A dynamic discrimination method for CO2 huff and puff miscible regions in shale oil reservoirs

Abstract

This invention discloses a method for dynamically identifying miscible regions in CO2 huff and puff of shale oil reservoirs, comprising: performing nuclear magnetic resonance (NMR) testing on core samples from the target reservoir; scanning the core samples to construct a three-dimensional core pore structure model, and importing NMR data to calibrate the initial fluid saturation; establishing a dynamic displacement numerical simulation model by combining the CO2-crude oil phase equation, interfacial tension model, and core permeability heterogeneity parameters; designing multiple huff and puff experiments to simulate the CO2 injection process, while simultaneously monitoring the changes in the core's NMR signal during displacement in real time, correcting the fluid saturation, pressure field, and interfacial tension parameters in the dynamic displacement numerical simulation model, and dividing the miscible regions; and selecting the optimal combination of development parameters based on the distribution of miscible regions under different injection timing, well shut-in time, and huff and puff cycles. This invention achieves accurate division and dynamic identification of miscible regions in CO2 huff and puff.

Description

Technical Field

[0001] This invention belongs to the field of petroleum engineering and oil and gas reservoir development technology, and particularly relates to a dynamic identification method for CO2 huff and puff miscible regions in shale oil reservoirs. Background Technology

[0002] Shale oil reservoirs, as an important oil and gas resource, hold a crucial position in today's energy sector. However, their characteristics, such as low porosity, low permeability, and strong heterogeneity, make fluid flow within the reservoir extremely complex. During development, CO2 huff and puff technology has become an important means of enhancing oil recovery. However, in practical applications, the transport patterns of CO2 within complex pore structures are difficult to observe directly, leading to significant challenges in the dynamic differentiation of the miscible front and rear edges.

[0003] Currently, existing technologies mainly include tracer-based CO2 migration monitoring methods, conventional numerical simulation techniques, and static nuclear magnetic resonance (NMR) analysis. Among these, tracer-based CO2 migration monitoring methods involve injecting chemical tracers into the reservoir and tracking CO2 migration paths by monitoring tracer production. However, in the complex pore structure of shale reservoirs, tracers are easily adsorbed or retained, leading to distorted data that fails to accurately reflect the actual CO2 migration path and its affected area.

[0004] On the other hand, conventional numerical simulation techniques mainly rely on theoretical models to predict the miscible front and displacement effects. These models are mostly based on idealized assumptions and do not incorporate actual microscopic pore structure data from core samples to correct model parameters. This makes the models poorly adaptable to simulating complex displacement processes in actual reservoirs, with limited prediction accuracy, and unable to meet the needs for dynamic discrimination of the miscible front and rear.

[0005] In addition, although nuclear magnetic resonance (NMR) curves and core scanning technology can provide static pore structure information of cores, such as porosity and permeability, their application is limited to static parameter measurement and has not yet been effectively combined with dynamic displacement processes, thus failing to meet the need for dynamic identification of miscible regions during CO2 displacement.

[0006] It is evident that existing technologies have significant shortcomings in dynamically identifying miscible regions, failing to accurately characterize the fluid distribution and miscibility features during CO2 displacement. Therefore, there is an urgent need for a technique that combines microscopic experimental data with dynamic simulation to accurately characterize the fluid distribution and miscibility features during CO2 displacement, thereby providing strong support for optimizing gas injection strategies. Summary of the Invention

[0007] To address the shortcomings of traditional methods in dynamically capturing the spatiotemporal evolution of miscible regions during CO2 displacement, neglecting the influence of injection timing, well shut-in time, and huff and puff cycles on the position of the miscible front, and the disconnect between numerical simulation models and actual core microstructures, this invention provides a dynamic discrimination method for CO2 huff and puff miscible regions in shale reservoirs.

[0008] This invention proposes a dynamic discrimination method for CO2 huff and puff miscible regions in shale oil reservoirs, comprising the following steps:

[0009] Nuclear magnetic resonance (NMR) tests were performed on core samples from the target reservoir to obtain transverse relaxation time spectrum curves of initial oil saturation, pore distribution, and fluid occurrence state.

[0010] CT scanning technology was used to scan the core samples of the target reservoir, a three-dimensional core pore structure model was constructed, and nuclear magnetic resonance data was imported to calibrate the initial fluid saturation. Combined with the CO2-crude oil phase equation, interfacial tension model and core permeability heterogeneity parameters, a dynamic displacement numerical simulation model was established.

