Wellbore fracture control methods and systems for oil perforating operations

Abstract

The present application relates to the technical field of oil perforation operation, and proposes a wellbore fracture control method and system for oil perforation operation, which comprises the following steps: collecting the spatial position of a perforation cluster in oil perforation operation, calculating the shadow intensity value of the perforation cluster, selecting a standard perforation cluster and calculating the closed pressure increment, calculating the net pressure compensation amount of the perforation cluster; determining the sequence of sequentially fracturing each perforation cluster, screening a high compensation cluster and determining the specific process of fracturing, synchronously placing a temporary plugging agent, and completing the fracturing of each perforation cluster; collecting the pump pressure curve during the fracturing process, collecting the backflow particle concentration during the fracturing process and after the pump is stopped, positioning the microseismic event, combining the pump pressure curve and the backflow particle concentration, determining whether the high compensation cluster is activated, if yes, determining that the operation meets the standard, and if not, updating the calibration coefficient in reverse. The present application can realize the wellbore fracture control of oil perforation operation.

Description

Technical Field

[0001] This invention relates to the field of oil perforation operation technology, and more specifically to a wellbore fracture control method and system for oil perforation operations. Background Technology

[0002] Oil well perforation is a process that uses specialized perforating guns to penetrate the well casing, cement sheath, and part of the formation rock, creating channels within the rock mass and establishing a connection between the formation and the wellbore to facilitate the entry of reservoir fluids. After perforation, high-pressure fluid is injected into the well. When the bottomhole pressure exceeds the formation fracturing pressure, it induces a network of open fractures extending along the direction of minimum principal stress around the wellbore. The length, width, and conductivity of the wellbore fractures directly determine the flow resistance of oil and gas from the matrix to the perforations. By reducing the cluster spacing, increasing the number of fractures, and optimizing perforation parameters, fracture-controlled reserves can be maximized. Therefore, it is necessary to quantitatively control the opening degree of each fracture cluster to improve reserve utilization and ultimate recovery rate, while avoiding casing deformation and wellhead overpressure. Furthermore, the use of nano-fracturing fluids, combined proppants, and temporary plugging agents further optimizes the process, increasing fracture complexity and control volume, and ultimately increasing gas production.

[0003] Because the multi-cluster perforation fracturing process is affected by the stress shadowing effect, the middle cluster fractures are disturbed by the stress of the fractures on both sides. The stress shadowing will significantly increase the closure pressure of the middle fracture and reduce its conductivity. Therefore, the fracturing fluid and proppant tend to enter the outer fractures, resulting in uneven proppant distribution. This leads to uneven wellbore fracture expansion and affects the overall fracturing effect. Summary of the Invention

[0004] This invention provides a method and system for controlling wellbore fractures in oil perforation operations, to solve the problem of uneven wellbore fracture propagation caused by the superposition of stress shadows due to the dynamic interference of stress shadows from adjacent clusters in the middle cluster of fractures during oil perforation operations. The specific technical solution adopted is as follows:

[0005] In a first aspect, one embodiment of the present invention provides a wellbore fracture control method for oil perforation operations, the method comprising the following steps:

[0006] The spatial location of each perforation in all perforation clusters of oil perforation operations is collected. Based on the differences in the spatial location of perforations in different perforation clusters, the shadow intensity value of each perforation cluster is calculated. A standard perforation cluster is selected based on the shadow intensity value, and the closing pressure increment of the standard perforation cluster is obtained. Combined with the shadow intensity value of the perforation cluster, the net pressure compensation of each perforation cluster is calculated, and a calibration coefficient is set.

[0007] The order of fracturing each perforation cluster is determined based on the net pressure compensation value of the perforation cluster. High compensation clusters are selected from the perforation clusters. The specific fracturing process is determined based on the net pressure compensation value of the high compensation clusters. Temporary plugging agent is simultaneously injected and bottom hole pressure is collected while fracturing each perforation cluster. The volume of temporary plugging agent injected into the perforation cluster is determined based on the change in bottom hole pressure. A calibration coefficient is set to complete the fracturing of each perforation cluster.

[0008] Pump pressure curves are collected during fracturing, and backflow particle concentrations are collected during fracturing and after pump shutdown to locate microseismic events. Combining pump pressure curves and backflow particle concentrations, it is determined whether high-compensation clusters are activated. If so, the operation is deemed to have met the standards; otherwise, the calibration coefficients are updated in reverse.

