can make full use of a small amount of conventional experimental test data to achieve simple, fast, and accurate determination of gas drive potential, significantly improving evaluation efficiency and time while reducing related economic costs.

[0045] Specifically, the methods for evaluating gas drive potential can be as follows: Figure 1 As shown. Figure 1 This is a flowchart illustrating a method for determining the oil reservoir's gas drive potential, as shown in one embodiment of this application. (Refer to...) Figure 1 The gas drive potential evaluation method of this application may include the following steps: Step S11: Obtain experimental data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions.

[0046] In one implementation, step S11 may include: Through gas-driven oil capillary experiments, experimental data on the relationship between oil recovery rate and gas injection volume in sand-filled capillary under different pressure conditions were obtained.

[0047] In this embodiment, gas-driven oil capillary experiments under different gas injection pressure conditions can be conducted in advance to obtain data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions. The crude oil recovery rate can be represented by the crude oil recovery rate, and the relationship data can be represented by the relationship curve.

[0048] In this embodiment, the relationship data obtained through the gas-driven oil capillary experiment cannot reflect the relationship between crude oil recovery and gas injection volume in a real environment. However, it can be used to guide the determination of the mixing factor and thus obtain the relationship between crude oil recovery rate and gas injection volume in a real environment (which will be described later). Therefore, the relationship data obtained through the gas-driven oil capillary experiment can be used as experimental relationship data.

[0049] Step S12: Obtain the first mixing factor under different pressure conditions using the given values ​​of each parameter to be fitted.

[0050] Step S13: Based on the one-dimensional displacement numerical simulation grid model, each of the first mixing factors is sequentially input into the modified black oil numerical simulator to obtain the first relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The modified black oil numerical simulator uses mixing factors to represent the influence of injected gas on crude oil properties and flow parameters.

[0051] In this embodiment, before sequentially inputting each of the first mixing factors into the corrected black oil numerical simulator, the following steps may also be included: A one-dimensional displacement numerical simulation grid model is established based on the capillary parameters used in the gas-driven oil capillary experiment. The capillary parameters include at least the capillary inner diameter, capillary length, porosity, and permeability. The one-dimensional displacement numerical simulation grid model is established using a rectangular coordinate system or a radial coordinate system. The cross-sectional area of ​​the grid in the flow direction is consistent with the cross-sectional area of ​​the thin tube, and the length of a single grid in the flow direction is not less than a preset length.

[0052] In this embodiment, the one-dimensional displacement numerical simulation grid model is a physical model. The modified black oil numerical simulator can obtain data on the relationship between crude oil recovery and gas injection volume under different pressure conditions based on this physical model and the input mixing factor. The modified black oil numerical simulator uses a mixing factor to represent the influence of injected gas on crude oil properties and flow parameters.

[0053] The preset length can generally be set to 1m based on experience, but it can also be set to other values ​​according to actual needs.

[0054] The first mixing factor is calculated according to the mixing factor formula, which contains multiple parameters to be fitted. Users can arbitrarily give values ​​to each parameter to be fitted in order to calculate the first mixing factor.

[0055] The values ​​of each parameter to be fitted can be determined in any way, and this embodiment does not impose any specific restrictions on this.

[0056] For example, the user provides a set of parameters to be fitted and obtains the first mixing factor w1 under pressure P1, the first mixing factor w2 under pressure P2, and the first mixing factor w3 under pressure P3. Then, w1 is input into a modified black oil numerical simulator. The simulator, based on a one-dimensional displacement numerical simulation grid model, can output the first relationship data between crude oil recovery and gas injection volume at pressure P1. Similarly, w2 is input into the same simulator, which outputs the first relationship data between crude oil recovery and gas injection volume at pressure P2. Finally, w3 is input into the same simulator, which outputs the first relationship data between crude oil recovery and gas injection volume at pressure P3. The specific values ​​of P1, P2, and P3 can be set according to actual needs.

[0057] Step S14: When the relative error between the first relational data and the experimental relational data is less than a preset threshold, the values ​​of each parameter to be fitted corresponding to the first mixing factor are determined as standard parameter values ​​to be fitted.