[0011] Multiple sets of throughput experiments were designed to simulate the CO2 injection process under different development strategies. At the same time, by real-time monitoring of the nuclear magnetic resonance signal changes of the core during the displacement process, the fluid saturation, pressure field and interfacial tension parameters in the dynamic displacement numerical simulation model were corrected.

[0012] The miscible region is divided based on fluid saturation, pressure field, and interfacial tension parameters;

[0013] Based on the distribution of miscible regions under different injection timing, well shut-in time, and injection / pump cycles, a graph of gas injection efficiency-recovery ratio was established to select the optimal combination of development parameters.

[0014] Optionally, the process of performing nuclear magnetic resonance testing on core samples from the target reservoir to obtain transverse relaxation time spectrum curves of initial oil saturation, pore distribution, and fluid occurrence state includes:

[0015] Multi-point measurements were performed on the core sample of the target reservoir using nuclear magnetic resonance equipment to obtain transverse relaxation time spectrum curves at different locations. The obtained curves were then averaged to obtain transverse relaxation time spectrum curves that represent the initial oil saturation, pore distribution, and fluid occurrence state of the entire target reservoir core sample.

[0016] Optionally, the process of using CT scanning technology to scan core samples of the target reservoir and constructing a three-dimensional core pore structure model includes:

[0017] The core sample of the target reservoir is placed in a CT scanning device and scanned from multiple angles to obtain several two-dimensional slice images. The obtained two-dimensional slice images are reconstructed into three-dimensional pore structure images through image reconstruction algorithms. Image processing technology is used to identify the fracture network and matrix pores in the three-dimensional pore structure images, determine the spatial distribution characteristics, and then construct a three-dimensional core pore structure model.

[0018] Optionally, the process of establishing a dynamic displacement numerical simulation model includes:

[0019] By selecting the CO2-crude oil phase equation and interfacial tension model, and combining them with the permeability heterogeneity parameter of the core, a dynamic displacement numerical simulation model capable of simulating the dynamic displacement process of CO2 in the core was constructed using numerical simulation technology to build the model and set the parameters.

[0020] Optionally, multiple sets of throughput experiments are designed to simulate the CO2 injection process under different development strategies. Simultaneously, by real-time monitoring of the nuclear magnetic resonance signal changes in the core during the displacement process, the process of correcting the fluid saturation, pressure field, and interfacial tension parameters in the dynamic displacement numerical simulation model includes:

[0021] Based on actual development needs, multiple sets of development strategy parameters, including different injection timing, well shut-in time, and injection / pump cycles, were determined. Injection / pump experiments were conducted according to these parameters. During the experiments, nuclear magnetic resonance equipment was used to monitor the signal changes of the core samples of the target reservoir in real time. Based on these signal changes, the fluid saturation, pressure field, and interfacial tension parameters in the numerical simulation model were dynamically adjusted and corrected.

[0022] Optionally, the process of dividing the miscible region based on fluid saturation, pressure field, and interfacial tension parameters includes:

[0023] The miscible front was determined by the sudden increase in light component signal in the nuclear magnetic resonance curve and the miscible pressure threshold in the numerical simulation pressure field; the miscible region was delineated by combining the connectivity of CO2 wave path in the CT scan image and the range of interfacial tension dropping to the critical value; and the remaining oil region was determined by using the unchanged residual oil peak in the nuclear magnetic resonance signal and the low displacement efficiency region in the numerical simulation.

[0024] Optionally, the process of determining the miscibility front based on the sudden increase in the light component signal in the nuclear magnetic resonance curve and the miscibility pressure threshold in the numerically simulated pressure field includes:

[0025] By analyzing the nuclear magnetic resonance curves, the location where the signal of the light component begins to increase significantly is identified. At the same time, the region that reaches the miscibility pressure threshold is determined in the pressure field results of numerical simulation. By comprehensively comparing and analyzing these two pieces of location information, the location of the miscibility front is finally determined.

[0026] Optionally, the process of defining the mixed-phase region by combining the connectivity of the CO2 wave path in the CT scan image and the range of interfacial tension decreasing to a critical value includes:

[0027] By observing the CO2 sweep path in CT scan images and analyzing connectivity, and by examining the range of the region where interfacial tension drops to the critical value in numerical simulation results, the boundaries and range of the mixed-phase region can be delineated.

