Shale volatile oil reservoir simulation method considering fracturing fluid injection phase change

Abstract

The invention relates to the technical field of numerical reservoir simulation, in particular to a shale volatile oil reservoir simulation method considering fracturing fluid injection phase change, comprising: acquiring shale volatile oil reservoir development parameters and core data of a target block; the method comprises the following steps: establishing a shale volatile oil reservoir numerical basic simulation model according to shale volatile oil reservoir development parameters, preparing a micro-fluidic chip according to core data, performing pore scale bubble point test, and correcting parameters of the basic simulation model according to bubble point data after fracturing fluid injection; establishing a shale volatile oil reservoir numerical value complete simulation model considering the fracturing fluid injection phase change, and analyzing the influence of the injected fracturing fluid on the oil and gas yield by using the shale volatile oil reservoir numerical value complete simulation model. According to the method, the production rule in the shale volatile oil reservoir exploitation process can be accurately obtained, the numerical simulation method of the shale volatile oil reservoir is perfected, and the method has important significance for guiding efficient development of the shale volatile oil reservoir.

Description

Technical Field

[0001] The present invention relates to the technical field of oil reservoir numerical simulation, in particular to a shale volatile oil reservoir simulation method taking into account the phase change of fracturing fluid injection. Background Art

[0002] my country boasts abundant shale oil resources. Currently, the combination of horizontal well technology and multi-stage hydraulic fracturing has significantly increased shale oil reserves and boosted production. Shale oil reservoirs are unconventional formations with widespread nanoscale pores, resulting in extremely low porosity and permeability. To exploit these reservoirs, hydraulic fracturing is often used to create an efficient fracture network.

[0003] In particular, in volatile shale reservoirs, due to the unique properties of this type of reservoir, after the injection of large amounts of fracturing fluid, the fluid phase undergoes significant changes as pressure changes, causing the fluid behavior to differ from that under bulk conditions. Therefore, accurately describing the phase properties of the fluid in volatile shale reservoirs after fracturing treatment is crucial for the effective development of this type of reservoir.

[0004] However, existing simulation methods for shale volatile oil reservoirs mostly rely on traditional reservoir simulation techniques. These methods struggle to accurately predict the actual production performance of shale volatile oil reservoirs, thus hindering the normal development process. Therefore, there is an urgent need to develop a new simulation method that fully considers the fluid phase changes caused by large-scale fracturing fluid injection to provide a scientific basis and technical support for the efficient development and utilization of shale volatile oil reservoirs. Summary of the Invention

[0005] The present invention provides a shale volatile oil reservoir simulation method that takes into account the phase changes caused by fracturing fluid injection. It fully considers the phase changes at different pore scales in the shale volatile oil reservoir after the fracturing fluid is injected. By accurately simulating the production dynamics of the shale volatile oil reservoir, the impact of the phase changes caused by the fracturing fluid injection on the output of the shale volatile oil reservoir is analyzed, and the production laws during the exploitation of the shale volatile oil reservoir are accurately obtained. The numerical simulation method of the shale volatile oil reservoir is improved, which is of great significance for guiding the efficient development of the shale volatile oil reservoir.

[0006] This application provides the following technical solutions: A shale volatile oil reservoir simulation method considering the phase change of fracturing fluid injection includes: S1. Obtain the development parameters and core data of shale volatile oil reservoirs in the target block; S2. Extract pore shape based on core data of target block; S3. Design a microfluidic chip model based on core data and considering the characteristics of fractures; S4. Perform pore-scale bubble point testing based on the microfluidic chip model to obtain pore-scale bubble point data after fracturing fluid injection; S5. Based on the development parameters of the shale volatile oil reservoir in the target block, a basic numerical simulation model of the shale volatile oil reservoir is established using the reservoir numerical simulation software CMG; S6. Apply the obtained pore-scale bubble point data after fracturing fluid injection to the numerical basic simulation model of shale volatile oil reservoirs, establish a complete simulation model of shale volatile oil reservoirs that takes into account the phase change of fracturing fluid injection, and analyze the impact of the phase change of fracturing fluid injection on oil and gas production.

