A method for regulating fracture conductivity and interwell connectivity with EGS graded proppant

Abstract

The application discloses a kind of EGS grading support agent regulation fracture conductivity and interwell communication method, belong to geothermal resource development field, including the following steps: S1: fracture network partition and conductivity design: based on the geomechanical parameter of target dry hot rock reservoir, geothermal field distribution and well layout, with injection well and production well as center, the fracturing influence area of injection well and production well is divided into near well high conductivity area, transition regulation area and far well communication area;Injection well and production well far well communication area interpenetration forms interwell continuous conductivity channel.The application constructs gradient conductivity fracture network, solves the problem of traditional EGS single support agent high temperature conductivity attenuation, interwell flow dead zone, early heat breakthrough, realizes long-term stability of fracture conductivity, improves interwell communication and heat extraction efficiency, delays heat breakthrough, applicable to deep high temperature dry hot rock artificial thermal reservoir construction.

Description

Technical Field

[0001] This invention relates to the field of geothermal resource development technology, and in particular to a method for regulating fracture flow and inter-well connectivity using EGS graded proppant. Background Technology

[0002] Enhanced geothermal systems (EGS) are a clean geothermal development technology that utilizes artificial hydraulic fracturing to create a fracture network in low-permeability hot dry rock (HDR), forming an artificial geothermal reservoir and enabling thermal energy extraction. Currently, the core technological bottleneck in the engineering application of EGS lies in the fracture network construction and operational control phases, specifically manifested as follows: Firstly, there is the issue of reduced fracture conductivity. Traditional EGS fracturing uses proppant of a single particle size. Under long-term high-temperature and high-pressure geothermal fluid circulation, the proppant is prone to embedding, breakage, and migration, leading to a gradual decrease in fracture aperture and an exponential decline in conductivity. Studies have shown that traditional proppants can lose 30%-50% of their strength in environments above 200℃, severely affecting the long-term operational stability of the system.

[0003] Secondly, the lack of connectivity between wells makes it difficult for existing fracturing technologies to accurately control the direction and shape of fracture expansion, which can easily lead to the formation of a single main fracture or local blockage of the fracture network. This results in fluid short-circuiting or dead zones between the injection well and the production well, limiting the effective heat exchange area and causing low system heat recovery efficiency.

[0004] Third, premature thermal breakthrough occurs because the fracture network is highly heterogeneous, and high-conductivity channels preferentially form dominant flow paths, causing geothermal fluids to rapidly break through to the production well, resulting in a sharp drop in production temperature (thermal breakthrough) and a shortened system economic lifespan. Some publicly disclosed EGS demonstration projects have experienced a significant reduction in system lifespan due to thermal breakthrough.

[0005] Fourth, heat loss is severe. The fracture network does not make sufficient contact with the surrounding rock, the fluid flows too fast in the fractures, the heat exchange time is insufficient, a large amount of heat energy is retained inside the rock mass, and the heat extraction efficiency is generally less than 10%.

[0006] To address the aforementioned issues, existing technologies primarily employ methods such as chemical stimulation, repeated fracturing, and variable displacement injection. However, these methods suffer from drawbacks such as complex processes, high costs, and uncontrollable effects. Furthermore, existing improvement methods mainly focus on numerical simulation of fracturing, post-fracturing secondary repeated fracturing, and simple chemical temporary plugging during the construction phase. These are all remedial measures after fluid short-circuiting occurs and cannot systematically address the aforementioned deficiencies from the perspectives of reservoir spatial layout, graded matching of proppant materials, and the source of fracturing construction. Although reverse proppant addition and graded proppant fracturing processes are publicly available in the oil and gas sector, oil and gas reservoirs operate under low-temperature and low-closure stress conditions, which differ significantly from the high-temperature and high-stress environment of hot dry rocks above 200°C. Summary of the Invention

[0007] Purpose of the Invention: The purpose of this invention is to provide a method for regulating fracture conductivity and inter-well connectivity using graded proppant in EGS, solving the technical problems caused by the use of a single proppant in traditional EGS, such as rapid conductivity decay at high temperatures, numerous dead zones in inter-well flow, premature thermal breakthrough induced by dominant flow, and low thermal extraction efficiency. By spatially grading the proppant particle size and concentration, a gradient non-uniform conductivity fracture network is constructed, achieving the technical goals of long-term stable fracture conductivity, directional enhancement of inter-well connectivity, significant improvement in heat exchange efficiency, and effective delay of thermal breakthrough.