[0028] Optionally, the process of determining the remaining oil region using the unchanged residual oil peak in the nuclear magnetic resonance signal and the low displacement efficiency region in the numerical simulation includes:

[0029] By analyzing the nuclear magnetic resonance signal, the location of the residual oil peak that has not changed is identified. At the same time, the low displacement efficiency region in the numerical simulation results is examined. By combining these two pieces of location information, the region where the residual oil is located is finally determined.

[0030] The present invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory, wherein the processor executes the computer program to implement the steps of the method.

[0031] Compared with the prior art, the present invention has the following advantages and technical effects:

[0032] High-precision dynamic discrimination: By combining dynamic monitoring of nuclear magnetic resonance and real-time feedback of CT scan data, the spatial resolution of mixed-phase region discrimination is improved;

[0033] Development strategy optimization: Clarify the impact of injection timing, well shut-in time, and injection / pump cycles on displacement efficiency, and achieve multi-parameter synergistic optimization of injection timing, well shut-in time, and injection / pump cycles, which can guide the design of on-site gas injection schemes;

[0034] Model adaptability enhancement: The numerical model is corrected based on real core data, which significantly improves the reliability of predictions;

[0035] Precise location of the miscible front: By combining nuclear magnetic resonance curves and numerical simulation of the pressure field, the location of the miscible front can be accurately determined. This precise location helps to better understand the dynamic changes of the fluid during CO2 displacement and provides a key basis for optimizing gas injection strategies.

[0036] Rational delineation of miscible regions: By utilizing the connectivity of CO2 sweep paths and the range within which interfacial tension drops to critical values ​​in CT scan images, miscible regions can be rationally delineated. This allows developers to clearly understand the sweep range and displacement effect of CO2 in the core, thereby optimizing development plans and improving oil recovery.

[0037] Accurately determining the remaining oil region: By combining the unchanged residual oil peaks in the nuclear magnetic resonance signal with the low displacement efficiency region in the numerical simulation, the distribution of remaining oil can be accurately determined. This is of great significance for identifying areas that have not yet been effectively displaced and further improving oil recovery. Attached Figure Description

[0038] The accompanying drawings, which form part of this application, are used to provide a further understanding of this application. The illustrative embodiments and descriptions of this application are used to explain this application and do not constitute an undue limitation of this application. In the drawings:

[0039] Figure 1 This is a schematic diagram of the method flow according to an embodiment of the present invention;

[0040] Figure 2 This is a schematic diagram of a three-dimensional pore structure model of a rock core scan according to an embodiment of the present invention;

[0041] Figure 3 This is a diagram showing the distribution of the mixed-phase region under a transfusion timing of 0.5 MMP and one round of throughput in an embodiment of the present invention.

[0042] Figure 4 This is a diagram showing the distribution of the mixed-phase region under a transfusion timing of 0.8 MMP and 3 rounds of throughput in an embodiment of the present invention.

[0043] Figure 5 The diagrams show the relationship between gas injection efficiency and recovery rate under different development strategies in this invention, where (a) is the relationship diagram for different conversion timings, (b) is the relationship diagram for different well-drainage times, and (c) is the relationship diagram for different inrush and outrush cycles. Detailed Implementation

[0044] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. This application will now be described in detail with reference to the accompanying drawings and embodiments.

[0045] It should be noted that the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and although a logical order is shown in the flowchart, in some cases the steps shown or described may be executed in a different order than that shown here.

[0046] Example 1

[0047] This embodiment provides a method for dynamically identifying miscible regions of CO2 huff and puff in shale oil reservoirs, including the following steps:

[0048] Nuclear magnetic resonance (NMR) tests were performed on core samples from the target reservoir to obtain transverse relaxation time spectrum curves of initial oil saturation, pore distribution, and fluid occurrence state.

[0049] CT scanning technology was used to scan the core samples of the target reservoir, a three-dimensional core pore structure model was constructed, and nuclear magnetic resonance data was imported to calibrate the initial fluid saturation. Combined with the CO2-crude oil phase equation, interfacial tension model and core permeability heterogeneity parameters, a dynamic displacement numerical simulation model was established.

[0050] Multiple sets of throughput experiments were designed to simulate the CO2 injection process under different development strategies. At the same time, by real-time monitoring of the nuclear magnetic resonance signal changes of the core during the displacement process, the fluid saturation, pressure field and interfacial tension parameters in the dynamic displacement numerical simulation model were corrected.

