A method, system and application of gas drive and channeling sealing in complex fracture network

Abstract

The present application relates to a gas drive channeling sealing method, a channeling sealing system and application in a complex fracture network. The channeling sealing method comprises the following steps: S1, determining the permeability lower limit of the medium-large scale fracture sealing under the gas drive condition according to the fracture sealing strength of the first plugging agent under different permeability of the medium-large scale fracture in the gas drive process; S2, determining the permeability differential range of the medium-small scale fracture and matrix suitable for the second plugging agent according to the displacement differential pressure variation law of the second plugging agent under different permeability differential of the medium-small scale fracture; S3, establishing a numerical simulation model according to the permeability lower limit and the differential range; S4, determining the conductivity multiplication coefficient of the medium-large scale fracture and the medium-small scale fracture after sealing according to the numerical simulation model and the parameter index after sealing; S5, determining the conductivity multiplication coefficient range of the two-stage channeling sealing in the actual reservoir; S6, determining the two-stage channeling sealing position optimization design model of the gas drive well in the well group, and obtaining the sealing position of the medium-large scale fracture and the medium-small scale fracture; and S7, determining the amount of the first plugging agent and the second plugging agent.

Description

Technical Field

[0001] This invention relates to the field of unconventional oil and gas reservoir development, specifically to a gas drive sealing method, sealing system, and application in complex fracture networks. Background Technology

[0002] my country possesses vast tight oil reserves, particularly in the southern Hubei region, a key battleground for tight oil development. Currently, the recovery rate is only 1.14%, highlighting the urgent need to overcome technical hurdles in effective development. The southern Hubei tight oil reservoirs suffer from low formation pressure coefficients, insufficient natural energy, and low single-well production. To explore development methods to supplement energy, a CO2 flooding pilot test was conducted in the HH12 well area. However, due to the influence of natural and artificial fractures, gas channeling was severe, resulting in unsatisfactory production enhancement. Currently, controlling gas channeling and effectively improving CO2 utilization are crucial for improving the effectiveness of gas-driven development.

[0003] To address the challenge of sealing gas leakage through complex fracture networks at multiple scales between wells, a two-stage sealing process is proposed to effectively control gas leakage across fractures of different scales, expand the injected gas sweep volume, and improve the recovery rate of tight oil reservoirs. However, there is no successful experience to draw upon in applying two-stage sealing technology to tight oil injection supplementary energy tests, and there are few reports on the staged sealing simulation characterization and optimization studies of complex fracture networks. Therefore, it is urgent to establish an optimized two-stage sealing method for CO2 flooding with complex fracture networks in tight oil reservoirs, and the following two main technical challenges need to be overcome in the research process:

[0004] (1) Lack of simulation and characterization methods for two-stage sealing and channeling in tight reservoirs based on plugging agent adaptability

[0005] Based on previous geological understanding and reservoir engineering research, the development of large and medium-scale fractures in the Honghe Chang 8 tight sandstone reservoir was quantitatively characterized. Based on this, a multi-scale fracture physical model gas injection and sealing experiment was carried out. However, there is currently no effective simulation and characterization method for evaluating the adaptability of numerical simulation technology to graded sealing of medium and large-scale fracture plugs during the gas injection process, which restricts the subsequent optimization design of gas injection and sealing.

[0006] (2) Lack of optimized design methods for gas injection and sealing under complex fracture network conditions in tight reservoirs

[0007] Due to the difficulty in characterizing and grading complex fracture networks between wells, the development of gas injection energy in tight reservoirs is still in the exploratory and experimental stage. There is a lack of relevant research and understanding both domestically and internationally on how to optimize gas injection sealing design.

[0008] Based on the problems existing in the prior art, the present invention aims to further optimize the design of the sealing process for complex seam meshes based on the two-stage sealing simulation characterization technology. Summary of the Invention

[0009] To address the aforementioned problems in existing technologies, this invention provides a gas drive sealing method, sealing system, and application in complex fracture networks. By employing the sealing method and sealing system of this invention, the process parameters for two-stage gas drive sealing in tight oil reservoirs can be optimized, forming an optimized design method for two-stage gas drive sealing under complex fracture network conditions in tight oil reservoirs. This significantly improves the swept volume of gas drive, increasing the cumulative oil production and recovery rate of well groups.

