Method and device for determining oil reservoir fluid interaction state and storage medium

Abstract

The embodiment of the invention provides a method and device for determining the interaction state of oil reservoir fluid and a storage medium, and belongs to the field of oil reservoir exploration and development. The method for determining the oil reservoir fluid interaction state comprises the steps that the current water saturation and the current CO2 displacement pressure of a target oil reservoir are obtained; and determining the current fluid interaction state of the target oil reservoir according to the current water saturation and the current CO2 displacement pressure on the basis of a predetermined target corresponding relationship among the water saturation, the CO2 displacement pressure and the fluid interaction state. The accuracy of the oil reservoir fluid interaction state division result can be improved.

Description

Technical Field

[0001] The present invention relates to the field of oil reservoir exploration and development, and in particular to a method, a device and a storage medium for determining the interaction state of oil reservoir fluids. Background Art

[0002] CO2 is a highly efficient displacement medium with excellent displacement properties, enabling both enhanced oil recovery and carbon sequestration. Extensive research has been conducted domestically and internationally on CO2-EOR technology, categorizing the fluid interaction states between CO2 and crude oil in reservoirs into immiscible, near-miscible, miscible, and fully miscible states. To determine the fluid interaction state within a reservoir, technicians typically use capillary tube experiments. However, these methods differ significantly from the actual reservoir environment and fluids, resulting in significant errors. Summary of the Invention

[0003] The purpose of the embodiments of the present application is to provide a method, device and storage medium for determining the interaction state of fluids in an oil reservoir, so as to solve the problem in the prior art that the interaction state of fluids cannot be judged at different water saturations.

[0004] To achieve the above objectives, a first embodiment of the present application provides a method for determining the interaction state of reservoir fluids, the method comprising: Obtain the current water saturation and current CO2 displacement pressure of the target reservoir; Based on the predetermined target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state, the current fluid interaction state of the target reservoir is determined according to the current water saturation and the current CO2 displacement pressure.

[0005] In an embodiment of the present application, determining the target correspondence includes: based on a pre-constructed CO2-crude oil-water three-phase reservoir numerical simulation model, obtaining multiple simulated interfacial tensions and multiple simulated oil recovery efficiencies according to multiple first preset CO2 displacement pressures and multiple preset water saturations; obtaining an oil recovery efficiency-CO2 displacement pressure relationship curve and an interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation according to multiple preset water saturations, multiple preset CO2 displacement pressures, multiple simulated interfacial tensions, and multiple simulated oil recovery efficiencies; determining multiple target fluid interaction state boundary CO2 displacement pressures corresponding to each preset water saturation according to the oil recovery efficiency-CO2 displacement pressure relationship curve and the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, wherein the target fluid interaction state boundary CO2 displacement pressure is used to divide the fluid interaction state; according to the multiple target fluid interaction state boundary CO2 displacement pressures corresponding to each preset water saturation, obtaining the correspondence between the CO2 displacement pressure and the fluid interaction state corresponding to each preset water saturation to obtain the target correspondence.

[0006] In an embodiment of the present application, multiple target fluid interaction state limit CO2 displacement pressures include a first target fluid interaction state limit CO2 displacement pressure, a second target fluid interaction state limit CO2 displacement pressure, and a third target fluid interaction state limit CO2 displacement pressure; based on the oil recovery efficiency-CO2 displacement pressure relationship curve and the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, the multiple target fluid interaction state limit CO2 displacement pressures corresponding to each preset water saturation are determined, including: obtaining the immiscible maximum oil recovery efficiency corresponding to each preset water saturation; based on the oil recovery efficiency-CO2 displacement pressure relationship curve corresponding to each preset water saturation, determining the CO2 displacement pressures corresponding to the immiscible maximum oil recovery efficiency and the preset oil recovery efficiency, respectively, to obtain the first target fluid interaction state limit CO2 displacement pressure and the second target fluid interaction state limit CO2 displacement pressure; based on the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, determining the CO2 displacement pressure corresponding to the preset interfacial tension to obtain the third target fluid interaction state limit CO2 displacement pressure.

[0007] In an embodiment of the present application, obtaining the immiscible maximum oil recovery efficiency corresponding to each preset water saturation includes: obtaining the residual oil saturation and the original oil saturation corresponding to each preset water saturation; obtaining the saturation difference corresponding to each preset water saturation, wherein the saturation difference is the difference between the original oil saturation and the residual oil saturation; and determining the immiscible maximum oil recovery efficiency corresponding to each preset water saturation based on the saturation difference corresponding to each preset water saturation, wherein the immiscible maximum oil recovery efficiency is the ratio of the saturation difference to the original oil saturation.

[0008] In an embodiment of the present application, the residual oil saturation and the original oil saturation corresponding to each preset water saturation are obtained, including: based on a phase permeability experiment, obtaining a first oil-gas phase permeability curve corresponding to each preset water saturation, wherein the first oil-gas phase permeability curve includes a gas saturation-oil phase relative permeability curve and a gas saturation-gas phase relative permeability curve; according to the gas saturation-oil phase relative permeability curve and the gas saturation-gas phase relative permeability curve, determining the residual oil saturation and the original oil saturation, wherein the residual oil saturation is the deviation between the gas saturation when the oil phase relative permeability is zero and 1 on the gas saturation-oil phase relative permeability curve, and the original oil saturation is the deviation between the gas saturation when the gas phase relative permeability is zero and 1 on the gas saturation-gas phase relative permeability curve.

[0009] In an embodiment of the present application, the construction of a CO2-crude oil-water three-phase reservoir numerical simulation model includes: obtaining target reservoir characteristics of an explored reservoir and a second oil-gas phase permeability curve corresponding to the explored reservoir, wherein the target reservoir characteristics include average porosity and average permeability, wherein the second oil-gas phase permeability curve is an oil-gas phase permeability curve when the water saturation is zero; based on the initial CO2-crude oil-water three-phase reservoir numerical simulation model, according to the target reservoir characteristics, the pre-constructed CO2-crude oil two-phase fluid model, the second oil-gas phase permeability curve, the CO2 injection amount, the preset water saturation and a preset CO2 displacement pressure to obtain a target oil and gas composition; based on a preset interfacial tension algorithm, a target interfacial tension is obtained according to the target oil and gas composition; based on a pre-stored correspondence between the interfacial tension and the oil-gas relative permeability curve, a second oil-gas relative permeability curve is updated according to the target interfacial tension to obtain an updated second oil-gas relative permeability curve corresponding to the explored oil reservoir; the CO2 injection rate is increased, and the initial CO2-crude oil-water three-phase reservoir numerical simulation model is updated according to the updated second oil-gas relative permeability curve until the CO2 injection rate reaches a preset CO2 injection rate threshold.