[0058] In this embodiment, if the relative error between the first relational data and the experimental relational data is less than a preset threshold, the values ​​of each parameter to be fitted in step S12 can be determined as standard parameter values ​​to be fitted, which can be used to guide the determination of the mixing factor in subsequent steps.

[0059] Following the example in step S13 above, it can be determined whether the relative error between the first relationship data of crude oil recovery degree and gas injection volume under pressure P1 and the experimental relationship data under pressure P1 is less than a preset threshold; it can also be determined whether the relative error between the first relationship data of crude oil recovery degree and gas injection volume under pressure P2 and the experimental relationship data under pressure P2 is less than a preset threshold; and so on, it can be determined whether the relative error between the first relationship data of crude oil recovery degree and gas injection volume under pressure P3 and the experimental relationship data under pressure P3 is less than a preset threshold. If the relative error between the first relationship data under each pressure and the corresponding experimental relationship data is less than the preset threshold, it can be determined that the relative error between the first relationship data and the experimental relationship data is less than the preset threshold.

[0060] The method for calculating the relative error between the first relational data and the experimental relational data can be implemented in any way in the relevant technology, and this embodiment does not impose any specific restrictions on it.

[0061] Step S15: Obtain the second mixing factor under different pressure conditions using the standard parameters to be fitted.

[0062] In this embodiment, the first mixing factor and the second mixing factor are obtained in the same way.

[0063] Step S16: Based on the three-dimensional displacement numerical simulation grid model, input each of the second mixing factors into the modified black oil numerical simulator to obtain the second relationship data between crude oil recovery rate and gas injection volume under different pressure conditions.

[0064] In this embodiment, the three-dimensional displacement numerical simulation grid model is a physical model established based on the characteristics of the real environment. The modified black oil numerical simulator can obtain the relationship data between the degree of crude oil recovery and the amount of gas injection under different pressure conditions in the real environment based on the three-dimensional displacement numerical simulation grid model.

[0065] After determining the standard values ​​of each parameter to be fitted, the second mixing factor under different pressure conditions can be obtained through the mixing factor formula. Then, the second mixing factor is input into the corrected black oil numerical simulator.

[0066] For example, based on the standard parameters to be fitted, the second mixing factor w1' under pressure P1, the second mixing factor w2' under pressure P2, and the second mixing factor w3' under pressure P3 are obtained respectively. Then, w1' is input into the modified black oil numerical simulator, which, based on a three-dimensional displacement numerical simulation grid model, can output the second relationship data between crude oil recovery and gas injection volume under pressure P1. Similarly, w2' is input into the modified black oil numerical simulator, which, based on a three-dimensional displacement numerical simulation grid model, can output the second relationship data between crude oil recovery and gas injection volume under pressure P2. Finally, w3' is input into the modified black oil numerical simulator, which, based on a three-dimensional displacement numerical simulation grid model, can output the second relationship data between crude oil recovery and gas injection volume under pressure P3.

[0067] The second relationship data can reflect the relationship between crude oil recovery and gas injection volume under different pressure conditions in real environment. Through the second relationship data, the potential for gas-driven oil enhancement can be determined.

[0068] In practice, the preset threshold can generally be set to 10% based on experience. Of course, it can also be set to other values ​​according to actual needs. This embodiment does not impose any specific restrictions on this.

[0069] In conjunction with the above embodiments, in one implementation, when the relative error between the first relational data and the experimental relational data is not less than a preset threshold, the method of this application may further include the following steps: The values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions, and the first relationship data are obtained again until the relative error between the first relationship data and the experimental relationship data is less than a preset threshold.

[0070] In this embodiment, if the relative error between the first relational data and the experimental relational data is not less than a preset threshold, the values ​​of each parameter to be fitted can be repeatedly adjusted, and steps S12-S13 can be repeated until the relative error between the first relational data and the experimental relational data is less than the preset threshold before proceeding to step S14.

