Method for determining well track of production well of enhanced geothermal system

Abstract

The invention provides a method for determining a well track of a production well of an enhanced geothermal system, and relates to the technical field of geothermal energy development. The method provided by the invention comprises the following steps: firstly, acquiring an elliptical profile diagram of a crack in a target area, then determining a target distance between an injection well and a production well according to permeability and crack conductivity, and finally determining a plurality of track points corresponding to a plurality of moments according to a target tangent line on the elliptical profile diagram and the target distance. And then according to the multiple track points, the well track of the production well is obtained, then control over the well track of the production well can be achieved through the well track of the production well, and the production efficiency is effectively improved. According to the method provided by the invention, the actual distribution path of the cracks in the target area can be quickly and accurately determined by acquiring the plurality of elliptical profile diagrams corresponding to the plurality of moments, and the track points are set based on the elliptical profile diagrams, so that short circuit caused by excessive communication between the injection well and the production well can be effectively avoided; and the heat exchange efficiency can be effectively improved.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of geothermal energy development, and particularly relates to a method for determining a wellbore trajectory of a production well of an enhanced geothermal system. BACKGROUND

[0002] As a technology that artificially forms a network of fractures in underground rock formations using high-pressure fluids, Enhanced Geothermal Systems (EGS) have been widely researched and applied to improve the efficiency of developing underground thermal energy resources. EGS systems create fractures in the formation by artificially injecting fluids, enhancing the permeability of the geothermal reservoir, and thus improving the efficiency of heat conduction. This enables the exploitation of resources that traditional geothermal systems cannot access. However, the application of EGS systems still faces some technical challenges, particularly in the process of designing and constructing production wells, where fracture propagation control is a problem. Currently, the common wellbore design method is to perforate along the direction of the maximum principal stress, aiming to control the propagation of fractures. This method can theoretically effectively form fractures, but in practical applications, due to the uncontrollability of fracture propagation, it may lead to excessive connectivity between production wells and fractures, causing a "short circuit" phenomenon, where hot water that has not undergone sufficient heat exchange directly enters the production well, reducing the heat exchange efficiency of the system. In order to better control the fracture propagation path and optimize the production well trajectory,

[0003] In related technology 1, CN113253343A provides a method for identifying fault activity in underground gas storage based on microseismic monitoring technology, which can provide accurate data on the direction and shape of fracture propagation. In related technology 2, CN119045047A provides an intelligent horizontal well slim hole microseismic monitoring system and data processing method, which can use automatic detection algorithms to identify microseismic events and display microseismic and fracture evaluation data through data visualization tools. However, the microseismic monitoring technology in related technology 1 and related technology 2 is only used for passive monitoring and does not form a closed-loop control with perforation design and production well trajectory adjustment. This leads to certain limitations in wellbore trajectory optimization, making it impossible to achieve efficient dynamic adjustment, resulting in waste of resources and decline in development efficiency.

[0004] Therefore, there is an urgent need for a method for determining the wellbore trajectory of a production well of an enhanced geothermal system, which can quickly and accurately control the perforation phase angle and production well trajectory based on the fracture propagation process, thereby improving the heat energy collection efficiency of the EGS system and the sustainable use of resources. SUMMARY

[0005] The present application provides a method for determining the wellbore trajectory of a production well of an enhanced geothermal system, which can quickly and accurately determine the wellbore trajectory of a production well, thereby achieving precise control of the production wellbore to improve the heat energy collection efficiency of the EGS system and the sustainable use of resources.

[0006] To achieve the above object, embodiments of the present application adopt the following technical solutions:

[0007] In a first aspect, a method for determining a wellbore trajectory of a production well in an enhanced geothermal system is provided. The method comprises: obtaining a plurality of elliptical profile maps corresponding to fractures in a target region, the elliptical profile maps being used to describe a length, a width, a height, an inclination angle and an extension direction of each fracture; determining a target distance between an injection well and the production well according to a permeability of the target region and a fracture conductivity of the fractures; determining a trajectory point as a point located on a target tangent line of each elliptical profile map and having a distance to the injection well equal to the target distance, the target tangent line being the same as a maximum horizontal stress direction of the target region and not intersecting an extension line of a main extension direction of the fractures; and generating a wellbore trajectory of the production well according to the trajectory points corresponding to the elliptical profile maps.

[0008] In a possible implementation of the first aspect, the permeability k eq is determined according to the following formula:

[0009]

[0010] wherein k m is a matrix permeability, k f is a fracture permeability, and φ f is a fracture porosity.

[0011] In a possible implementation of the first aspect, the fracture conductivity F cd is determined according to the following formula:

[0012] F cd =k f ·w f ;

[0013] wherein w f is a fracture width.

[0014] In a possible implementation of the first aspect, the target distance D opt between the injection well and the production well is determined according to the following formula:

[0015] D opt =ξ·(0.6D min +0.4D max );

[0016]

[0017] wherein D max is a maximum allowable distance constrained by a flow efficiency, D min is a minimum allowable distance constrained by a thermal breakthrough, and r wh is the effective reservoir thickness; ΔP is the maximum allowable pressure drop; μ is the fluid viscosity of the injection fluid; q is the production flow rate of the production well; and α is the productivity index of the production well. max h is the effective reservoir thickness; ΔP is the maximum allowable pressure drop; μ is the fluid viscosity of the injection fluid; q is the production flow rate of the production well; and α is the productivity index of the production well. e h is the effective reservoir thickness; ΔP is the maximum allowable pressure drop; μ is the fluid viscosity of the injection fluid; q is the production flow rate of the production well; and α is the productivity index of the production well. bt h is the effective reservoir thickness; ΔP is the maximum allowable pressure drop; μ is the fluid viscosity of the injection fluid; q is the production flow rate of the production well; and α is the productivity index of the production well. t h is the effective reservoir thickness; ΔP is the maximum allowable pressure drop; μ is the fluid viscosity of the injection fluid; q is the production flow rate of the production well; and α is the productivity index of the production well.