[0010] In an embodiment of the present application, construction of a CO2-crude oil two-phase fluid model includes: obtaining a CO2-crude oil one-dimensional numerical capillary tube experimental model based on a preset oil-gas phase permeability curve and an initial CO2-crude oil two-phase fluid model; determining, based on the CO2-crude oil one-dimensional numerical capillary tube experimental model, a plurality of numerical experimental models with a plurality of second preset CO2 displacement pressures, a maximum oil recovery efficiency; determining a second preset CO2 displacement pressure corresponding to a maximum of the maximum oil recovery efficiencies of the plurality of numerical experimental models as a critical CO2 displacement pressure; determining a deviation between the critical CO2 displacement pressure and the preset critical CO2 displacement pressure to obtain a critical CO2 displacement pressure error value; and updating the initial CO2-crude oil two-phase fluid model until the critical CO2 displacement pressure error value is less than a preset pressure error threshold value to obtain the CO2-crude oil two-phase fluid model.

[0011] A second aspect of an embodiment of the present application provides a device for determining the interaction state of reservoir fluids, comprising: a memory configured to store instructions; and a processor configured to call instructions from the memory and to implement the above-mentioned method for determining the interaction state of reservoir fluids when executing the instructions.

[0012] A third aspect of an embodiment of the present application provides a machine-readable storage medium having stored thereon instructions for causing a machine to execute the above-mentioned method for determining the interaction state of reservoir fluids.

[0013] A fourth aspect of the present invention provides a computer program product comprising a computer program that, when executed by a processor, implements the aforementioned method for determining the interaction state of reservoir fluids. Other features and advantages of the present invention will be described in detail in the subsequent detailed description.

[0014] The above technical solution predetermines the target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state. The current water saturation and CO2 displacement pressure of the target reservoir are then obtained. Based on the current water saturation and CO2 displacement pressure, and the determined target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state, the current fluid interaction state of the target reservoir is determined. This achieves the technical effect of improving the accuracy of the reservoir fluid interaction state classification results. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] The accompanying drawings are used to provide a further understanding of the embodiments of the present invention and constitute a part of the specification. Together with the following detailed description, they are used to explain the embodiments of the present invention, but do not constitute a limitation of the embodiments of the present invention. In the accompanying drawings: Figure 1A flow chart of a method for determining the interaction state of reservoir fluids according to an embodiment of the present application is schematically shown. DETAILED DESCRIPTION

[0016] To make the purpose, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be clearly and completely described below in conjunction with the drawings in the embodiments of the present application. It should be understood that the specific implementation methods described herein are only used to illustrate and explain the embodiments of the present application and are not used to limit the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of this application.

[0017] It should be noted that the acquisition, transmission, storage, use, and processing of data in the technical solution of this application are in compliance with the relevant provisions of national laws and regulations. In the embodiments of this application, certain software, components, models, and other existing solutions in the industry may be mentioned. These should be considered as exemplary. Their purpose is only to illustrate the feasibility of implementing the technical solution of this application, but it does not mean that the applicant has or will necessarily use such solutions.

[0018] It should be noted that if the embodiments of the present application involve directional indications (such as up, down, left, right, front, back, etc.), such directional indications are only used to explain the relative position relationship, movement status, etc. between the various components under a certain specific posture (as shown in the accompanying drawings). If the specific posture changes, the directional indication will also change accordingly.

[0019] In addition, if there are descriptions involving "first", "second", etc. in the embodiments of the present application, the descriptions of "first", "second", etc. are only for descriptive purposes and cannot be understood as indicating or implying their relative importance or implicitly indicating the number of the indicated technical features. Therefore, the features defined as "first" and "second" may explicitly or implicitly include at least one of such features. In addition, the technical solutions between the various embodiments can be combined with each other, but they must be based on the fact that they can be implemented by ordinary technicians in this field. When the combination of technical solutions is contradictory or cannot be implemented, it should be deemed that such a combination of technical solutions does not exist and is not within the scope of protection required by this application.

[0020] It should be noted that the acquisition, transmission, storage, use, and processing of data in the technical solution of this application are in compliance with the relevant provisions of laws and regulations. In the embodiments of this application, certain software, components, models, and other existing solutions in the industry may be mentioned. These should be considered as exemplary. Their purpose is only to illustrate the feasibility of implementing the technical solution of this application, but it does not mean that the applicant has or will necessarily use such solutions.

[0021] Figure 1 The following schematically shows a flow chart for determining the interaction state of reservoir fluids in one embodiment of the present application. Figure 1 As shown, an embodiment of the present application provides a method for determining the interaction state of reservoir fluids. Taking the method applied to a processor as an example, the method may include the following steps: Step S101: Obtain the current water saturation and current CO2 displacement pressure of the target reservoir.

[0022] Step S102 : Based on the predetermined target correspondence between water saturation, CO 2 displacement pressure, and fluid interaction state, the current fluid interaction state of the target reservoir is determined according to the current water saturation and the current CO 2 displacement pressure.

[0023] It can be understood that the target reservoir refers to the reservoir whose fluid interaction state is to be determined. The current water saturation refers to the current water saturation of the target reservoir. The current CO2 displacement pressure refers to the displacement pressure of the target reservoir with the currently used CO2. The target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state refers to the correspondence between water saturation, CO2 displacement pressure, and fluid interaction state. At different water saturations and CO2 displacement pressures, there will be a corresponding fluid interaction state. The current fluid interaction state refers to the current fluid interaction state, which includes four fluid interaction states: immiscible, nearly miscible, miscible, and completely miscible.

