A method for dividing interwell fluid flow regions of gas injection high pressure miscible flooding

Abstract

The present application belongs to the technical field of oil and gas field development, and particularly relates to a method for dividing fluid flow regions among gas injection high-pressure miscible flooding wells. The present application collects target reservoir data, adopts numerical simulation software to establish a reservoir gas injection high-pressure miscible flooding multi-phase multi-component numerical simulation model, and solves the problem that the core scale of the laboratory experiment cannot completely simulate the field conditions. Through comprehensive use of oil saturation, oil phase injection gas component concentration and interfacial tension multi-parameter profile, a systematic division system based on numerical simulation is established, accurate identification of the original crude oil area, the oil-water two-phase area, the injected gas-containing crude oil area, the miscible zone, the oil-gas two-phase area and the injected gas area is realized, and a scientific basis is provided for gas injection high-pressure miscible flooding dynamic law research and development plan optimization.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a method for dividing the fluid flow zone between high-pressure miscible flooding wells. Background Technology

[0002] With the continuous advancement of unconventional oil and gas resource development, high-pressure miscible flooding via gas injection has attracted widespread attention as an important technical means to improve oilfield recovery. High-pressure miscible flooding involves injecting high-pressure gas into the reservoir, causing it to rapidly form a miscible phase with the crude oil. This reduces oil phase viscosity and improves reservoir displacement efficiency, thereby significantly enhancing oilfield development results. However, the original formation pressure of most target reservoirs is often below the critical value, making it difficult to directly meet the miscibility conditions in the initial stage of gas injection.

[0003] To address the aforementioned issues, high-pressure water injection is commonly used as a pre-pressurization method in field implementations. Although high-pressure water injection creates the necessary pressure environment for miscible flooding, the pressurization process itself triggers a series of complex reservoir property changes and seepage responses. These changes directly constitute the technical challenge of delineating inter-well fluid flow zones. Specifically, high-pressure water injection leads to the reconstruction of effective reservoir stress and non-uniform changes in porosity and permeability parameters. Pre-water flooding and subsequent gas injection create a complex three-phase seepage coupling of oil, gas, and water, resulting in a highly heterogeneous distribution of inter-well fluids. Under the combined effect of water injection followed by gas injection (or alternating gas and water injection), the inter-well fluids form a continuous distribution from the original crude oil, oil-water two-phase, crude oil containing injected gas, miscible zone to oil-gas two-phase and pure injected gas. However, the boundaries between the various flow zones often overlap, and existing zone delineation methods cannot fully reflect the zone boundary characteristics under such multi-factor coupling.

[0004] The existing implementation schemes mainly fall into two categories: one is the physical simulation method based on indoor experiments, which observes fluid distribution through long core displacement experiments or microscopic visualization models; the other is the numerical simulation partitioning method based on a single parameter threshold, which uses a single parameter profile and divides the region according to a fixed threshold.

[0005] The current methods for dividing the fluid flow region between high-pressure miscible flooding wells have the following drawbacks: (1) Physical simulation methods based on indoor experiments are limited by the experimental scale and cannot reflect the actual impact of reservoir heterogeneity and injection-production well spacing on fluid distribution at the field scale. The division results cannot directly guide field applications. (2) Numerical simulation division methods based on a single parameter threshold rely only on a certain parameter profile and use a fixed threshold for region division. They ignore the complex multiphase flow coupling between injected water, injected gas and crude oil during high-pressure miscible flooding and cannot systematically reflect the complete process from the original crude oil flow region to the injected gas flow region.

[0006] In summary, existing solutions for complex conditions involving pre-high-pressure water injection and subsequent gas injection miscible flooding have significant shortcomings in terms of the integrity of physical mechanisms and the synergistic application of multiple parameters. Therefore, this invention breaks through the limitations of single-parameter discrimination and proposes for the first time a region division method based on the synergistic application of multiple parameters such as oil saturation, oil phase injected gas component concentration, and interfacial tension. Through the joint discrimination of three parameters, the flow region can be completely and accurately identified, providing technical support for optimizing the seepage efficiency of gas injection high-pressure miscible flooding. Summary of the Invention