[0009] Furthermore, the specific method for calculating the shadow intensity value of each perforation cluster and selecting a standard perforation cluster based on the shadow intensity value is as follows:

[0010] The Euclidean distance between the spatial locations of different perforation clusters is denoted as the inter-cluster distance between different perforation clusters, and the ratio of the preset crack scale to the inter-cluster distance between different perforation clusters is denoted as the shadow contribution of different perforation clusters.

[0011] The sum of the shadow contributions of the same perforation cluster to all other perforation clusters is recorded as the shadow intensity value of the same perforation cluster.

[0012] The perforation cluster with the highest shadow intensity value is designated as the standard perforation cluster.

[0013] Furthermore, the specific method for obtaining the closure pressure increment of the standard perforation cluster is as follows:

[0014] Micro-fracturing experiments were conducted on a standard perforation cluster to obtain the instantaneous shut-in pressure response after pump shutdown. The G function was then used to obtain the closure pressure increment of the standard perforation cluster.

[0015] Furthermore, the specific method for obtaining the net pressure compensation amount of the perforation cluster is as follows:

[0016] The ratio of the closing pressure increment of the standard perforation cluster to the shadow intensity value is denoted as the standard ratio. The product of the shadow intensity value of the perforation cluster and the standard ratio is denoted as the net pressure compensation of the perforation cluster.

[0017] Furthermore, the specific method for determining the order of fracturing each perforation cluster based on the net pressure compensation value of the perforation cluster, and for selecting high-compensation clusters from the perforation clusters, includes:

[0018] Fracturing of each perforation cluster in descending order of net pressure compensation;

[0019] Round up 20% of the total number of perforation clusters in the oil perforation operation and denote it as the first value. The perforation cluster with the largest net pressure compensation of the first value is denoteed as the high compensation cluster.

[0020] Furthermore, the specific fracturing process includes:

[0021] Confirm wellbore integrity; pump in all pre-flush fluid; assign a short-duration, high-flow-rate pulse window for each high-compensation cluster and pump in sand-mixing fluid for the pulse window; arrange a transition section; compensate the high-compensation cluster; complete the remaining fracture fracturing; pump in displacement fluid.

[0022] Furthermore, the specific method for obtaining the volume of the temporary plugging agent is as follows:

[0023] For the fractured but not yet blown-out sections, a temporary plugging agent is injected at the preset design displacement and the bottom hole pressure is collected in real time until the temporary plugging agent reaches the perforation. The volume of the temporary plugging agent injected at this time is recorded as the first volume. The difference between the bottom hole pressure at this time and the bottom hole pressure at the beginning of the injection of the temporary plugging agent is recorded as the bottom hole pressure difference. The ratio of the first volume to the bottom hole pressure difference is recorded as the first ratio. The product of the net pressure compensation of the perforation cluster and the first ratio is recorded as the volume of temporary plugging agent injected into the perforation cluster.

[0024] Furthermore, the specific steps for determining whether a high-compensation cluster is activated are as follows:

[0025] The average pump pressure is calculated based on the pump pressure. When a continuous rise in pressure occurs for a duration greater than one-third of the pulse window, and the rise in pressure is greater than or equal to half of the net pressure compensation amount of the pulse window, the compensation is considered successful. When the compensation is considered successful, it is recorded as the first criterion being met.

[0026] The average backflow particle concentration is calculated based on the backflow particle concentration before fracturing pump shutdown. The relative proportion of the peak area of ​​a cluster to the total cumulative backflow sand is recorded as the first proportion of the cluster. When the backflow particle concentration of the tracer particle size segment or fluorescence channel corresponding to the cluster is greater than or equal to twice the average backflow particle concentration, and the first proportion of the cluster is greater than the sum of the average of the first proportions of other clusters and the standard deviation of the first proportions of all clusters, it is determined that the cluster has absorbed proppant and participated in flow. When the cluster has absorbed proppant and participated in flow, it is recorded that the second criterion is met.

[0027] To locate microseismic events, obtain microseismic cloud maps distributed along the wellbore, and determine whether fractures have been initiated, the event density per 100 meters of the entire section is used as the background value. If the number of microseismic events within ±25 meters of the target well section is more than twice the background density, and at the same time, the maximum magnitude event appears in the regional magnitude distribution, fractures are determined to have been initiated. When fractures are initiated, it is recorded that the third criterion is met.

