Method and device for determining a method for controlling microseismicity induced by hydraulic fracturing

Abstract

The application provides a method and device for controlling microseism after hydraulic fracturing, and relates to the technical field of geothermal resource development. The method comprises the following steps: in response to determining that microseism is induced during hydraulic fracturing, obtaining first pressure data of a fracturing wellhead in a first time period before the microseism occurs and second pressure data of the fracturing wellhead in a second time period after the microseism occurs. The type of the microseism is determined according to a target pressure change rate determined according to the first pressure data and the second pressure data. The type of the microseism comprises a first type of microseism and a second type of microseism, the first type of microseism representing microseism induced due to the increase of pore pressure of a fault caused by the entry of fracturing fluid into the fault, and the second type of microseism representing microseism induced due to the change of load of the fault caused by the local stress change caused by hydraulic fracturing construction. According to the type of the microseism, a target control measure for controlling the microseism from being induced again is determined.

Description

Technical Field

[0001] This application relates to the field of geothermal resource development technology, specifically to a method for seismic control after determining micro-earthquakes induced by hydraulic fracturing. Background Technology

[0002] Hot dry granite geothermal energy, as a large-scale clean energy source, possesses immense economic development value. Developing hot dry granite requires establishing an enhanced geothermal system, the core of which involves drilling wells into the geothermal reservoir and fracturing them to create a fracture network of a certain scale, constructing a circulation loop between injection wells and production wells to extract thermal energy for power generation.

[0003] However, hydraulic fracturing in hot dry rock can easily induce microseismic events. Although the magnitude of these events is not as high as that of fault activation, the large-scale slippage of natural structural planes caused by pore pressure during fracturing can lead to a rapid release of formation energy, potentially triggering destructive microseismic events. Therefore, controlling subsequent hydraulic fracturing operations after a microseismic event has been induced to prevent its re-induction is of paramount importance. Summary of the Invention

[0004] In view of this, this application provides a method and apparatus for determining seismic control after hydraulic fracturing-induced microseismic events.

[0005] One aspect of this application provides a method for seismic control after hydraulic fracturing-induced microseismic events. The method includes: in response to determining that a microseismic event has been induced during hydraulic fracturing, acquiring first pressure data at the wellhead of the fracturing well during a first time period before the microseismic event and second pressure data at the wellhead of the fracturing well during a second time period after the microseismic event. The type of microseismic event is determined based on a target pressure change rate determined from the first and second pressure data. The type of microseismic event includes at least one of a first type and a second type, where the first type characterizes microseismic events induced by increased pore pressure in the fault due to fracturing fluid entering the fault; and the second type characterizes microseismic events induced by changes in local stress caused by hydraulic fracturing operations, leading to changes in fault load. Based on the type of microseismic event, target control measures are determined to prevent the re-induction of microseismic events.

[0006] According to an embodiment of this application, determining the type of microearthquake based on the target pressure change rate determined by the first pressure data and the second pressure data may include: performing linear fitting on the first pressure data of the first time period and the second pressure data of the second time period respectively to obtain a first fitted line segment and a second fitted line segment; determining the target pressure change rate based on the pre-earthquake pressure change rate and the post-earthquake pressure change rate determined by the first fitted line segment and the second fitted line segment respectively; and determining the type of microearthquake based on the target pressure change rate.

[0007] According to an embodiment of this application, determining the type of microseismic event based on the target pressure change rate includes: determining the type of microseismic event as a first type when the target pressure change rate meets a preset difference condition; and determining the type of microseismic event as a second type when the target pressure change rate does not meet the preset difference condition.

[0008] According to an embodiment of this application, based on the type of microseismic event, target control measures for controlling the re-induction of microseismic events are determined, including: in the case where the type of microseismic event is determined to be a first type of microseismic event, determining the positional relationship between the fault that triggered the microseismic event and the hydraulically fractured thermal reservoir; and based on the positional relationship between the fault and the thermal reservoir, determining a sealing agent for sealing the fractures between the fault and the fractured well.

[0009] According to an embodiment of this application, based on the positional relationship between the fault and the thermal reservoir, a plugging agent for sealing the passage between the fault and the fracturing well is determined, including: when the location of the fault is determined to be below a predetermined position of the thermal reservoir in the depth direction, the plugging agent is determined to be quartz sand to prevent fracturing fluid from entering the fault.

[0010] According to an embodiment of this application, based on the positional relationship between the fault and the thermal reservoir, a plugging agent for sealing the passage between the fault and the fractured well is determined, further comprising: when it is determined that the location of the fault is above a preset position of the thermal reservoir in the depth direction, determining the plugging agent as a temporary plugging agent to temporarily seal the fracture between the fault and the fractured well, so as to promote the fracturing fluid to fracture the non-faulted part of the thermal reservoir.

[0011] According to an embodiment of this application, determining target control measures to prevent the re-induction of microseismic events based on the type of microseismic event further includes: if the type of microseismic event is determined to be a second type, acquiring the location, time of occurrence, and original microseismic waveform data of the microseismic event; performing moment tensor inversion on the original microseismic waveform data based on the location and time of occurrence of the microseismic event to determine the rupture surface parameters and principal stress parameters; determining the target stress conditions for fault slippage based on the rupture surface parameters and principal stress parameters; and determining the wellhead pressure for hydraulic fracturing operations based on the target stress conditions.