[0024] Specifically, in the present application, when the target correspondence between water saturation, CO2 displacement pressure and fluid interaction state is known, the corresponding fluid interaction state can be obtained according to the current water saturation and the current CO2 displacement pressure. Among them, the current water saturation is obtained through on-site exploration. The current CO2 displacement pressure can be obtained through detection and is artificially set. The present application can obtain in advance the target correspondence between water saturation, CO2 displacement pressure and fluid interaction state when the water saturation is 0%, 15%, 30% and 60%. When it is necessary to determine the fluid interaction state of a specific water saturation, the target correspondence corresponding to the water saturation of 0%, 15%, 30% and 60% is selected. For example, if it is necessary to determine the fluid interaction state of an oil reservoir with a water saturation of 42%, the target correspondence with a water saturation of 30% can be selected to judge the fluid interaction state.

[0025] The above technical solution predetermines the target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state. The current water saturation and CO2 displacement pressure of the target reservoir are then obtained. Based on the current water saturation and CO2 displacement pressure, and the determined target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state, the current fluid interaction state of the target reservoir is determined. This achieves the technical effect of improving the accuracy of the reservoir fluid interaction state classification results.

[0026] In one embodiment, determining the target correspondence includes: based on a pre-constructed CO2-crude oil-water three-phase reservoir numerical simulation model, obtaining multiple simulated interfacial tensions and multiple simulated oil recovery efficiencies according to multiple first preset CO2 displacement pressures and multiple preset water saturations; obtaining an oil recovery efficiency-CO2 displacement pressure relationship curve and an interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation according to the multiple preset water saturations, the multiple preset CO2 displacement pressures, the multiple simulated interfacial tensions, and the multiple simulated oil recovery efficiencies; determining multiple target fluid interaction state boundary CO2 displacement pressures corresponding to each preset water saturation according to the oil recovery efficiency-CO2 displacement pressure relationship curve and the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, wherein the target fluid interaction state boundary CO2 displacement pressure is used to divide the fluid interaction state; obtaining a correspondence between the CO2 displacement pressure and the fluid interaction state corresponding to each preset water saturation according to the multiple target fluid interaction state boundary CO2 displacement pressures corresponding to each preset water saturation, so as to obtain the target correspondence.

[0027] It is understood that the CO2-crude oil-water three-phase reservoir numerical simulation model is a pre-built model. The first preset CO2 displacement pressure is a preset CO2 displacement pressure applied to the CO2-crude oil-water three-phase reservoir numerical simulation model. The preset water saturation is a preset water saturation. The simulated interfacial tension is the interfacial tension simulated by the CO2-crude oil-water three-phase reservoir numerical simulation model under a certain first preset CO2 displacement pressure and a preset water saturation. The simulated oil recovery efficiency is the oil recovery efficiency simulated by the CO2-crude oil-water three-phase reservoir numerical simulation model under a certain first preset CO2 displacement pressure and a preset water saturation. The oil recovery efficiency-CO2 displacement pressure relationship curve is a curve showing the relationship between the first preset CO2 displacement pressure and the simulated oil recovery efficiency. The interfacial tension-CO2 displacement pressure relationship curve is a curve showing the relationship between the first preset CO2 displacement pressure and the simulated interfacial tension. The target fluid interaction state boundary CO2 displacement pressure is the critical displacement pressure value between the four fluid interaction states and is used to classify the fluid interaction states. The target correspondence is the correspondence between water saturation, CO2 displacement pressure and fluid interaction state. There will be a corresponding fluid interaction state under different water saturations and CO2 displacement pressures.

[0028] Specifically, the present application inputs multiple first preset CO2 displacement pressures and multiple preset water saturations into a pre-built CO2-crude oil-water three-phase reservoir numerical simulation model to output multiple simulated interfacial tensions and multiple simulated oil recovery efficiencies. Under each preset water saturation, different first preset CO2 displacement pressures will correspond to a simulated interfacial tension and a simulated oil recovery efficiency, and multiple simulated interfacial tensions and multiple simulated oil recovery efficiencies will be output accordingly based on the multiple first preset CO2 displacement pressures. Each preset water saturation will correspond to an oil recovery efficiency-CO2 displacement pressure relationship curve and an interfacial tension-CO2 displacement pressure relationship curve. Different preset water saturations will correspond to different oil recovery efficiency-CO2 displacement pressure relationship curves and different interfacial tension-CO2 displacement pressure relationship curves. Based on the obtained oil recovery efficiency-CO2 displacement pressure relationship curve and interfacial tension-CO2 displacement pressure relationship curve, the three target fluid interaction state limit CO2 displacement pressures corresponding to each preset water saturation can be determined. The three target fluid interaction state limit CO2 displacement pressures can be used to divide the displacement pressure into four sections, corresponding to four different fluid interaction states. This can achieve the effect of dividing the fluid interaction state according to the preset water saturation and the target fluid interaction state limit CO2 displacement pressure, thereby obtaining the target correspondence between water saturation, CO2 displacement pressure and fluid interaction state.

[0029] In one embodiment, the multiple target fluid interaction state limit CO2 displacement pressures include a first target fluid interaction state limit CO2 displacement pressure, a second target fluid interaction state limit CO2 displacement pressure, and a third target fluid interaction state limit CO2 displacement pressure; according to the oil recovery efficiency-CO2 displacement pressure relationship curve and the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, the multiple target fluid interaction state limit CO2 displacement pressures corresponding to each preset water saturation are determined, including: obtaining the immiscible maximum oil recovery efficiency corresponding to each preset water saturation; based on the oil recovery efficiency-CO2 displacement pressure relationship curve corresponding to each preset water saturation, determining the CO2 displacement pressures corresponding to the immiscible maximum oil recovery efficiency and the preset oil recovery efficiency, respectively, to obtain the first target fluid interaction state limit CO2 displacement pressure and the second target fluid interaction state limit CO2 displacement pressure; based on the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, determining the CO2 displacement pressure corresponding to the preset interfacial tension, to obtain the third target fluid interaction state limit CO2 displacement pressure.