[0028] The high-compensation cluster is activated when at least two criteria are met.

[0029] Furthermore, the specific steps for the reverse update of the calibration coefficients are as follows:

[0030] The calibration coefficients include the standard ratio and the first ratio;

[0031] Increase the standard ratio of high-compensation clusters corresponding to the determination that no compensation was successful; increase the first ratio of high-compensation clusters corresponding to the determination that no clusters have been inhaled with proppant and participated in diversion.

[0032] Secondly, embodiments of the present invention also provide a wellbore fracture control system for oil perforation operations, including a memory, a processor, and a computer program stored in the memory and running on the processor, wherein the processor executes the computer program to implement the steps of any of the methods described above.

[0033] The beneficial effects of this invention are:

[0034] This application first quantifies the intensity of the additional closing stress on the perforation cluster from adjacent perforation clusters, obtaining the shadow intensity value of the perforation cluster. The larger the shadow intensity value, the stronger the additional closing stress from adjacent perforation clusters. Then, the influence of adjacent perforation clusters on the closing pressure of the standard perforation cluster is evaluated, obtaining the closing pressure increment. Subsequently, the net pressure compensation for each perforation cluster is calculated. The net pressure compensation can be calibrated on-site using data from a single micro-fracturing experiment without requiring large-scale numerical simulations, reducing the risk of intermediate cluster failure and improving the effectiveness of the overall fracture network. The perforation clusters are fracturing sequentially according to their net pressure compensation from largest to smallest. High-compensation clusters are then injected with liquid in descending order of net pressure compensation, with a fixed amount of temporary plugging agent simultaneously added. A short-duration high-flow-rate pulse is applied at the beginning of each injection cycle, while the liquid volume is increased. During the window period before the bottom hole pressure is fully depleted, the stress shadow is forcibly broken through. At the same time, a temporary plugging agent is used to temporarily seal the low-compensation orifices. The biodegradable temporary plugging agent is introduced within the pulse window and can preferentially enter the already opened and higher-velocity low-compensation orifices with the fluid flow, quickly forming a temporary seal. This increases local friction and allows for the redistribution of fluid volume, which involves high pressure first, then sealing, and then reversing. This ensures that the most vulnerable intermediate clusters fracture preferentially and continuously absorb proppant without increasing the total fluid volume, thus optimizing the fracture development effect. Finally, based on microseismic events, pump pressure curves, and backflow particle concentration, it is determined whether the high-compensation clusters are activated. If so, the operation is deemed to have met the standards. If not, the calibration coefficient is updated in reverse. This solves the problem of uneven wellbore fracture expansion caused by the superposition of stress shadows due to the dynamic interference of stress shadows from adjacent clusters in the intermediate clusters during oil perforation operations, thus achieving wellbore fracture control in oil perforation operations. Attached Figure Description

[0035] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0036] Figure 1 This is a schematic flowchart of a wellbore fracture control method for oil perforation operations provided in an embodiment of the present invention.

[0037] Figure 2 This is a flowchart illustrating the process of obtaining shadow intensity values ​​according to an embodiment of the present invention. Detailed Implementation

[0038] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0039] Please see Figure 1 The diagram illustrates a flowchart of a wellbore fracture control method for oil perforation operations according to an embodiment of the present invention, which includes the following steps:

[0040] Step S001: Collect the spatial position of each perforation in all perforation clusters of oil perforation operations. Based on the differences in the spatial position of perforations in different perforation clusters, calculate the shadow intensity value of each perforation cluster. Select a standard perforation cluster based on the shadow intensity value, obtain the closing pressure increment of the standard perforation cluster, and calculate the net pressure compensation amount of each perforation cluster based on the shadow intensity value of the perforation cluster, and set the calibration coefficient.

[0041] In wellbore fracture control during oil perforation operations, a perforation cluster refers to a group of perforations arranged around the wellbore according to certain rules and design requirements. The spatial positions of all perforations are obtained from the perforation design documents for oil perforation operations, and the spatial position of the middle perforation within the perforation cluster is recorded as the spatial position of the perforation cluster.

[0042] It is important to understand that most shale horizontal wells use multiple coplanar perforations within a single section. All perforation clusters are located in the same horizontal section with small elevation differences. Therefore, different fractures can be regarded as geometrically coplanar fractures. While ignoring the vertical additional stress, the inter-cluster distance between different perforation clusters can be calculated directly based on the spatial position differences of different perforation clusters.