[0008] Technical solution: A method for regulating fracture conductivity and inter-well connectivity using EGS-graded proppant includes the following steps: S1: Fracture Network Zoning and Conductivity Design: Based on the geomechanical parameters, geothermal field distribution, and well layout of the target hot dry rock reservoir, with the injection well and production well as the center, the fracturing influence zone of both the injection well and the production well is divided into a near-wellbore high conductivity zone, a transition control zone, and a far-wellbore connectivity zone. The far-wellbore connectivity zones of the injection well and the production well are interconnected to form a continuous inter-wellbore conductivity channel. The geothermal fluid circulation path passes sequentially through the near-wellbore high conductivity zone of the injection well, the transition control zone of the injection well, the far-wellbore connectivity zone of the injection well, the far-wellbore connectivity zone of the production well, the transition control zone of the production well, and the near-wellbore high conductivity zone of the production well. When the system is running, the constructed gradient non-uniform flow-conducting fracture network forms a complete seepage channel from the injection well to the production well: cold water enters from the injection well and flows sequentially through the near-well high conductivity zone, transition control zone, and far-well connectivity zone of the injection well. After the far-well connectivity zone connects with the far-well connectivity zone of the production well, it continues to flow through the far-well connectivity zone, transition control zone, and near-well high conductivity zone of the production well, and finally exits through the production well.

[0009] The design objectives of this operational path are as follows: Utilizing a three-stage gradient flow guidance architecture, fluids can rapidly pass through the near-wellbore high-conductivity zone with large fracture openings and high conductivity, significantly reducing near-wellbore flow resistance and pumping energy consumption; in the transition control zone, medium flow velocities are used to balance reservoir pressure distribution, suppressing the formation of high-conductivity dominant flow channels and preventing local fluid concentration; in the far-wellbore interconnection zone, low flow velocities and long seepage paths facilitate sufficient heat exchange with the high-temperature surrounding rock, extending the heat exchange time of the fluid in the reservoir and achieving efficient heat extraction; simultaneously, the far-wellbore interconnection zones of the injection well and production well are interconnected, ensuring a uniform and stable interconnected volume between wells, eliminating flow dead zones, effectively delaying thermal breakthrough time, and improving the overall system's heat recovery efficiency and economic lifespan.

[0010] S2: Three-stage proppant selection: The near-wellbore high conductivity zone is equipped with primary proppant with a particle size of 0.9–1.2 mm and a volume concentration of 15%–25%; the transition control zone is equipped with secondary proppant with a particle size of 0.45–0.6 mm and a volume concentration of 8%–15%; the far-wellbore connectivity zone is equipped with tertiary proppant with a particle size of 0.2–0.3 mm and a volume concentration of 3%–8%; the primary, secondary, and tertiary proppants are all high-temperature resistant ceramic particles or resin-coated ceramic particles with a compressive strength ≥69 MPa; meeting the requirements of high-temperature and high-pressure reservoir conditions.

[0011] S3: Preferred Reverse Stage Fracturing and Resin Curing Construction in Distant Wells: Directional perforation is performed along the line connecting the injection well and the production well to inject pre-fracturing fluid to create hydraulic fractures in the reservoir. Following the sequence of first fracturing the distant well connectivity zone to build a microfracture network, then expanding and stabilizing secondary fractures in the transition control zone, and finally strengthening and building high-conductivity channels in the near-wellbore high-conductivity zone, fracturing fluids carrying tertiary, secondary, and primary proppant are pumped sequentially, ensuring that the tertiary, secondary, and primary proppants are sequentially laid in the distant well connectivity zone, transition control zone, and near-wellbore high-conductivity zone. In this application, "proppant-carrying fracturing fluid" and "proppant ratio" are both common technical terms in the field of hydraulic fracturing; "sand" is a general term for proppant in the industry and is not limited to quartz sand, but includes the high-temperature resistant ceramic granules and resin-coated ceramic granules used in this invention; the "proppant ratio" refers to the ratio of proppant volume to fracturing fluid volume. After completing the above-mentioned sand-carrying fracturing fluid pumping operation, a low-viscosity displacement fluid is injected to allow the tertiary, secondary, and primary proppant to settle and position. Then, a curable resin coating liquid is injected to fully cure the proppant using the reservoir temperature conditions of 80~220℃. The well is shut in and left to solidify for no less than 48 hours to lock the primary, secondary, and tertiary proppant within the target fracture to form a zoned gradient propping framework.