[0018] In a possible implementation manner of the first aspect, in the case that the permeability is less than 0.1 mD and the fracture conductivity is less than 10 md·m, the target distance D between the injection well and the production well is determined according to the following formula: opt

[0019] D opt = D min .

[0020] In the case that the permeability is greater than 50 mD and the fracture conductivity is greater than 100 md·m, the target distance D between the injection well and the production well is determined according to the following formula: opt

[0021] D opt = 1.1D max .

[0022] In a possible implementation manner of the first aspect, before the multiple elliptical profile maps corresponding to the fractures in the target region are obtained, the method further includes: determining the maximum horizontal stress and the minimum horizontal stress of the target region; and determining the perforation phase angle of the injection well according to the maximum horizontal stress and the minimum horizontal stress of the target region.

[0023] In a possible implementation manner of the first aspect, the maximum horizontal stress σ H is determined according to the following formula:

[0024]

[0025] wherein v is the Poisson's ratio, σ v is the vertical stress, α is the Biot's coefficient, P p is the current pore pressure, P p0 is the initial pore pressure; K is the tectonic stress coefficient, σ tectonic is the additional horizontal stress.

[0026] The minimum horizontal stress σ h is determined according to the following formula:

[0027]

[0028] wherein E is the Young's modulus, ε h is the minimum horizontal strain. ​​

[0029] In one possible implementation of the first aspect, determining the perforation phase angle of the injection well based on the maximum and minimum horizontal stresses in the target area includes: determining the perforation phase angle to be 60° when the ratio of the maximum to minimum horizontal stresses in the target area is greater than or equal to 1.5; determining the perforation phase angle to be 120° when the ratio of the maximum to minimum horizontal stresses in the target area is greater than 1.2 and less than 1.5; and determining the perforation phase angle to be 180° when the ratio of the maximum to minimum horizontal stresses in the target area is less than or equal to 1.2.

[0030] In one possible implementation of the first aspect, determining the perforation phase angle of the injection well based on the maximum and minimum horizontal stresses in the target area includes: determining the perforation phase angle to be 60° when the difference between the maximum and minimum horizontal stresses in the target area is less than 3 MPa; determining the perforation phase angle to be 90° when the difference between the maximum and minimum horizontal stresses in the target area is greater than or equal to 3 MPa and less than or equal to 7 MPa; and determining the perforation phase angle to be 120° when the difference between the maximum and minimum horizontal stresses in the target area is greater than 7 MPa.

[0031] In one possible implementation of the first aspect, the method further includes: when the difference between the maximum and minimum horizontal stress in the target area is less than 3 MPa, determining that the perforations of the injection well are arranged spirally along the well wall; when the difference between the maximum and minimum horizontal stress in the target area is greater than or equal to 3 MPa and less than or equal to 7 MPa, determining that the perforations of the injection well are arranged orthogonally along the well wall; and when the difference between the maximum and minimum horizontal stress in the target area is greater than 7 MPa, determining that the perforations of the injection well are arranged alternately along the well wall.

[0032] In one possible implementation of the first aspect, acquiring multiple elliptical contour maps corresponding to fractures in the target area includes: acquiring elliptical contour maps of fractures in the target area corresponding to each time node at a preset frequency using a microseismic monitoring system; the method further includes: if the ratio of the major or minor axis of the elliptical contour map at the first time node to the major or minor axis of the elliptical contour map at the second time node is greater than or equal to a first threshold, reducing the injection-production pressure difference of the production well and reducing the injection fluid temperature of the injection well at the second time node, wherein the first time node and the second time node are any two adjacent time nodes; if the ratio of the height of the elliptical contour map at the first time node to the height of the elliptical contour map at the second time node is greater than or equal to a second threshold, reducing the injection volume of the injection fluid in the injection well at the second time node.

[0033] The beneficial effects of this invention are as follows: The method provided by this invention first obtains an elliptical contour map of the fractures in the target area, then determines the target distance between the injection well and the production well based on the permeability and fracture conductivity, and finally determines multiple trajectory points corresponding to multiple time points based on the target tangent on the elliptical contour map and the target distance. Then, the wellbore trajectory of the production well is obtained based on these multiple trajectory points, thereby enabling control of the production well trajectory and effectively improving production efficiency. Furthermore, the method provided by this invention, by obtaining multiple elliptical contour maps corresponding to multiple time points, can quickly and accurately determine the actual distribution path of the fractures in the target area. Setting trajectory points based on the elliptical contour map can effectively avoid excessive connectivity between the injection well and the production well, thus preventing short circuits and effectively improving heat exchange efficiency. Moreover, the target distance provided by this invention is determined based on two constraints: flow efficiency and thermal breakthrough. The trajectory points determined by the target tangent and the target distance can connect the trajectory points with multiple fracture branches, thereby improving the stable acquisition of heat flow and preventing the injected fluid from flowing directly into the production well without sufficient heat exchange. Finally, the method provided by this invention can effectively improve the heat exchange efficiency of the system and extend the stable operation cycle of the system by continuously monitoring the fracture generation trend at adjacent time nodes and adjusting the allowable parameters of the injection well and production well based on the fracture generation trend.