[0010] The first aspect of this invention provides a gas-driven sealing method for complex stitched meshes, the sealing method comprising the following steps:

[0011] S1. Based on the crack sealing strength of the first plugging agent under different permeabilities in medium and large-scale cracks during the gas drive process, determine the lower limit of permeability for sealing medium and large-scale cracks under gas drive conditions.

[0012] S2. Based on the variation law of displacement pressure difference of the second plugging agent under different permeability levels in small and medium-scale fractures, determine the range of permeability levels of small and medium-scale fractures and matrix for which the second plugging agent is applicable.

[0013] S3. Establish a numerical model based on the lower limit of permeability and the range of grade differences;

[0014] S4. Based on the numerical model and the parameter indicators after crack sealing, determine the conductivity multiplication factor after sealing the medium-to-large scale cracks and the medium-to-small scale cracks;

[0015] S5. Determine the range of the conductivity multiplication factor for two-stage gas drive channeling in actual oil reservoirs;

[0016] S6. Determine the optimal design model for the two-stage sealing and channeling positions between gas-driven wells in the well group, and obtain the sealing positions for the medium-to-large scale fractures and the medium-to-small scale fractures;

[0017] S7. Determine the dosage of the first plugging agent and the second plugging agent.

[0018] The sealing method provided by this invention addresses the challenge of sealing cross-contamination in complex multi-scale fracture networks between wells. It employs a two-stage sealing process and utilizes physical simulation experiments to study the adaptability of sealing agents for fractures of different scales, clarifying the sealing permeability limits for medium-to-large-scale and small-to-medium-scale fractures in gas-driven operations under complex fracture networks in tight oil reservoirs. Furthermore, by simulating and characterizing the experimental process, the process of simulating fracture sealing strength using the conductivity multiplier (MULTX) was determined. Combined with simulations of gas injection production enhancement effects under different sealing degrees in actual well groups, the sensitivity of the two-stage sealing conductivity multiplier under complex fracture network conditions was analyzed. The parameter setting range of the two-stage sealing conductivity multiplier was further determined, resulting in a two-stage sealing simulation characterization method. This method facilitates the optimization design of gas-driven sealing processes in well groups, forming an optimized two-stage sealing method for gas-driven operations under complex fracture networks in tight oil reservoirs.

[0019] Furthermore, the gas-driven process in this invention is preferably CO2-driven.

[0020] Furthermore, the sealing method and system for complex fracture networks provided by this invention can form an optimized design method for two-stage sealing during gas-driven operations. The optimized gas-driven swept volume is significantly increased, the cumulative oil production of the well group is increased, the oil exchange rate is increased, and the stage recovery degree and recovery rate are all improved to a certain extent. The sealing method and system provided by this invention provide strong technical support for the optimized design and development of two-stage sealing technology for gas-driven operations under complex fracture network conditions in tight oil reservoirs, and also provide important reference for the development of gas injection exploration in similar tight oil reservoirs.

[0021] In some embodiments of the present invention, cracks can be classified according to their opening size as large cracks (>100μm), medium cracks (10-100μm), small cracks (1-10μm), and micro cracks (<1μm).

[0022] According to some embodiments of the sealing method of the present invention, step S1 further includes: establishing a multi-scale fracture physical model based on the quantitative characterization results of the complex fracture network of the reservoir, determining the adaptability evaluation of the first plugging agent to medium and large-scale fractures during the gas drive process, and then obtaining the pseudo-resistance coefficient of the first plugging agent under different permeabilities of the medium and large-scale fractures, determining the fracture sealing strength in combination with the development of the medium and large-scale fractures and the composition of the first plugging agent, and determining the lower limit of permeability based on the data analysis results.