[0012] Optionally, in step S1, the near-wellbore high conductivity zone is an area with a radius of 10–30 m around the wellbore, designed with a conductivity of 10–50 D to reduce fluid flow resistance in the near-wellbore area; the transition control zone is an area with a radius of 30–150 m, designed with a conductivity of 1–10 D to balance reservoir pressure distribution and suppress the formation of dominant flows; the far-wellbore connectivity zone is an area with a radius of 150–500 m, designed with a conductivity of 0.1–1 D to extend fluid heat exchange time and achieve uniform connectivity between wells. It should be noted that the radii given for each zone are the range of values ​​for the zone boundaries, and can be selected within the corresponding range based on reservoir geological conditions during actual engineering implementation; the boundaries of adjacent zones overlap to achieve gapless coverage of the fracturing-affected area.

[0013] Optionally, in step S2, the turbidity of the primary, secondary, and tertiary proppant is ≤100 FTU; the sphericity of the primary proppant is ≥0.9, and the acid solubility is ≤5%; the surfaces of the secondary and tertiary proppant are coated with a phenolic resin pre-cured layer with a temperature resistance rating of not less than 250℃.

[0014] Optionally, in step S3, the installation and pressure testing of the ground supporting facilities shall be completed before construction, and the test pressure shall not be less than 1.2 times the maximum construction pressure. The ground supporting facilities include ground pump sets, sand mixing equipment and manifold system; the perforation density of the directional perforation is 16 holes / m, and the phase angle is 60°.

[0015] Optionally, in step S3, the fracturing of the far-well connectivity zone to construct a microfracture network is the far-well fracturing stage, and the displacement rate in this stage is 2-4 m³ / s. 3 The flow rate is 4-6 m / min, using low-viscosity fracturing fluid to deliver the third-stage proppant; the transition control zone expands and stabilizes secondary fractures, which is the transition expansion stage, during which the flow rate is increased to 4-6 m / min. 3 The secondary proppant is delivered at a rate of 6-10 m³ / min using medium-viscosity fracturing fluid. The near-wellbore high-conductivity zone enhancement stage involves constructing a high-conductivity channel, with a flow rate of 6-10 m³ / min. 3 The flow rate is [ratio] / min, using high-viscosity fracturing fluid to deliver primary proppant. High-conductivity channels are the main fractures.

[0016] Optionally, the fracturing fluid viscosity is 5~10 mPa·s during the far-well fracturing stage; 30~50 mPa·s during the transitional propagation stage; and 100~200 mPa·s during the near-well reinforcement stage. During the construction process, microseismic monitoring is used to track the fracture propagation range in real time to ensure that the fractures in the far-well connectivity zone of the injection well extend toward the production well.

[0017] Optionally, in step S3, the far-wellbore fracturing stage, the transition expansion stage, and the near-wellbore enhancement stage all employ a stepped increase in the sand ratio for sand addition operations. Specifically, in the far-wellbore stage, the sand ratio is increased in a stepped manner, starting at 3% and increasing by 1% every 2 hours until it stabilizes at 8%. In the transition expansion stage, the sand ratio is increased from 8% to 15% in a stepped manner, increasing by 2% every 3 hours. In the near-wellbore enhancement stage, the sand ratio is increased from 20% to 28% in a stepped manner, increasing by 3% every 4 hours.

[0018] Optionally, in step S3, injecting a low-viscosity displacement fluid to allow the tertiary, secondary, and primary proppant to settle and be positioned constitutes the displacement and solidification stage. In this stage, low-viscosity slickwater is first injected as the displacement fluid to displace all the primary, secondary, and tertiary proppant in the wellbore and near-well high conductivity zone to the target fracture location. Then, a curable phenolic resin coating fluid is injected, followed by a post-displacement fluid to push the resin coating fluid into the fractures of the near-well high conductivity zone, transition control zone, and far-well connectivity zone.

[0019] The flow concentration factor Fc = maximum flow rate of a single cluster (single crack) / average flow rate of all clusters in that segment, i.e.: Fc = qmax / q Where qmax is the flow rate of the cluster with the most influent; q is the theoretical average flow rate (total discharge / number of clusters) of all perforation clusters in this section, which is divided into the following states: 1. Fc=1.0: Ideally uniform, with each cluster receiving exactly the same amount of liquid; 2. Fc≤2.0: The flow distribution is relatively uniform, there are no obviously dominant cracks, and multiple clusters of cracks expand synchronously; 3. Fc>2.0: A few clusters compete for most of the fracturing fluid, resulting in a significantly dominant flow channel (dominant fracture).