[0007] To address the shortcomings of existing technologies, this invention proposes a multi-parameter collaborative method for delineating inter-well fluid flow regions. This invention collects target reservoir data and uses numerical simulation software to establish a multiphase, multi-component numerical simulation model of high-pressure miscible flooding in the reservoir, solving the problem that core-scale experiments in laboratory settings cannot fully simulate field conditions. Furthermore, by comprehensively utilizing multi-parameter profiles including oil saturation, oil-phase injected gas component concentration, and interfacial tension, a systematic delineation system based on numerical simulation is established. This enables accurate identification of the original crude oil zone, oil-water two-phase zone, crude oil zone containing injected gas, miscible zone, oil-gas two-phase zone, and injected gas zone, providing a scientific basis for studying the dynamic laws of high-pressure miscible flooding and optimizing development schemes.

[0008] The technical problem to be solved by this invention is achieved by the following technical solution: a method for dividing the fluid flow region between high-pressure miscible wells during gas injection, comprising the following steps: S1. Establish a multiphase, multicomponent numerical simulation model for high-pressure miscible flooding in reservoirs via gas injection. Collect target reservoir data and use numerical simulation software to establish a multiphase, multi-component numerical simulation model for high-pressure miscible flooding of the reservoir, including a geological model, a fluid model, and an ultra-high pressure water injection porosity-permeability variation model. The methods for establishing the geological model, fluid model, and ultra-high pressure water injection porosity-permeability variation model are existing technologies, and can be operated according to the instruction manual of the numerical simulation software. The specific steps will not be elaborated here. S2, Obtaining various parameter profiles between injection and production wells Based on the numerical simulation model established in step S1, a multiphase and multicomponent numerical simulation of high-pressure miscible flooding in oil reservoir gas injection is carried out. Various parameter profiles between injection and production wells are extracted at the end of the pressure flooding process (the end of high-pressure miscible flooding in gas injection), mainly including oil saturation, interfacial tension, and concentration of oil phase injected gas components. The distribution curves of oil saturation profile between injection and production wells, the distribution curves of oil phase injected gas component concentration between injection and production wells, and the distribution curves of oil saturation profile between injection and production wells are obtained. The horizontal axis of the curve represents dimensionless length, with 0-1 representing the distance between injection and production wells. The 0 end represents the injection well, and the 1 end represents the production well. S3. Determine the criteria for dividing inter-well fluid zones. The distribution curve of oil saturation profile between injection and production wells is used as the main indicator to divide the original crude oil flow area. The area where the oil saturation at the production well end has not changed is defined as the original crude oil flow area. The oil-water two-phase flow zone is divided by using the oil phase injection gas component concentration profile distribution curve between injection and production wells as the main indicator. The region from the left end of the original crude oil flow zone to the point where the injection gas component concentration begins to be greater than 0 is defined as the oil-water two-phase flow zone. The distribution curve of the injection gas component concentration profile between injection and production wells is used as the main indicator to divide the crude oil flow area containing injection gas. The area from the left end of the oil-water two-phase flow area to 20% of the injection gas component concentration is defined as the crude oil flow area containing injection gas. The interfacial tension profile distribution curve between injection and production wells is used as the main indicator to divide the flow region of the miscible zone. The position where the injected gas content in the oil phase is equal to 0.2 (i.e. 20%) is defined as the front edge of the miscible zone, and the position where the oil-gas interfacial tension is equal to 0.1 dyne / cm is defined as the rear edge of the miscible zone. The flow region between the front edge and the rear edge of the miscible zone is the flow region of the miscible zone. The oil saturation profile distribution curve between injection and production wells is used as the main indicator to divide the oil and gas two-phase flow region. The region from the left end of the miscible zone flow region to the point where the oil saturation begins to increase at the injection well end is defined as the oil and gas two-phase flow region. The oil saturation profile distribution curve between injection and production wells is used as the main indicator to divide the injected gas flow region. The region from the left end of the oil and gas two-phase flow region to the injection well end is defined as the injected gas flow region. S4. Division of fluid flow zones between wells Based on the various parameter profiles between injection and production wells at the end of the pressure drive process (the end of the high-pressure miscible phase drive, the research object is the division of the fluid flow region after pressure drive, so the end of pressure drive is taken), according to the division criteria in step S3, based on the oil saturation profile distribution curve between injection and production wells, the oil phase injected gas component concentration distribution curve between injection and production wells, and the oil saturation profile distribution curve between injection and production wells, the flow region between injection and production wells is divided into six flow regions in sequence: the original crude oil region, the oil-water two-phase flow region, the crude oil flow region containing injected gas, the miscible zone flow region, the oil-gas two-phase flow region, and the injected gas flow region, thus completing the division of the fluid flow region between wells.