[0023] According to some embodiments of the sealing method of the present invention, step S2 further includes: establishing a multi-scale fracture physical model based on the quantitative characterization results of the complex fracture network of the oil reservoir, determining the adaptability evaluation of the second plugging agent to small and medium-scale fractures during the gas drive process, obtaining the displacement pressure difference variation law of the second plugging agent under different permeability levels of small and medium-scale fractures, and determining the range of the displacement pressure difference based on the increase of the displacement pressure difference.

[0024] In this step, the quantitative characterization results of the complex fracture network in the reservoir are determined based on the dynamic characterization technology of the fracture network between injection and production wells. This invention does not limit the method used in this quantitative characterization process. The multi-scale fracture physical model includes a core experimental physical model of the fractures. Furthermore, core experiments are used to evaluate whether the first and second plugging agents have good adaptability to medium-to-large-scale and medium-to-small-scale fractures, respectively, and to determine their applicable limits, thereby conducting an adaptability evaluation.

[0025] According to a preferred embodiment of the sealing method of the present invention, in step S3, a numerical model is established using the attribute parameters representing graded cracks in the Intersect numerical simulator.

[0026] According to some embodiments of the sealing method of the present invention, in step S4, the parameter index includes at least one of the changes in pressure, oil production, and gas production rate after sealing.

[0027] According to some embodiments of the sealing method of the present invention, in step S4, the experimental results are fitted using a numerical simulation method based on the numerical model obtained above, and then the conductivity multiplication factor after sealing medium-to-large scale cracks and medium-to-small scale cracks is determined.

[0028] According to some embodiments of the sealing method of the present invention, step S5 further includes: establishing a numerical model of the actual reservoir gas drive well group, and determining the range of the conductivity multiplication factor of the gas drive two-stage sealing method in the actual reservoir based on the conductivity multiplication factor in step S4.

[0029] In some embodiments of the sealing method according to the present invention, the first plugging agent is starch gel, and the second plugging agent is ethylenediamine. The types of the first and second plugging agents are not limited in this invention. For CO2 injection development in ultra-low permeability reservoirs, starch gel is preferred as a suitable plugging agent system when controlling medium-to-large-scale gas channeling, while ethylenediamine is preferred as a suitable plugging agent system when controlling CO2-driven gas channeling in small-to-medium-scale fractures. In different embodiments of the present invention, first and second plugging agents with different sealing performance can also be selected according to the actual sealing requirements.

[0030] According to some embodiments of the sealing method of the present invention, in step S6, based on the two-stage sealing position optimization design model, the sealing position, dosage and adaptability of the first plugging agent in medium and large-scale cracks can be determined, as well as the sealing position, dosage and adaptability of the second plugging agent in medium and small-scale cracks.

[0031] According to a preferred embodiment of the gas channel sealing method of the present invention, step S6 further includes: for medium and large-scale fractures, since the gas channel volume is small, it should be completely sealed; for medium and small-scale fractures, two sealing positions are considered, with the second plugging agent set at 1 / 3 of the distance from the injection well and 1 / 3 of the distance from the production well.

[0032] According to a preferred embodiment of the sealing method of the present invention, step S7 further includes: based on previous research on geology and reservoir engineering, the development volume of large-scale and small-scale fractures between different injection and production wells has been quantitatively characterized. Combining the above steps, a first plugging agent is used to seal the large-scale fractures, and the amount of the first plugging agent is equivalent to the volume of the large-scale fractures. A two-stage sealing process is used to seal the small-scale fracture network system, and the total amount of the obtained second plugging agent system is optimized. The volume of fractures sealed by the second plugging agent is determined according to the grade difference range obtained in step S2, and thus the amount of the second plugging agent is obtained.