[0012] According to an embodiment of this application, the fracture surface parameters include the azimuth and dip angle of the fracture surface; based on the fracture surface parameters and principal stress parameters, the target stress condition for fault slippage is determined, including: decomposing the principal stress into normal stress and shear stress based on the azimuth, dip angle and principal stress parameters of the fracture surface; and determining the target stress condition for fault slippage based on the Mohr stress circle drawn based on the normal stress and shear stress.

[0013] According to an embodiment of this application, obtaining the location, time of occurrence, and original microseismic waveform data of a microseismic event includes: using multiple microseismic stations arranged around a fracturing well to detect microseismic events, so that when a microseismic event is detected to be induced, the location, time of occurrence, and original microseismic waveform data of the microseismic event are obtained using the multiple microseismic stations.

[0014] Another aspect of this application provides a seismic control device for determining the re-induction of microseismic events after hydraulic fracturing. The device includes: an acquisition module, configured to acquire first pressure data at the wellhead of the fracturing well during a first time period before the microseismic event and second pressure data at the wellhead of the fracturing well during a second time period after the microseismic event, in response to the determination that a microseismic event has been detected during the hydraulic fracturing process; a first determination module, configured to determine the type of microseismic event based on a target pressure change rate determined from the first and second pressure data; the type of microseismic event includes at least one of a first type and a second type, wherein the first type of microseismic event represents a microseismic event induced by an increase in pore pressure in the fault due to fracturing fluid entering the fault; and the second type of microseismic event represents a microseismic event induced by a change in load on the fault due to local stress changes caused by hydraulic fracturing operations; and a second determination module, configured to determine target control measures for preventing the re-induction of microseismic events based on the type of microseismic event.

[0015] According to the embodiments of this application, by acquiring the pressure data at the wellhead of the fracturing well during a preset time period before and after an earthquake, the target pressure change rate can be determined to accurately distinguish the earthquake type, i.e., whether it is induced by the increase in pore pressure caused by the entry of fracturing fluid into the fault, or by the change in fault load caused by local stress changes due to hydraulic fracturing construction. Based on the accurate judgment of the earthquake type, more targeted earthquake control measures can be determined, improving the rationality and effectiveness of earthquake control measures, more effectively reducing the potential hazards caused by earthquakes, and ensuring the safety and stability of related areas and projects. Attached Figure Description

[0016] The above and other objects, features and advantages of this application will become clearer from the following description of embodiments of this application with reference to the accompanying drawings.

[0017] Figure 1 A flowchart illustrating a method for determining seismic control after hydraulic fracturing-induced microseisms, according to an embodiment of this application, is shown.

[0018] Figure 2a A schematic diagram of linear fitting of a first type of microseismic event according to an embodiment of this application is shown.

[0019] Figure 2b A schematic diagram of linear fitting for a second type of microseismic event according to an embodiment of this application is shown.

[0020] Figure 3A schematic diagram of the fault structure distribution and fractured well according to an embodiment of this application is shown.

[0021] Figure 4 A flowchart is shown for determining a seismic control method after hydraulic fracturing-induced microseisms, according to another embodiment of this application.

[0022] Figure 5 A structural block diagram of a seismic control device for determining hydraulically fracturing-induced microseisms according to an embodiment of this application is shown. Detailed Implementation

[0023] The embodiments of this application will now be described with reference to the accompanying drawings. However, it should be understood that these descriptions are exemplary only and are not intended to limit the scope of this application. In the following detailed description, numerous specific details are set forth to provide a thorough understanding of the embodiments of this application for ease of explanation. However, it will be apparent that one or more embodiments may be implemented without these specific details. Furthermore, descriptions of well-known structures and technologies are omitted in the following description to avoid unnecessarily obscuring the concepts of this application.

[0024] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the scope of this application. The terms “comprising,” “including,” etc., as used herein indicate the presence of features, steps, operations, and / or components, but do not exclude the presence or addition of one or more other features, steps, operations, or components.

[0025] All terms used herein (including technical and scientific terms) have the meanings commonly understood by those skilled in the art, unless otherwise defined. It should be noted that the terms used herein are to be interpreted in a manner consistent with the context of this specification, and not in an idealized or overly rigid way.

[0026] When using expressions such as "at least one of A, B and C", they should generally be interpreted in accordance with the meaning that is commonly understood by those skilled in the art (e.g., "a system having at least one of A, B and C" should include, but is not limited to, a system having A alone, a system having B alone, a system having C alone, a system having A and B, a system having A and C, a system having B and C, and / or a system having A, B and C, etc.).

[0027] In related studies, hydraulic fracturing-induced microseismic events exhibit three modes. The first is fault activation caused by pore pressure effects: specifically, fracturing fluid entering large-scale structural planes, represented by faults, induces microseismic events. The second is fault activation caused by pore elastic effects: specifically, the fracturing process causes local stress changes that disturb the normal and tangential stresses on large-scale structural planes, represented by faults. The third is fault activation caused by seismic creep: specifically, the unstable region at the distal end of a large-scale structural plane, represented by faults, is gradually loaded by seismic creep in the near-terminal stable region. When the creep front impacts the fault region, the rock composition exhibits dynamic weakening behavior, leading to dynamic fracturing. The third mode is relatively easy to identify because its initiation time lags significantly behind that of hydraulic fracturing in hot dry rocks. The first mode, compared to the second, has a more pronounced impact on large-scale structural planes, represented by faults, and may therefore induce larger seismic energy levels, leading to more severe consequences. Therefore, distinguishing the types of microseismic events induced by hot dry rock during hydraulic fracturing and proposing corresponding control measures are crucial for the large-scale development of hot dry rock geothermal energy.