[0051] The miscible region is divided based on fluid saturation, pressure field, and interfacial tension parameters;

[0052] Based on the distribution of miscible regions under different injection timing, well shut-in time, and injection / pump cycles, a graph of gas injection efficiency-recovery ratio was established to select the optimal combination of development parameters.

[0053] The feasible process of performing nuclear magnetic resonance testing on core samples from the target reservoir to obtain transverse relaxation time spectrum curves of initial oil saturation, pore distribution, and fluid occurrence state includes:

[0054] Multi-point measurements were performed on the core sample of the target reservoir using nuclear magnetic resonance equipment to obtain transverse relaxation time spectrum curves at different locations. The obtained curves were then averaged to obtain transverse relaxation time spectrum curves that represent the initial oil saturation, pore distribution, and fluid occurrence state of the entire target reservoir core sample.

[0055] The feasible process of using CT scanning technology to scan core samples of the target reservoir and construct a three-dimensional core pore structure model includes:

[0056] The core sample of the target reservoir is placed in a CT scanning device and scanned from multiple angles to obtain several two-dimensional slice images. The obtained two-dimensional slice images are reconstructed into three-dimensional pore structure images through image reconstruction algorithms. Image processing technology is used to identify the fracture network and matrix pores in the three-dimensional pore structure images, determine the spatial distribution characteristics, and then construct a three-dimensional core pore structure model.

[0057] The feasible process of establishing a dynamic displacement numerical simulation model includes:

[0058] By selecting the CO2-crude oil phase equation and interfacial tension model, and combining them with the permeability heterogeneity parameter of the core, a dynamic displacement numerical simulation model capable of simulating the dynamic displacement process of CO2 in the core was constructed using numerical simulation technology to build the model and set the parameters.

[0059] Feasible design of multiple throughput experiments to simulate CO2 injection processes under different development strategies, and the process of correcting fluid saturation, pressure field, and interfacial tension parameters in the dynamic displacement numerical simulation model by real-time monitoring of nuclear magnetic resonance signal changes in the core during displacement, includes:

[0060] Based on actual development needs, multiple sets of development strategy parameters, including different injection timing, well shut-in time, and injection / pump cycles, were determined. Injection / pump experiments were conducted according to these parameters. During the experiments, nuclear magnetic resonance equipment was used to monitor the signal changes of the core samples of the target reservoir in real time. Based on these signal changes, the fluid saturation, pressure field, and interfacial tension parameters in the numerical simulation model were dynamically adjusted and corrected.

[0061] The feasible process of dividing the miscible region based on fluid saturation, pressure field, and interfacial tension parameters includes:

[0062] The miscible front was determined by the sudden increase in light component signal in the nuclear magnetic resonance curve and the miscible pressure threshold in the numerical simulation pressure field; the miscible region was delineated by combining the connectivity of CO2 wave path in the CT scan image and the range of interfacial tension dropping to the critical value; and the remaining oil region was determined by using the unchanged residual oil peak in the nuclear magnetic resonance signal and the low displacement efficiency region in the numerical simulation.

[0063] The feasible process of determining the miscibility front based on the sudden increase in the light component signal in the nuclear magnetic resonance curve and the miscibility pressure threshold in the numerically simulated pressure field includes:

[0064] By analyzing the nuclear magnetic resonance curves, the location where the signal of the light component begins to increase significantly is identified. At the same time, the region that reaches the miscibility pressure threshold is determined in the pressure field results of numerical simulation. By comprehensively comparing and analyzing these two pieces of location information, the location of the miscibility front is finally determined.

[0065] The feasible process of defining the mixed-phase region by combining the connectivity of the CO2 wave path in the CT scan image and the range of interfacial tension decreasing to a critical value includes:

[0066] By observing the CO2 sweep path in CT scan images and analyzing connectivity, and by examining the range of the region where interfacial tension drops to the critical value in numerical simulation results, the boundaries and range of the mixed-phase region can be delineated.

[0067] The feasible process of determining the remaining oil region using the unchanged residual oil peaks in the nuclear magnetic resonance signal and the low displacement efficiency region in the numerical simulation includes:

[0068] By analyzing the nuclear magnetic resonance signal, the location of the residual oil peak that has not changed is identified. At the same time, the low displacement efficiency region in the numerical simulation results is examined. By combining these two pieces of location information, the region where the residual oil is located is finally determined.