[0033] A second aspect of the present invention provides a sealing system for the above-described sealing method in complex sewn mesh, the sealing system comprising:

[0034] The data acquisition module is used to collect the crack plugging strength of the first plugging agent under different permeabilities in medium and large-scale cracks during the gas drive process, determine the lower limit of permeability for plugging medium and large-scale cracks under gas drive conditions, and collect the displacement pressure difference variation law of the second plugging agent under different permeability levels in small and medium-scale cracks, and determine the range of permeability levels of small and medium-scale cracks and matrix for which the second plugging agent is applicable.

[0035] The data analysis module is used to establish a numerical model based on the lower limit of penetration rate and the range of grade differences;

[0036] The data integration module is used to determine the conductivity multiplication factor after sealing the medium-to-large scale fractures and the medium-to-small scale fractures based on the numerical model and the parameter indicators after fracture sealing, and to determine the range of the conductivity multiplication factor for gas-driven two-stage channeling in actual reservoirs.

[0037] The positioning module is used to determine the optimized design model for the two-stage sealing and channeling positions between gas-driven wells in the well group, and to obtain the sealing positions of the medium-to-large scale fractures and the medium-to-small scale fractures.

[0038] A dosing module is used to determine the dosage of the first plugging agent and the second plugging agent.

[0039] According to some embodiments of the sealing system of the present invention, the data acquisition module is further used to establish a multi-scale fracture physical model based on the quantitative characterization results of the complex fracture network of the reservoir, and to determine the adaptability evaluation of the first plugging agent to medium and large-scale fractures and / or the adaptability evaluation of the second plugging agent to medium and small-scale fractures during the gas drive process.

[0040] According to some embodiments of the sealing system of the present invention, the data integration module is further used to determine the range of the conductivity multiplication factor of the two-stage sealing system in the actual reservoir based on the numerical model of the actual reservoir gas drive well group and the conductivity multiplication factor after the medium-to-large scale fractures and medium-to-small scale fractures are sealed.

[0041] A third aspect of the present invention also provides an application of the above-described gas-driven sealing method or system for complex fracture networks in the oil recovery process of tight oil reservoirs with complex fracture networks. However, it is not limited thereto.

[0042] The beneficial effects of this invention are:

[0043] The gas-driven fracture sealing method and sealing system provided by this invention, based on numerical simulation characterization of gas-driven fracture sealing strength experiments in large-scale and small-scale fractures in tight reservoirs, analyzes the gas injection production enhancement effect of well groups under different sealing strengths, optimizes the gas-driven two-stage sealing process parameters, and obtains an optimized design model for gas-driven two-stage sealing under complex fracture network conditions in tight oil reservoirs.

[0044] The gas-driven sealing method and sealing system for complex fractured networks provided by this invention can increase the gas-driven swept volume from 1.4% to 24.1%, increase the cumulative oil production of the well group by 11,200 tons, achieve an oil exchange rate of 0.23t / t, improve the stage recovery rate by 3.76 percentage points, and achieve a recovery rate of 6.08%.

[0045] Furthermore, the gas-driven fracture sealing method and sealing system provided by this invention provide strong technical support for the optimized design and technological development of two-stage gas-driven fracture sealing technology in tight oil reservoirs, and also provide important reference for exploring effective gas injection development methods for similar tight oil reservoirs. Attached Figure Description

[0046] Figure 1 This is a flowchart of the starch gel blocking system blockage experiment provided in Example 1 of the present invention.

[0047] Figure 2 This is a flowchart of the ethylenediamine blocking experiment provided in Example 1 of the present invention.

[0048] Figure 3 The sealing strength of the starch gel with a monomer concentration of 4 wt% provided in Example 1 of this invention for cracks with different permeability under different dosages.

[0049] Figure 4 This is a schematic diagram of the displacement pressure difference curves for the continuous CO2 flooding and ethylenediamine blocking experiment provided in Example 1 of the present invention.

[0050] Figure 5 The diagram shows a numerical simulation model of the core test for sealing cracks provided in Embodiment 1 of the present invention, wherein the grid size is 1cm × 0.3cm × 0.5cm.