[0071] The method for determining the oil recovery potential of reservoirs using the method described in this application first obtains experimental data on the relationship between oil recovery rate and gas injection rate under different pressure conditions. Next, based on the given values ​​of various fitting parameters, a first mixing factor between injected gas and oil under different pressure conditions is calculated using a mixing factor calculation formula. Then, each of the first mixing factors is input into a modified black oil numerical simulator, which, based on a one-dimensional displacement numerical simulation grid model, outputs the first relationship data between oil recovery rate and gas injection rate under different pressure conditions. When the relative error between the first relationship data and the experimental relationship data is less than a preset threshold, the values ​​of the fitting parameters corresponding to the first mixing factor are determined as standard fitting parameter values, and a second mixing factor under different pressure conditions is calculated based on these standard fitting parameter values. Finally, each of the second mixing factors is input into the modified black oil numerical simulator, which, based on a three-dimensional displacement numerical simulation grid model, outputs the second relationship data between oil recovery rate and gas injection rate under different pressure conditions. Since the second relationship data can reflect the relationship between oil recovery rate and gas injection volume under different pressure conditions in a real environment, the potential for gas-driven oil enhancement can be determined through this data. The method described in this application allows for the efficient, rapid, and accurate determination of gas-driven potential by making full use of limited conventional experimental test data, significantly improving evaluation efficiency and reducing related economic costs.

[0072] In conjunction with the above embodiments, in one implementation method, the mixing factor of injected gas and crude oil under different pressure conditions can be calculated using the following formula (1): (1) in, denoted as mixing factor, a, b, c, and d are different parameters to be fitted, MMP is the minimum miscibility pressure of oil and gas determined by capillary experiments, P is the system pressure, and e is the natural index.

[0073] In this embodiment, if the conditions in step S14 are not met, the values ​​of the parameters to be fitted, a, b, c, and d can be repeatedly adjusted, and steps S12-S13 can be repeated until the conditions in step S14 are met.

[0074] In one embodiment, based on the above examples, the modified black oil numerical simulator is obtained by modifying the three-component black oil model of oil-gas-water using a pseudo-miscible method. During the modification process, it is assumed that the injected gas and oil are mutually soluble but cannot dissolve in the aqueous phase. The density of the crude oil in the modified black oil numerical simulator is calculated using the following formulas (2)-(4): (2) (3) (4) in, This is the corrected crude oil density. The original density of the oil phase. The density of crude oil after complete miscibility. To achieve the saturation of the injected gas, S o S represents the saturation level of crude oil. or Residual oil saturation, The median value. This represents the density of the gas phase.

[0075] The viscosity of crude oil in the revised black oil numerical simulator is calculated using the following formulas (5)-(6): (5) (6) in, This indicates the corrected crude oil viscosity. The viscosity of crude oil in a completely miscible state. The viscosity is the viscosity of crude oil in its immiscible state. The viscosity of the injected gas.

[0076] The relative permeability in the revised black oil numerical simulator is calculated using the following formula (7): (7) Where, k rp This represents the relative permeability of the p-phase (p = oil, gas). This represents the relative permeability of the p-phase under miscible conditions. ω represents the relative permeability of the p-phase under immiscible conditions. omax This represents the maximum value of the mixing factor.

[0077] In this embodiment, the quasi-miscible method is used to modify the three-component black oil model of oil-gas-water to obtain a modified black oil numerical simulator. This method assumes that the injected gas and oil are miscible but cannot dissolve in the aqueous phase. A mixing factor is introduced to consider the influence of the injected gas on the properties and flow parameters of crude oil, thereby indirectly simulating the effects of miscibility, partial miscibility, and immiscibility on the gas drive process. The changes in crude oil physical properties and relative permeability caused by the miscibility of injected gas and oil are described by the above formulas (2)-(7).

[0078] In conjunction with the above embodiments, in one implementation, before inputting each of the second mixing factors into the corrected black oil numerical simulator, the method of this application may further include the following steps: Based on the geological and development characteristics of the actual block, a three-dimensional displacement numerical simulation grid model is established. The geological characteristics include at least formation dip angle, thickness, porosity, permeability, and permeability variation coefficient. The development characteristics include at least remaining oil saturation, reservoir pressure, well pattern, and well spacing.