[0007] Technical Principle: Acquire the development parameters and core samples of shale volatile oil reservoirs in the target block, analyze the core samples to obtain pore parameters, and construct a microfluidic chip based on the pore-fracture coupling model based on the pore parameters and fracture characteristics. Perform bubble point testing on the microfluidic chip to obtain bubble point data that can reflect the phase change after fracturing fluid injection; construct a basic numerical simulation model of the reservoir based on the development parameters of the shale volatile oil reservoir, and apply the bubble point data reflecting the phase change after fracturing fluid injection in the reservoir numerical model to realize a complete numerical simulation model of the reservoir that can take into account the phase change after fracturing fluid injection. Based on the completed reservoir numerical simulation model, oil and gas production is evaluated.

[0008] Beneficial Effects: This technical solution optimizes the entire process, from core sample analysis to reservoir numerical simulation, through a series of steps. It aims to accurately assess the oil and gas production of shale volatile oil reservoirs after fracturing fluid injection. Its core approach is to combine micro- and macro-scale data to construct a complete reservoir numerical model that reflects the fluid phase changes under actual reservoir conditions.

[0009] First, pore parameters were obtained by analyzing core samples from volatile oil reservoirs in the target shale. Taking into account the characteristics of fractures, a microfluidic chip based on a pore-fracture coupling model was constructed. This effectively simulates the actual pore and fracture network of the reservoir and allows for bubble point testing to obtain key data on phase changes after fracturing fluid injection. This data can help analyze the mechanism by which fracturing fluid affects fluid distribution within the reservoir.

[0010] Secondly, a basic reservoir numerical simulation model was constructed based on the development parameters of shale volatile oil reservoirs. In particular, bubble point data obtained from a microfluidic chip was used to adjust the model parameters, enabling it to more accurately reflect the phase changes after fracturing fluid injection. This step considers the impact of complex microscopic physical phenomena on macroscopic production behavior, significantly improving the model's accuracy and reliability.

[0011] A complete numerical reservoir simulation model, integrating both microscopic and macroscopic information, enables oil and gas production assessment. This approach provides more accurate production forecasts and helps precisely determine production dynamics and formulate optimal production systems. This entire process not only enhances understanding of the dynamic behavior of shale volatile oil reservoirs but also provides strong technical support for improving oil recovery and reducing development costs. This approach enables more scientific and rational reservoir management, maximizing economic benefits and resource utilization.

[0012] Furthermore, the shale volatile oil reservoir development parameters include reservoir structural parameters, reservoir physical property parameters, relative permeability data, formation fluid PVT parameters, well parameters and hydraulic fracturing parameters, wherein: The reservoir structural parameters describe the structural morphology of the reservoir, including reservoir size, burial depth and small layer thickness; The reservoir physical properties describe the oil and gas reserves, including formation pressure, permeability, porosity, rock compressibility and water saturation; The relative permeability data describes the flow capacity of oil, gas and water in the reservoir at different saturations; The formation fluid PVT parameters are used to describe the properties of the reservoir fluid, including the mole fraction of the components in the reservoir, the bubble point pressure at the formation temperature, the oil-gas ratio at different pressures, and the phase change parameters of each component under unrestricted conditions. The phase change parameters include the critical parameter, eccentricity factor, molar mass, and binary interaction coefficient, and the critical parameters include the critical pressure and critical temperature. The well parameters include well type, perforation location and working conditions, wherein the working conditions include bottom hole flowing pressure; The hydraulic fracturing parameters are used to obtain the distribution of fractures in the reservoir after hydraulic fracturing, including the number of hydraulic fracturing stages, stage spacing, number of hydraulic fracturing clusters, cluster spacing, half-length of hydraulic fractures, and height of hydraulic fractures; The core data are core samples collected from the target block.