[0020] Optionally, dynamic flow control and thermal breakthrough early warning steps are also included: reservoir temperature and flow data are collected in real time through a downhole distributed fiber optic sensing device, which consists of a downhole temperature sensor and a fiber optic monitoring cable. The surface control system automatically determines the control threshold and initiates the temporary plugging agent injection procedure. When a local temperature gradient > 5℃ / m or a flow concentration factor > 2.0 is detected, a degradable temporary plugging agent is injected into the dominant flow channel. The degradable temporary plugging agent is injected by a temporary plugging agent injection device. The particle size of the temporary plugging agent is 1 / 5 to 1 / 3 of the particle size of the primary, secondary, and tertiary proppant in the near-wellbore high conductivity zone, transition control zone, and far-wellbore connectivity zone. The temporary plugging agent completely degrades under geothermal environmental conditions for 48 to 72 hours, achieving reversible control of the fracture flow pattern. The injection pressure is increased simultaneously with the injection of the degradable temporary plugging agent, forcing the geothermal fluid to turn to the low conductivity zone, balancing the flow distribution within the fracture network. After the temperature field returns to uniformity, the temporary plugging agent automatically degrades under the action of geothermal temperature, restoring the flow pattern.

[0021] Optionally, after the well is shut in and allowed to solidify, the well is opened to release the excess fracturing fluid and resin residue, and then pressure drop test and tracer detection are performed to verify the fracture conductivity and inter-well connectivity. After passing the tests, the system enters the geothermal system circulation operation phase.

[0022] Beneficial effects: 1. Significantly improved conductivity stability: By matching high-temperature resistant proppant of corresponding specifications with fractures of different scales in three zones, and cooperating with resin coating liquid to solidify and lock, a zoned gradient support skeleton is formed, which inhibits the breakage, embedding and migration behavior of proppant under high temperature conditions, significantly reduces the rate of decay of conductivity, and extends the design operating life of the reservoir.

[0023] 2. Significantly enhanced inter-well connectivity: Through the near-well-transition-far-well three-zone gradient flow guiding architecture, the far-well connectivity zone of the injection well and the far-well connectivity zone of the production well are interconnected, eliminating a large number of flow dead zones, effectively increasing the heat exchange connectivity volume, and improving the utilization rate of geothermal resources in dry hot rock mass.

[0024] 3. Highly optimized heat exchange efficiency: The gradient flow guide structure constrains the fluid seepage path, reduces flow resistance near the well, and enables low-speed, long-path heat exchange far from the well, extending the contact time between the working fluid and the high-temperature surrounding rock, thus significantly improving the heat extraction efficiency.

[0025] 4. Effectively delay thermal breakthrough: Relying on the buffer effect of the transition control zone, the generation of a single dominant flow short-circuit channel is suppressed. Combined with optional fiber-optic-degradable temporary blocking dynamic control methods, the thermal breakthrough time is delayed, extending the economic mining cycle of the power plant.

[0026] 5. Improved process controllability and economy: Reverse staged precise sand addition allows the fracturing scheme to be iteratively optimized according to geological conditions, reducing engineering construction risks; although the use of proppant and resin materials brings a slight increase in initial investment, the system life is extended and the heat output is improved. Compared with the traditional single proppant fracturing scheme, the cost per kilowatt-hour of mining can be reduced. Attached Figure Description

[0027] Figure 1 This is a schematic diagram of the fracture partitioning structure of the present invention (the arrows in the diagram indicate the direction of geothermal fluid seepage from the injection well to the production well); Figure 2 This is a partial schematic diagram of the cracks and proppant in this invention; Figure 3 This is a schematic diagram of the fracturing and monitoring system of the present invention; Figure 4 This is a schematic diagram of the advantageous flow channel, proppant (taking secondary proppant as an example), and temporary plugging agent sealing of the present invention; In the diagram: 1. Injection well; 2. Production well; 3. Near-well high conductivity zone; 4. Transition control zone; 5. Far-well connectivity zone; 6. Primary proppant; 7. Secondary proppant; 8. Tertiary proppant; 9. Primary fracture; 10. Secondary fracture; 11. Microfracture network; 12. Manifold system; 13. Sand mixing equipment; 14. Temporary plugging agent injection device; 15. Downhole temperature sensor; 16. Fiber optic monitoring cable; 17. Surface control system; 18. Dominant flow channel; 19. Temporary plugging agent; 20. Surface pump set. Detailed Implementation

[0028] To make the technical solution of the present invention clearer, the present invention will be further described in detail below with reference to the accompanying drawings and specific embodiments.