[0034] Secondly, the present invention provides an enhanced geothermal system production wellbore trajectory determination system, the system comprising: an image acquisition module for acquiring multiple elliptical contour maps corresponding to fractures in a target area, the elliptical contour maps describing the length, width, height, dip angle, and extension direction of each fracture; a distance determination module for determining the target distance between the injection well and the production well based on the permeability of the target area and the fracture conductivity; a point determination module for determining the points located on the target tangent of each elliptical contour map, and whose distance from the injection well is the target distance, as trajectory points, the target tangent being in the same direction as the maximum horizontal stress in the target area, and the target tangent not intersecting with the extension line of the main extension direction of the fracture; and a trajectory determination module for generating the production wellbore trajectory based on the trajectory points corresponding to each elliptical contour map.

[0035] Thirdly, an electronic device is provided, the electronic device including a memory and one or more processors; the memory is coupled to the processors; wherein the memory stores computer program code, the computer program code including computer instructions, which, when executed by the processor, cause the electronic device to perform the method as described in any implementation of the first aspect.

[0036] Fourthly, a computer-readable storage medium is provided, including computer instructions that, when executed on an electronic device, cause the electronic device to perform a method as described in any implementation of the first aspect.

[0037] Fifthly, a computer program product is provided that, when run on a computer, causes the computer to perform the method in any implementation of the first aspect.

[0038] Understandably, the beneficial effects achieved by the system of the second aspect, the electronic device of the third aspect, the computer-readable storage medium of the fourth aspect, and the computer program product of the fifth aspect provided above can be referred to with reference to the beneficial effects of the first aspect and any of its possible design embodiments, which will not be repeated here. Attached Figure Description

[0039] Figure 1 This is a schematic diagram of the structure of an electronic device provided in an embodiment of the present invention;

[0040] Figure 2 A flowchart illustrating a method for determining the wellbore trajectory of an enhanced geothermal system production well, provided as an embodiment of the present invention;

[0041] Figure 3 This is a schematic diagram of an elliptical outline provided in an embodiment of the present invention;

[0042] Figure 4 A schematic diagram of a target tangent provided in an embodiment of the present invention;

[0043] Figure 5 This is a schematic diagram illustrating the process of determining trajectory points according to an embodiment of the present invention;

[0044] Figure 6 A flowchart illustrating another method for determining the wellbore trajectory of an enhanced geothermal system production well, provided in an embodiment of the present invention;

[0045] Figure 7 A flowchart illustrating another method for determining the wellbore trajectory of an enhanced geothermal system production well, provided as an embodiment of the present invention;

[0046] Figure 8 A flowchart illustrating another method for determining the wellbore trajectory of an enhanced geothermal system production well, provided as an embodiment of the present invention;

[0047] Figure 9 This is a schematic diagram of the structure of a determination system provided in an embodiment of the present invention. Detailed Implementation

[0048] The technical solutions of the embodiments of the present invention will be described below with reference to the accompanying drawings. In the description of the present invention, unless otherwise stated, " / " indicates that the objects before and after are in an "or" relationship. For example, A / B can represent A or B. The "or" in the present invention is merely a description of the relationship between the related objects, indicating that three relationships can exist. For example, A or B can represent: A alone, A and B simultaneously, and B alone. A and B can be singular or plural. Furthermore, in the description of the present invention, unless otherwise stated, "multiple" refers to two or more. "At least one of the following" or similar expressions refer to any combination of these items, including any combination of single or plural items.

[0049] Furthermore, to facilitate a clear description of the technical solutions of the embodiments of the present invention, the terms "first" and "second" are used in the embodiments of the present invention to distinguish identical or similar items with essentially the same function and effect. Those skilled in the art will understand that the terms "first" and "second" do not limit the quantity or execution order, and that the terms "first" and "second" are not necessarily different.

[0050] In this embodiment of the invention, the terms "exemplary" or "for example" are used to indicate that something is an example, illustration, or description. Any embodiment or design described as "exemplary" or "for example" in this embodiment of the invention should not be construed as superior or more advantageous than other embodiments or designs. Specifically, the use of terms such as "exemplary" or "for example" is intended to present the relevant concepts in a concrete manner for ease of understanding.

[0051] Enhanced Geothermal Systems (EGS), a technology that uses high-pressure fluids to artificially create fracture networks in underground rock formations, has been widely researched and applied to improve the development efficiency of underground thermal energy resources. EGS systems generate fractures in the formation by artificially injecting fluids, enhancing the permeability of geothermal reservoirs and thus improving heat transfer efficiency, enabling the exploitation of resources inaccessible to traditional geothermal systems. However, the application of EGS systems still faces some technical challenges, particularly in controlling fracture propagation during production well design and construction. Currently, a common wellbore design method is perforation along the direction of maximum principal stress, aiming to control fracture propagation. While this method can theoretically effectively create fractures, in practical applications, the uncontrollable nature of fracture propagation can lead to excessive connectivity between the production well and the fractures, causing a "short circuit" phenomenon—hot water that has not undergone sufficient heat exchange directly enters the production well, reducing the system's heat exchange efficiency.

[0052] In related technology 1, CN113253343A provides a method for identifying fault activity in underground gas storage facilities based on microseismic monitoring technology, which can provide accurate data on fracture propagation direction and morphology. In related technology 2, CN119045047A provides an intelligent microseismic monitoring system and data processing method for small-bore horizontal wells, which can identify microseismic events using automated detection algorithms and display microseismic and fracture assessment data through data visualization tools. However, the microseismic monitoring technologies in related technologies 1 and 2 are only used for passive monitoring and fail to form a closed-loop control with perforation design and production wellbore trajectory adjustment. This results in limitations in wellbore trajectory optimization, making efficient dynamic adjustment impossible, leading to resource waste and decreased development efficiency.

[0053] Therefore, there is an urgent need for an enhanced geothermal system production well trajectory design method that can quickly and accurately control the perforation phase angle and production well trajectory based on the fracture propagation process, thereby improving the thermal energy harvesting efficiency and sustainable resource utilization of the EGS system.