[0043] The crack size represents the expected crack extension size of the perforation cluster under undisturbed conditions. It is generally taken as greater than or equal to 10 meters and less than or equal to 40 meters. In this embodiment, the crack size is taken as 15 meters.

[0044] The Euclidean distance between the spatial locations of different perforation clusters is denoted as the inter-cluster distance of different perforation clusters. The ratio of the crack scale to the inter-cluster distance of different perforation clusters is denoted as the shadow contribution of different perforation clusters. The sum of the shadow contributions of the same perforation cluster and all other perforation clusters is denoted as the shadow intensity value of the same perforation cluster.

[0045] In order to avoid the denominator being zero during the ratio calculation process, a preset value needs to be added to the denominator. In this example, the preset value is 0.1 meters.

[0046] The flowchart for obtaining shadow intensity values ​​is as follows: Figure 2 As shown, the shadow intensity value of a perforation cluster represents the intensity of the additional closing stress on the perforation cluster from adjacent perforation clusters. It is a data quantification result of invisible and intangible stress interference. The larger the shadow intensity value of a perforation cluster, the stronger the additional closing stress it experiences from adjacent perforation clusters.

[0047] For all perforation clusters in oil perforation operations, the cluster with the largest shadow intensity value is designated as the standard perforation cluster. Micro-fracturing experiments or diagnostic injection DFIT experiments are performed on the standard perforation cluster to obtain the instantaneous shut-in pressure response after pump shutdown. Using the G-function or pressure derivative method, the closure pressure increment of the standard perforation cluster is obtained based on the instantaneous shut-in pressure response after pump shutdown. The ratio of the closure pressure increment of the standard perforation cluster to the shadow intensity value is denoted as the standard ratio. The product of the shadow intensity value of the perforation cluster and the standard ratio is denoted as the net pressure compensation of the perforation cluster.

[0048] It should be noted that the standard ratio is one of the calibration coefficients.

[0049] Understandably, the closing pressure increment reflects the degree of influence of adjacent perforation clusters on the closing pressure of the standard perforation cluster. The net pressure compensation can be calibrated on-site using data from a single micro-fracture experiment without the need for large-scale numerical simulations, reducing the risk of intermediate cluster failure and improving the effectiveness of the overall fracture network. The net pressure compensation of the standard perforation cluster is equal to the value of the closing pressure increment of the standard perforation cluster.

[0050] The greater the net pressure compensation of the perforation cluster, the more bottom hole net pressure needs to be compensated for in order to open and extend the fractures in the perforation cluster.

[0051] At this point, the net pressure compensation of the perforation cluster is obtained.

[0052] Step S002: Determine the order of fracturing each perforation cluster according to the net pressure compensation value of the perforation cluster, and select high compensation clusters from the perforation clusters. Determine the specific fracturing process according to the net pressure compensation value of the high compensation clusters. Simultaneously, release temporary plugging agent and collect bottom hole pressure while fracturing each perforation cluster. Determine the volume of temporary plugging agent to be released into the perforation cluster according to the change in bottom hole pressure, and set calibration coefficients to complete the fracturing of each perforation cluster.

[0053] In traditional multi-cluster perforation fracturing, perforation clusters are fracturing sequentially from lowest to highest initiation pressure. However, this process only considers the frictional resistance between different perforation clusters and neglects the dynamic interference of stress shadows from adjacent clusters. This often leads to the middle cluster being affected by the superposition of stress shadows, becoming the cluster with the highest actual fracturing pressure, thus easily causing the failure of the fracturing center cluster. Furthermore, when multiple clusters compete for fluid volume simultaneously, if high-shadow fractures do not obtain sufficient net pressure and flow rate in time, the tip will be pushed back by the additional closure stress induced by neighboring clusters, making it difficult to reopen subsequent fluid injection. Therefore, traditional multi-cluster perforation fracturing methods have limitations and require more precise dynamic analysis and optimization strategies to improve fracturing efficiency.