[0030] It can be understood that the first target fluid interaction state boundary CO2 displacement pressure is the boundary CO2 displacement pressure between the non-fluid interaction state and the near-fluid interaction state. The second target fluid interaction state boundary CO2 displacement pressure is the boundary CO2 displacement pressure between the near-fluid interaction state and the fluid interaction state. The third target fluid interaction state boundary CO2 displacement pressure is the boundary CO2 displacement pressure between the fluid interaction state and the complete fluid interaction state. The immiscible maximum oil recovery efficiency is the maximum oil recovery efficiency under the non-fluid interaction state. The preset oil recovery efficiency can be 90%, which is the preset oil recovery efficiency and is used to determine the CO2 displacement pressure corresponding to the preset oil recovery efficiency, which serves as the second target fluid interaction state boundary CO2 displacement pressure. The preset interfacial tension is 0, which is the preset interfacial tension and is used to determine the CO2 displacement pressure corresponding to the preset interfacial tension, which serves as the third target fluid interaction state boundary CO2 displacement pressure. The oil recovery efficiency-CO2 displacement pressure relationship curve represents the relationship between the first preset CO2 displacement pressure and the simulated oil recovery efficiency. The interfacial tension-CO2 displacement pressure relationship curve is a relationship curve between the first preset CO2 displacement pressure and the simulated interfacial tension.

[0031] Specifically, the processor of the present application first obtains the maximum immiscible oil recovery efficiency corresponding to each preset water saturation. On the oil recovery efficiency-CO2 displacement pressure relationship curve corresponding to each preset water saturation, the two CO2 displacement pressures corresponding to the maximum immiscible oil recovery efficiency and 90% oil recovery efficiency are found, respectively. These two CO2 displacement pressures are the first target fluid interaction state boundary CO2 displacement pressure and the second target fluid interaction state boundary CO2 displacement pressure. In other words, the boundary CO2 displacement pressures between the non-fluid interaction state and the near-fluid interaction state, as well as the boundary CO2 displacement pressures between the near-fluid interaction state and the fluid interaction state, are obtained. On the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation, the CO2 displacement pressure corresponding to the point where the interfacial tension is zero is determined to obtain the boundary CO2 displacement pressures between the fluid interaction state and the complete fluid interaction state. Therefore, the present application can classify the fluid interaction state into immiscible, near-miscible, miscible, and complete miscible based on multiple target fluid interaction state boundary CO2 displacement pressures, while taking into account the influence of water saturation.

[0032] In one embodiment, obtaining the immiscible maximum oil recovery efficiency corresponding to each preset water saturation includes: obtaining the residual oil saturation and the original oil saturation corresponding to each preset water saturation; obtaining the saturation difference corresponding to each preset water saturation, wherein the saturation difference is the difference between the original oil saturation and the residual oil saturation; and determining the immiscible maximum oil recovery efficiency corresponding to each preset water saturation based on the saturation difference corresponding to each preset water saturation, wherein the immiscible maximum oil recovery efficiency is the ratio of the saturation difference to the original oil saturation.

[0033] It is understood that the preset water saturation is a pre-set water saturation. The residual oil saturation is the residual oil saturation in the model. The original oil saturation is the original oil saturation in the model. The saturation difference is the difference between the original oil saturation and the residual oil saturation. The immiscible maximum oil recovery efficiency refers to the maximum oil recovery efficiency under non-fluid interaction conditions.

[0034] Specifically, the residual oil saturation and original oil saturation corresponding to each preset water saturation are obtained; the ratio of the saturation difference corresponding to each preset water saturation to the original oil saturation is calculated to obtain the maximum immiscible oil recovery efficiency. This application can achieve the effect of classifying fluid interaction states by determining the maximum immiscible oil recovery efficiency.

[0035] In one embodiment, obtaining the residual oil saturation and the original oil saturation corresponding to each preset water saturation includes: obtaining a first oil-gas phase permeability curve corresponding to each preset water saturation based on a phase permeability experiment, wherein the first oil-gas phase permeability curve includes a gas saturation-oil phase relative permeability curve and a gas saturation-gas phase relative permeability curve; determining the residual oil saturation and the original oil saturation according to the gas saturation-oil phase relative permeability curve and the gas saturation-gas phase relative permeability curve, wherein the residual oil saturation is the deviation between the gas saturation when the oil phase relative permeability is zero and 1 on the gas saturation-oil phase relative permeability curve, and the original oil saturation is the deviation between the gas saturation when the gas phase relative permeability is zero and 1 on the gas saturation-gas phase relative permeability curve.

[0036] It can be understood that the first oil-gas relative permeability curve is an oil phase relative permeability curve and a gas phase relative permeability curve when the water saturation is not 0. The first oil-gas relative permeability curve includes a gas saturation-oil phase relative permeability curve and a gas saturation-gas phase relative permeability curve.

[0037] Specifically, the first oil-gas relative permeability curve yields the gas saturation at zero oil phase relative permeability and the gas saturation at zero gas phase relative permeability. The deviations of these two gas saturations from 1 represent the residual oil saturation and initial oil saturation, thereby deriving the maximum immiscible displacement efficiency, which facilitates subsequent classification of fluid interaction states.

[0038] In one embodiment, the construction of a CO2-crude oil-water three-phase reservoir numerical simulation model includes: obtaining target reservoir characteristics of an explored reservoir and a second oil-gas phase permeability curve corresponding to the explored reservoir, wherein the target reservoir characteristics include average porosity and average permeability, and the second oil-gas phase permeability curve is an oil-gas phase permeability curve when the water saturation is zero; based on the initial CO2-crude oil-water three-phase reservoir numerical simulation model, according to the target reservoir characteristics, the pre-constructed CO2-crude oil two-phase fluid model, the second oil-gas phase permeability curve, the CO2 injection amount, and the preset water saturation and a preset CO2 displacement pressure to obtain a target oil and gas composition; based on a preset interfacial tension algorithm, a target interfacial tension is obtained according to the target oil and gas composition; based on a pre-stored correspondence between the interfacial tension and the oil-gas relative permeability curve, a second oil-gas relative permeability curve is updated according to the target interfacial tension to obtain an updated second oil-gas relative permeability curve corresponding to the explored oil reservoir; the CO2 injection rate is increased, and the initial CO2-crude oil-water three-phase reservoir numerical simulation model is updated according to the updated second oil-gas relative permeability curve until the CO2 injection rate reaches a preset CO2 injection rate threshold.

[0039] It is understood that the target reservoir characteristics include average porosity and average permeability. The second oil-gas relative permeability curve is the oil-gas relative permeability curve when the water saturation is zero. The second oil-gas relative permeability curve includes a gas saturation-oil phase relative permeability curve and a gas saturation-gas phase relative permeability curve. The target oil and gas composition is the oil and gas composition output from the initial CO2-crude oil-water three-phase reservoir numerical simulation model. The target interfacial tension is the interfacial tension calculated based on the target oil and gas composition. The preset CO2 injection volume threshold can be 1.2 PV.