[0029] like Figures 1-4 This is a schematic diagram illustrating the process principle of the present invention.

[0030] Combined with appendix Figures 1-3 The system composition and implementation logic of the present invention are as follows: 1. Fracture Network Zoning Structure: Centered on injection well 1 and production well 2, a semi-concentric three-level functional zoning is constructed. The near-wellbore high conductivity zone 3, transition control zone 4, and far-wellbore connectivity zone 5 form a gradient fracture influence area; in the near-wellbore high conductivity zone 3, primary proppant 6 supports the main fracture 9; in the transition control zone 4, secondary proppant 7 supports the secondary fracture 10; in the far-wellbore connectivity zone 5, tertiary proppant 8 supports the microfracture network 11; the particle size of the primary, secondary, and tertiary proppants in the near-wellbore high conductivity zone, transition control zone, and far-wellbore connectivity zone gradually changes, achieving a smooth transition in conductivity and avoiding flow instability.

[0031] 2. Fracturing construction system: The fracturing fluid injection manifold system 12 connects the surface pump group 20 to the downhole perforation section, and achieves precise delivery of proppant through graded discharge and sand ratio control; the sand mixing equipment 13 is equipped with a three-stage sand storage tank to achieve online precise mixing of primary, secondary and tertiary proppant; the temporary plugging agent injection device 14 is equipped with temporary plugging agents of different particle sizes to achieve precise sealing of the dominant flow channel.

[0032] 3. Dynamic monitoring and control system: Downhole temperature sensor 15 and fiber optic monitoring cable 16 collect reservoir temperature and flow data in real time; surface control system 17 integrates data processing and decision-making modules, and automatically starts temporary plugging control when the flow concentration coefficient is >2.0; the temporary plugging agent degrades in the geothermal reservoir environment for 48 to 72 hours, realizing reversible control of fracture conductivity.

[0033] 4. Fluid flow path and heat exchange mechanism: The far well connection zone 5 of injection well 1 and production well 2 are interconnected in the middle area between the wells, forming a complete seepage channel. When the system is running, the low temperature heat exchange medium is injected from injection well 1 and flows through the near well high conductivity zone 3 of injection well 1, the transition control zone 4 of injection well 1, and the far well connection zone 5 of injection well 1 in sequence. After passing through the interconnected far well connection zone 5, it continues to flow through the far well connection zone 5 of production well 2, the transition control zone 4 of production well 2, and the near well high conductivity zone 3 of production well 2, and finally exits through production well 2.

[0034] This operational path relies on a three-stage gradient flow guidance architecture, enabling fluid to pass rapidly through the near-wellbore high-conductivity zone 3 with large fracture openings and high conductivity, significantly reducing near-wellbore flow resistance and pumping energy consumption; in the transition control zone 4, a medium flow velocity is used to balance reservoir pressure distribution, suppressing the formation of high-conductivity dominant flow channels and avoiding local fluid concentration; in the far-wellbore connection zone 5, a low flow velocity and long seepage path are used to fully exchange heat with the high-temperature surrounding rock, extending the heat exchange time of the fluid in the reservoir and achieving efficient heat extraction; at the same time, the far-wellbore connection zones 5 of injection well 1 and production well 2 are interconnected, ensuring the formation of a uniform and stable interconnected volume between wells, eliminating flow dead zones, effectively delaying thermal breakthrough time, and improving the overall heat recovery efficiency and economic life of the system.

[0035] Example 1

[0036] A certain granite dry hot rock EGS project has a reservoir depth of 3500m, a reservoir temperature of 220℃, a rock mass compressive strength of 180MPa, a well distance of 400m between injection well 1 and production well 2, a designed target heat recovery power of 5MW, and a system design operating life of 25 years.

[0037] S1: Fracture network zoning and conductivity design: The well is divided into three zones centered on injection well 1 and production well 2. The three zones are the near-well high conductivity zone 3, the transition control zone 4, and the far-well connectivity zone 5. The near-well high conductivity zone 3 has a radius of 25m and a designed conductivity of 25D. The transition control zone 4 has a radius of 25-120m and a designed conductivity of 6D. The far-well connectivity zone 5 has a radius of 120-400m and a designed conductivity of 0.6D. The far-well connectivity zone 5 of injection well 1 and the far-well connectivity zone 5 of production well 2 are interconnected in the middle of the wells, and the geothermal fluid completes the circulation heat exchange according to the set path.