[0054] In view of this, embodiments of the present invention provide a method for determining the wellbore trajectory of an enhanced geothermal system production well. The method includes: acquiring multiple elliptical contour maps corresponding to fractures in a target area, wherein the elliptical contour maps are used to describe the length, width, height, dip angle, and extension direction of each fracture; determining the target distance between the injection well and the production well based on the permeability and fracture conductivity of the target area; determining the point located on the target tangent of each elliptical contour map, and whose distance from the injection well is the target distance, as the trajectory point, wherein the target tangent is in the same direction as the maximum horizontal stress in the target area, and the target tangent does not intersect with the extension line of the main extension direction of the fracture; and generating the wellbore trajectory of the production well based on the trajectory point corresponding to each elliptical contour map.

[0055] The beneficial effects of this invention are as follows: The method provided by this invention first obtains an elliptical contour map of the fractures in the target area, then determines the target distance between the injection well and the production well based on the permeability and fracture conductivity, and finally determines multiple trajectory points corresponding to multiple time points based on the target tangent on the elliptical contour map and the target distance. Then, the wellbore trajectory of the production well is obtained based on these multiple trajectory points, thereby enabling control of the production well trajectory and effectively improving production efficiency. Furthermore, the method provided by this invention, by obtaining multiple elliptical contour maps corresponding to multiple time points, can quickly and accurately determine the actual distribution path of the fractures in the target area. Setting trajectory points based on the elliptical contour map can effectively avoid excessive connectivity between the injection well and the production well, thus preventing short circuits and effectively improving heat exchange efficiency. Moreover, the target distance provided by this invention is determined based on two constraints: flow efficiency and thermal breakthrough. The trajectory points determined by the target tangent and the target distance can connect the trajectory points with multiple fracture branches, thereby improving the stable acquisition of heat flow and preventing the injected fluid from flowing directly into the production well without sufficient heat exchange. Finally, the method provided by this invention can effectively improve the heat exchange efficiency of the system and extend the stable operation cycle of the system by continuously monitoring the fracture generation trend at adjacent time nodes and adjusting the allowable parameters of the injection well and production well based on the fracture generation trend.

[0056] In some embodiments, the method for determining the wellbore trajectory of an enhanced geothermal system production well provided in this invention can be executed by an enhanced geothermal system production well trajectory determination system 100 (hereinafter referred to as determination system 100).

[0057] As an example, the determination system 100 can be any electronic device 200 with data processing capabilities, such as a general-purpose computer, personal computer, laptop computer, switch, or tablet computer. The specific implementation of the determination system 100 is not limited here.

[0058] Figure 1 A schematic diagram of the hardware structure of an electronic device provided in an embodiment of the present invention is shown. The electronic device 200 includes a processor 210, a memory 220, and a communication interface 230.

[0059] Processor 210 may include one or more processing cores. Processor 210 connects to various parts within electronic device 200 using various interfaces and lines, and performs various functions and processes data of electronic device 200 by running or executing instructions, programs, code sets, or instruction sets stored in memory 220, and by calling data stored in memory 220. Optionally, processor 210 may be implemented using at least one of the following hardware forms: Central Processing Unit (CPU), Graphics Processing Unit (GPU), Digital Signal Processing (DSP), Field-Programmable Gate Array (FPGA), and Programmable Logic Array (PLA).

[0060] The memory 220 may include random access memory (RAI) or read-only memory (ROI). Optionally, the memory 220 may include non-transitory computer-readable storage ledger. The memory 220 may be used to store instructions, programs, code, code sets, or instruction sets. The memory 220 may include a program storage area. The program storage area may store instructions for implementing an operating system, instructions for implementing at least one function (such as image acquisition, distance determination and extraction, and trajectory determination), and instructions for implementing the various method embodiments described above.

[0061] The communication interface 230 is used to communicate with other devices, equipment, or communication networks, such as data storage devices, image processing devices, or Ethernet, wireless access networks (RAN), wireless local area networks (WLAN), etc.

[0062] In terms of physical implementation, the aforementioned devices (such as processor 210, memory 220, and communication interface 230) can each be devices within the same device (such as a laptop computer). Alternatively, at least two of these devices can be located within the same device, i.e., as different devices within the same device, similar to the deployment of devices or components in a distributed system.

[0063] It is understood that the structure illustrated in this embodiment does not constitute a specific limitation on the electronic device 200. In other embodiments of the present invention, the electronic device 200 may include more or fewer components than illustrated, or combine some components, or split some components, or have different component arrangements. The illustrated components may be implemented in hardware, software, or a combination of software and hardware.

[0064] The following description, in conjunction with the accompanying drawings, illustrates a method for determining the wellbore trajectory of an enhanced geothermal system production well according to an embodiment of the present invention.

[0065] Figure 2 This is a flowchart illustrating a method for determining the wellbore trajectory of an enhanced geothermal system production well, provided as an embodiment of the present invention. Optionally, this method can be... Figure 1 The illustrated electronic device 200 performs this operation. The method may include the following steps:

[0066] S1. Obtain multiple elliptical contour maps corresponding to the cracks in the target area.

[0067] Specifically, elliptical profile maps are used to describe the length, width, height, dip angle, and extension direction of each crack. It's important to note that an elliptical profile map is a graphical tool that uses an elliptical geometric model to visualize or analyze the spatial distribution, orientation, density, or extension trend of cracks within a target area. Through elliptical fitting, the complex crack network of the target area is simplified into a statistical model with defined geometric parameters (major axis, minor axis, and orientation angle), thereby quantifying the dominant direction, extent of expansion, and heterogeneity of the cracks. The elliptical profile map includes the ellipse center, major axis, minor axis, rotation angle, and ellipse eccentricity.