[0028] Figure 1 A flowchart illustrating a method for determining seismic control after hydraulic fracturing-induced microseisms, according to an embodiment of this application, is shown.

[0029] like Figure 1 As shown, the method includes operations S110 to S130.

[0030] In operation S110, in response to the determination that a microseismic event has been induced during the hydraulic fracturing process, the first pressure data of the fracturing wellhead in the first time period before the microseismic event and the second pressure data of the fracturing wellhead in the second time period after the microseismic event are acquired.

[0031] In operation S120, the type of microseismic event is determined based on the target pressure change rate determined by the first pressure data and the second pressure data.

[0032] In operation S130, target control measures are determined based on the type of microseismic event to prevent the re-induction of microseismic events.

[0033] Microseismic types include at least one of type I and type II. Type I microseismic characteristics are microseismic events induced by the increase in pore pressure of the fault due to the entry of fracturing fluid into the fault. Type II microseismic characteristics are microseismic events induced by changes in the load on the fault due to local stress changes caused by hydraulic fracturing operations.

[0034] In the embodiments of this application, during the hydraulic fracturing of the dry hot shaft, the pressure at the wellhead can be continuously monitored to obtain a curve showing the change of wellhead pressure over time. Simultaneously, the injection volume of fracturing fluid can also be monitored to obtain curves showing the change of fracturing fluid discharge over time and the change of cumulative fluid volume over time.

[0035] Hydraulic fracturing includes a fracturing phase and a pump shutdown phase. During the fracturing phase, an instrument truck can be used to monitor the wellhead pressure. After the hydraulic fracturing process stops, a wellhead pressure gauge can be installed at the wellhead. During installation, the instrument truck maintains continuous monitoring of the wellhead pressure. During the pump shutdown phase, the wellhead pressure data is recorded using the wellhead pressure gauge until the next fracturing phase.

[0036] During hydraulic fracturing, when it is confirmed that microseismic events have been induced, the timing of the microseismic event can be determined first, and the wellhead pressure fluctuation curves for a predetermined period before and after the microseismic event can be extracted. Thus, the first pressure data and the second pressure data can be obtained.

[0037] For example, the first time period can be 100-200 seconds before the earthquake, and the second time period can be 100-200 seconds after the earthquake. The embodiments of this application are not limited to this and can be selected according to actual needs.

[0038] Microseismic events generally refer to high-energy microseismic events generated by hydraulic fracturing. Their energy is typically greater than ML1.5 on the Richter scale. They are generated by the slippage of large-scale structures near the wellbore during the fracturing process, such as fault slippage. Because the focal depth is generally consistent with the depth of the fracturing section of the fracturing well, the energy transmitted to the surface by the induced microseismic events is relatively strong.

[0039] The target pressure change rate characterizes the difference between pre-earthquake and post-earthquake pressure changes. For Type I microearthquakes, due to continuous fluid leakage into the fault, the wellhead pressure exhibits a significant and sustained downward trend, which may be accelerated during a microearthquake. Therefore, the absolute value of the target pressure change rate for Type I microearthquakes is usually large. For Type II microearthquakes, the local stress changes caused by hydraulic fracturing disturb large-scale structural surfaces, preventing communication between the ruptures accompanying the microearthquake and the fracturing fluid in the well. Consequently, they do not affect the wellhead pressure, and there is no pressure drop due to significant fluid loss. Therefore, the target pressure change rate for Type II microearthquakes is usually small. By utilizing the difference in target pressure change rates between Type I and Type II microearthquakes, it is possible to quickly distinguish between them.

[0040] After determining the type of microseismic event, target control measures matching the earthquake type can be identified to control the subsequent hydraulic fracturing operations, thereby improving the effectiveness of seismic control measures.

[0041] According to the embodiments of this application, by acquiring the pressure data at the wellhead of the fracturing well during a preset time period before and after an earthquake, the target pressure change rate can be determined to accurately distinguish the earthquake type, i.e., whether it is induced by the increase in pore pressure caused by the entry of fracturing fluid into the fault, or by the change in fault load caused by local stress changes due to hydraulic fracturing construction. Based on the accurate judgment of the earthquake type, more targeted earthquake control measures can be determined, improving the rationality and effectiveness of earthquake control measures, more effectively reducing the potential hazards caused by earthquakes, and ensuring the safety and stability of related areas and projects.

[0042] According to an embodiment of this application, determining the type of microearthquake based on the target pressure change rate determined by the first pressure data and the second pressure data may include: performing linear fitting on the first pressure data of the first time period and the second pressure data of the second time period respectively to obtain a first fitted line segment and a second fitted line segment; determining the target pressure change rate based on the pre-earthquake pressure change rate and the post-earthquake pressure change rate determined by the first fitted line segment and the second fitted line segment respectively; and determining the type of microearthquake based on the target pressure change rate.

[0043] For example, linear fitting can be performed on the wellhead pressure curves 100-200 seconds before and after the earthquake to obtain a first fitted line segment and a second fitted line segment. The derivatives of the first and second fitted line segments are then calculated, and the pre-earthquake pressure change rate and the post-earthquake pressure change rate are obtained based on the absolute values ​​of the derivatives. Based on the pre-earthquake and post-earthquake pressure change rates, a target pressure change rate representing the pre-earthquake and post-earthquake pressure changes is calculated.

[0044] According to embodiments of this application, the type of microseismic event is determined by linearly fitting pressure data and comparing the pressure change rates before and after the earthquake, thereby quantifying the pressure change characteristics before and after the microseismic event, simplifying the complex data analysis process and improving processing efficiency.