[0040] Specifically, the CO2-crude oil-water three-phase reservoir numerical simulation model of the present application is a model that is continuously updated until the CO2 injection rate reaches a preset CO2 injection rate threshold. A target interfacial tension is determined based on the target oil and gas composition. Based on the pre-stored correspondence between interfacial tension and oil-gas permeability curves, a second oil-gas permeability curve is updated according to the target interfacial tension to obtain an updated second oil-gas permeability curve corresponding to the explored reservoir. The initial CO2-crude oil-water three-phase reservoir numerical simulation model is then updated based on the updated second oil-gas permeability curve. The pre-stored correspondence between interfacial tension and oil-gas permeability curves is based on the correspondence between interfacial tension and fluid interaction state at zero water saturation. The present application obtains the corresponding fluid interaction state from the target interfacial tension. Based on the correspondence between the fluid interaction state and the oil-gas permeability curves, the corresponding oil-gas permeability curve is selected based on the fluid interaction state and the second oil-gas permeability curve is updated. By continuously updating the CO2-crude oil-water three-phase reservoir numerical simulation model by updating the oil-gas permeability curves while CO2 is continuously injected, the model accuracy can be improved.

[0041] In one embodiment, constructing a CO2-crude oil two-phase fluid model includes: obtaining a CO2-crude oil one-dimensional numerical capillary tube experimental model based on a preset oil-gas permeability curve and an initial CO2-crude oil two-phase fluid model; determining, based on the CO2-crude oil one-dimensional numerical capillary tube experimental model, a plurality of numerical experimental models with a plurality of second preset CO2 displacement pressures, a maximum oil recovery efficiency; determining a second preset CO2 displacement pressure corresponding to a maximum of the maximum oil recovery efficiencies of the plurality of numerical experimental models as a critical CO2 displacement pressure; determining a deviation between the critical CO2 displacement pressure and the preset critical CO2 displacement pressure to obtain a critical CO2 displacement pressure error value; and updating the initial CO2-crude oil two-phase fluid model until the critical CO2 displacement pressure error value is less than a preset pressure error threshold value to obtain the CO2-crude oil two-phase fluid model.

[0042] It is understood that the preset oil-gas relative permeability curve refers to the preset oil phase relative permeability curve and gas phase relative permeability curve under the condition of zero water saturation. The initial CO2-crude oil two-phase fluid model is the initially constructed CO2-crude oil two-phase fluid model. The second preset CO2 displacement pressure is a preset CO2 displacement pressure used to determine the critical CO2 displacement pressure. The preset critical CO2 displacement pressure is a preset critical CO2 displacement pressure, which can be obtained based on capillary tube experiments. The preset pressure error threshold is a preset pressure error threshold.

[0043] Specifically, the CO2-crude oil two-phase fluid model is used to construct a CO2-crude oil-water three-phase reservoir numerical simulation model. The processor of this application obtains a CO2-crude oil one-dimensional numerical capillary experimental model based on a preset oil-gas permeability curve and an initial CO2-crude oil two-phase fluid model. The processor determines the critical CO2 displacement pressure through the CO2-crude oil one-dimensional numerical capillary experimental model, and determines the deviation between the critical CO2 displacement pressure and the preset critical CO2 displacement pressure to obtain a critical CO2 displacement pressure error value. When the critical CO2 displacement pressure error value is greater than the preset pressure error threshold, the initial CO2-crude oil two-phase fluid model is updated to obtain a CO2-crude oil two-phase fluid model. It can be seen that the processor uses the critical CO2 displacement pressure obtained from the CO2-crude oil one-dimensional numerical capillary experimental model constructed based on the CO2-crude oil two-phase fluid model to verify whether the CO2-crude oil two-phase fluid model used is correct. The correctness of the CO2-crude oil two-phase fluid model can be verified through the above steps.

[0044] The specific steps can be as follows: Step 1: Determine the minimum miscibility pressure of CO2-crude oil through CO2-crude oil capillary experiments and establish a CO2-crude oil two-phase fluid model.

[0045] The capillary tube experiment is one of the currently recognized methods for determining the minimum miscibility pressure of CO2-crude oil. Through the CO2-crude oil capillary tube experiment, the minimum miscibility pressure under two-phase conditions is determined. Combined with the experimental results of chromatography, PVT, etc., a CO2-crude oil two-phase fluid model is established using numerical simulation methods. The steps include: Step 1-1: Sampling the formation fluid of the target reservoir to obtain representative crude oil and formation water samples of the target reservoir; Sampling is conducted at the target reservoir site to obtain representative oil, water, and gas samples from the target reservoir. Sample quality is then checked to ensure representativeness. During sampling, the sampling pressure must be higher than the crude oil saturation pressure to prevent crude oil degassing, which could lead to deviations in component test results.

[0046] Step 1-2: Determine the composition of crude oil through gas chromatography experiments; Using typical oil and gas samples, we conducted gas chromatography experiments using an Agilent 7890A experimental device to determine the composition of the oil and gas samples. We collated the experimental data and checked whether the mole fractions of each component summed to 100%. Based on the experimental results, we formulated the experimental oil and tested its gas-to-oil ratio.

[0047] Steps 1-3: Through conventional crude oil PVT experiments and CO2-injection crude oil PVT experiments, clarify the phase characteristics of crude oil under different CO2 concentrations; Conventional PVT tests and CO2-injected crude oil PVT tests were conducted using compounded experimental oil. Conventional PVT tests included mass expansion, multiple degassing cycles, and density testing. CO2-injected crude oil PVT tests included crude oil volume expansion and viscosity testing. By compiling experimental data, it was determined whether the crude oil sample's saturation pressure, density, and viscosity, among other properties, were consistent with those of the target crude oil.

[0048] Step 1-4: Through CO2-crude oil slim tube experiments, obtain the relationship curve between oil displacement efficiency and displacement pressure and determine the minimum miscibility pressure of CO2-crude oil; A CO2-crude oil slim tube experiment was conducted, testing five pressure points above the formation saturation pressure. The oil recovery efficiency was calculated after injecting 1.2 PV of CO2. When the oil recovery exceeded 90%, the minimum miscibility pressure of CO2-crude oil was determined using linear regression. The slim tube experimental parameters were: 20 m length, 4.0 mm inner diameter, 1.0 mm thickness, 170-325 mesh filler, 36.36% porosity, and 3.986 D permeability.