[0079] Geological characteristics may include formation dip angle, thickness, porosity, permeability, and permeability variation coefficient, while development characteristics may include remaining oil saturation, reservoir pressure, well pattern, and well spacing. For hydraulically fractured wells, the length of artificial fractures and fracture conductivity must also be considered.

[0080] Geological and development features can be set according to actual needs, and this embodiment does not impose specific restrictions on them.

[0081] In conjunction with the above embodiments, in one implementation, when the method of this application is used to determine the oil enhancement potential of reservoirs via gas drive, the reservoir type can include at least all possible reservoir types, including conventional sandstone / clastic / carbonate reservoirs and tight oil / shale reservoirs. The gas drive medium can include at least potential gas drive media such as nitrogen, deoxygenated air, hydrocarbon gas, and carbon dioxide, and can use single-component gases or multi-component mixed gases.

[0082] In conjunction with the above embodiments, in one implementation, the method of this application may further include: Through water drive simulation experiments, third-party relationship data between crude oil recovery rate and gas injection volume under different pressure conditions were obtained; The gas-driven oil production potential of the reservoir is determined based on the second relationship data and the third relationship data.

[0083] In this embodiment, to illustrate the accuracy of the method proposed in this application, a water drive simulation model can be further constructed, and the second relationship data can be compared with the water drive simulation experimental results. If the two results are in good agreement, it indicates that the proposed method has high accuracy, that is, the gas drive oil enhancement potential of the reservoir can be determined well based on the second relationship data.

[0084] The reservoir gas drive potential evaluation method based on capillary experiments and improved black oil numerical values ​​provided in this application can quickly, economically, and accurately determine the oil enhancement effect of different gas drive media.

[0085] The following section will take CO2 flooding of a low-permeability reservoir as an example to provide a detailed explanation of the gas-driven oil enhancement potential determination method of this application, as shown in steps 1-8.

[0086] Step 1: Conduct CO2-assisted oil recovery capillary experiments under different pressure conditions to obtain the relationship between crude oil recovery rate and injected gas volume under injection pressures of 25 MPa, 30 MPa, and 35 MPa. Figures 2a-2c As shown. Figure 2a This is a schematic diagram illustrating the relationship between crude oil recovery rate and gas injection volume at 25 MPa, as shown in one embodiment of this application. Figure 2b This is a schematic diagram illustrating the relationship between crude oil recovery rate and gas injection volume at 30 MPa, as shown in one embodiment of this application. Figure 2c This is a schematic diagram illustrating the relationship between crude oil recovery rate and gas injection volume at 35 MPa, as shown in one embodiment of this application.

[0087] Among them, Figures 2a-2c In the graph, the horizontal axis represents the injected hydrocarbon volume multiple (HCPV), the vertical axis represents the crude oil recovery rate (oil recovery ratio), the small squares represent the experimental results of the CO2 flooding capillary experiment, and the solid line represents the simulation calculation results obtained in subsequent step 5. According to... Figures 2a-2c It can be seen that the experimental results and simulation calculation results of CO2-driven oil displacement capillary experiments differ under different pressure conditions, and the agreement between the experimental results and simulation calculation results also varies. Specifically, the injected hydrocarbon volume ratio = the ratio of the total injected gas volume to the hydrocarbon volume present in the capillary, and the total injected gas volume = injection time * injection rate (specific parameters can be found in industry references).

[0088] Step 2: Modify the traditional three-phase black oil model of oil-gas-water and compile a numerical simulation program to obtain the modified black oil numerical simulator.

[0089] Step 3: Based on the parameters of the thin tube model in Step 1 (e.g., length 20m, inner diameter 4.4mm, porosity 33.46%, permeability 10.8μm2), establish a one-dimensional gas-driven numerical simulation grid model with an injection rate of 0.2mL / min at the injection end.

[0090] Step 4: Given the values ​​of the parameters to be determined, a, b, c, and d, calculate the mixing factor under different pressures according to equation (1). .