[0009] The preferred method for dividing step S4 in this invention is as follows: (1) Division of the original crude oil flow area: Based on the distribution curve of oil saturation profile between injection and production wells, the left boundary is the point where the oil saturation at the production well tip begins to be lower than the original oil saturation (the oilfield will provide field data, including the original oil saturation. The modeling will be based on the field data). The right boundary is the production well, which is the flow area ①. This flow area has not yet been affected by injected water and is the original crude oil flow area. (2) Division of oil-water two-phase flow region: According to the distribution curve of oil phase injected gas component concentration profile between injection and production wells, the left boundary is the point where the injected gas component concentration begins to be greater than 0. The flow region ② is obtained by extending to the left boundary of the initial flow region ①. The injected gas has not yet affected this flow region, which is the two-phase flow region of injected water and original crude oil. (3) Division of the flow zone of crude oil containing injected gas: According to the distribution curve of the oil phase injected gas component concentration profile between injection and production wells, the left boundary is at 20% of the injected gas component concentration. The flow zone ③ is obtained by reaching the left boundary of flow zone ②. The injected gas has diffused into the crude oil in this flow zone but has not formed a miscible phase. It is a two-phase flow zone of injected water and crude oil containing injected gas (which can be understood as the flow zone of injected water + crude oil containing injected gas (oil-water two-phase)). (4) Division of the flow zone of the miscible zone: According to the interfacial tension profile distribution curve between injection and production wells, the left boundary is the point where the oil and gas interfacial tension is less than 0.1 dyn / cm. The flow zone ④ is obtained by extending to the left boundary of flow zone ③. The injected gas and crude oil form a miscible zone in this flow zone, which is the flow zone of the miscible zone. (5) Division of the oil and gas two-phase flow region: Based on the oil saturation profile distribution curve between injection and production wells, take the point where the oil saturation at the injection wellhead begins to increase as the left boundary, and extend to the left boundary of flow region ④ to obtain flow region ⑤. In this flow region, the injected gas can only be miscible with the remaining oil from the gas drive, and it is a two-phase flow region of injected gas and crude oil (high-pressure miscible drive of gas injection requires water drive first and then gas injection to complete the high-pressure miscible drive. Flow region ③ is the flow region of injected water + crude oil containing injected gas (oil-water two-phase), and flow region ⑤ is the flow region of injected gas + crude oil (oil-gas two-phase)). (6) Division of the injection gas flow zone: Based on the oil saturation profile distribution curve between injection and production wells, the flow zone ⑥ is obtained by taking the injection well end as the left boundary and extending to the left boundary of the flow zone ⑤. The crude oil in this flow zone is the non-flowing heavy component remaining after the injection gas extraction, which is the injection gas flow zone.

[0010] Preferably, in step S1 of this invention, the fluid model is constructed by fitting experimental data of the high-pressure physical properties of the crude oil and injected gas system, thereby ensuring the reliability of the model calculation; The ultra-high pressure water injection porosity-permeability variation model was obtained by fitting measured experimental data of reservoir core porosity and permeability as a function of effective stress. The high-pressure physical property experiments of the crude oil and injected gas system and the measured experiments of reservoir core porosity and permeability as a function of effective stress are existing technologies, and their specific implementation methods will not be elaborated further.

[0011] Model parameters need to be fitted with experimental data to ensure the reliability of the model. Fitting the model parameters with field data and experimental data ensures the accuracy of the model. Fluid models and porosity-permeability variation models essentially refer to the model parameters set within the software. However, to complete the numerical simulation, the target reservoir data needs to be set to the specified location in the model.

[0012] Preferably, in step S1 of this invention, the numerical simulation software is CMG.