[0013] Furthermore, the S2 includes: S2-1. Analyze core data to obtain shale pore size distribution data; S2-2. Draw a core pore size distribution map considering the porosity contribution according to the porosity and permeability of each core; S2-3, using a bimodal fitting method to determine the characteristic parameter distribution of the chip physical model; S2-4, obtain core scan images using a scanning electron microscope; S2-5. Binarize the core electron scanning image to extract the pore shape.

[0014] Furthermore, the S2-3 uses a Gaussian mixture model to fit the pore size distribution, and the two main characteristic pore parameters determined are 13 nm and 510 nm.

[0015] Furthermore, the S3 includes: S3-1. Design a pore network model based on core data analysis results; S3-2. Analyze the characteristics of hydraulic fractures and design a fracture network model. Integrate the pore network model with the fracture network model to form a pore-fracture coupling model that includes primary fractures and secondary fractures. S3-3. Measure the wetting angle of the core samples and calculate the average contact angle of the shale core to determine the modification plan; S3-4. Use the selected modification scheme to modify the microfluidic chip until the target wetting angle requirement is met.

[0016] Furthermore, the modification scheme includes a target wetting angle to be achieved, a concentration of a chemical agent used for the modification treatment, and a number of flushing times.

[0017] Furthermore, the target wetting angle is 65°.

[0018] Further, the S5 includes: S5-1. Determine the reservoir size and structure of the shale volatile oil reservoir based on the reservoir structural parameters and reservoir physical property parameters in the shale volatile oil reservoir development parameters. Use the Builder module in the reservoir numerical simulation software CMG to construct a shale volatile oil reservoir numerical simulation model. Set the grid size according to the actual situation of the target block and perform grid division on the shale volatile oil reservoir numerical simulation model. S5-2. Based on the reservoir physical properties and formation fluid PVT parameters in the shale volatile oil reservoir development parameters, combined with the relative permeability data in the shale volatile oil reservoir development parameters, the relative permeability data is set using the Builder module in the reservoir numerical simulation software CMG. The component data created by the WINPROP module is imported into the shale volatile oil reservoir numerical simulation model to construct the pore distribution within the shale reservoir and the distribution of formation fluids within the pores of the shale reservoir; S5-3. According to the well parameters in the shale volatile oil reservoir development parameters and in combination with the actual working conditions, set the well positions, perforation positions and working conditions of each well in the shale volatile oil reservoir numerical simulation model; S5-4. Based on the hydraulic fracturing parameters in the shale volatile oil reservoir development parameters, artificial fractures are established in the shale volatile oil reservoir numerical simulation model using grid encryption.

[0019] Further, the S6 includes: S6-1. Apply the pore-scale bubble point after fracturing fluid injection to the numerical simulation model of shale volatile oil reservoirs to establish a shale volatile oil reservoir model that takes into account the phase change of fracturing fluid injection; S6-2, simulate the phase changes of shale volatile oil reservoirs during fracturing fluid injection through three-phase flash calculation; S6-3. Use the shale volatile oil reservoir model that takes into account the phase change of fracturing fluid injection to simulate and calculate the oil and gas production of the shale volatile oil reservoir, and analyze the impact of the phase change of fracturing fluid injection on the oil and gas production based on the simulation results.