[0091] Step 5: Substitute the results into the improved black oil numerical simulator established in step 2, calculate the crude oil recovery rate and gas injection rate curves under different gas injection pressures (i.e., simulation results), and compare them with the thin tube experimental results obtained in step 1.

[0092] Step 6: Repeatedly adjust the values ​​of the parameters to be fitted, a, b, c, and d, until the simulation results match the results of the thin tube experiment in Step 1. Experimental results show that when a, b, c, and d are 1.0, 0.98, 6.5, and 4.1 respectively (corresponding to...) The curve showing the relationship with pressure is as follows: Figure 3 As shown), the relative error between the simulation results and the results of the thin tube experiment in step 1 is less than 10% (e.g. Figures 2a-2c (As shown). Figure 3 This is a schematic diagram illustrating the relationship between a mixing factor and pressure, as shown in one embodiment of this application.

[0093] exist Figure 3 In the diagram, the horizontal axis represents pressure (MPa), and the vertical axis represents the mixing factor. .

[0094] Step 7: To demonstrate the accuracy of the method proposed in this application, a numerical simulation model of gas-drive oil recovery from long core samples is further constructed, and the simulation results are compared with the actual long core displacement experimental results. For example... Figure 4 As shown, the curves relating crude oil recovery rate to gas injection rate obtained by simulation calculation using the method of this application are in good agreement with the results of actual long core displacement experiments, indicating that the proposed method has high accuracy. Figure 4 This is a schematic diagram showing a comparison between experimental and simulation results of long core displacement, as illustrated in an embodiment of this application.

[0095] exist Figure 4 In the diagram, small squares represent the results of long core displacement experiments, while solid lines represent simulation calculation results; the two show good agreement.

[0096] Step 8: Based on the aforementioned parameters, establish a three-dimensional numerical simulation grid model according to the actual geological and development characteristics of the block. Simulate the gas-driven oil production process under the actual geological and development conditions under the condition of injection-production balance. The gas-driven oil production potential is clarified by comparing the simulation results with those of water-driven oil production.

[0097] Here, we take a single well group in a conceptual five-point well network (see...) Figure 5Taking [example 1] as an example, the simulation process is briefly explained. The grid model has a grid number of 21×21×5, with each grid measuring 20m×20m×2m. The porosity is 17.1%, permeability ranges from 0.5 to 15 mD, with an average of 5.7 mD. The formation pressure is 33 MPa, and the crude oil viscosity under these conditions is 1.7 mPa•s. The model center is an injection well, with four production wells located at the grid corners. Assuming the wells produce at a constant fluid rate, the injection rate of the injection wells is determined while ensuring injection-production balance. Figure 6 The figure shows the simulation results of gas-drive and water-drive. As can be seen from the figure, when the injection rate exceeds 0.2 HCPV, CO2-drive is more effective than water-drive. When the injection rate reaches 0.65 HCPV or higher, the recovery rate of CO2-drive remains essentially unchanged (approximately 42%) with increasing injection rate. In contrast, the recovery rate of water-drive is only 27.8%. Compared to water-drive, CO2-drive can increase the recovery rate by approximately 14.2%, indicating that CO2-drive has excellent oil recovery potential in this block. Figure 5 This is a schematic diagram of the permeability distribution and well location of a three-dimensional geological model shown in one embodiment of this application. Figure 6 This is a schematic diagram showing a comparison of the relationship curves between CO2 and water drive recovery degree and injection volume, as illustrated in one embodiment of this application.

[0098] The method for determining the oil enhancement potential of reservoirs via gas drive, provided by this invention, can quickly, economically, and accurately determine the oil enhancement effect of different gas drive media. Furthermore, the oil enhancement potential evaluation method for reservoirs based on improved black oil simulation provided by this invention offers reliable evaluation results, high efficiency, and low cost. It can fully utilize limited conventional experimental test data to achieve a simple, rapid, and accurate determination of gas drive potential, significantly improving evaluation efficiency and time while reducing related economic costs.

[0099] It should be noted that, for the sake of simplicity, the method embodiments are all described as a series of actions. However, those skilled in the art should understand that the embodiments of the present invention are not limited to the described order of actions, because according to the embodiments of the present invention, some steps can be performed in other orders or simultaneously. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions involved are not necessarily essential to the embodiments of the present invention.