[0049] Step 1-5: Split the crude oil components according to the principle of similar properties to obtain pseudo-components representing the properties of the target reservoir formation fluid, as shown in Table 1; To improve computational efficiency and ensure accuracy in numerical simulations, a component splitting method was used to group crude oil components with similar properties into a single category (particularly, components with a higher carbon number were grouped as Cn+). This crude oil component splitting yielded simple pseudo-components representing the properties of the target reservoir's formation fluid. The rationality of the pseudo-components was determined by comparing them with the crude oil phase diagram.

[0050] Steps 1-6: Based on the pseudo-component, PVT, and capillary tube experimental results, the characteristic parameters of the equation of state for each pseudo-component are obtained, and a CO2-crude oil fluid model is established, as shown in Table 2.

[0051] Through the above experiments, the CMG software WINPROP module was used to carry out phase fitting, and the characteristic parameters were continuously adjusted to ensure that the simulation results were consistent with the phase experimental results. The characteristic parameters of the state equation of each pseudo-component were obtained, and the CO2-crude oil fluid model was established. This model was used for subsequent simulation calculations.

[0052] Step 2: Through the CO2-crude oil numerical capillary experiment, the relationship curve between CO2 oil displacement efficiency, interfacial tension and displacement pressure under two-phase conditions is obtained to verify the CO2-crude oil fluid model.

[0053] Due to the unstable sand packing structure and physical property preferences in capillary tube experiments, the pore structure characteristics of low-permeability reservoirs cannot be accurately characterized. To avoid the experimental results errors caused by such factors, a numerical simulation method is used to determine the minimum miscibility pressure, obtain the relationship between CO2 oil displacement efficiency, interfacial tension and displacement pressure, and verify the correctness of the CO2-crude oil fluid model.

[0054] Step 2-1: Sampling the target reservoir core to obtain a representative core sample of the target reservoir; Sampling is carried out at the target reservoir site to obtain core samples from the target reservoir. The integrity and length of the samples are then checked to ensure they are representative. During sampling, it is important to prevent core breakage due to pressure changes.

[0055] Step 2-2: Obtain oil-water and oil-gas relative permeability curves through phase permeability experiments; Relative permeability testing experiments are carried out using representative core samples of the target reservoir to obtain oil-water and oil-gas relative permeability curves for use in numerical simulations and to improve the accuracy of simulation results.

[0056] Step 2-3: Based on the CO2-crude oil fluid model and phase permeability curve, a CO2-crude oil numerical capillary tube experimental model is established; Based on the CO2-crude oil fluid model and CO2-crude oil relative permeability curve, combined with the actual capillary geometry, a one-dimensional capillary flow numerical experimental model was established. Model parameters included a displacement length of 20 m, 200 grid cells with a step size of 10 cm, and a square cross-section with a side length of 4 mm. The average porosity was 12.5%, and the average permeability was 3000 mD. One injection well and one production well were located at each end of the model. The simulation ended when the injected CO2 volume reached 1.2 PV.

[0057] Step 2-4: Conduct numerical capillary experiments on CO2-crude oil at different pressures to obtain the relationship curves between oil displacement efficiency, interfacial tension, and displacement pressure. Calculate the error between the minimum miscible pressure simulation results and the experimental results to verify the correctness of the CO2-crude oil fluid model. Using a numerical capillary model, we conducted CO2-crude oil miscibility pressure tests at various pressures, referencing capillary experiments. We generated curves showing the relationship between oil displacement efficiency, interfacial tension, and displacement pressure. We then used linear regression to determine the simulated minimum miscibility pressure and the range of different fluid interaction states. We then compared the results with the capillary experiments and calculated the relative error. This also verified the accuracy of the CO2-crude oil fluid model.

[0058] Step 2-5: Based on the relationship curves between oil displacement efficiency, interfacial tension and displacement pressure, determine the maximum oil displacement efficiency, critical interfacial tension and pressure threshold corresponding to different fluid interaction states of CO2-crude oil two phases.

[0059] Based on the relationship curves between oil recovery efficiency, interfacial tension, and displacement pressure obtained by simulation, the range of different fluid interaction states under CO2-crude oil two-phase conditions, as well as the maximum oil recovery efficiency, critical interfacial tension, and pressure thresholds corresponding to different fluid interaction states, were determined. The simulation results default to a water saturation of 0, which can be compared with subsequent simulation results with water saturation conditions to facilitate analysis of the impact of different water saturations on the fluid interaction state.

[0060] Step 3: Through numerical reservoir simulation, obtain the relationship curve between CO2 oil displacement efficiency, interfacial tension and displacement pressure under three-phase conditions, and judge and characterize the influence of different water saturations on the interaction state of CO2-crude oil fluid.

[0061] Numerical slim tube experiments are based on a one-dimensional numerical slim tube model, and porosity and permeability are referenced to slim tube test results, without considering water saturation. Therefore, to accurately determine and characterize the impact of different water saturations on the CO2-crude oil fluid interaction, a three-dimensional reservoir numerical simulation was conducted.

[0062] Step 3-1: Based on the target reservoir characteristics, fluid model and phase permeability curve, a numerical simulation model of the CO2-crude oil-water three-phase reservoir is established; Based on the target reservoir properties (mainly including an average porosity of 12.5% ​​and an average permeability of 7.57 mD), combined with fluid models and phase permeability curves, a numerical simulation model of a CO2-crude oil-water three-phase reservoir suitable for CO2 flooding was established. Component numerical simulations were performed using the GEM module of CMG software. This model considered variations in water saturation, simulating low, medium, and high water saturation conditions with Sw = 15%, 30%, and 60%, respectively.

[0063] Step 3-2: By conducting numerical simulations of the reservoir under different water saturation conditions, the changes in fluid composition within each grid at each moment in the model are obtained. The equation of state is used to calculate the CO2-crude oil interaction (Equation 1-1) and determine the changes in oil-gas interfacial tension. (1-1) Where σ is the oil-gas interfacial tension; Nc is the oil phase component; [P]i is the unit conversion coefficient; bLm and bvm are the phase densities of the oil component and the gas component, respectively; x i and y i are the phase mole fractions of oil and gas components respectively; t is the different simulation moments.