[0069] Example 2

[0070] like Figure 1 As shown in this embodiment, a method for dynamically identifying miscible regions of CO2 huff and puff in shale oil reservoirs includes the following steps:

[0071] Step 1: Core sample preparation and experimental data acquisition:

[0072] Core samples from the target reservoir were collected and subjected to nuclear magnetic resonance (NMR) tests to obtain T2 spectrum curves of initial oil saturation, pore distribution, and fluid occurrence state.

[0073] High-precision CT scanning technology was used to obtain three-dimensional pore structure images of rock core sections, and to identify the spatial distribution characteristics of fracture networks and matrix pores.

[0074] Step 2: Construct a core-scale numerical simulation model:

[0075] like Figure 2 As shown, a three-dimensional core pore structure model was established based on CT scan data, and NMR data was imported to calibrate the initial fluid saturation in the model.

[0076] A dynamic displacement numerical simulation model was constructed by introducing the CO2-crude oil phase equation and interfacial tension model, combined with the heterogeneity parameter of core permeability.

[0077] Step 3: Dynamic throughput experiment and parameter optimization:

[0078] Design multiple sets of injection and spitting experiments, adjust the injection timing (e.g., 0.5 MMP, 0.8 MMP and 1.1 MMP), well shut-in time (e.g. 3 h, 6 h and 12 h) and injection and spitting cycles (1-3 cycles) to simulate the CO2 injection process under different development strategies;

[0079] By monitoring the changes in NMR signals of the core during displacement in real time, the fluid saturation, pressure field, and interfacial tension parameters in the numerical model are dynamically corrected.

[0080] Step 4: Miscible region identification and residual oil analysis:

[0081] Miscible front: Determined by the intersection region of the sudden increase in light component signal in NMR curve (reflecting CO2 dissolution) and miscible pressure threshold (e.g., ≥22MPa) in numerical simulation pressure field;

[0082] Mixed region: Delineated by combining the connectivity of CO2 wave path in CT scan images and the range where interfacial tension drops to a critical value (e.g., 0.01 dyn / cm);

[0083] Residual oil region: Determined by combining the residual oil peaks that have not changed in the NMR signal (T2 spectrum > 100ms) and the low displacement efficiency region in the numerical simulation.

[0084] Step 5: Development Strategy Optimization:

[0085] like Figure 5 As shown, based on the distribution of miscible regions under different injection timing, well shut-in time and injection cycles, a "gas injection efficiency-recovery rate" relationship chart is established to select the optimal combination of development parameters.

[0086] Example 1:

[0087] The injection timing is 0.5 MMP, the well-closing time is 3 hours, and one round of injection and purging is performed.

[0088] NMR curves showed a 30% increase in the signal of light components in the leading region, and CT scans showed CO2 diffusion along the main fracture.

[0089] Numerical simulation determined that the miscibility front was located 1.5 cm from the injection end, and the remaining oil was concentrated in the microporous region, such as... Figure 3 As shown.

[0090] Example 2:

[0091] The injection timing is 0.8 MMP, the well-closing time is 6 hours, and 3 rounds of injection and rejection are performed:

[0092] NMR signals showed that the miscible region extended to 60% of the core length, and the interfacial tension decreased to 0.008 dyn / cm;

[0093] The remaining oil area is reduced to 12% of the total pore volume, such as Figure 4 As shown.

[0094] Example 3

[0095] This embodiment also discloses a computer device, including a memory, a processor, and a computer program stored in the memory, wherein the processor executes the computer program to implement the steps of the method described in Embodiment 1.

[0096] The above are merely preferred embodiments of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of the claims.