[0045] According to an embodiment of this application, determining the type of microseismic event based on the target pressure change rate includes: determining the type of microseismic event as a first type when the target pressure change rate meets a preset difference condition; and determining the type of microseismic event as a second type when the target pressure change rate does not meet the preset difference condition.

[0046] For example, the preset difference condition can be a preset threshold. For instance, the preset difference condition can be 180%. The embodiments of this application are not limited to this; the preset difference condition can be determined based on actual engineering experience, or it can be determined based on geological parameters and construction parameters.

[0047] For example, when the target pressure change rate is greater than 180%, it indicates that the induced microseismic event is caused by the increase in pore pressure on the large-size structural surface, that is, the fracturing fluid enters the large-size structural surface. The reason is that the wellhead pressure fluctuation is caused by the communication between the rupture accompanying the induced earthquake during the fracturing process and the fluid in the well.

[0048] When the target pressure change rate is less than 180%, it indicates that the induced earthquake is caused by the load change on the large-size structural surface. That is, the local stress change caused during the hydraulic fracturing process disturbs the large-size structural surface. The reason is that the rupture accompanying the induced earthquake during the fracturing process does not form a communication with the fluid in the well, and therefore does not affect the wellhead pressure.

[0049] Figure 2a A schematic diagram of linear fitting of a first type of microseismic event according to an embodiment of this application is shown.

[0050] like Figure 2a As shown, due to the continuous leakage of fracturing fluid into the fault, the wellhead pressure exhibits a significant and sustained downward trend, which may be accelerated by microseismic events. After linearly fitting the pre-seismic and post-seismic pressure curves and differentiating the fitted segments, the pre-seismic pressure change rate was approximately 0.000728, and the post-seismic pressure change rate was approximately 0.00215. Therefore, the target pressure change rate was calculated as (0.00215 - 0.000728) / 0.000728 × 100% = 195%. Thus, the earthquake type was determined to be Type I.

[0051] Figure 2b A schematic diagram of linear fitting for a second type of microseismic event according to an embodiment of this application is shown.

[0052] like Figure 2b As shown, the rupture accompanying the induced microseismic event did not form a connection with the fracturing fluid in the well. The wellhead pressure would not experience a pressure drop due to the loss of a large amount of fluid. After linearly fitting the pre-seismic and post-seismic pressure curves and differentiating the fitted segments, the pre-seismic pressure change rate was approximately 0.000186, and the post-seismic pressure change rate was approximately 0.000212. Therefore, the target pressure change rate was calculated as (0.000212 - 0.000186) / 0.000186 × 100% = 13.9%. Thus, the earthquake type was determined to be Type II.

[0053] According to the embodiments of this application, by comparing the target pressure change rate with preset difference conditions, the method for identifying microseismic types is simplified, and the efficiency and accuracy of identification are improved.

[0054] If it is determined that a microseismic event has been induced, construction can be stopped immediately. Based on the method for determining the type of microseismic event described above, the type of microseismic event can be determined. Then, based on the type of microseismic event, target control measures can be determined to prevent the microseismic event from being induced again.

[0055] The target control measures for different types of microseismic events are described in further detail below.

[0056] According to an embodiment of this application, determining the target control measures for controlling the re-induction of microseismic events based on the type of microseismic event may include: in the case where the type of microseismic event is determined to be a first type of microseismic event, determining the positional relationship between the fault that triggered the microseismic event and the hydraulically fractured thermal reservoir; and determining a sealing agent for sealing the fractures between the fault and the fractured well based on the positional relationship between the fault and the thermal reservoir.

[0057] Since Type I microseismic events occur when fracturing fluid enters a large-scale structural surface dominated by faults, leading to increased pore pressure, sealing agents can be used to plug the fractures between the fault and the fracturing well.

[0058] For example, the relative positional relationship between a fault and a thermal reservoir can be determined based on the depth of the fault within the thermal reservoir.

[0059] According to an embodiment of this application, based on the positional relationship between the fault and the thermal reservoir, the sealing agent used to seal the passage between the fault and the fracturing well may include: if the location of the fault is determined to be below a predetermined position of the thermal reservoir in the depth direction, the sealing agent is determined to be quartz sand to prevent fracturing fluid from entering the fault.

[0060] For example, the preset location may be a portion within 20% of the bottom of the fracturing section of the thermal reservoir. The embodiments of this application are not limited to this, and can be adaptively adjusted according to geological parameters.

[0061] For example, the bottom 20% of the fracturing section in a thermal reservoir is typically under high confining pressure, where the fault may be compacted and has low natural permeability. However, once fracturing fluid enters, it is more prone to disturbance and seismic induction. Quartz sand particles can embed themselves in structural pores or fractures under high pressure, forming a physical barrier that completely blocks fracturing fluid from entering the structural surface of the fault. In other words, the bottom 20% of the fracturing section should be abandoned to prevent it from acting as a fluid channel to trigger fault slip or microseismic activity.

[0062] According to an embodiment of this application, when the location of the fault is determined to be below a predetermined position in the depth direction of the thermal reservoir, the fracturing fluid cannot continue to be injected after the deep structural surface is filled with quartz sand, thereby reducing the risk of fault activation.