[0100] Based on the same inventive concept, one embodiment of this application provides an apparatus 700 for measuring the oil reservoir's gas drive potential. (Reference) Figure 7 , Figure 7 This is a structural block diagram of an apparatus for measuring the oil reservoir's gas drive potential, as illustrated in one embodiment of this application. Figure 7 As shown, the device 700 includes: The first acquisition module 701 is used to obtain experimental data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions; The second obtaining module 702 is used to obtain the first mixing factor under different pressure conditions by using the given values ​​of each parameter to be fitted; The third acquisition module 703 is used to sequentially input each of the first mixing factors into the modified black oil numerical simulator based on the one-dimensional displacement numerical simulation grid model to obtain the first relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The modified black oil numerical simulator uses mixing factors to represent the influence of injected gas on crude oil properties and flow parameters. The first determining module 704 is used to determine the values ​​of each parameter to be fitted corresponding to the first mixing factor as standard parameter values ​​when the relative error between the first relation data and the experimental relation data is less than a preset threshold. The fourth obtaining module 705 is used to obtain a second mixing factor under different pressure conditions using the standard parameter values ​​to be fitted; The fifth acquisition module 706 is used to input each of the second mixing factors into the modified black oil numerical simulator based on the three-dimensional displacement numerical simulation grid model to obtain the second relationship data between crude oil recovery rate and gas injection volume under different pressure conditions.

[0101] Alternatively, the mixing factor can be calculated using the following formula:

[0102] in, denoted as mixing factor, a, b, c, and d are different parameters to be fitted, MMP is the minimum miscibility pressure of oil and gas determined by capillary experiments, P is the system pressure, and e is the natural index.

[0103] Optionally, the modified black oil numerical simulator is obtained by modifying the three-component black oil model of oil-gas-water using a pseudo-miscible method. During the modification process, it is assumed that the injected gas and oil are miscible but insoluble in the aqueous phase. The density of the crude oil in the modified black oil numerical simulator is calculated using the following formula:

[0104]

[0105]

[0106] in, This is the corrected crude oil density. The original density of the oil phase. The density of crude oil after complete miscibility. To achieve the saturation of the injected gas, S o S represents the saturation level of crude oil. or Residual oil saturation, Indicates the density of the gas phase; The viscosity of crude oil in the revised black oil numerical simulator is calculated using the following formula:

[0107]

[0108] in, This indicates the corrected crude oil viscosity. The viscosity of crude oil in a completely miscible state. The viscosity is the viscosity of crude oil in its immiscible state. The viscosity of the injected gas; The relative permeability in the modified black oil numerical simulator is calculated using the following formula:

[0109] Where, k rp This represents the relative permeability of the p-phase. This represents the relative permeability of the p-phase under miscible conditions. ω represents the relative permeability of the p-phase under immiscible conditions. omax This represents the maximum value of the mixing factor.

[0110] Optionally, the first obtaining module 701 includes: The submodule is used to obtain experimental data on the relationship between oil recovery rate and gas injection volume under different pressure conditions through gas-driven oil capillary experiments. The device 700 further includes: The first module is used to establish a one-dimensional displacement numerical simulation grid model based on the capillary parameters used in the gas-driven oil capillary experiment. The capillary parameters include at least the capillary inner diameter, capillary length, porosity, and permeability. The one-dimensional displacement numerical simulation grid model is established using a rectangular coordinate system or a radial coordinate system. The cross-sectional area of ​​the grid in the flow direction is consistent with the cross-sectional area of ​​the capillary, and the length of a single grid in the flow direction is not less than a preset length.

[0111] Optionally, the device 700 further includes: The second module is used to establish a three-dimensional displacement numerical simulation grid model based on the geological and development characteristics of the actual block. The geological characteristics include at least formation dip angle, thickness, porosity, permeability, and permeability variation coefficient. The development characteristics include at least remaining oil saturation, reservoir pressure, well pattern, and well spacing.