[0013] Compared with the prior art, the beneficial effects of the present invention are: Compared with existing technologies, this invention establishes a complete well-to-well fluid flow region division system from injection well to production well, realizing the full-chain division of six flow regions: the original crude oil region, the oil-water two-phase flow region, the crude oil flow region containing injected gas, the miscible zone flow region, the oil-gas two-phase flow region, and the injected gas flow region. This system can systematically reflect the distribution patterns of various fluids during high-pressure miscible displacement of gas injection.

[0014] Compared to existing methods relying on single parameters or indoor physical simulations, this invention overcomes the limitations of incomplete or misjudged divisions caused by single-parameter methods by collaboratively discriminating multiple parameter profiles, such as oil saturation, oil-phase injected gas component concentration, and interfacial tension. Furthermore, this invention clarifies the discrimination parameters and numerical thresholds for the boundaries of each flow region, such as an injected gas concentration of 20% and an interfacial tension of 0.1 dyn / cm, eliminating the need for manual experience-based judgment and achieving quantifiable, repeatable, and engineering-operable division results. Through the scientific division of inter-well fluid flow regions, this invention provides a reliable basis for optimizing development schemes for high-pressure miscible flooding reservoirs, guiding injection strategies, well network layout, and exploitation measures, thereby effectively improving oilfield recovery and reducing development risks. It possesses significant technological innovation and engineering application value. Attached Figure Description

[0015] Figure 1 This is a flowchart of the method for dividing the fluid flow region between high-pressure gas injection and miscible wells according to the present invention. Figure 2 This is a profile distribution curve of various parameters between injection and production wells; Figure 3 This is a schematic diagram of the leading edge and trailing edge of the miscible phase; Figure 4 This is a schematic diagram showing the distribution of fluid flow zones between injection and production wells. Detailed Implementation

[0016] The present invention will be further described below with reference to the accompanying drawings and embodiments, but the scope of protection of the present invention is not limited to the following embodiments. The following embodiments all employ the fluid flow region division method between high-pressure miscible wells described in this invention for experimental purposes.

[0017] like Figure 1As shown, a method for dividing the fluid flow zone between high-pressure miscible flooding wells includes the following steps: S1. Establish a multiphase, multicomponent numerical simulation model for high-pressure miscible flooding in reservoirs via gas injection. Collect target reservoir data and use numerical simulation software to establish a multiphase, multi-component numerical simulation model of high-pressure miscible flooding for gas injection in the reservoir, including a geological model, a fluid model, and an ultra-high pressure water injection porosity-permeability variation model; in step S1, the numerical simulation software is CMG, and the modeling method is existing technology, which will not be described in detail here.

[0018] S2, Obtaining various parameter profiles between injection and production wells Based on the numerical simulation model established in step S1, a multiphase, multi-component numerical simulation of high-pressure miscible flooding in oil reservoirs is conducted. Various parameter profiles between injection and production wells are extracted at the end of the pressure flooding process (the end of high-pressure miscible flooding), mainly including oil saturation, interfacial tension, and oil phase injected gas component concentration. This yields the oil saturation profile distribution curve, oil phase injected gas component concentration distribution curve, and oil saturation profile distribution curve between injection and production wells. These curves can be derived from the numerical simulation results.

[0019] To create the technical policy diagram, the well spacing is set to be dimensionless. This allows for guidance under different field conditions; simply increase the actual well spacing proportionally. Specifically, the horizontal axis of the curve represents the dimensionless length, with 0-1 representing the injection-production well spacing, where 0 represents the injection well and 1 represents the production well.

[0020] S3. Determine the criteria for dividing inter-well fluid zones. like Figure 3 As shown, this invention uses oil-gas interfacial tension and the injected gas content in the oil phase as the main indicators to delineate the miscible zone. The trailing edge of the miscible zone is located in the oil-gas two-phase region, and its position is determined by the oil-gas interfacial tension; the lower the oil-gas interfacial tension, the higher the degree of miscibility. The leading edge of the miscible zone is located in the oil phase region containing dissolved injected gas, where only the liquid phase exists and there is no oil-gas interfacial tension; its position is determined by the injected gas content in the oil phase. When the injected gas content in the oil phase is 0.2%, the viscosity of the oil phase decreases by about 25%, which is considered to have achieved the miscibility effect required in engineering. The position where the injected gas content in the oil phase is equal to 0.2 is defined as the leading edge of the miscible zone. Based on the changing trend of the oil-gas interfacial tension, an oil-gas interfacial tension of 0.1 dyne / cm is defined as the critical oil-gas miscible interfacial tension; that is, when the oil-gas interfacial tension is below 0.1 dyne / cm, the injected gas phase and the oil phase can be considered to have reached a miscible state.