[0063] According to an embodiment of this application, based on the positional relationship between the fault and the thermal reservoir, a plugging agent for sealing the passage between the fault and the fractured well is determined, further comprising: when it is determined that the location of the fault is above a preset position of the thermal reservoir in the depth direction, determining the plugging agent as a temporary plugging agent to temporarily seal the fracture between the fault and the fractured well, so as to promote the fracturing fluid to fracture the non-faulted part of the thermal reservoir.

[0064] For example, the preset location could be a portion within the upper 80% range of the fracturing section of the thermal reservoir. The embodiments of this application are not limited to this, and can be adaptively adjusted according to geological parameters.

[0065] For example, the confining pressure in the upper 80% of the thermal reservoir is low. After the temporary plugging agent (such as polymer particles, fibers or biodegradable materials) enters the structural surface of the fault under high pressure, it quickly seals the fractures through adsorption, expansion or bridging, forcing the fracturing fluid to extend to the unmodified area in order to maintain the fracture network in the thermal reservoir.

[0066] For example, to achieve shielding between large structural surfaces such as faults and the fractured well, a temporary plugging agent can be pumped in at the initial stage of each hydraulic fracturing operation (the first 5% of the injection volume). The injection volume of the temporary plugging agent can increase with the cumulative injection volume, and the injection volume of the temporary plugging agent should not be less than 5% of the cumulative injection volume of the fractured well. For example, if the cumulative injection volume is 10,000 m³, the injection volume of the temporary plugging agent in this stage should not be less than 500 kg.

[0067] Figure 3 A schematic diagram of the fault structure distribution and fractured well according to an embodiment of this application is shown.

[0068] like Figure 3 As shown, a fracturing well 320 is drilled from the surface into the thermal reservoir 310 to hydraulically fracture the reservoir. In the event of a Type I earthquake, the relative positions of the fault and the thermal reservoir are determined. If the fault is located in the upper 80% of the reservoir, such as the first fault 331, a temporary plugging agent is used to temporarily seal the fracture between the first fault 331 and the fracturing well 320. If the fault is located in the lower 20% of the reservoir, such as the second fault 332, quartz sand is used to temporarily seal the fracture between the second fault 332 and the fracturing well 320.

[0069] According to the embodiments of this application, depending on the depth of the fault's structural plane in the geothermal reservoir, quartz sand sealing (deep part) or temporary plugging agent sealing (upper part) can be used in a differentiated manner. This can achieve the dual objectives of blocking the risk of microseismic events induced by deep faults and optimizing the development efficiency of geothermal energy storage in the upper part, thus taking into account both earthquake safety control and the economic efficiency of geothermal resource development.

[0070] According to embodiments of this application, determining the target control measures for preventing the re-induction of microseismic events, based on the type of microseismic event, may further include: if the type of microseismic event is determined to be a second type, acquiring the location, time of occurrence, and original microseismic waveform data of the microseismic event; performing moment tensor inversion on the original microseismic waveform data based on the location and time of occurrence of the microseismic event to determine the rupture surface parameters and principal stress parameters; determining the target stress conditions for fault slippage based on the rupture surface parameters and principal stress parameters; and determining the wellhead pressure for hydraulic fracturing operations based on the target stress conditions.

[0071] For example, multiple microseismic stations arranged around the fractured well can be used to detect microseisms, so that when a microseismic event is induced, the location, time of occurrence, and raw microseismic waveform data of the microseismic event can be obtained using multiple microseismic stations.

[0072] The number of microseismic stations deployed around the fracturing well shall not be less than 60. These stations, centered on the hydraulic fracturing well, can be evenly distributed in a star-shaped pattern around the well to continuously monitor the original microseismic waveforms during the fracturing and pump shutdown phases. This embodiment is not limited to this; the microseismic stations can also be appropriately adjusted according to terrain, human activity areas, and buildings. The straight-line distance between the adjusted location and the preset route should not exceed 20 meters.

[0073] The stress waves generated by the induced earthquake are first received by microseismic stations, and the three-dimensional coordinates of the induced earthquake and the time of its occurrence can be determined by the time difference method.

[0074] Moment tensor inversion can be performed based on the original microseismic waveform data of the received stress waves to obtain the energy level and rupture mechanism of the induced earthquake.

[0075] Moment tensor inversion can obtain rupture surface parameters such as azimuth, dip, slip angle, and rupture radius, which define the geometric characteristics of the structural surface. The rupture mechanism also reveals the stress state near the earthquake source, such as principal stress parameters like direction and magnitude. Furthermore, moment tensor inversion can be used to determine the rupture nature of the focal event, such as shear rupture or tensile rupture.

[0076] According to embodiments of this application, determining the target stress condition for fault slippage based on fracture surface parameters and principal stress parameters may include: decomposing the principal stress into normal stress and shear stress based on the azimuth, dip angle, and principal stress parameters of the fracture surface; and determining the target stress condition for fault slippage based on the Mohr stress circle drawn based on the normal stress and shear stress.

[0077] For example, a Mohr stress circle can be constructed with normal stress as the abscissa and shear stress as the ordinate. The center of the Mohr stress circle is determined based on the average principal stress, and the radius is determined based on the maximum shear stress.

[0078] For example, the shear strength envelope, i.e., the Mohr-Coulomb failure criterion envelope, can be drawn based on rock mechanics parameters (such as the internal friction angle φ and cohesion c). If the Mohr stress circle lies below the shear strength envelope, the structural surface is in a stable state and will not slip. If the Mohr stress circle is tangent to or intersects the shear strength envelope, the structural surface is in a critical slip or slip state.