[0051] Figure 6 The figure shows the fitting curve of the gas production rate change before and after sealing in the CO2-driven core experiment provided in Example 1 of the present invention, wherein the amount of plugging agent used is 0.2 PV (pore volume).

[0052] Figure 7 This is a schematic diagram illustrating the influence of fracture sealing and channeling strength on production indicators under CO2 flooding conditions in well groups, as provided in Embodiment 1 of the present invention.

[0053] Figure 8This is a schematic diagram illustrating the optimized design concept for sealing and channeling locations of inter-well fractures provided in Embodiment 1 of the present invention.

[0054] Figure 9 This is a schematic diagram illustrating the optimized setting of the inter-well fracture sealing location provided in Embodiment 1 of the present invention.

[0055] Figure 10 This is a comparison curve of the predicted production curves of oil wells at different plugging locations in the CO2 flooding of the well group provided in Embodiment 1 of the present invention.

[0056] Figure 11 This is a comparison curve of the gas-oil ratio and cumulative oil production of oil wells under different plugging agent dosages in the small-to-medium scale fracture network development zone provided in Embodiment 1 of the present invention.

[0057] Figure 12 This is a schematic diagram showing the distribution of oil saturation changes in a well group over ten years of gas injection, as provided in Embodiment 1 of the present invention.

[0058] Figure 13 This is a schematic diagram of the cumulative oil production curve of a well group after ten years of CO2 flooding and two-stage sealing and channeling, as provided in Embodiment 1 of the present invention. Detailed Implementation

[0059] To make the present invention easier to understand, the present invention will be described in detail below with reference to embodiments and accompanying drawings. These embodiments are for illustrative purposes only and are not limited to the scope of application of the present invention.

[0060]

Example 1

[0061] This embodiment provides an optimization method for gas drive sealing and channeling under complex fracture network conditions in tight oil reservoirs, including the following process:

[0062] (1) Based on the quantitative characterization results of the complex fracture network in the tight oil reservoir in southern Hubei, a multi-scale fracture physical model was established. For example... Figure 1 and Figure 2 As shown, indoor experimental studies were conducted to evaluate the adaptability of starch gel to sealing and channeling of medium and large-scale cracks during CO2 flooding, and indoor experimental studies were conducted to evaluate the adaptability of ethylenediamine to sealing and channeling of medium and small-scale cracks.

[0063] (2) From step (1), the pseudo-resistance coefficient of starch gel under different effective permeabilities in medium and large-scale fractures can be obtained. Combined with the previous research on the development status of medium and large-scale fractures and plugging agent formulations in the tight reservoir of southern Hubei, the plugging strength of starch gel with a monomer concentration of 4wt% under different dosages for fractures with different permeabilities is obtained. Thus, the lower limit of permeability for plugging medium and large-scale fractures under CO2 flooding conditions is determined, such as... Figure 3 As shown.

[0064] (3) From step (1), the variation law of displacement pressure difference of ethylenediamine under different permeability levels in small and medium-scale fractures can be obtained. By analyzing the increase in displacement pressure difference, the suitable range of permeability difference between small and medium-scale fractures and the matrix that ethylenediamine can control can be obtained, such as... Figure 4 As shown.

[0065] (4) Based on the above steps (1), (2), and (3), establish the numerical model of the physical simulation, such as... Figure 5 As shown, experimental results such as changes in pressure, oil production, and gas production rate after fracture plugging were fitted, and the conductivity multiplication factor after plugging medium-to-large-scale and medium-to-small-scale fractures under experimental conditions was obtained, such as... Figure 6 As shown.

[0066] in, Figure 5 The core-scale numerical model was established based on the core physical model containing fractures produced in the laboratory experiment of the two-stage fracture sealing agent system. The figure is a permeability distribution map in the X direction, where the dark area in the middle of the model is the fracture zone with high permeability, and the other areas are dense matrix areas.