[0068] For example, see Figure 3 , Figure 3 This is a schematic diagram of an elliptical profile provided in an embodiment of the present invention, including a main crack A and multiple branch cracks B, and the length, width, height, dip angle and extension direction of each.

[0069] In one possible implementation, S1 specifically includes: acquiring elliptical contour maps of cracks in the target area corresponding to each time node in multiple time nodes at a preset frequency through a microseismic monitoring system.

[0070] Specifically, the system periodically acquires elliptical contour maps of cracks in the target area at each time point through a microseismic monitoring system. For example, with a preset frequency of once per hour, the system acquires elliptical contour maps of cracks in the target area at 8:00, 9:00, 10:00, and 11:00 on the same day through the microseismic monitoring system. By using multiple elliptical contour maps, the changes and trends of cracks in the target area between 8:00 and 11:00 can be determined.

[0071] Microseismic monitoring systems are technologies that use arrays of seismic sensors to record high-frequency microseismic wave signals induced by hydraulic fracturing or natural activity in real time, and determine the spatial location, energy, and rupture mechanism of microseismic events based on seismic inversion methods (such as source location and moment tensor interpretation). Obtaining an elliptical profile map of cracks in a target area using a microseismic monitoring system mainly involves the following steps: First, spatial clustering analysis is performed on the microseismic event clusters to extract dominant rupture regions; then, principal component analysis or covariance matrix fitting methods are used to calculate the geometric distribution characteristics of the event clusters, obtaining the major axis direction (reflecting the dominant extension trend of cracks), minor axis (lateral expansion range), eccentricity, and rotation angle of the ellipse; finally, an elliptical profile map is generated by combining confidence intervals, visually representing the geometric morphology and anisotropy of the crack network.

[0072] It should be noted that the above preset frequency per hour is only an example. The system 100 can flexibly set the preset frequency according to the actual usage scenario. The specific value of the preset frequency is not particularly limited in this embodiment of the invention.

[0073] S2. Determine the target distance between the injection well and the production well based on the permeability and fracture conductivity of the target area.

[0074] In one possible implementation, the penetration rate k eq The formula for determining it is:

[0075]

[0076] Where, k m k represents the matrix permeability. f For crack permeability, φ f This refers to the porosity of the crack.

[0077] In another possible implementation, the penetration rate k eq The formula for determining it is:

[0078]

[0079] Where, k matrix =k m , φ f For crack porosity, w f Let θ be the crack width, and θ be the angle between the crack and the direction of the maximum principal stress.

[0080] Crack conductivity F cd The formula for determining it is:

[0081] F cd =k f ·w f ;

[0082] Among them, w f The width of the crack.

[0083] It should be understood that the above methods for determining permeability and fracture conductivity are merely illustrative examples. The determination system can also use other parameters to determine permeability and fracture conductivity according to the actual scenario, and the embodiments of the present invention do not impose any special limitations on this.

[0084] Furthermore, the target distance D between the injection well and the production well. opt The formula for determining it is:

[0085] D opt =ξ·(0.6D min +0.4D max );

[0086]

[0087] Among them, D max D is the maximum permissible distance constrained by flow efficiency. min r is the minimum allowable distance constrained by thermal breakthrough. w Where is the production wellbore radius; h is the effective reservoir thickness; ΔP max The maximum allowable pressure drop; μ is the fluid viscosity of the injected fluid; q is the production flow rate of the production well; α e t is the equivalent thermal diffusivity. bt The target thermal breakthrough time is given by φ, where φ is the total porosity and c is the total porosity. t The compression factor is 1.

[0088] Optionally, when the permeability is less than 0.1 mD and the fracture conductivity is less than 10 md·m, the target distance D between the injection well and the production well is... opt The formula for determining it is:

[0089] D opt =D min ;

[0090] When the permeability is greater than 50 mD and the fracture conductivity is greater than 100 md·m, the target distance D between the injection well and the production well is... opt The formula for determining it is:

[0091] D opt =1.1D max .

[0092] S3. The point located on the target tangent line of each elliptical contour map and whose distance from the injection well is the target distance is determined as the trajectory point.

[0093] Specifically, the target tangent is in the same direction as the maximum horizontal stress in the target area, and the target tangent does not intersect with the extension of the main extension direction of the crack.

[0094] For example, see Figure 4 , Figure 4 This is a schematic diagram of a target tangent provided in an embodiment of the present invention. The elliptical contour diagram A is an elliptical contour diagram obtained by the system at 8 points through the microseismic monitoring system. In the elliptical contour diagram A, tangents A1 and A2 are in the same direction as the maximum horizontal stress in the target area, but tangent A2 intersects the extension line of the main extension direction of the crack, while tangent A1 does not intersect the extension line of the main extension direction of the crack. Therefore, tangent A1 is the target tangent, and the trajectory point is located on tangent A1.

[0095] Combination Figure 4 See Figure 5 , Figure 5 This is a schematic diagram of a process for determining a trajectory point provided in an embodiment of the present invention. When the location of the injection well is point C, the point located on the target tangent and at a distance D from the injection well is point E. Therefore, the determination system 100 determines point E as the trajectory point.

[0096] S4. Generate the production wellbore trajectory based on the trajectory points corresponding to each elliptical contour map.

[0097] Based on the above example, the system determines the trajectory points corresponding to each elliptical contour map in sequence using the above method, and then connects the trajectory points corresponding to each elliptical contour map in chronological order to obtain the production wellbore trajectory. This can also be understood as: determining the trajectory points corresponding to each time point based on the elliptical contour map obtained at each time point, and then connecting these trajectory points to obtain the production wellbore trajectory.