[0020] Furthermore, the S6 further includes: S6-4. Propose production optimization suggestions based on the analysis results of simulation calculations. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 This is a flow chart of a shale volatile oil reservoir simulation method considering the phase change of fracturing fluid injection according to the present invention; Figure 2 (a) is a schematic diagram of shale pore size distribution. Figure 2(b) is a schematic diagram of the core pore size distribution considering the porosity contribution. Figure 2 (c) is a schematic diagram of the characteristic parameter distribution of the chip physical model determined by bimodal fitting. Figure 2 (d) is a core electron scanning image. Figure 2 (e) is a schematic diagram of pore shape extraction from binary core electron scanning images; Figure 3 (a) is a schematic diagram of the pore network model. Figure 3 (b) is a schematic diagram of the hole-peak coupling model. Figure 3 (c) is a schematic diagram of the designed microfluidic chip; Figure 4 (a) shows the PT phase diagram of the fluid measured by the pore-scale bubble point test during the depressurization process. Figure 4 (b) shows the PT phase diagram of the fluid measured by the pore-scale bubble point test during the pressure reduction process after fracturing fluid injection; Figure 5 This is a schematic diagram of the numerical basic simulation model for shale volatile oil reservoirs; Figure 6 (a) is a comparison chart of cumulative oil production; Figure 6 (b) is a comparison chart of the cumulative gas production. DETAILED DESCRIPTION

[0022] This paper proposes a shale volatile oil reservoir simulation method that considers the phase behavior changes of fracturing fluid injection. This method is primarily based on CMG's reservoir numerical simulation tools. CMG's reservoir numerical simulation software tools can meet a wide range of reservoir simulation needs, from simple to complex. These tools not only facilitate a deeper understanding of reservoir flow patterns but also provide strong support for making scientific and rational development decisions. These tools include IMEX (providing extensive PVT (pressure-volume-temperature) processing capabilities), GEM (suitable for simulating more complex component models, including volatile oil reservoirs, condensate gas reservoirs, and CO2 flooding processes), WinProp (a standalone PVT analysis software for analyzing the phase behavior of reservoir fluids), Builder (a pre-processor for the CMG software series, used for creating and editing simulation models), and Results (a post-processor for viewing and analyzing simulation results).

[0023] The following is further described in detail through specific implementation methods: Example 1 A simulation method for shale volatile oil reservoirs considering the phase change of fracturing fluid injection, such as Figure 1 As shown, the specific steps include: S1. Obtain the development parameters and core data of shale volatile oil reservoirs in the target block.

[0024] In order to establish a numerical simulation model for the reservoir, it is necessary to obtain the original parameters of the target block, including shale volatile oil reservoir development parameters and core data.

[0025] The shale volatile oil reservoir development parameters include reservoir structural parameters, reservoir physical property parameters, relative permeability data, formation fluid PVT parameters, well parameters and hydraulic fracturing parameters. The reservoir structural parameters describe the structural morphology of the reservoir, including reservoir size, burial depth and small layer thickness; The reservoir physical properties describe the oil and gas reserves, including formation pressure, permeability, porosity, rock compressibility and water saturation; The relative permeability data describes the flow capacity of oil, gas and water in the reservoir at different saturations; The formation fluid PVT parameters are used to describe the properties of the reservoir fluid, including the mole fraction of the components in the reservoir, the bubble point pressure at the formation temperature, the oil-gas ratio at different pressures, and the phase change parameters of each component under unrestricted conditions. The phase change parameters include the critical parameter, eccentricity factor, molar mass, and binary interaction coefficient, and the critical parameters include the critical pressure and critical temperature. The well parameters include well type, perforation location and working conditions, wherein the working conditions include bottom hole flowing pressure; The hydraulic fracturing parameters are used to obtain the distribution of fractures in the reservoir after hydraulic fracturing, including the number of hydraulic fracturing stages, stage spacing, number of hydraulic fracturing clusters, cluster spacing, half-length of hydraulic fractures, and height of hydraulic fractures; The core data are core samples collected from the target block.

[0026] In this example, the target block's reservoir structural parameters include a reservoir size of 1100m × 600m × 10m, a buried depth of 2000m, and an average sub-layer thickness of 2m. Based on these reservoir structural parameters, a grid is divided into 55 × 30 × 5 sections. Reservoir physical properties include a formation pressure of 37.74MPa, an average porosity of 0.035, an average permeability of 0.004md, a water saturation of 33%, and a rock compressibility of 0.001MPa-1. The production wells in the target block are horizontal wells with a horizontal length of 700m and a bottomhole flowing pressure of 2MPa. Hydraulic fracturing parameters include 12 hydraulic fracture segments with a segment spacing of 60m, a hydraulic fracture half-length of 100m, and a height of 10m.