[0067] (5) Establish a numerical model of the CO2 flooding test well group in an actual oil reservoir to simulate the gas injection production enhancement effect of the well group under different sealing degrees, analyze the sensitivity of the conductivity multiplier under complex fracture network conditions, and obtain the range of values ​​for the conductivity multiplier of the two-stage sealing of large-scale fractures and small-scale fracture networks in actual tight oil reservoirs during CO2 flooding. The results are as follows: Figure 7 As shown.

[0068] (6) Based on steps (2), (3), (4) and (5) above, establish an optimized design concept for the two-stage sealing and channeling positions between CO2-driven wells in the well group, such as... Figure 8 As shown. For medium- to large-scale fractures, due to the small volume of gas channeling pathways, they should all be sealed. For small- to medium-scale fracture networks, consider the following... Figure 9 The two sealing locations shown are: the plugging agent is placed at 1 / 3 of the distance from the injection well to the push-out well, and at 1 / 3 of the distance from the production well to the push-out well. Through numerical simulation optimization, the optimal fracture sealing location for the CO2-driven well group was obtained, as shown below. Figure 10 As shown.

[0069] in, Figure 9 The base map in the image is the fracture model of the CO2 injection test well group. Figure 9The three diagrams in the middle represent the range of fracture sealing locations between each well. The fractures between wells HH12P152 and HH12P72 are mainly small to medium-sized fractures, and the upper box indicates the location of the second plugging agent, ethylenediamine, in the fracture sealing location between these wells. The fractures between wells HH156 and HH12P70 are mainly medium to large-sized fractures, and the lower left ellipse indicates the location of the first plugging agent, starch gel, in the fracture sealing location between these wells. The fractures between wells HH12P72 and HH12P48 are mainly small to medium-sized fractures, and the lower right ellipse indicates the location of the second plugging agent, ethylenediamine, in the fracture sealing location between these wells.

[0070] (7) Based on previous geological and reservoir engineering research, the development volume of large-scale and small-scale fractures between different injection and production wells was quantitatively characterized. Accordingly, combined with steps (2), (3), (4), and (5), a design was developed to use starch gel or higher-strength inorganic plugging agents to seal large-scale fractures, with the plugging agent dosage being equivalent to the fracture volume. A two-stage sealing process was used to seal the small-scale fracture network system, optimizing the total dosage of the plugging agent system. The dosage of ethylenediamine was determined based on the lower limit of the permeability difference obtained in step (3), thus determining the fracture volume to be sealed by ethylenediamine, and consequently, the dosage of ethylenediamine. Figure 11 As shown.

[0071] like Figure 12 and Figure 13 As shown in this embodiment, after the two-stage sealing optimization of the actual well group, the CO2 sweep volume of the well group was greatly expanded, the CO2 sweep range increased from 1.4% to 24.1%, the oil exchange rate per ton of gas was 0.23t / t, the stage recovery degree was increased by 3.76 percentage points, and the recovery rate reached 6.08%.

[0072] The above description is merely a preferred embodiment of the present invention. It should be noted that, for those skilled in the art, based on the technical teachings provided by the present invention and as common knowledge in the field, other equivalent modifications and improvements can be made, and these should also be considered within the scope of protection of the present invention.

Claims

1. A gas-driven method for sealing off cross-linking in complex stitched mesh, the method comprising the following steps: S1. Based on the crack sealing strength of the first plugging agent under different permeabilities in medium and large-scale cracks during the gas drive process, determine the lower limit of permeability for sealing medium and large-scale cracks under gas drive conditions. S2. Based on the variation law of displacement pressure difference of the second plugging agent under different permeability levels in small and medium-scale fractures, determine the range of permeability levels of small and medium-scale fractures and matrix for which the second plugging agent is applicable. S3. Establish a numerical model based on the lower limit of permeability and the range of grade differences; S4. Based on the numerical model, fit the experimental results of the changes in pressure, oil production, and gas production rate after crack plugging obtained in steps S1 and S2, and obtain the conductivity multiplication factor after plugging the medium-to-large scale cracks and medium-to-small scale cracks under the experimental conditions. S5. Determine the range of the conductivity multiplication factor for two-stage gas drive channeling in actual oil reservoirs; S6. Determine the optimal design model for the two-stage sealing and channeling positions between gas-driven wells in the well group, and obtain the sealing positions for the medium-to-large scale fractures and the medium-to-small scale fractures; S7. Determine the dosage of the first plugging agent and the second plugging agent.