[0054] Fracturing of the perforation clusters is carried out sequentially in descending order of net pressure compensation, with a fixed amount of temporary plugging agent being injected simultaneously. A short-duration high-flow-rate pulse is applied at the beginning of each injection cycle to forcefully break through the stress shadow within the window period when the fluid volume is sufficient and the bottom hole pressure has not been completely consumed. At the same time, the low-shadow perforations are temporarily sealed with temporary plugging agent, forming a fluid volume redistribution of high pressure first, then sealing, and then reversing. This ensures that the most vulnerable intermediate clusters are preferentially fractured and continuously absorb proppant without increasing the total fluid volume.

[0055] The specific steps for administering the temporary plugging agent are as follows: after the bridge plug is set or sealed, first administer a constant low displacement ( Test extrusion and fracturing were conducted to confirm the integrity of the wellbore. Then, the discharge rate was increased to the design discharge rate in one go. Under the designed displacement, all pre-fluid, sand mixing fluid and displacement fluid are continuously pumped in sequence. The proppant is mixed in evenly according to a uniform sand ratio, and the temporary plugging agent is added at once according to experience.

[0056] Specifically, the value of constant low displacement should be greater than or equal to 1. And less than or equal to 2 The design displacement should be greater than or equal to 3. And less than or equal to 6 .

[0057] Specifically, in the entire injection fracturing process, the fracturing fluid serves as the base fluid, composed of water, thickener, and additives; proppant is used to support unclosed fractures, and the material is resin-coated sand or ceramic particles; temporary plugging agent is used for temporary sealing of fractures, and the material is biodegradable polymer, heat-sensitive material, or composite chemical reagent; pre-fracturing fluid is used to break the rock and contains only fracturing fluid; proppant-mixing fluid is used to carry proppant and contains both fracturing fluid and proppant, and may also include temporary plugging agent; displacement fluid is used to push the remaining sand into the fracture and contains only fracturing fluid.

[0058] Round up 20% of the total number of perforation clusters in the oil perforation operation and denote it as the first value. The perforation cluster with the largest net pressure compensation of the first value is denoteed as the high compensation cluster.

[0059] A continuous fracturing process includes: confirming wellbore integrity; pumping in all pre-flush fluid; defining a short-duration, high-flow-rate pulse window for each high-compensation cluster and pumping mixed sand fluid into the pulse window; arranging a transition section; compensating the high-compensation cluster; completing the fracturing of the remaining fractures; and pumping in displacement fluid. Confirming wellbore integrity ensures wellbore structural safety, laying the foundation for subsequent fracturing operations; pumping in all pre-flush fluid breaks up the rock, preparing for subsequent mixed sand fluid injection; compensating the high-compensation cluster enhances its fluid inflow capacity; completing the fracturing of the remaining fractures involves continuing to pump in the remaining mixed sand fluid at the designed flow rate after the high-compensation clusters are treated, opening other fractures; and pumping in displacement fluid pushes the remaining proppant into the fractures, completing the fracturing process.

[0060] Preferably, as an embodiment of this application, the total amount of the sand-mixing liquid is set to 600. The design displacement is set to 5. The pumping time for the sand mixing solution is set to 120. .

[0061] For example, if there are a total of 12 perforations in an oil perforation operation, i.e., 12 perforation clusters, then the three perforation clusters with the largest net pressure compensation are the high-compensation clusters. These three high-compensation clusters need to be divided into three pulse windows, and 10% of the mixing fluid volume should be used to compensate for the high-compensation clusters, i.e., 60... The mixed sand solution is used to compensate the high-compensation clusters, with 20 samples taken per pulse window. For the mixed sand solution, if the discharge rate is increased to 1.5 times the original design discharge rate within the pulse window, then the duration of each pulse window is approximately 2.7 seconds. Furthermore, a 30-second transition period is maintained between every two pulse windows to reduce the discharge rate back to the design discharge rate, allowing the temporary plugging agent to settle fully at a low flow rate and preventing it from being washed away by the high pressure of the next window.

[0062] Understandably, the high-compensation clusters are injected with liquid in descending order of net pressure compensation. There are transition sections between different high-compensation clusters until all pulse windows are completed. Then, all the mixed sand liquid is pumped in according to the design displacement to open other cracks. Finally, the displacement liquid is pumped in.