[0021] The position where the interfacial tension between oil and gas is equal to 0.1 dyne / cm is defined as the trailing edge of the miscible zone.

[0022] Specifically, such as Figure 2 and Figure 4 As shown, the distribution curve of oil saturation profile between injection and production wells is used as the main indicator to divide the original crude oil flow area, and the area where the oil saturation at the production well end has not changed is defined as the original crude oil flow area. The oil-water two-phase flow zone is divided by using the oil phase injection gas component concentration profile distribution curve between injection and production wells as the main indicator. The region from the left end of the original crude oil flow zone to the point where the injection gas component concentration begins to be greater than 0 is defined as the oil-water two-phase flow zone. The distribution curve of the injection gas component concentration profile between injection and production wells is used as the main indicator to divide the crude oil flow area containing injection gas. The area from the left end of the oil-water two-phase flow area to 20% of the injection gas component concentration is defined as the crude oil flow area containing injection gas. The interfacial tension profile distribution curve between injection and production wells is used as the main indicator to divide the flow region of the miscible zone. The position where the injected gas content in the oil phase is equal to 0.2 is defined as the front edge of the miscible zone, and the position where the oil-gas interfacial tension is equal to 0.1 dyne / cm is defined as the rear edge of the miscible zone. The flow region between the front edge and the rear edge of the miscible zone is the flow region of the miscible zone. The oil saturation profile distribution curve between injection and production wells is used as the main indicator to divide the oil and gas two-phase flow region. The region from the left end of the miscible zone flow region to the point where the oil saturation begins to increase at the injection well end is defined as the oil and gas two-phase flow region. The oil saturation profile distribution curve between injection and production wells is used as the main indicator to divide the injected gas flow region. The region from the left end of the oil and gas two-phase flow region to the injection well end is defined as the injected gas flow region. S4. Division of fluid flow zones between wells Based on the various parameter profiles between injection and production wells at the end of the pressure drive process (the end of the high-pressure miscible phase drive, the research object is the division of the fluid flow region after pressure drive, so the end of pressure drive is taken), according to the division criteria in step S3, based on the oil saturation profile distribution curve between injection and production wells, the oil phase injected gas component concentration distribution curve between injection and production wells, and the oil saturation profile distribution curve between injection and production wells, the flow region between injection and production wells (the straight line region between injection and production wells) is divided into six flow regions in sequence: the original crude oil region, the oil-water two-phase flow region, the crude oil flow region containing injected gas, the miscible zone flow region, the oil-gas two-phase flow region, and the injected gas flow region, thus completing the division of the fluid flow region between wells.

[0023] Specifically, the specific division method for step S4 is as follows: (1) Division of the original crude oil flow area: such as Figure 2As shown, based on the oil saturation profile distribution curve between injection and production wells, the left boundary is defined as the point where the oil saturation at the production well tip begins to fall below the original oil saturation (the oilfield will provide field data, including the original oil saturation. The modeling will be based on the field data). The right boundary is defined as the production well. This results in flow region ①, which is the original crude oil flow region, as it has not yet been affected by injected water.

[0024] (2) Division of the oil-water two-phase flow region: such as Figure 2 As shown, based on the distribution curve of the oil phase injected gas component concentration profile between injection and production wells, the left boundary is taken where the injected gas component concentration begins to be greater than 0. The flow region ② is obtained by extending to the left boundary of the initial flow region ①. The injected gas has not yet affected this flow region, which is a two-phase flow region of injected water and original crude oil.

[0025] (3) Division of crude oil flow areas including injected gas: such as Figure 2 As shown, according to the distribution curve of the oil phase injected gas component concentration profile between injection and production wells, the left boundary is at 20% of the injected gas component concentration. The flow region ③ is obtained at the left boundary of flow region ②. The injected gas in this flow region has diffused into the crude oil but has not formed a miscible phase. It is a two-phase flow region of injected water and crude oil containing injected gas (which can be understood as the flow region of injected water + crude oil containing injected gas (oil-water two-phase)).