[0038] S2: Selection of three-stage proppant: Primary proppant 6 is made of bauxite ceramsite with a particle size of 1.0 mm, a volume concentration of 22%, a sphericity ≥0.9, and an acid solubility ≤5%; Secondary proppant 7 has a particle size of 0.5 mm and a volume concentration of 10%; Tertiary proppant 8 has a particle size of 0.25 mm and a volume concentration of 5%; Phenolic resin pre-cured layers are applied to the surfaces of secondary proppant 7 and tertiary proppant 8; All proppants have a compressive strength ≥69 MPa, turbidity ≤100 FTU, and a temperature resistance rating of 250℃.

[0039] S3: Preferred Reverse Stage Fracturing and Resin Curing Construction at Distant Wells: (1) Construction preparation and perforation operation (24 hours before construction): Complete the installation and pressure test of the surface pump set 20, sand mixing equipment 13 and manifold system 12. The test pressure is 1.2 times the maximum construction pressure. Run the fracturing string to the target reservoir section, and perform directional perforation along the line connecting the injection well and the production well. The thickness of the perforation section is 20m, the perforation density is 16 holes / m, and the phase angle is 60°.

[0040] (2) Pre-fluidization stage (0-12h): with a discharge rate of 2.5m 3 Inject slickwater pretreatment solution at a rate of 300 m³ / min, with a total volume of 300 m³. 3 Hydraulic fracturing was performed on the reservoir with an initial fracturing pressure of approximately 72 MPa. After the fractures initiated and steadily propagated, the discharge rate was gradually increased to 3 m³ / s. 3 / min, causing the main fracture 9 to extend towards the far well connectivity zone 5, while activating natural fractures to form a microfracture network 11, providing a channel for the subsequent delivery of primary, secondary and tertiary proppant.

[0041] (3) Far-well fracturing stage (12-60h): Maintain a discharge rate of 3m³ / h 3The injection rate of slickwater fracturing fluid was 60 m³ / min, and a stepped increase in the proppant ratio was used to carry stage 3 proppant 8 into the far-well connectivity zone 5. The fracturing fluid viscosity was 5-10 mPa·s. The initial proppant ratio was 3%, which was increased by 1% every 2 hours until it stabilized at 8%. The total proppant injection rate in this stage was 60 m³ / min. 3 Total liquid volume 1200m 3 The proppant is transported with the fracturing fluid to the far well area 120-400m away from the wellbore to fill the microfracture network 11 and construct a low-conductivity connecting channel in the far well. During the construction process, the range of fracture expansion is tracked in real time by wellhead pressure and microseismic monitoring to ensure that the fracture in the far well extends towards the production well 2.

[0042] (4) Transitional expansion phase (60-84h): Increase injection displacement to 5m 3 At a speed of / min, switch to linear gel fracturing fluid to enhance proppant carrying capacity, carrying secondary proppant 7 into transition control zone 4, with fracturing fluid viscosity of 30~50 mPa·s; proppant ratio starts at 8%, increasing by 2% every 3 hours, up to a maximum of 15%; total proppant addition in this stage is 80 m³ / min. 3 Total liquid volume 1000m 3 Secondary proppant 7 settles in the transition zone 25-120m from the wellbore, supporting secondary fractures 10 and forming a transition buffer zone with medium conductivity, thus achieving a smooth connection between the far-well microfracture network 11 and the near-well main fracture 9.

[0043] (5) Near-well reinforcement stage (84-108h): Further increase the discharge rate to 8m 3 / min, high-viscosity gel fracturing fluid carrying primary proppant 6 is injected into the near-wellbore high conductivity zone 3. The viscosity of the high-viscosity gel fracturing fluid is 100~200 mPa·s; the sand ratio starts at 20%, increasing by 3% every 4 hours, up to a maximum of 28%; the total sand addition is 120m³. 3 Total liquid volume 900m 3 Large-particle-size, high-concentration primary proppant 6 fills the near-wellbore main fracture 9, forming a high-conductivity near-wellbore channel and significantly reducing near-wellbore flow resistance.

[0044] (6) Replacement and curing stage (108-120h): First inject 200m 3 Low-viscosity slickwater displacement fluid was used to displace all primary proppant 6, secondary proppant 7, and tertiary proppant 8 in the wellbore and near-wellbore area to the target fracture location, preventing sand settling in the wellbore; 50m of fluid was injected. 3 Curable phenolic resin coating liquid, the resin coating liquid uniformly coats the surface of primary proppant 6, secondary proppant 7 and tertiary proppant 8, and then 100m... 3 The post-displacement fluid pushes the resin into the near-well high conductivity zone 3, the transition control zone 4, and the far-well connectivity zone 5 fracture.