[0079] For example, based on the results of Mohr's stress circle analysis, the range of bottom-hole net pressure that will maintain the stability of the fault's structural surface can be determined. If the bottom-hole net pressure exceeds this range, the fault's structural surface may experience slippage. Based on the relationship between the bottom-hole net pressure and the wellhead pressure, the range within which the wellhead pressure should be controlled can be determined. By adjusting the wellhead pressure, the bottom-hole net pressure can be indirectly controlled, thereby ensuring the stability of the fault's structural surface.

[0080] For example, during hydraulic fracturing, measures such as small-volume, long-cycle hydraulic fracturing, setting multiple pump-stopping stages during fracturing, and waiting for the fracturing fluid in the thermal reservoir to be lost to reduce the pressure of the thermal reservoir can be adopted to avoid inducing earthquakes due to excessive concentration of effective stress.

[0081] According to an embodiment of this application, when the type of microseismic event is type II, the induced earthquake rupture mechanism is obtained by performing moment tensor inversion on the original microseismic waveform data. The sliding conditions of the large-size structural surface under load disturbance conditions are calculated using the Mohr stress circle rule. This can accurately reveal the range of net pressure control at the bottom of the well, thereby limiting the wellhead pressure and reducing the further occurrence of induced earthquakes.

[0082] Figure 4 A flowchart is shown for determining a seismic control method after hydraulic fracturing-induced microseisms, according to another embodiment of this application.

[0083] like Figure 4 As shown, the method includes operations S401 to S413.

[0084] During operation of S401, the pressure at the wellhead of the fractured well is continuously monitored.

[0085] Operate S402 to obtain the pressure fluctuation curves before and after the earthquake.

[0086] In operation S403, the pressure fluctuation curve is linearly fitted and differentiated to determine the target pressure change rate.

[0087] If the target pressure change rate meets the preset difference condition, execute operation S404. In operation S404, the type of microseismic event is determined to be type one.

[0088] In operation S405, the sealing agent used to seal the fractures between the fault and the fractured well is determined based on the location relationship between the fault and the thermal reservoir.

[0089] If the fault is below the preset location, execute operation S406 to determine that the plugging agent is quartz sand. If the fault is above the preset location, execute operation S407 to determine that the plugging agent is a temporary plugging agent.

[0090] If the target pressure change rate does not meet the preset difference condition, execute operation S408. In operation S408, the type of microseismic event is determined to be type II.

[0091] Using S409, the location, time of occurrence, and raw microseismic waveform data of the microseismic event are obtained.

[0092] In operation S410, based on the location and time of occurrence of the microseismic event, moment tensor inversion is performed on the original microseismic waveform data to determine the rupture surface parameters and principal stress parameters.

[0093] In operation S411, based on the azimuth, dip angle and principal stress parameters of the fracture surface, the principal stress is decomposed into normal stress and shear stress.

[0094] In operation S412, the target stress condition for fault slip is determined by drawing a molar stress circle based on normal stress and shear stress.

[0095] In operation S413, the wellhead pressure for hydraulic fracturing is determined based on the target stress conditions.

[0096] According to the embodiments of this application, by first determining the earthquake type based on the target pressure change rate, and then determining the matching earthquake control measures according to the earthquake type, the safe and efficient exploitation of subsequent geothermal resources is ensured.

[0097] Figure 5 A structural block diagram of a seismic control device for determining hydraulically fracturing-induced microseisms according to an embodiment of this application is shown.

[0098] like Figure 5 As shown, the seismic control device 500 for determining the micro-earthquake induced by hydraulic fracturing includes an acquisition module 510, a first determination module 520, and a second determination module 530.

[0099] The acquisition module 510 is used to acquire, in response to the determination that a microseismic event has been induced during the hydraulic fracturing process, the first pressure data of the wellhead of the fracturing well in the first time period before the microseismic event and the second pressure data of the wellhead of the fracturing well in the second time period after the microseismic event.

[0100] The first determining module 520 is used to determine the type of microseismic event based on the target pressure change rate determined by the first pressure data and the second pressure data. The type of microseismic event includes at least one of the first type and the second type. The first type of microseismic event is characterized by microseismic events induced by the increase in pore pressure of the fault due to the entry of fracturing fluid into the fault. The second type of microseismic event is characterized by microseismic events induced by the change in load of the fault due to the change in local stress caused by hydraulic fracturing construction.

[0101] The second determining module 530 determines, based on the type of microseismic event, target control measures to prevent the microseismic event from being induced again.

[0102] According to an embodiment of this application, the first determining module 520 includes a fitting submodule, a first determining submodule, and a second determining submodule.

[0103] The fitting submodule is used to perform linear fitting on the first pressure data of the first time period and the second pressure data of the second time period, respectively, to obtain the first fitted line segment and the second fitted line segment.

[0104] The first determination submodule is used to determine the target pressure change rate based on the pre-earthquake pressure change rate and the post-earthquake pressure change rate determined by the first fitted line segment and the second fitted line segment, respectively.

[0105] The second determination submodule is used to determine the type of microseismic event based on the target pressure change rate.

[0106] According to an embodiment of this application, the second determining submodule includes a first determining unit and a second determining unit.

[0107] The first determining unit is used to determine the type of microseismic earthquake as the first type of microseismic earthquake when the target pressure change rate meets the preset difference condition.

[0108] The second determining unit is used to determine the type of microseismic earthquake as the second type when the target pressure change rate does not meet the preset difference condition.

[0109] According to an embodiment of this application, the second determining module 530 includes a third determining submodule and a fourth determining submodule.