[0098] As described in S1-S4 above, the method provided by this invention first obtains an elliptical contour map of the fractures in the target area. Then, it determines the target distance between the injection well and the production well based on the permeability and fracture conductivity. Finally, it determines multiple trajectory points corresponding to multiple time points based on the target tangent on the elliptical contour map and the target distance. The production wellbore trajectory is then obtained based on these multiple trajectory points, enabling control of the production well trajectory and effectively improving production efficiency. Furthermore, the method provided by this invention, by obtaining multiple elliptical contour maps corresponding to multiple time points, can quickly and accurately determine the actual distribution path of the fractures in the target area. Setting trajectory points based on the elliptical contour map effectively avoids excessive connectivity between the injection well and the production well, thus preventing short circuits and effectively improving heat exchange efficiency. Moreover, the target distance provided by this invention is determined based on two constraints: flow efficiency and thermal breakthrough. The trajectory points determined by the target tangent and the target distance allow the trajectory points to connect with multiple fracture branches, thereby improving the stable acquisition of heat flow and preventing the injected fluid from flowing directly into the production well without sufficient heat exchange.

[0099] In some embodiments, see Figure 6 Prior to S1 above, the method provided in this embodiment of the invention further includes:

[0100] S61. Determine the maximum and minimum horizontal stresses in the target area.

[0101] In some embodiments, the maximum horizontal stress σ H The formula for determining it is:

[0102]

[0103] Where v is Poisson's ratio, σ v For vertical stress, α is the Biot coefficient, and P p P represents the current pore pressure. p0 σ is the initial pore pressure; K is the tectonic stress coefficient; σ tectonic To add horizontal stress;

[0104] Minimum horizontal stress σ h The formula for determining it is:

[0105]

[0106] Where E is Young's modulus, ε h This represents the minimum horizontal strain.

[0107] It should be understood that the above methods for determining the maximum and minimum horizontal stress are merely illustrative examples. The system can also use other parameters to determine the maximum and minimum horizontal stress according to the actual scenario, and the embodiments of the present invention do not impose any special limitations on this.

[0108] S62. Determine the perforation phase angle of the injection well based on the maximum and minimum horizontal stresses in the target area.

[0109] Specifically, the perforation phase angle refers to the angle between adjacent perforations along the circumference of the wellbore, used to describe the spatial distribution of perforating charges on the casing or open hole wellbore. The perforation phase angle is used to determine the geometry of the perforation cluster, thus affecting the initiation and propagation behavior of fracturing fractures.

[0110] In some embodiments, see Figure 7 The aforementioned S62 specifically includes:

[0111] S6211. When the ratio of the maximum horizontal stress to the minimum horizontal stress in the target area is greater than or equal to 1.5, the perforation phase angle is determined to be 60°.

[0112] S6212. When the ratio of the maximum horizontal stress to the minimum horizontal stress in the target area is greater than 1.2 and less than 1.5, the perforation phase angle is determined to be 120°.

[0113] S6213. When the ratio of the maximum horizontal stress to the minimum horizontal stress in the target area is less than or equal to 1.2, the perforation phase angle is determined to be 180°.

[0114] In other embodiments, see Figure 8 The aforementioned S62 specifically includes:

[0115] S6221. When the difference between the maximum and minimum horizontal stress in the target area is less than 3 MPa, the perforation phase angle is determined to be 60°.

[0116] S6222. When the difference between the maximum and minimum horizontal stress in the target area is greater than or equal to 3 MPa and less than or equal to 7 MPa, the perforation phase angle is determined to be 90°.

[0117] S6223. When the difference between the maximum and minimum horizontal stress in the target area is greater than 7 MPa, the perforation phase angle is determined to be 120°.

[0118] Furthermore, the method provided in this embodiment of the invention also includes:

[0119] When the difference between the maximum and minimum horizontal stress in the target area is less than 3 MPa, the perforation arrangement of the injection well is determined to be spiral distribution along the well wall; when the difference between the maximum and minimum horizontal stress in the target area is greater than or equal to 3 MPa and less than or equal to 7 MPa, the perforation arrangement of the injection well is determined to be orthogonal distribution along the well wall; when the difference between the maximum and minimum horizontal stress in the target area is greater than 7 MPa, the perforation arrangement of the injection well is determined to be staggered distribution along the well wall.

[0120] In one possible implementation, the method provided by the embodiments of the present invention further includes:

[0121] If the ratio of the major or minor axis of the elliptical profile at the first time node to the major or minor axis of the elliptical profile at the second time node is greater than or equal to the first threshold, the injection-production pressure difference of the production well and the injection fluid temperature of the injection well are reduced at the second time node, wherein the first time node and the second time node are any two adjacent time nodes.

[0122] If the ratio of the height of the elliptical profile at the first time node to the height of the elliptical profile at the second time node is greater than or equal to the second threshold, the injection volume of the injection fluid in the injection well is reduced at the second time node.

[0123] Specifically, if the ratio of the major or minor axis of the elliptical profile at the first time point to the major or minor axis of the elliptical profile at the second time point is greater than or equal to a first threshold, the anomaly observed is local over-expansion. In this case, reducing the injection-production pressure differential of the production well and reducing the injection fluid temperature of the injection well can effectively reduce the fracture propagation rate. If the ratio of the height of the elliptical profile at the first time point to the height of the elliptical profile at the second time point is greater than or equal to a second threshold, the anomaly observed is vertical breakthrough. In this case, reducing the injection volume of the injection fluid in the injection well can effectively stabilize the fracture height.

[0124] The method provided in this invention continuously monitors the fracture generation trend at adjacent time points and adjusts the allowable parameters of the injection well and production well based on the fracture generation trend, which can effectively improve the heat exchange efficiency of the system and extend the stable operation cycle of the system.