2. The sealing method according to claim 1, characterized in that, Step S1 also includes: establishing a multi-scale fracture physical model based on the quantitative characterization results of the complex fracture network in the oil reservoir, determining the adaptability evaluation of the first plugging agent to medium and large-scale fractures during the gas drive process, and then obtaining the pseudo-resistance coefficient of the first plugging agent under different permeabilities of the medium and large-scale fractures. Combining the development of the medium and large-scale fractures and the composition of the first plugging agent, the fracture sealing strength is determined, and the lower limit of permeability is determined.

3. The sealing method according to claim 1 or 2, characterized in that, Step S2 also includes: establishing a multi-scale fracture physical model based on the quantitative characterization results of the complex fracture network of the oil reservoir, determining the adaptability evaluation of the second plugging agent to small and medium-scale fractures during the gas drive process, obtaining the displacement pressure difference variation law of the second plugging agent under different permeability levels of small and medium-scale fractures, and determining the range of the displacement pressure difference based on the increase of the displacement pressure difference.

4. The sealing method according to claim 1 or 2, characterized in that, Step S5 also includes: establishing a numerical model of the actual reservoir gas drive well group, and determining the range of the conductivity multiplication factor of the actual reservoir gas drive two-stage sealing based on the conductivity multiplication factor in step S4.

5. The sealing method according to claim 1 or 2, characterized in that, The first plugging agent is starch gel, and the second plugging agent is ethylenediamine.

6. A sealing system for use in the gas-driven sealing method for complex stitched meshes according to any one of claims 1-5, characterized in that, The blocking system includes: The data acquisition module is used to collect the crack plugging strength of the first plugging agent under different permeabilities in medium and large-scale cracks during the gas drive process, determine the lower limit of permeability for plugging medium and large-scale cracks under gas drive conditions, and collect the displacement pressure difference variation law of the second plugging agent under different permeability levels in small and medium-scale cracks, and determine the range of permeability levels of small and medium-scale cracks and matrix for which the second plugging agent is applicable. The data analysis module is used to establish a numerical model based on the lower limit of penetration rate and the range of grade differences; The data integration module is used to determine the conductivity multiplication factor after sealing the medium-to-large scale fractures and the medium-to-small scale fractures based on the numerical model and the parameter indicators after fracture sealing, and to determine the range of the conductivity multiplication factor for gas-driven two-stage channeling in actual reservoirs. The positioning module is used to determine the optimized design model for the two-stage sealing and channeling positions between gas-driven wells in the well group, and to obtain the sealing positions of the medium-to-large scale fractures and the medium-to-small scale fractures. A dosing module is used to determine the dosage of the first plugging agent and the second plugging agent.

7. The sealing and blocking system according to claim 6, characterized in that, The data acquisition module is also used to establish a multi-scale fracture physical model based on the quantitative characterization results of the complex fracture network in the reservoir, and to determine the adaptability evaluation of the first plugging agent to medium and large-scale fractures and / or the adaptability evaluation of the second plugging agent to medium and small-scale fractures during the gas drive process.

8. The sealing and blocking system according to claim 6 or 7, characterized in that, The data integration module is also used to determine the range of the conductivity multiplication factor for two-stage gas drive well group sealing in the actual reservoir based on the numerical model of the actual reservoir gas drive well group and the conductivity multiplication factor after the medium-to-large scale fractures and medium-to-small scale fractures are plugged.

9. The application of a gas-driven sealing method for complex fracture networks as described in any one of claims 1-5 or a gas-driven sealing system for complex fracture networks as described in any one of claims 6-8 in the oil production process of complex fracture networks in tight oil reservoirs.

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