[0110] The third determination submodule is used to determine the positional relationship between the fault that triggered the microseismic event and the hydraulically fracturing reservoir when the type of microseismic event is determined to be the first type.

[0111] The fourth determination submodule is used to determine the sealing agent used to seal the fractures between the fault and the fractured well based on the positional relationship between the fault and the thermal reservoir.

[0112] According to an embodiment of this application, the fourth determining submodule includes a third determining unit and a fourth determining unit.

[0113] The third determining unit is used to determine that the sealing agent is quartz sand when the location of the fault is below a preset position of the thermal reservoir in the depth direction, so as to prevent fracturing fluid from entering the fault.

[0114] The fourth determining unit is used to determine the plugging agent as a temporary plugging agent when the location of the fault is determined to be above a preset position of the thermal reservoir in the depth direction, so as to temporarily seal the fracture between the fault and the fractured well, so as to promote the fracturing fluid to fracture the non-fault part of the thermal reservoir.

[0115] According to an embodiment of this application, the second determining module 530 further includes an acquisition submodule, an inversion submodule, a fifth determining submodule, and a sixth determining submodule.

[0116] The acquisition submodule is used to acquire the location, time of occurrence, and original microseismic waveform data of a microseismic event when the type of microseismic event is determined to be type II.

[0117] The inversion submodule is used to perform moment tensor inversion on the original microseismic waveform data based on the location and time of occurrence of the microseismic event, and to determine the rupture surface parameters and principal stress parameters.

[0118] The fifth determination submodule is used to determine the target stress conditions for fault slippage based on the rupture surface parameters and principal stress parameters.

[0119] The sixth determination submodule is used to determine the wellhead pressure for hydraulic fracturing operations based on the target stress conditions.

[0120] According to an embodiment of this application, the fracture surface parameters include the azimuth and dip angle of the fracture surface. The fifth determination submodule includes a decomposition unit and a fifth determination unit.

[0121] The decomposition element is used to decompose the principal stress into normal stress and shear stress based on the azimuth, dip angle and principal stress parameters of the fracture surface.

[0122] The fifth determining unit is used to determine the target stress condition for fault slippage based on the molar stress circle drawn based on normal stress and shear stress.

[0123] According to an embodiment of this application, the acquisition module is used to detect microseismic events using multiple microseismic stations arranged around the fractured well, so that when a microseismic event is detected to be induced, the multiple microseismic stations can be used to acquire the location, time of occurrence, and original microseismic waveform data of the microseismic event.

[0124] Any one or more of the modules, submodules, units, and subunits according to the embodiments of this application, or at least part of the functions of any one or more of them, can be implemented in one module. Any one or more of the modules, submodules, units, and subunits according to the embodiments of this application can be implemented by dividing them into multiple modules. Any one or more of the modules, submodules, units, and subunits according to the embodiments of this application can be at least partially implemented as hardware circuits, such as field-programmable gate arrays (FPGAs), programmable logic arrays (PLAs), systems-on-a-chip, systems-on-a-substrate, systems-on-package, application-specific integrated circuits (ASICs), or implemented by hardware or firmware in any other reasonable manner by integrating or packaging circuits, or implemented in any one of software, hardware, and firmware, or in a suitable combination of any of these. Alternatively, one or more of the modules, submodules, units, and subunits according to the embodiments of this application can be at least partially implemented as computer program modules, which, when run, can perform corresponding functions.

[0125] For example, any plurality of the acquisition module 510, the first determination module 520, and the second determination module 530 can be combined into one module / unit / subunit, or any one of these modules / units / subunits can be split into multiple modules / units / subunits. Alternatively, at least part of the functionality of one or more of these modules / units / subunits can be combined with at least part of the functionality of other modules / units / subunits and implemented in one module / unit / subunit. According to embodiments of this application, at least one of the acquisition module 510, the first determination module 520, and the second determination module 530 can be at least partially implemented as hardware circuitry, such as a field-programmable gate array (FPGA), a programmable logic array (PLA), a system-on-a-chip, a system-on-a-substrate, a system-on-package, an application-specific integrated circuit (ASIC), or any other reasonable means of integrating or packaging the circuitry, or implemented in software, hardware, or firmware, or in any suitable combination of any of these three implementation methods. Alternatively, at least one of the acquisition module 510, the first determination module 520, and the second determination module 530 may be implemented at least partially as a computer program module, which can perform corresponding functions when the computer program module is run.

[0126] It should be noted that the stress analysis device part in the embodiments of this application corresponds to the stress analysis method part in the embodiments of this application. The description of the stress analysis device part is specifically referred to in the stress analysis method part, and will not be repeated here.

[0127] The embodiments of this application have been described above. However, these embodiments are merely illustrative and not intended to limit the scope of this application. Although various embodiments have been described above, this does not mean that the measures in the various embodiments cannot be used advantageously in combination. The scope of this application is defined by the appended claims and their equivalents. Various substitutions and modifications can be made by those skilled in the art without departing from the scope of this application, and all such substitutions and modifications should fall within the scope of this application.