[0026] (4) Division of the flow region in the miscible phase zone: such as Figure 2 As shown, based on the interfacial tension profile distribution curve between injection and production wells, the left boundary is defined as the point where the oil-gas interfacial tension is below 0.1 dyn / cm. Flowing region ④ is obtained by extending to the left boundary of flow region ③. In this flow region, the injected gas and crude oil form a miscible zone, which is the miscible zone flow region.

[0027] (5) Division of the two-phase flow region of oil and gas: such as Figure 2 As shown, based on the oil saturation profile distribution curve between injection and production wells, the left boundary is defined by the point where the oil saturation at the gas injection wellhead begins to increase. Flowing region ⑤ is obtained by extending to the left boundary of flow region ④. In this flow region, the injected gas can only be miscible with the remaining oil from the gas drive, forming a two-phase flow region of injected gas and crude oil (high-pressure miscible flow requires water drive followed by gas injection to complete the high-pressure miscible flow. Flow region ③ is a flow region of injected water + crude oil containing injected gas (oil-water two-phase), and flow region ⑤ is a flow region of injected gas + crude oil (oil-gas two-phase)).

[0028] (6) Division of the injected gas flow zone: such as Figure 2 As shown, based on the oil saturation profile distribution curve between injection and production wells, with the gas injection well tip as the left boundary, the flow region ⑥ is obtained from the left boundary of the flow region ⑤. The crude oil in this flow region is the non-flowing heavy component remaining after extraction by the injected gas, which is the injected gas flow region.

[0029] The values ​​corresponding to the above boundaries are obtained from the numerical simulation data output by the model.

[0030] This invention is specifically applied to high-pressure miscible flooding reservoirs, especially in high-pressure miscible flooding development scenarios with reservoir depths greater than 3000m and injection pressures exceeding 35MPa. The core technical problems this invention aims to solve include: the ambiguity of multi-fluid zone delineation, where conventional physical simulations or single-parameter threshold methods cannot effectively distinguish complex flow regions between wells.

Claims

1. A method for dividing the fluid flow region between high-pressure miscible displacement wells during gas injection, characterized in that, Includes the following steps: S1. Establish a multiphase, multicomponent numerical simulation model for high-pressure miscible flooding in reservoirs via gas injection. Collect target reservoir data and use numerical simulation software to establish a multiphase and multicomponent numerical simulation model for high-pressure miscible flooding of the reservoir, including geological model, fluid model, and ultra-high pressure water injection porosity and permeability variation model; S2, Obtaining various parameter profiles between injection and production wells Based on the numerical simulation model established in step S1, a multiphase and multicomponent numerical simulation of high-pressure miscible flooding in oil reservoirs is carried out. Various parameter profiles between injection and production wells at the end of the pressure flooding process are extracted, mainly including oil saturation, interfacial tension, and concentration of oil phase injected gas components. The distribution curves of oil saturation profile between injection and production wells, the distribution curves of oil phase injected gas component concentration between injection and production wells, and the distribution curves of oil saturation profile between injection and production wells are obtained. The horizontal axis of the curve represents dimensionless length, with 0-1 representing the distance between injection and production wells. The 0 end represents the injection well, and the 1 end represents the production well. S3. Determine the criteria for dividing inter-well fluid zones. The distribution curve of oil saturation profile between injection and production wells is used as the main indicator to divide the original crude oil flow area. The area where the oil saturation at the production well end has not changed is defined as the original crude oil flow area. The oil-water two-phase flow zone is divided by using the oil phase injection gas component concentration profile distribution curve between injection and production wells as the main indicator. The region from the left end of the original crude oil flow zone to the point where the injection gas component concentration begins to be greater than 0 is defined as the oil-water two-phase flow zone. The distribution curve of the injection gas component concentration profile between injection and production wells is used as the main indicator to divide the crude oil flow area containing injection gas. The area from the left end of the oil-water two-phase flow area to 20% of the injection gas component concentration is defined as the crude oil flow area containing injection gas. The interfacial tension profile distribution curve between injection and production wells is used as the main indicator to divide the flow region of the miscible zone. The position where the injected gas content in the oil phase is equal to 0.2 is defined as the front edge of the miscible zone, and the position where the oil-gas interfacial tension is equal to 0.1 dyne / cm is defined as the rear edge of the miscible zone. The flow region between the front edge and the rear edge of the miscible zone is the flow region of the miscible zone. The oil saturation profile distribution curve between injection and production wells is used as the main indicator to divide the oil and gas two-phase flow region. The region from the left end of the miscible zone flow region to the point where the oil saturation begins to increase at the injection well end is defined as the oil and gas two-phase flow region. The oil saturation profile distribution curve between injection and production wells is used as the main indicator to divide the injected gas flow region. The region from the left end of the oil and gas two-phase flow region to the injection well end is defined as the injected gas flow region. S4. Division of fluid flow zones between wells Based on the profiles of various parameters between injection and production wells at the end of the pressure drive process, and according to the division criteria in step S3, the flow regions between injection and production wells are divided into six flow regions in sequence: the original crude oil region, the oil-water two-phase flow region, the crude oil flow region containing injected gas, the miscible zone flow region, the oil-gas two-phase flow region, and the injected gas flow region, based on the distribution curves of oil saturation profiles, oil phase injection gas component concentration distribution curves, and oil saturation profile distribution curves. This completes the division of fluid flow regions between wells.