[0112] Optionally, the method is used to determine the oil enhancement potential of a reservoir through gas drive, wherein the reservoir includes at least: conventional sandstone / clastic / carbonate reservoirs and tight oil / shale reservoirs; the gas drive medium includes at least one or more mixed gases selected from nitrogen, deoxygenated air, hydrocarbon gas, and carbon dioxide.

[0113] Optionally, the device 700 further includes: The sixth module is used to obtain the third relationship data between oil recovery rate and gas injection volume under different pressure conditions through water drive simulation experiments; The second determining module is used to determine the gas-driven oil enhancement potential of the reservoir based on the second relationship data and the third relationship data.

[0114] Optionally, the device 700 further includes: The seventh acquisition module is used to reacquire the values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions, and the first relationship data until the relative error between the first relationship data and the experimental relationship data is less than a preset threshold.

Claims

1. A method for determining the oil recovery potential of a reservoir via gas drive, characterized in that, include: Experimental data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions were obtained; By using the given values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions is obtained; Based on a one-dimensional displacement numerical simulation grid model, each of the first mixing factors is sequentially input into the modified black oil numerical simulator to obtain the first relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The modified black oil numerical simulator uses mixing factors to represent the influence of injected gas on crude oil properties and flow parameters. When the relative error between the first relational data and the experimental relational data is less than a preset threshold, the values ​​of each parameter to be fitted corresponding to the first mixing factor are determined as standard parameter values ​​to be fitted. The second mixing factor under different pressure conditions is obtained by using the standard parameters to be fitted. Based on the three-dimensional displacement numerical simulation grid model, each of the second mixing factors is input into the modified black oil numerical simulator to obtain the second relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The mixing factor is calculated using the following formula: in, , where is the mixing factor, a, b, c, and d are different parameters to be fitted, MMP is the minimum miscibility pressure of oil and gas determined by the capillary experiment, P is the system pressure, and e is the natural index. The modified black oil numerical simulator is obtained by modifying the three-component black oil model of oil-gas-water using a pseudo-miscible method. During the modification process, it is assumed that the injected gas and oil are miscible but insoluble in the aqueous phase. The density of the crude oil in the modified black oil numerical simulator is calculated using the following formula: in, This is the corrected crude oil density. The original density of the oil phase. The density of crude oil after complete miscibility. To achieve the saturation of the injected gas, S o S represents the saturation level of crude oil. or Residual oil saturation, Indicates the density of the gas phase; The viscosity of crude oil in the revised black oil numerical simulator is calculated using the following formula: in, This indicates the corrected crude oil viscosity. The viscosity of crude oil in a completely miscible state. The viscosity is the viscosity of crude oil in its immiscible state. The viscosity of the injected gas; The relative permeability in the modified black oil numerical simulator is calculated using the following formula: Where, k rp This represents the relative permeability of the p-phase. This represents the relative permeability of the p-phase under miscible conditions. ω represents the relative permeability of the p-phase under immiscible conditions. omax This represents the maximum value of the mixing factor.

2. The method according to claim 1, characterized in that, Experimental data on the relationship between oil recovery rate and gas injection rate under different pressure conditions were obtained, including: Through gas-driven oil capillary experiments, experimental data on the relationship between oil recovery rate and gas injection volume in sand-filled capillary under different pressure conditions were obtained. Before sequentially inputting each of the first mixing factors into the corrected black oil numerical simulator, the method further includes: A one-dimensional displacement numerical simulation grid model is established based on the capillary parameters used in the gas-driven oil capillary experiment. The capillary parameters include at least the capillary inner diameter, capillary length, porosity, and permeability. The one-dimensional displacement numerical simulation grid model is established using a rectangular coordinate system or a radial coordinate system. The cross-sectional area of ​​the grid in the flow direction is consistent with the cross-sectional area of ​​the thin tube, and the length of a single grid in the flow direction is not less than a preset length.