[0027] S2. Extracting pore shape based on the core data of the target block, specifically including the following steps: S2-1. Analyze core data to obtain shale pore size distribution data.

[0028] The pore structure data of shale is determined using tests such as mercury intrusion or gas adsorption.

[0029] In this example, the mercury intrusion method was used to analyze the core data, and the shale pore size distribution was obtained as shown in FIG2( a ).

[0030] S2-2. According to the porosity and permeability of each core, draw a core pore size distribution map considering the porosity contribution.

[0031] The pore size distribution data obtained from the mercury injection test were sorted out and the pore size distribution diagram of the core was drawn as shown in Figure 2(b).

[0032] S2-3. Use the bimodal fitting method to determine the characteristic parameter distribution of the chip physical model.

[0033] In this embodiment, the Gaussian mixture model (GMM) is used to fit the pore size distribution. As shown in FIG2( c ), the two main characteristic pore parameters are determined to be 13 nm and 510 nm.

[0034] S2-4. Obtain core scanning images using a scanning electron microscope.

[0035] The core data was cut, polished and coated, and the SEM image was obtained using a scanning electron microscope (SEM) as shown in Figure 2(d).

[0036] S2-5. Binarize the core electron scanning image to extract the pore shape.

[0037] The SEM images were imported into image processing software and the threshold algorithm was applied to convert the images into binary black and white images, where black represents the pore area and white represents the matrix area, as shown in Figure 2(e).

[0038] S3. Design a microfluidic chip model based on core data and considering the characteristics of fractures. Specifically including: S3-1. Design a pore network model based on core data analysis results; Depending on the pore distribution, a random network model or a regular network model can be selected. Based on core data analysis, parameters such as matrix, pore size, pore shape, and pore connectivity are determined. Software tools such as PoreSpy and OpenPNM are then used to generate a pore network model. The pore network model designed in this example is shown in Figure 3(a), where the white portion represents bimodal small and medium-sized nanopores, and the yellow portion represents bimodal medium and large nanopores.

[0039] S3-2. Analyze the characteristics of the hydraulic fractures and design a fracture network model. The pore network model and the fracture network model are integrated to form a pore-fracture coupling model including primary fractures and secondary fractures, as shown in Figure 3(b).

[0040] The pore-fracture coupling model can intuitively display the complex pore network and fracture structure within the reservoir, providing important foundational data for subsequent reservoir simulation and development strategy formulation. Based on the pore structure and fracture characteristics of the shale reservoir, the channel layout of the microfluidic chip is designed, including the microscopic geometry of the matrix pore and fracture network.

[0041] S3-3. Measure the wetting angle of the core samples and calculate the average contact angle of the shale core to determine the modification plan.

[0042] The surface of the microfluidic chip needs to be modified to adjust the wettability so that it is close to the actual reservoir conditions.

[0043] The modification scheme includes the target wetting angle to be achieved, the concentration of the chemical reagent used for the modification treatment, and the number of flushing times. The target wetting angle in this embodiment is 65°.

[0044] S3-4. Use the selected modification scheme to modify the microfluidic chip until the target wetting angle requirement is met.

[0045] The microfluidic chip based on the above design can precisely control the wetting properties, as shown in Figure 3(c).

[0046] S4. Based on the microfluidic chip model, a pore-scale bubble point test is performed to obtain the pore-scale bubble point data after the fracturing fluid is injected.

[0047] According to the formation conditions of the shale oil reservoir, a simulated liquid (such as an oil-gas mixture) that can represent the formation fluid is prepared to ensure that the fluid's composition, viscosity, density and other parameters are consistent with the actual reservoir fluid characteristics, completing the preparation of the microfluidic chip model.