2. The method for dividing the fluid flow region between high-pressure miscible wells according to claim 1, characterized in that, The specific division method for step S4 is as follows: (1) Division of the original crude oil flow area: According to the distribution curve of oil saturation profile between injection and production wells, the left boundary is the point where the oil saturation at the production well end begins to be lower than the original oil saturation, and the right boundary is the production well. The flow area ① is obtained. The injected water has not yet affected this flow area, which is the original crude oil flow area. (2) Division of oil-water two-phase flow region: According to the distribution curve of oil phase injected gas component concentration profile between injection and production wells, the left boundary is the point where the injected gas component concentration begins to be greater than 0. The flow region ② is obtained by extending to the left boundary of the initial flow region ①. The injected gas has not yet affected this flow region, which is the two-phase flow region of injected water and original crude oil. (3) Division of the flow zone of crude oil containing injected gas: According to the distribution curve of the oil phase injected gas component concentration profile between injection and production wells, the left boundary is at 20% of the injected gas component concentration. The flow zone ③ is obtained at the left boundary of flow zone ②. The injected gas in this flow zone has diffused into the crude oil but has not formed a miscible phase. It is a two-phase flow zone of injected water and crude oil containing injected gas. (4) Division of the flow zone of the miscible zone: According to the interfacial tension profile distribution curve between injection and production wells, the left boundary is the point where the oil and gas interfacial tension is less than 0.1 dyn / cm. The flow zone ④ is obtained by extending to the left boundary of flow zone ③. The injected gas and crude oil form a miscible zone in this flow zone, which is the flow zone of the miscible zone. (5) Division of the two-phase flow zone of oil and gas: According to the oil saturation profile distribution curve between injection and production wells, the left boundary is the point where the oil saturation at the injection wellhead begins to increase. The flow zone ⑤ is obtained by extending to the left boundary of flow zone ④. The injected gas in this flow zone can only be mixed with the remaining oil in the gas drive, and it is a two-phase flow zone of injected gas and crude oil. (6) Division of the injection gas flow zone: Based on the oil saturation profile distribution curve between injection and production wells, the flow zone ⑥ is obtained by taking the injection well end as the left boundary and extending to the left boundary of the flow zone ⑤. The crude oil in this flow zone is the non-flowing heavy component remaining after extraction by the injection gas, which is the injection gas flow zone.

3. The method for dividing the fluid flow region between high-pressure miscible wells according to claim 1, characterized in that: In step S1, the fluid model is constructed based on the high-pressure physical property experimental data of the crude oil and injected gas system; The ultra-high pressure water injection porosity variation model was obtained by fitting measured experimental data of reservoir core porosity and permeability as a function of effective stress.

4. The method for dividing the fluid flow region between high-pressure miscible wells according to claim 1, characterized in that: In step S1, the numerical simulation software is CMG.

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