[0125] The foregoing primarily describes the solutions of the embodiments of the present invention from a methodological perspective. It is understood that, to achieve the aforementioned functions, the system 100 includes at least one of the hardware structures and software modules corresponding to the execution of each function. Those skilled in the art should readily recognize that, in conjunction with the units and algorithm steps of the various examples described in the embodiments disclosed herein, the embodiments of the present invention can be implemented in hardware or a combination of hardware and computer software. Whether a function is executed in hardware or by computer software driving hardware depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of the embodiments of the present invention.

[0126] In this embodiment of the invention, the system 100 can be divided into functional units according to the above method example. For example, the system 100 can be divided into functional units corresponding to various functions, or two or more functions can be integrated into one processing unit. The integrated unit can be implemented in hardware or as a software functional unit. It should be noted that the unit division in this embodiment is illustrative and only represents one logical functional division; other division methods may be used in actual implementation.

[0127] For example, Figure 9 This diagram illustrates a hardware structure of a determination system according to an embodiment of the present invention. The determination system 100 includes: an image acquisition module 110, used to acquire multiple elliptical contour maps corresponding to fractures in a target area, the elliptical contour maps describing the length, width, height, dip angle, and extension direction of each fracture; a distance determination module 120, used to determine the target distance between the injection well and the production well based on the permeability of the target area and the fracture conductivity; a point determination module 130, used to determine points located on the target tangent of each elliptical contour map, and whose distance from the injection well is the target distance, as trajectory points, the target tangent being in the same direction as the maximum horizontal stress in the target area, and the target tangent not intersecting with the extension line of the main extension direction of the fracture; and a trajectory determination module 140, used to generate a production wellbore trajectory based on the trajectory points corresponding to each elliptical contour map.

[0128] It should be understood that a detailed description of the above-mentioned optional methods can be found in the foregoing method embodiments, and will not be repeated here. Furthermore, explanations of any of the determination systems 100 provided above, as well as descriptions of their beneficial effects, can be found in the corresponding method embodiments described above, and will not be repeated here.

[0129] This invention also provides a computer-readable storage medium storing at least one computer instruction, which is loaded and executed by a processor to implement the methods of the various embodiments described above. Explanations of the relevant content and descriptions of the beneficial effects of any of the computer-readable storage media provided above can be found in the corresponding embodiments described above, and will not be repeated here.

[0130] This invention also provides a chip. This chip integrates a control circuit for implementing the functions of the aforementioned determining system 100 and one or more ports. Optionally, the functions supported by this chip are as described above and will not be repeated here.

[0131] Those skilled in the art will understand that the program for implementing all or part of the steps of the above embodiments, which can be executed by a program instructing related hardware, can be stored in a computer-readable storage medium. The storage medium mentioned above can be a read-only memory, a random access memory, etc. The processing unit or processor mentioned above can be a central processing unit, a general-purpose processor, an application-specific integrated circuit (ASIC), a microprocessor (DSP), a field-programmable gate array (FPGA), or other programmable logic devices, transistor logic devices, hardware components, or any combination thereof.

[0132] This invention also provides a computer program product containing instructions that, when executed on a computer, cause the computer to perform any of the methods described in the above embodiments. The computer program product includes one or more computer instructions. When the computer program instructions are loaded and executed on a computer, all or part of the flow or function according to the embodiments of this invention is generated. The computer may be a general-purpose computer, a special-purpose computer, a computer network, or other programmable device. The computer instructions may be stored in a computer-readable storage medium or transmitted from one computer-readable storage medium to another. For example, computer instructions may be transmitted from one website, computer, server, or data center to another via wired (e.g., coaxial cable, fiber optic, digital subscriber line (DSL)) or wireless (e.g., infrared, wireless, microwave, etc.) means. The computer-readable storage medium may be any available medium accessible to a computer or a data storage device such as a server or data center that integrates one or more available media. The available medium may be a magnetic medium (e.g., floppy disk, hard disk, magnetic tape), an optical medium (e.g., DVD), or a semiconductor medium (e.g., SSD), etc.

[0133] It should be noted that the devices for storing computer instructions or computer programs provided in the embodiments of the present invention, such as, but not limited to, the aforementioned memory, computer-readable storage medium, and communication chip, are all non-transitory. Those skilled in the art should recognize that the functions described in the embodiments of the present invention in one or more of the above examples can be implemented using hardware, software, firmware, or any combination thereof. When implemented using software, these functions can be stored in a computer-readable storage medium or transmitted as one or more instructions or code on a computer-readable storage medium. Computer-readable storage media include computer storage media and communication media, wherein communication media include any medium that facilitates the transmission of computer programs from one place to another. Storage media can be any available medium accessible to general-purpose or special-purpose computers.

[0134] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those skilled in the art can make changes, modifications, substitutions and variations to the above embodiments within the scope of the present invention.

Claims

1. An enhanced geothermal system production well borehole trajectory determination method, characterized by, The method comprises: obtaining a plurality of elliptical profile maps corresponding to the fractures in the target region, the elliptical profile maps being used to describe the length, width, height, inclination and extension direction of each fracture; determining a target distance between the injection well and the production well according to the permeability of the target region and the fracture conductivity; determining a trajectory point as a point located on a target tangent line of each of the elliptical profile maps and having a distance of the target distance from the injection well, the target tangent line being the same as the maximum horizontal stress direction of the target region and the target tangent line not intersecting the extension line of the main extension direction of the fracture; generating a wellbore trajectory of the production well according to the trajectory points corresponding to each of the elliptical profile maps.

2. The method of claim 1, wherein, The permeability k eq The determination formula is: where k m is the matrix permeability, k f is the fracture permeability, and φ f is the fracture porosity.

3. The method of claim 2, wherein, The fracture conductivity F cd The determination formula is: F cd = k f · w f ; where w f is the crack width.