[0064] In CO2 displacement simulations, the fluid composition within the grid becomes more complex due to the influence of water saturation, making it difficult to accurately determine the state of the CO2-crude oil fluid interaction. Therefore, to obtain the CO2-crude oil interfacial tension, an equation of state is applied to calculate the CO2-crude oil interaction and determine the oil-gas interfacial tension at different times. The calculation formula is shown in Equation 1-1.

[0065] Step 3-3: Based on the change of oil-gas interfacial tension, the phase permeability curve interpolation method is used to accurately capture the dynamic changes of fluid interaction state, and obtain the relationship curves of oil displacement efficiency, interfacial tension and pressure under different fluid interaction states at different water saturations; In this case, the fluid interaction state is primarily determined by considering the changes in oil displacement efficiency and interfacial tension with pressure. However, different fluid interaction states affect the CO2 displacement efficiency, which is most directly reflected in the changes in the phase permeability curve in numerical simulations. Therefore, a phase permeability curve interpolation method is used to simulate different fluid interaction states, and the phase permeability curve used for different fluid interaction states is determined by Formula 1-2. The oil-gas phase permeability curve at the initial moment is used; when the fluid interaction state is near, the phase permeability curve between the miscible and immiscible phases is used for simulation; when the fluid interaction state is miscible and complete, the phase permeability curve at the miscible moment is used for simulation. At this time, further judgment is required based on the interfacial tension. When the interfacial tension is zero, the fluid interaction state is complete, and the oil displacement efficiency is higher. When the interfacial tension is not zero, the fluid interaction state is present, and the oil displacement efficiency is slightly lower.

[0066] Step 3-4: Based on the simulation results, the oil displacement efficiency and interfacial tension of different CO2-crude oil interaction states at different water saturations are obtained, and the effect of different water saturations on the pressure threshold of different CO2-crude oil interaction states is clarified; Through numerical simulation, we obtained the relationship curves between oil recovery efficiency and interfacial tension change with pressure under different CO2-crude oil fluid interaction states at different water saturations. This can determine the impact of water saturation on CO2-crude oil miscibility, judge the change in the miscibility pressure threshold of CO2 and crude oil, and thus determine the fluid interaction state in the reservoir.

[0067] Step 3-5: By calculating the improvement effect of crude oil mobility (Equation 1-2), the influence of different water saturations on CO2 oil displacement under different fluid interaction states is obtained. This is used to characterize the CO2 oil displacement mechanism under different fluid interaction states and clarify the main controlling factors affecting the displacement efficiency.

[0068] (1-2) Among them, △f is the improvement effect of crude oil mobility; K is the reservoir permeability within the grid; μ is the reservoir crude oil viscosity.

[0069] One of the mechanisms of CO2 flooding is to reduce crude oil viscosity, thereby improving its flowability. However, the effect of CO2 on improving crude oil viscosity varies under different fluid interaction conditions. Therefore, the different CO2-crude oil interaction states play a crucial role in the effectiveness of CO2 flooding development, and CO2 flooding development effectiveness is measured by calculating the improvement in crude oil flowability. By calculating the change in crude oil mobility using Equation 1-2, we can characterize the degree to which multiple fluid interaction states improve crude oil flowability, determine the CO2 flooding mechanism at different stages, and further clarify the key factors affecting flooding efficiency.

[0070] Step 4: Based on the judgment and characterization methods of the CO2-crude oil fluid interaction state at different water saturations, as shown in Table 3, CO2 flooding engineering applications after water flooding in low permeability reservoirs are carried out.

[0071] The above method can be used to judge and characterize the fluid interaction state of CO2 flooding after water flooding in low permeability oil reservoirs, guide the optimal design of development plans, maximize crude oil recovery, reduce economic costs, and maximize benefits.

[0072] Table 1 Formation crude oil composition and pseudo-component classification

[0073] Table 2 PVT test results of formation crude oil

[0074] Table 3 Classification criteria for different fluid interaction states under different water saturation conditions

[0075] A second aspect of an embodiment of the present application provides a device for determining the interaction state of reservoir fluids, comprising: a memory configured to store instructions; and a processor configured to call instructions from the memory and to implement the above-mentioned method for determining the interaction state of reservoir fluids when executing the instructions.

[0076] A third aspect of an embodiment of the present application provides a machine-readable storage medium having stored thereon instructions for causing a machine to execute the above-mentioned method for determining the interaction state of reservoir fluids.

[0077] A fourth aspect of the present invention provides a computer program product comprising a computer program that, when executed by a processor, implements the aforementioned method for determining the interaction state of reservoir fluids. Other features and advantages of the present invention will be described in detail in the subsequent detailed description.

[0078] It should also be noted that the terms "comprises," "includes," or any other variations thereof are intended to encompass non-exclusive inclusion, such that a process, method, commodity, or apparatus that includes a series of elements includes not only those elements but also other elements not explicitly listed, or includes elements inherent to such process, method, commodity, or apparatus. In the absence of further limitations, an element defined by the phrase "comprises a ..." does not exclude the presence of other identical elements in the process, method, commodity, or apparatus that includes the element.

[0079] The above are merely embodiments of the present application and are not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present application should all be included within the scope of the claims of the present application.

Claims

1. A method for determining the interaction state of fluids in a reservoir, characterized in that: The method comprises: Obtain the current water saturation and current CO2 displacement pressure of the target reservoir; Based on the predetermined target correspondence between water saturation, CO2 displacement pressure, and fluid interaction state, the current fluid interaction state of the target reservoir is determined according to the current water saturation and the current CO2 displacement pressure.