[0045] (7) Well shut-in and solidification and quality inspection (120-168h): Close the wellhead valve and shut in the well for 48h to allow the resin coating fluid to fully solidify under the action of reservoir temperature, and bind and lock the primary proppant 6, secondary proppant 7 and tertiary proppant 8 into a stable support skeleton. After the well shut-in is completed, open the well to release the blowout and drain the excess fracturing fluid and resin residue. Then, pressure drop test and tracer test are carried out to verify the fracture conductivity and inter-well connectivity. After passing the test, the system will enter the circulation operation stage.

[0046] S4: Dynamic Flow Control and Thermal Breakthrough Early Warning: A downhole distributed fiber optic sensing device, consisting of downhole temperature sensor 15 and fiber optic monitoring cable 16, collects reservoir temperature and flow data in real time. The surface control system 17 receives the monitoring data. During initial system operation, the injection flow rate is 50 kg / s, the injection temperature is 60℃, the initial production temperature is 208℃, and the thermal power is 4.8 MW. Monitoring shows that the temperature gradient of production well 2 is 8℃ / m, and the flow concentration factor is 2.5, reaching the control threshold. A biodegradable temporary plugging agent 19 with a particle size of 0.125 mm is injected into the dominant flow channel 18 through the temporary plugging agent injection device 14, with a liquid volume of 5 m³. 3 Simultaneously increasing the injection pressure forces the fluid to shift to a low-conductivity region; after 72 hours, the temporary plugging agent 19 is completely degraded, and the temperature field returns to uniformity.

[0047] The above embodiments merely illustrate several implementation methods of the present invention, and their descriptions are relatively specific and detailed, but they should not be construed as limiting the scope of the present invention. It should be noted that those skilled in the art can make various modifications and improvements without departing from the concept of the present invention, and these all fall within the protection scope of the present invention. Therefore, the protection scope of this patent should be determined by the appended claims.

Claims

1. A method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant, characterized in that, Includes the following steps: S1: Fracture Network Zoning and Conductivity Design: Centered on the injection well and production well, the fracturing influence zones of both the injection well and production well are divided into a near-wellbore high conductivity zone, a transition control zone, and a far-wellbore connectivity zone. The far-wellbore connectivity zones of the injection well and production well are interconnected to form a continuous inter-well conductivity channel. The geothermal fluid circulation path passes sequentially through the near-wellbore high conductivity zone of the injection well, the transition control zone of the injection well, the far-wellbore connectivity zone of the injection well, the far-wellbore connectivity zone of the production well, the transition control zone of the production well, and the near-wellbore high conductivity zone of the production well. S2: Three-stage proppant selection: The near-wellbore high conductivity zone is equipped with primary proppant, with a particle size of 0.9–1.2 mm and a volume concentration of 15%–25%; the transition control zone is equipped with secondary proppant, with a particle size of 0.45–0.6 mm and a volume concentration of 8%–15%; the far-wellbore connectivity zone is equipped with tertiary proppant, with a particle size of 0.2–0.3 mm and a volume concentration of 3%–8%; the primary, secondary, and tertiary proppants are all high-temperature resistant ceramic particles or resin-coated ceramic particles with a compressive strength ≥69 MPa; S3: Preferred Reverse Stage Fracturing and Resin Curing Construction in Distant Wells: Directional perforation is performed along the line connecting the injection well and the production well to inject pre-fracturing fluid to create hydraulic fractures in the reservoir. Following the sequence of first fracturing the distant well connectivity zone to build a microfracture network, then expanding and stabilizing secondary fractures in the transition control zone, and finally strengthening and building high-conductivity channels in the near-wellbore high-conductivity zone, fracturing fluids carrying tertiary, secondary, and primary proppant are pumped sequentially. This allows the tertiary, secondary, and primary proppant to be laid sequentially in the distant well connectivity zone, transition control zone, and near-wellbore high-conductivity zone. After completing the above-mentioned proppant-carrying fracturing fluid injection, displacement fluid is injected to allow the tertiary, secondary, and primary proppant to settle and position. Then, a curable resin coating liquid is injected, and curing is performed using the reservoir temperature of 80~220℃. The well is shut in for at least 48 hours to allow the proppant to solidify, locking it within the target fractures to form a zoned gradient support framework.

2. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 1, characterized in that, In step S1, the near-wellbore high conductivity zone is a region with a radius of 10-30m around the wellbore, designed with a conductivity capacity of 10-50D; the transition control zone is a region with a radius of 30-150m, designed with a conductivity capacity of 1-10D; and the far-wellbore connection zone is a region with a radius of 150-500m, designed with a conductivity capacity of 0.1-1D. The boundaries of the near-wellbore high conductivity zone, the transition control zone, and the far-wellbore connection zone can overlap to achieve gapless coverage of the fracturing influence zone.

3. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 2, characterized in that, In step S2, the turbidity of the primary, secondary, and tertiary proppant is ≤100 FTU; the sphericity of the primary proppant is ≥0.9 and the acid solubility is ≤5%; the surfaces of the secondary and tertiary proppants are coated with a phenolic resin pre-cured layer with a temperature resistance rating of not less than 250℃.

4. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 1, characterized in that, In step S3, the installation and pressure test of the ground supporting facilities are completed before construction, and the test pressure is not less than 1.2 times the maximum construction pressure.

5. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 1, characterized in that, In step S3, the fracturing of the far-wellbore connectivity zone to construct a microfracture network is the far-wellbore fracturing stage, and the displacement rate in this stage is 2-4 m³ / s. 3 The flow rate is 4-6 m / min, using low-viscosity fracturing fluid to deliver the third-stage proppant; the transition control zone expands and stabilizes secondary fractures, which is the transition expansion stage, during which the flow rate is increased to 4-6 m / min. 3 The secondary proppant is delivered at a rate of 6-10 m³ / min using medium-viscosity fracturing fluid. The near-wellbore high-conductivity zone enhancement stage involves constructing a high-conductivity channel, with a flow rate of 6-10 m³ / min. 3 The first-stage proppant is delivered at a rate of / min using high-viscosity fracturing fluid.

6. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 5, characterized in that, The fracturing fluid viscosity during the far-well fracturing stage is 5~10 mPa·s; the fracturing fluid viscosity during the transitional extension stage is 30~50 mPa·s; and the fracturing fluid viscosity during the near-well reinforcement stage is 100~200 mPa·s. During the construction process, microseismic monitoring is used to track the fracture extension range in real time to ensure that the fractures in the far-well connectivity zone of the injection well extend towards the production well.

7. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 5, characterized in that, In step S3, the far-well fracturing stage, the transitional expansion stage, and the near-well reinforcement stage all employ a stepped increase in the sand ratio for sand addition operations.

8. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 1, characterized in that, In step S3, the injection of displacement fluid causes the tertiary, secondary, and primary proppant to settle and be positioned, which is the displacement and solidification stage. In this stage, low-viscosity slickwater is first injected as the displacement fluid to replace all the primary, secondary, and tertiary proppant in the wellbore and near-well high conductivity zone to the target fracture location. Then, a curable phenolic resin coating liquid is injected, followed by the injection of post-displacement fluid to push the resin coating liquid into the fractures in the near-well high conductivity zone, transition control zone, and far-well connectivity zone.

9. The method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 1, characterized in that, It also includes dynamic flow control and thermal breakthrough early warning steps: real-time collection of reservoir temperature and flow data through downhole distributed fiber optic sensing devices; when a local temperature gradient > 5℃ / m or flow concentration coefficient > 2.0 is detected, a biodegradable temporary plugging agent is injected into the dominant flow channel. The particle size of the temporary plugging agent is 1 / 5 to 1 / 3 of the particle size of the primary, secondary, and tertiary proppant in the corresponding near-wellbore high conductivity zone, transition control zone, and far-wellbore connectivity zone; the temporary plugging agent completely degrades under geothermal environmental conditions for 48 to 72 hours, realizing reversible control of the fracture flow pattern. At the same time as injecting the biodegradable temporary plugging agent, the injection pressure is increased, forcing the geothermal fluid to turn to the low conductivity zone and balancing the flow distribution inside the fracture network.

10. A method for regulating fracture conductivity and inter-well connectivity using EGS staged proppant according to claim 1, characterized in that, After the well is shut in and allowed to solidify, the well is opened to release the excess fracturing fluid and resin residue. Then, pressure drop tests and tracer detection are performed to verify the fracture conductivity and the connection between the injection well and the production well. Once the tests are passed, the system enters the geothermal system circulation operation phase.

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