4. The method of claim 3, wherein, The target distance D between the injection well and the production well opt The determination formula is: D opt = ξ · (0.6D min + 0.4D max ); where D max is the maximum allowable distance with flow efficiency as the constraint, D min is the minimum allowable distance with thermal breakthrough as the constraint; r w is the production wellbore radius; h is the reservoir net pay thickness; ΔP max is the maximum allowable pressure drop; μ is the fluid viscosity of the injection fluid; q is the production rate of the production well, a e is the equivalent thermal diffusivity, t bt is the target thermal breakthrough time, φ is the total porosity, c t is the compressibility.

5. The method of claim 4, wherein, In the case where the permeability is less than 0.1 mD and the fracture conductivity is less than 10 md-m, the target distance D between the injection well and the production well is determined by the formula: opt D = 0.1 x (10 - 0.1) D opt = D min ; In the case where the permeability is greater than 50 mD and the fracture conductivity is greater than 100 md-m, the target distance D between the injection well and the production well is determined by the formula: opt D = 0.5 * (L + W) D opt = 1.1D max .

6. The method of claim 5, wherein, Before the step of obtaining a plurality of elliptical profile maps corresponding to the fractures in the target region, the method further comprises: determining the maximum horizontal stress and the minimum horizontal stress of the target region; determining a perforation phase angle of the injection well according to the maximum horizontal stress and the minimum horizontal stress of the target region.

7. The method of claim 6, wherein, The maximum horizontal stress σ H The determination formula is: where v is the Poisson's ratio, σ v is the vertical stress, a is the Biot's coefficient, P p is the current pore pressure, P p0 is the initial pore pressure; K is the tectonic stress coefficient, σ tectonic is the additional horizontal stress; The formula for determining the minimum horizontal stress is: where E is the Young's modulus, ε h is the minimum horizontal strain.

8. The method of claim 7, wherein, The step of determining the perforation phase angle of the injection well according to the maximum horizontal stress and the minimum horizontal stress of the target region comprises: in the case that the ratio of the maximum horizontal stress to the minimum horizontal stress of the target region is greater than or equal to 1.5, determining the perforation phase angle as 60°; in the case that the ratio of the maximum horizontal stress to the minimum horizontal stress of the target region is greater than 1.2 and less than 1.5, determining the perforation phase angle as 120°; in the case that the ratio of the maximum horizontal stress to the minimum horizontal stress of the target region is less than or equal to 1.2, determining the perforation phase angle as 180°.

9. The method of claim 7, wherein, The step of determining the perforation phase angle of the injection well according to the maximum horizontal stress and the minimum horizontal stress of the target region comprises: in the case that the difference between the maximum horizontal stress and the minimum horizontal stress of the target region is less than 3 MPa, determining the perforation phase angle as 60°; in the case that the difference between the maximum horizontal stress and the minimum horizontal stress of the target region is greater than or equal to 3 MPa and less than or equal to 7 MPa, determining the perforation phase angle as 90°; in the case that the difference between the maximum horizontal stress and the minimum horizontal stress of the target region is greater than 7 MPa, determining the perforation phase angle as 120°.

10. The method of claim 9, wherein, The method further comprises: in the case that the difference between the maximum horizontal stress and the minimum horizontal stress of the target region is less than 3 MPa, determining the arrangement mode of the perforations of the injection well as a spiral distribution along the well wall of the injection well; in the case that the difference between the maximum horizontal stress and the minimum horizontal stress of the target region is greater than or equal to 3 MPa and less than or equal to 7 MPa, determining the arrangement mode of the perforations of the injection well as an orthogonal distribution along the well wall of the injection well; in the case that the difference between the maximum horizontal stress and the minimum horizontal stress of the target region is greater than 7 MPa, determining the arrangement mode of the perforations of the injection well as a staggered distribution along the well wall of the injection well.

11. The method of claim 1, wherein, The step of obtaining a plurality of elliptical profile maps corresponding to the fractures in the target region comprises: obtaining, by a microseismic monitoring system, an elliptical profile map of the fractures in the target region corresponding to each of a plurality of time nodes at a preset frequency; The method further comprises: In a case that a ratio of a long axis or a short axis of the elliptical profile graph at the first time node to a long axis or a short axis of the elliptical profile graph at the second time node is greater than or equal to a first threshold value, the injection-production pressure difference of the production well is reduced at the second time node, and the injection liquid temperature of the injection well is reduced at the second time node, wherein the first time node and the second time node are any two adjacent time nodes; In a case that a ratio of a height of the elliptical profile graph at the first time node to a height of the elliptical profile graph at the second time node is greater than or equal to a second threshold value, the injection amount of the injection liquid of the injection well is reduced at the second time node.

12. An enhanced geothermal system production well borehole trajectory determination system, characterized by, The system comprises: An image acquisition module configured to acquire a plurality of elliptical profile graphs corresponding to the fractures in the target region, the elliptical profile graphs being used to describe the length, width, height, dip angle and extension direction of each fracture; A distance determination module configured to determine a target distance between the injection well and the production well according to the permeability of the target region and the fracture conductivity; A point determination module configured to determine a point located on a target tangent line of each of the elliptical profile graphs and having a distance to the injection well of the target distance as a trajectory point, the target tangent line being the same as the maximum horizontal stress direction of the target region, and the target tangent line not intersecting with an extension line of the main extension direction of the fracture; A trajectory determination module configured to generate a production well borehole trajectory according to the trajectory points corresponding to each of the elliptical profile graphs.

13. An electronic device, comprising: Comprise: A processor; A memory for storing instructions executable by the processor; The processor is configured to execute the instructions to implement the enhanced geothermal system production well borehole trajectory determination method according to any one of claims 1-11.

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