[0063] Furthermore, the method for calculating the volume of temporary plugging agent deployed during the sequential fracturing of each perforation cluster is as follows:

[0064] For the fractured but not yet blown-out sections, a temporary plugging agent is injected at the preset design displacement and the bottom hole pressure is collected in real time until the temporary plugging agent reaches the perforation. The volume of the temporary plugging agent injected at this time is recorded as the first volume. At the same time, the difference between the bottom hole pressure at this time and the bottom hole pressure at the beginning of the injection of the temporary plugging agent is recorded as the bottom hole pressure difference. The ratio of the first volume to the bottom hole pressure difference is recorded as the first ratio. The product of the net pressure compensation of the perforation cluster and the first ratio is recorded as the second volume of the perforation cluster.

[0065] It is important to understand that the second volume of the perforation cluster is the volume of temporary plugging agent added to the perforation cluster, and the temporary plugging agent with the second volume is added to the corresponding perforation cluster within the first 30-50 seconds of the pulse window.

[0066] Because the pressure propagation speed at the bottom of the well is much greater than the redistribution speed of fluid friction, under continuous horizontal pumping, the wellbore pressure will instantly spread to all orifices. At this time, whether fluid enters the orifice depends only on the local breakthrough pressure. The earlier the high pressure is applied, the earlier the high compensation cluster will break through.

[0067] At the baseline discharge rate, the bottom hole net pressure cannot reach the breakthrough threshold of the high-compensation cluster. However, the perforation cluster has already opened and is continuously injecting fluid. When the discharge rate suddenly increases, the bottom hole pressure will also jump instantaneously, thus exceeding the breakthrough threshold of the high-compensation cluster. At this time, the fractures in the perforation cluster already exist. Therefore, when the pressure rises, its volume expansion demand is greater, which will lead to a pressure response lag. The newly broken high-compensation cluster fractures are in the initial fracture stage, the fractures are narrower, and the response to pressure jumps is more sensitive, thus absorbing additional fluid volume to achieve the purpose of compensation.

[0068] Meanwhile, the biodegradable temporary plugging agent introduced into the pulse window can preferentially enter the already opened, low-compensation orifice with a higher flow rate, quickly forming a temporary seal. This increases local friction, essentially closing the first-opened door, forcing subsequent liquid flow to the still-open, high-compensation orifice. The flow rate at the high-compensation orifice is relatively low, and the newly broken crack is narrow, resulting in a low probability of temporary plugging agent retention. This achieves a temporary sealing effect, i.e., redistribution of liquid volume and optimization of crack development.

[0069] At this point, the fracturing of each perforation cluster is complete.

[0070] Step S003: Collect pump pressure curves during fracturing, collect backflow particle concentrations during fracturing and after pump shutdown, locate microseismic events, and determine whether high-compensation clusters are activated by combining pump pressure curves and backflow particle concentrations. If so, determine that the operation meets the standards; otherwise, update the calibration coefficients in reverse.

[0071] During the sequential fracturing of each perforation cluster, the pump pressure curve is collected by the surface high-pressure pump inlet pressure sensor. The pump pressure curve is a curve that continuously records the change of wellhead pressure over time.

[0072] Preferably, as an embodiment of this application, the sampling frequency of wellhead pressure should be greater than or equal to 1Hz and less than or equal to 10Hz. In this embodiment, the sampling frequency of wellhead pressure is set to 5Hz. The average value of all pump pressures collected in the first 30 seconds within the same pulse window is recorded as the average pump pressure. When a continuous rise in pressure occurs with a duration greater than one-third of the pulse window, and the rise amplitude is greater than or equal to half of the net pressure compensation amount of the pulse window, the compensation is deemed successful. When the compensation is deemed successful, it is recorded as the first criterion being met.

[0073] During and after fracturing, a laser particle size analyzer installed in the wellhead backflow line is used to continuously detect the number and concentration of proppant particles in the backflow fluid to obtain the backflow particle concentration.

[0074] The sampling frequency for the backflow particle concentration was 1 Hz. It is understood that fluorescent tracer sand was added before collecting the backflow particle concentration data, and different fluorescent agents were added at different pulse windows to distinguish different clusters. In fracturing operations, a "cluster" represents a region or stage in the fracturing fracture occupied by different fluorescent tracer sands. Each cluster is distinguished by different pulse windows or tracing methods. By continuously monitoring the signal in the backflow fluid, the proppant distribution and flow participation of each cluster can be analyzed.