3. The method according to claim 1, characterized in that, Before inputting each of the second mixing factors into the corrected black oil numerical simulator, the method further includes: Based on the geological and development characteristics of the actual block, a three-dimensional displacement numerical simulation grid model is established. The geological characteristics include at least formation dip angle, thickness, porosity, permeability, and permeability variation coefficient. The development characteristics include at least remaining oil saturation, reservoir pressure, well pattern, and well spacing.

4. The method for determining the oil reservoir gas drive potential as described in claim 1, characterized in that, The method is used to determine the oil enhancement potential of reservoirs through gas drive, wherein the reservoirs include at least: conventional sandstone / clastic / carbonate reservoirs and tight oil / shale reservoirs; the gas drive medium includes at least one or more mixed gases selected from nitrogen, deoxygenated air, hydrocarbon gas, and carbon dioxide.

5. The method for determining the oil reservoir gas drive potential as described in claim 4, characterized in that, The method further includes: Through water drive simulation experiments, third-party relationship data between crude oil recovery rate and gas injection volume under different pressure conditions were obtained; The gas-driven oil production potential of the reservoir is determined based on the second relationship data and the third relationship data.

6. The method for determining the oil reservoir gas drive potential as described in claim 1, characterized in that, When the relative error between the first relational data and the experimental relational data is not less than a preset threshold, the method further includes: The values ​​of each parameter to be fitted, the first mixing factor under different pressure conditions, and the first relationship data are obtained again until the relative error between the first relationship data and the experimental relationship data is less than a preset threshold.

7. A device for determining the oil reservoir gas drive potential, characterized in that, include: The first acquisition module is used to obtain experimental data on the relationship between crude oil recovery rate and gas injection volume under different pressure conditions; The second acquisition module is used to obtain the first mixing factor under different pressure conditions by using the given values ​​of each parameter to be fitted; The third acquisition module is used to sequentially input each of the first mixing factors into the modified black oil numerical simulator based on the one-dimensional displacement numerical simulation grid model, and obtain the first relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The modified black oil numerical simulator uses mixing factors to represent the influence of injected gas on crude oil properties and flow parameters. The first determining module is used to determine the values ​​of each parameter to be fitted corresponding to the first mixing factor as standard parameter values ​​when the relative error between the first relation data and the experimental relation data is less than a preset threshold. The fourth module is used to obtain a second mixing factor under different pressure conditions using the standard parameters to be fitted. The fifth module is used to input each of the second mixing factors into the modified black oil numerical simulator based on the three-dimensional displacement numerical simulation grid model to obtain the second relationship data between crude oil recovery rate and gas injection volume under different pressure conditions. The mixing factor is calculated using the following formula: in, , where is the mixing factor, a, b, c, and d are different parameters to be fitted, MMP is the minimum miscibility pressure of oil and gas determined by the capillary experiment, P is the system pressure, and e is the natural index. The modified black oil numerical simulator is obtained by modifying the three-component black oil model of oil-gas-water using a pseudo-miscible method. During the modification process, it is assumed that the injected gas and oil are miscible but insoluble in the aqueous phase. The density of the crude oil in the modified black oil numerical simulator is calculated using the following formula: in, This is the corrected crude oil density. The original density of the oil phase. The density of crude oil after complete miscibility. To achieve the saturation of the injected gas, S o S represents the saturation level of crude oil. or Residual oil saturation, Indicates the density of the gas phase; The viscosity of crude oil in the revised black oil numerical simulator is calculated using the following formula: in, This indicates the corrected crude oil viscosity. The viscosity of crude oil in a completely miscible state. The viscosity is the viscosity of crude oil in its immiscible state. The viscosity of the injected gas; The relative permeability in the modified black oil numerical simulator is calculated using the following formula: Where, k rp This represents the relative permeability of the p-phase. This represents the relative permeability of the p-phase under miscible conditions. ω represents the relative permeability of the p-phase under immiscible conditions. omax This represents the maximum value of the mixing factor.

8. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes, it implements the steps in the method for determining the oil reservoir gas drive potential as described in any one of claims 1-6.

9. A computer-readable storage medium having a computer program stored thereon, characterized in that, When executed by the processor, the program implements the steps in the method for determining the oil reservoir gas drive potential as described in any one of claims 1-6.

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