[0048] Fill the sample with simulated fluid and perform a pore-scale bubble point test during the depressurization process. By analyzing the dynamic data of bubble formation during the depressurization process (including bubble point pressure, bubble number, size distribution, etc.), the phase change law at the pore scale can be evaluated.

[0049] Injecting fracturing fluid and conducting a pore-scale bubble point test after injection simulates the behavior of fracturing fluid invading the reservoir during actual fracturing. Comparing the bubble point pressure, bubble distribution, and number before and after fracturing fluid injection quantifies the impact of the fracturing fluid on pore-scale bubble point characteristics and analyzes the impact of the fracturing fluid on the phase state of the fluid within the pores.

[0050] In this embodiment, the bubble points of the fluid in the artificial fractures, microfractures and matrix pores are measured as shown in FIG4(a); the bubble points of the fluid in the artificial fractures, microfractures and matrix pores measured by the pore-scale bubble point test after the fracturing fluid is injected are shown in FIG4(b).

[0051] S5. Based on the development parameters of the shale volatile oil reservoir in the target block, a numerical simulation model of the shale volatile oil reservoir is established using the reservoir numerical simulation software CMG, which specifically includes the following steps: S5-1. Determine the reservoir size and structure of the shale volatile oil reservoir based on the reservoir structural parameters and reservoir physical parameters in the shale volatile oil reservoir development parameters. Use the Builder module in the reservoir numerical simulation software CMG to construct a numerical basic simulation model for the shale volatile oil reservoir, such as Figure 5 As shown, the grid size is set according to the actual situation of the target block, and the numerical simulation model of shale volatile oil reservoir is grid-divided. This embodiment adopts a local encrypted grid to finely describe the fracture area.

[0052] S5-2. Based on the reservoir physical properties and formation fluid PVT parameters in the shale volatile oil reservoir development parameters, combined with the relative permeability data in the shale volatile oil reservoir development parameters, the relative permeability data is set using the Builder module in the reservoir numerical simulation software CMG. The component data created by the WINPROP module is imported into the shale volatile oil reservoir numerical basic simulation model to construct the pore distribution within the shale reservoir and the formation fluid distribution within the shale reservoir pores.

[0053] S5-3. Based on the well parameters in the shale volatile oil reservoir development parameters and in combination with actual working conditions, set the well locations, perforation locations, and working conditions of each well in the shale volatile oil reservoir numerical basic simulation model; S5-4. Based on the hydraulic fracturing parameters in the shale volatile oil reservoir development parameters, artificial fractures are established using grid encryption in the shale volatile oil reservoir numerical basic simulation model.

[0054] S6. Apply the obtained pore-scale bubble point after fracturing fluid injection to the numerical basic simulation model of shale volatile oil reservoirs, establish a complete simulation model of shale volatile oil reservoirs that takes into account the phase change of fracturing fluid injection, and analyze the impact of the phase change of fracturing fluid injection on oil and gas production. Specifically, the steps include: S6-1. Apply the pore-scale bubble point after fracturing fluid injection to the basic numerical simulation model of shale volatile oil reservoirs to establish a complete simulation model of shale volatile oil reservoirs that takes into account the phase change of fracturing fluid injection; By integrating the bubble point data after fracturing fluid injection into the numerical simulation model, the phase changes after fracturing fluid injection can be reflected.

[0055] S6-2, simulate the phase changes of shale volatile oil reservoirs during fracturing fluid injection through three-phase flash calculation; S6-3. Use a complete simulation model of shale volatile oil reservoirs that takes into account the phase change of fracturing fluid injection to calculate the oil and gas production of shale volatile oil reservoirs. Based on the simulation results, analyze the impact of the phase change of fracturing fluid injection on the oil and gas production.