2. The method according to claim 1, characterized in that Determining the target correspondence relationship includes: Based on a pre-built CO2-crude oil-water three-phase reservoir numerical simulation model, a plurality of simulated interfacial tensions and a plurality of simulated oil displacement efficiencies are obtained according to a plurality of first preset CO2 displacement pressures and a plurality of preset water saturations; According to the plurality of preset water saturations, the plurality of preset CO2 displacement pressures, the plurality of simulated interfacial tensions, and the plurality of simulated oil displacement efficiencies, an oil displacement efficiency-CO2 displacement pressure relationship curve and an interfacial tension-CO2 displacement pressure relationship curve corresponding to each of the preset water saturations are obtained; Determine, based on the oil displacement efficiency-CO2 displacement pressure relationship curve and the interfacial tension-CO2 displacement pressure relationship curve corresponding to each of the preset water saturations, a plurality of target fluid interaction state limit CO2 displacement pressures corresponding to each of the preset water saturations, wherein the target fluid interaction state limit CO2 displacement pressures are used to divide the fluid interaction state; According to the multiple target fluid interaction state limit CO2 displacement pressures corresponding to each of the preset water saturations, the corresponding relationship between the CO2 displacement pressure corresponding to each of the preset water saturations and the fluid interaction state is obtained to obtain the target corresponding relationship.

3. The method according to claim 2, characterized in that The multiple target fluid interaction state limit CO2 displacement pressures include a first target fluid interaction state limit CO2 displacement pressure, a second target fluid interaction state limit CO2 displacement pressure, and a third target fluid interaction state limit CO2 displacement pressure; determining the multiple target fluid interaction state limit CO2 displacement pressures corresponding to each preset water saturation according to the oil recovery efficiency-CO2 displacement pressure relationship curve and the interfacial tension-CO2 displacement pressure relationship curve corresponding to each preset water saturation includes: Obtaining the maximum immiscible displacement efficiency corresponding to each of the preset water saturations; Based on the oil displacement efficiency-CO2 displacement pressure relationship curve corresponding to each of the preset water saturations, determining the CO2 displacement pressures corresponding to the immiscible maximum oil displacement efficiency and the preset oil displacement efficiency, respectively, to obtain the first target fluid interaction state limit CO2 displacement pressure and the second target fluid interaction state limit CO2 displacement pressure; Based on the interfacial tension-CO2 displacement pressure relationship curve corresponding to each of the preset water saturations, the CO2 displacement pressure corresponding to the preset interfacial tension is determined to obtain the third target fluid interaction state limit CO2 displacement pressure.

4. The method according to claim 3, characterized in that The obtaining of the maximum immiscible displacement efficiency corresponding to each of the preset water saturations includes: Obtaining the residual oil saturation and the original oil saturation corresponding to each of the preset water saturations; Obtaining saturation differences corresponding to the preset water saturations, wherein the saturation differences are differences between the original oil saturation and the residual oil saturation; The immiscible maximum oil displacement efficiency corresponding to each of the preset water saturations is determined according to the saturation difference corresponding to each of the preset water saturations, wherein the immiscible maximum oil displacement efficiency is the ratio of the saturation difference to the original oil saturation.

5. The method according to claim 4, characterized in that The obtaining of the residual oil saturation and the original oil saturation corresponding to each of the preset water saturations includes: Based on the phase permeability experiment, first oil-gas phase permeability curves corresponding to the preset water saturations are obtained, wherein the first oil-gas phase permeability curves include a gas saturation-oil phase relative permeability curve and a gas saturation-gas phase relative permeability curve; The residual oil saturation and the original oil saturation are determined based on the gas saturation-oil phase relative permeability curve and the gas saturation-gas phase relative permeability curve, wherein the residual oil saturation is the deviation between the gas saturation when the oil phase relative permeability is zero on the gas saturation-oil phase relative permeability curve and 1, and the original oil saturation is the deviation between the gas saturation when the gas phase relative permeability is zero on the gas saturation-gas phase relative permeability curve and 1.

6. The method according to claim 2, characterized in that The construction of the CO2-crude oil-water three-phase reservoir numerical simulation model includes: Obtaining target reservoir characteristics of an explored oil reservoir and a second oil-gas relative permeability curve corresponding to the explored oil reservoir, wherein the target reservoir characteristics include average porosity and average permeability, and wherein the second oil-gas relative permeability curve is an oil-gas relative permeability curve when the water saturation is zero; Based on the initial CO2-crude oil-water three-phase reservoir numerical simulation model, the target oil and gas composition is obtained according to the target reservoir characteristics, the pre-constructed CO2-crude oil two-phase fluid model, the second oil and gas relative permeability curve, the CO2 injection rate, the preset water saturation, and the preset CO2 displacement pressure; Based on a preset interfacial tension algorithm, a target interfacial tension is obtained according to the target oil and gas composition; Based on the pre-stored correspondence between the interfacial tension and the oil-gas relative permeability curve, updating the second oil-gas relative permeability curve according to the target interfacial tension to obtain an updated second oil-gas relative permeability curve corresponding to the explored oil reservoir; The CO2 injection rate is increased, and the initial CO2-crude oil-water three-phase reservoir numerical simulation model is updated according to the updated second oil-gas relative permeability curve until the CO2 injection rate reaches a preset CO2 injection rate threshold.

7. The method according to claim 6, characterized in that The construction of the CO2-crude oil two-phase fluid model includes: According to the preset oil-gas phase permeability curve and the initial CO2-crude oil two-phase fluid model, a CO2-crude oil one-dimensional numerical capillary experimental model is obtained; Based on the CO2-crude oil one-dimensional numerical slim tube experimental model, determining the maximum oil displacement efficiency of multiple numerical experimental models according to multiple second preset CO2 displacement pressures; Determining a second preset CO2 displacement pressure corresponding to a maximum of the maximum oil displacement efficiencies of the multiple numerical experimental models as a critical CO2 displacement pressure; Determining a deviation between the critical CO2 displacement pressure and a preset critical CO2 displacement pressure to obtain a critical CO2 displacement pressure error value; The initial CO2-crude oil two-phase fluid model is updated until the critical CO2 displacement pressure error value is less than a preset pressure error threshold, so as to obtain the CO2-crude oil two-phase fluid model.

8. A device for determining the interaction state of fluids in an oil reservoir, characterized in that: include: a memory configured to store instructions; as well as A processor is configured to call the instructions from the memory and implement the method for determining the interaction state of reservoir fluids according to any one of claims 1 to 7 when executing the instructions.

9. A machine-readable storage medium, characterized in that The machine-readable storage medium stores instructions for causing a machine to execute the method for determining the interaction state of reservoir fluids according to any one of claims 1 to 7.

10. A computer program product comprising a computer program, characterized in that The computer program implements the method for determining the interaction state of reservoir fluids according to any one of claims 1 to 7 when executed by a processor.

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