Claims

1. A method for determining seismic control after hydraulic fracturing-induced microearthquakes, characterized in that, The method includes: In response to the determination that a microseismic event was induced during the hydraulic fracturing process, the first pressure data of the wellhead of the fracturing well in the first time period before the microseismic event and the second pressure data of the wellhead of the fracturing well in the second time period after the microseismic event are obtained. The type of microseismic event is determined based on the target pressure change rate determined by the first pressure data and the second pressure data. The type of microseismic event includes at least one of the first type and the second type. The first type of microseismic event is characterized by microseismic events induced by the increase in pore pressure of the fault due to the entry of fracturing fluid into the fault. The second type of microseismic event is characterized by microseismic events induced by the change in load of the fault due to the change in local stress caused by hydraulic fracturing. If the microseismic type is determined to be a type 1 microseismic, determine the positional relationship between the fault that triggered the microseismic and the hydraulically fracturing thermal reservoir. Based on the positional relationship between the fault and the thermal reservoir, a sealing agent for sealing the fractures between the fault and the fractured well is determined; If the microseismic type is determined to be a type II microseismic earthquake, the location, time of occurrence, and original microseismic waveform data of the microseismic earthquake are obtained. Based on the location and time of occurrence of the microseismic events, moment tensor inversion is performed on the original microseismic waveform data to determine the rupture surface parameters and principal stress parameters. Based on the fracture surface parameters and the principal stress parameters, the target stress condition for the fault to slip is determined; Based on the target stress conditions, the wellhead pressure for hydraulic fracturing operations is determined. The fracture surface parameters include the azimuth and dip angle of the fracture surface; The determination of the target stress condition for fault slippage based on the fracture surface parameters and the principal stress parameters includes: Based on the azimuth, dip angle and principal stress parameters of the fracture surface, the principal stress is decomposed into normal stress and shear stress. Based on the molar stress circle drawn from the normal stress and shear stress, the target stress condition for the fault to slip is determined.

2. The method according to claim 1, characterized in that, The step of determining the type of microseismic event based on the target pressure change rate determined from the first pressure data and the second pressure data includes: Linear fitting is performed on the first pressure data in the first time period and the second pressure data in the second time period to obtain a first fitted line segment and a second fitted line segment. The target pressure change rate is determined based on the pre-earthquake pressure change rate and post-earthquake pressure change rate determined by the first fitted line segment and the second fitted line segment, respectively. The type of micro-earthquake is determined based on the target pressure change rate.

3. The method according to claim 2, characterized in that, Determining the type of microseismic event based on the target pressure change rate includes: If the target pressure change rate is determined to meet the preset difference condition, the type of the microseismic event is determined to be a first type of microseismic event; If the target pressure change rate does not meet the preset difference condition, the microseismic type is determined to be a second type of microseismic.

4. The method according to claim 1, characterized in that, The step of determining the sealing agent for sealing the fractures between the fault and the fractured well based on the positional relationship between the fault and the thermal reservoir includes: If the location of the fault is determined to be below a predetermined position in the depth direction of the thermal reservoir, the sealing agent is determined to be quartz sand to prevent fracturing fluid from entering the fault.

5. The method according to claim 1, characterized in that, The step of determining the sealing agent for sealing the fractures between the fault and the fractured well based on the positional relationship between the fault and the thermal reservoir includes: If the location of the fault is determined to be above a predetermined position in the depth direction of the thermal reservoir, the plugging agent is determined to be a temporary plugging agent to temporarily seal the fracture between the fault and the fractured well, so as to promote the fracturing fluid to fracture the non-faulted part of the thermal reservoir.

6. The method according to claim 1, characterized in that, The acquisition of the location, time of occurrence, and original microseismic waveform data of the microseismic event includes: Multiple microseismic stations arranged around the fractured well are used to detect microseismic events. If a microseismic event is detected, the location, time of occurrence, and original microseismic waveform data of the microseismic event are obtained using the multiple microseismic stations.

7. A seismic control device for determining the aftermath of hydraulic fracturing-induced microseismic events, characterized in that, The device includes: The acquisition module is used to acquire, in response to the determination that a microseismic event has been induced during the hydraulic fracturing process, the first pressure data of the wellhead of the fracturing well in the first time period before the microseismic event and the second pressure data of the wellhead of the fracturing well in the second time period after the microseismic event. The first determining module is used to determine the type of the microseismic event based on the target pressure change rate determined by the first pressure data and the second pressure data. The type of the microseismic event includes at least one of a first type and a second type. The first type of microseismic event is characterized by microseismic events induced by the increase in pore pressure of the fault due to the entry of fracturing fluid into the fault. The second type of microseismic event is characterized by microseismic events induced by the change in load of the fault due to the change in local stress caused by hydraulic fracturing operations. The second determining module is used to determine the positional relationship between the fault that caused the micro-earthquake and the thermal reservoir where hydraulic fracturing is performed when the type of the micro-earthquake is determined to be a first type of micro-earthquake. Based on the positional relationship between the fault and the thermal reservoir, a sealing agent for sealing the fractures between the fault and the fractured well is determined; If the microseismic type is determined to be a type II microseismic earthquake, the location, time of occurrence, and original microseismic waveform data of the microseismic earthquake are obtained. Based on the location and time of occurrence of the microseismic events, moment tensor inversion is performed on the original microseismic waveform data to determine the rupture surface parameters and principal stress parameters. Based on the fracture surface parameters and the principal stress parameters, the target stress condition for the fault to slip is determined; Based on the target stress conditions, the wellhead pressure for hydraulic fracturing operations is determined. The fracture surface parameters include the azimuth and dip angle of the fracture surface; The determination of the target stress condition for fault slippage based on the fracture surface parameters and the principal stress parameters includes: Based on the azimuth, dip angle and principal stress parameters of the fracture surface, the principal stress is decomposed into normal stress and shear stress. Based on the molar stress circle drawn from the normal stress and shear stress, the target stress condition for the fault to slip is determined.

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