[0056] Since the bubble point of the fluid in different pore scales decreases after the fracturing fluid is injected, the crude oil will be degassed later, which is conducive to obtaining more oil production. In order to analyze the impact of fracturing fluid injection on the production of shale volatile oil reservoirs, the oil and gas production simulated without considering the phase change of fracturing injection are compared with the oil and gas production simulated with the phase change of fracturing fluid injection. As shown in Figure 6 (a), when the phase change of fracturing fluid injection is considered, the oil production in 3000 days is 17231m 3 Without considering the phase change of the fracturing fluid injection, the oil production in the same time is 16808m 3 As shown in Figure 6 (b), considering the phase change of the fracturing fluid injection, the gas production in 3000 days is 6.85×106m 3 Without considering the phase change of the fracturing fluid injection, the gas production in the same time is 6.58×106m 3 It can be seen that the injection of fracturing fluid leads to an increase in the gas-oil ratio of the fluid, and the gas production mainly comes from the degassing of ground crude oil, so the gas production also increases significantly.

[0057] S6-4. Propose production optimization suggestions based on the analysis results of simulation calculations.

[0058] Based on the analysis results of shale reservoir simulation calculations, and taking into account multiple aspects such as reservoir characteristics, fluid properties, and well pattern layout, a variety of production optimization suggestions based on simulation results can be put forward, such as adjusting completion design, improving fracturing strategy, optimizing fracture parameters, and optimizing fracturing fluid formulation.

[0059] The above are only embodiments of the present invention. The invention is not limited to the fields involved in this implementation case. Common knowledge such as the specific structure and characteristics of the scheme are not described in detail here. It should be pointed out that for those skilled in the art, without departing from the structure of the present invention, several modifications and improvements can be made, which should also be regarded as the scope of protection of the present invention. These will not affect the effect of the implementation of the present invention and the practicality of the patent. The scope of protection required by this application shall be based on the content of its claims, and the specific implementation methods and other records in the specification can be used to interpret the content of the claims.

Claims

1. A shale volatile oil reservoir simulation method considering the phase change of fracturing fluid injection, characterized by: include: S1. Obtain the development parameters and core data of shale volatile oil reservoirs in the target block; S2. Extract pore shape based on core data of target block; S3. Design a microfluidic chip model based on core data and considering the characteristics of fractures; S4. Perform pore-scale bubble point testing based on the microfluidic chip model to obtain pore-scale bubble point data after fracturing fluid injection; S5. Based on the development parameters of the shale volatile oil reservoir in the target block, a basic numerical simulation model of the shale volatile oil reservoir is established using the reservoir numerical simulation software CMG; S6. Apply the obtained pore-scale bubble point data after fracturing fluid injection to the basic numerical simulation model of shale volatile oil reservoirs, establish a complete numerical simulation model of shale volatile oil reservoirs that takes into account the phase change of fracturing fluid injection, and analyze the impact of the phase change of fracturing fluid injection on oil and gas production.

2. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 1, characterized in that: The shale volatile oil reservoir development parameters include reservoir structural parameters, reservoir physical property parameters, relative permeability data, formation fluid PVT parameters, well parameters and hydraulic fracturing parameters, among which: The reservoir structural parameters describe the structural morphology of the reservoir, including reservoir size, burial depth and small layer thickness; The reservoir physical properties describe the oil and gas reserves, including formation pressure, permeability, porosity, rock compressibility and water saturation; The relative permeability data describes the flow capacity of oil, gas and water in the reservoir at different saturations; The formation fluid PVT parameters are used to describe the properties of the reservoir fluid, including the mole fraction of the components in the reservoir, the bubble point pressure at the formation temperature, the oil-gas ratio at different pressures, and the phase change parameters of each component under unrestricted conditions. The phase change parameters include the critical parameter, eccentricity factor, molar mass, and binary interaction coefficient, and the critical parameters include the critical pressure and critical temperature. The well parameters include well type, perforation location and working conditions, wherein the working conditions include bottom hole flowing pressure; The hydraulic fracturing parameters are used to obtain the distribution of fractures in the reservoir after hydraulic fracturing, including the number of hydraulic fracturing stages, stage spacing, number of hydraulic fracturing clusters, cluster spacing, half-length of hydraulic fractures, and height of hydraulic fractures; The core data are core samples collected from the target block.

3. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 1, characterized in that: The S2 includes: S2-1. Analyze core data to obtain shale pore size distribution data; S2-2. Draw a core pore size distribution map considering the porosity contribution according to the porosity and permeability of each core; S2-3, using a bimodal fitting method to determine the characteristic parameter distribution of the chip physical model; S2-4, obtain core scan images using a scanning electron microscope; S2-5. Binarize the core electron scanning image to extract the pore shape.

4. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 3, characterized in that: S2-3 uses a Gaussian mixture model to fit the pore size distribution, and the two main characteristic pore parameters determined are 13nm and 510nm.

5. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 1, characterized in that: The S3 includes: S3-1. Design a pore network model based on core data analysis results; S3-2. Analyze the characteristics of hydraulic fractures and design a fracture network model. Integrate the pore network model with the fracture network model to form a pore-fracture coupling model that includes primary fractures and secondary fractures. S3-3. Measure the wetting angle of the core samples and calculate the average contact angle of the shale core to determine the modification plan; S3-4. Use the selected modification scheme to modify the microfluidic chip until the target wetting angle requirement is met.

6. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 5, characterized in that: The modification plan includes the target wetting angle to be achieved, the concentration of the chemical reagent used for the modification treatment, and the number of flushing times.

7. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 6, characterized in that: The target wetting angle is 65°.

8. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 1, characterized in that: The S5 includes: S5-1. Determine the reservoir size and structure of the shale volatile oil reservoir based on the reservoir structural parameters and reservoir physical property parameters in the shale volatile oil reservoir development parameters. Use the Builder module in the reservoir numerical simulation software CMG to construct a shale volatile oil reservoir numerical simulation model. Set the grid size according to the actual situation of the target block and perform grid division on the shale volatile oil reservoir numerical simulation model. S5-2. Based on the reservoir physical properties and formation fluid PVT parameters in the shale volatile oil reservoir development parameters, combined with the relative permeability data in the shale volatile oil reservoir development parameters, the relative permeability data is set using the Builder module in the reservoir numerical simulation software CMG. The component data created by the WINPROP module is imported into the shale volatile oil reservoir numerical simulation model to construct the pore distribution within the shale reservoir and the distribution of formation fluids within the pores of the shale reservoir; S5-3. According to the well parameters in the shale volatile oil reservoir development parameters and in combination with the actual working conditions, set the well positions, perforation positions and working conditions of each well in the shale volatile oil reservoir numerical simulation model; S5-4. Based on the hydraulic fracturing parameters in the shale volatile oil reservoir development parameters, artificial fractures are established in the shale volatile oil reservoir numerical simulation model using grid encryption.

9. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 1, characterized in that: The S6 includes: S6-1. Apply the pore-scale bubble point after fracturing fluid injection to the numerical simulation model of shale volatile oil reservoirs to establish a shale volatile oil reservoir model that takes into account the phase change of fracturing fluid injection; S6-2, simulate the phase changes of shale volatile oil reservoirs during fracturing fluid injection through three-phase flash calculation; S6-3. Use the shale volatile oil reservoir model that takes into account the phase change of fracturing fluid injection to simulate and calculate the oil and gas production of the shale volatile oil reservoir, and analyze the impact of the phase change of fracturing fluid injection on the oil and gas production based on the simulation results.

10. The method for simulating shale volatile oil reservoirs taking into account the phase change of fracturing fluid injection according to claim 9, characterized in that: The S6 further includes: S6-4. Propose production optimization suggestions based on the analysis results of simulation calculations.

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