Claims

1. A method for determining the dynamic behavior of a CO2 huff and puff miscible region in a shale oil reservoir, characterized in that, The method comprises the following steps: Carrying out nuclear magnetic resonance test on a target oil reservoir core sample to obtain an initial oil saturation, a pore distribution and a transverse relaxation time spectrum curve of a fluid occurrence state; Scanning the target oil reservoir core sample by using a CT scanning technology to construct a three-dimensional core pore structure model, and importing the nuclear magnetic resonance data to calibrate the initial fluid saturation, combining a CO2-crude oil phase state equation, an interfacial tension model and core permeability heterogeneity parameters to establish a dynamic displacement numerical simulation model; Designing multiple groups of huff and puff experiments to simulate CO2 injection processes under different development strategies, and simultaneously correcting fluid saturation, pressure field and interfacial tension parameters in the dynamic displacement numerical simulation model by monitoring changes in the nuclear magnetic resonance signals of the core during the displacement process in real time; Dividing a miscible phase region based on the fluid saturation, pressure field and interfacial tension parameters; Based on the distribution of the miscible phase region under different injection timing, soak time and huff and puff cycles, establishing a gas injection efficiency-recovery ratio relationship chart to select the best development parameter combination; The process of scanning the target oil reservoir core sample by using the CT scanning technology to construct the three-dimensional core pore structure model comprises: Placing the target oil reservoir core sample in a CT scanning device, scanning the target oil reservoir core sample from multiple angles to obtain a plurality of two-dimensional slice images, reconstructing the obtained two-dimensional slice images into a three-dimensional pore structure image by using an image reconstruction algorithm, and identifying a fracture network and a matrix pore in the three-dimensional pore structure image by using an image processing technology to determine spatial distribution characteristics, and then constructing the three-dimensional core pore structure model; The process of establishing the dynamic displacement numerical simulation model comprises: Selecting the CO2-crude oil phase state equation and the interfacial tension model, combining the permeability heterogeneity parameters of the core, and using numerical simulation technology to build and set parameters of the model to construct the dynamic displacement numerical simulation model which can simulate the dynamic displacement process of CO2 in the core; The process of dividing the miscible phase region based on the fluid saturation, pressure field and interfacial tension parameters comprises: Determining a miscible phase front according to a sudden increase of a light component signal in the nuclear magnetic resonance curve and a miscible phase pressure threshold in the numerical simulation pressure field, demarcating the miscible phase region in combination with the connectivity of a CO2 sweep path in the CT scanning image and a range in which the interfacial tension is reduced to a critical value, and determining a remaining oil region by using a residual oil peak in the nuclear magnetic resonance signal which does not change and a low displacement efficiency region in the numerical simulation; The process of determining the miscible phase front according to the sudden increase of the light component signal in the nuclear magnetic resonance curve and the miscible phase pressure threshold in the numerical simulation pressure field comprises: Analyzing the nuclear magnetic resonance curve to find a position at which the light component signal starts to significantly increase, and determining a region reaching the miscible phase pressure threshold in the pressure field result of the numerical simulation, comprehensively comparing and analyzing the two position information, and finally determining a position of the miscible phase front; The process of demarcating the miscible phase region in combination with the connectivity of the CO2 sweep path in the CT scanning image and the range in which the interfacial tension is reduced to the critical value comprises: Observe the sweep path of CO2 in CT scan image, analyze the connectivity, and view the area where the interfacial tension drops to the critical value in the numerical simulation result, combine the two results to determine the boundary and range of the miscible phase region; The process of determining the remaining oil region by using the unchanged residual oil peak in the nuclear magnetic resonance signal and the low displacement efficiency region in the numerical simulation includes: Analyze the nuclear magnetic resonance signal to find the position corresponding to the unchanged residual oil peak, and view the low displacement efficiency region in the numerical simulation result, and comprehensively consider the two position information to finally determine the region where the remaining oil is located.

2. The method of claim 1, wherein the process of performing nuclear magnetic resonance test on the target oil reservoir core sample to obtain the initial oil saturation, pore distribution and fluid occurrence state transverse relaxation time spectrum curve includes: Using a nuclear magnetic resonance device to perform multi-point measurement on the target oil reservoir core sample to obtain the transverse relaxation time spectrum curve at different positions, and performing average processing on the obtained curve to obtain the transverse relaxation time spectrum curve representing the initial oil saturation, pore distribution and fluid occurrence state of the whole target oil reservoir core sample.

3. The method of claim 1, wherein the process of designing multiple groups of throughput experiments to simulate CO2 injection process under different development strategies, and simultaneously correcting the fluid saturation, pressure field and interfacial tension parameters in the dynamic displacement numerical simulation model by real-time monitoring of the change of the nuclear magnetic resonance signal of the core during displacement process includes: According to the actual development needs, determine the development strategy parameters of multiple different injection switching times, soak time and throughput cycles, and perform throughput experiments according to these parameters, and use the nuclear magnetic resonance device to monitor the signal change of the target oil reservoir core sample in real time during the experiment, and dynamically adjust and correct the fluid saturation, pressure field and interfacial tension parameters in the numerical simulation model according to the signal change. The processor executes the computer program to implement the steps of the method of any one of claims 1-3. The processor executes the computer program to implement the steps of the method of any one of claims 1-3.

4. A computer apparatus comprising a memory, a processor, and a computer program stored on the memory, wherein the computer program, when executed by the processor, causes the processor to perform the method of any one of claims 1 to 3. ​

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