[0075] The average concentration of all backflow particles collected within 5 minutes before fracturing pump shutdown is taken as the average backflow particle concentration. The relative proportion of the peak area of ​​a cluster to the total cumulative reverse sand discharge is recorded as the first proportion of the cluster. When the backflow particle concentration of the tracer particle size segment or fluorescence channel corresponding to a cluster is greater than or equal to twice the average backflow particle concentration, and the first proportion of the cluster is greater than the sum of the average of the first proportions of other clusters and the standard deviation of the first proportions of all clusters, it is determined that the cluster has absorbed proppant and participated in flow conduction. When a cluster has absorbed proppant and participated in flow conduction, it is recorded that the second criterion is met.

[0076] Microseismic events are weak seismic wave signals generated by rock fracturing during hydraulic fracturing operations. Microseismic events reflect the rock fracturing process and help assess fracturing effectiveness and fracture propagation.

[0077] During the fracturing process of each perforation cluster, each pumped in A microseismic event is located using fluid volume analysis, and a microseismic cloud map is obtained showing the distribution along the wellbore. Based on the microseismic cloud map, fracture initiation is determined. The event density per 100 meters of the entire well section is used as the background value. If, within a range of ±25 meters near the target well section, the number of microseismic events is more than twice the background density, and the maximum magnitude event appears in the magnitude distribution of that area, fracture initiation is determined. When fracture initiation occurs, the third criterion is considered met.

[0078] The method for locating microseismic events is a well-known technique and will not be elaborated further. Specifically, by capturing weak seismic waves generated by rock fracturing using a detector array installed downhole, the location of the microseismic event's source, the time of occurrence, and the magnitude are calculated using travel-time inversion technology, and a microseismic cloud map distributed along the wellbore is obtained. In this embodiment, events exceeding 70% of the maximum magnitude are defined as events of the maximum magnitude.

[0079] When at least two criteria are met, the high-compensation cluster is determined to be activated. The number of high-compensation clusters corresponding to the met criteria is counted, and the ratio of the number of high-compensation clusters corresponding to the met criteria to the total number of high-compensation clusters is recorded as the activation rate. When the activation rate is greater than the third quartile of the activation rate of the drilled wells in the oil perforation operation, the operation is determined to be compliant. When the activation rate is less than or equal to the third quartile of the activation rate of the drilled wells in the oil perforation operation, the operation is determined to be non-compliant, and the calibration coefficient is updated in reverse.

[0080] The specific steps for reverse updating the calibration coefficients are as follows: Increase the standard ratio of the high-compensation clusters corresponding to the cases where compensation was unsuccessful by 0.05. The first ratio of the high-compensation clusters corresponding to the criteria that no clusters have been observed to have absorbed proppant and participated in diversion is increased by 0.05. .

[0081] It should be noted that the increase in the standard ratio should be greater than or equal to 0.02. And less than or equal to 0.06 The increase in the first ratio should be greater than or equal to 0.02. And less than or equal to 0.06 .

[0082] Understandably, if the net pressure compensation of the high-compensation cluster corresponding to the failure to achieve compensation success has not overcome the stress shadow, increasing the standard ratio of the high-compensation cluster corresponding to the failure to achieve compensation success can obtain greater compensation pressure under the same shadow intensity. If the cluster has absorbed proppant and participated in flow, it indicates that the volume of temporary plugging agent is insufficient, the low-compensation orifice has not been effectively blocked, and it is still consuming liquid. Increasing the first ratio of the high-compensation cluster corresponding to the failure to absorb proppant and participate in flow can release more temporary plugging agent, increase the flow resistance of non-high-compensation clusters, and force the liquid to flow towards high-compensation clusters.

[0083] This achieves wellbore fracture control during oil perforation operations.

[0084] Based on the same inventive concept as the above methods, embodiments of the present invention also provide a wellbore fracture control system for oil perforation operations, including a memory, a processor, and a computer program stored in the memory and running on the processor. When the processor executes the computer program, it implements the steps of any one of the above-described wellbore fracture control methods for oil perforation operations.

[0085] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A wellbore fracture control method for oil perforation operations, characterized in that, The method includes the following steps: Step 1: Collect the spatial location of each perforation in all perforation clusters of oil perforation operations. Based on the differences in the spatial location of perforations in different perforation clusters, calculate the shadow intensity value of each perforation cluster. Select a standard perforation cluster based on the shadow intensity value, obtain the closing pressure increment of the standard perforation cluster, and set a calibration coefficient based on the shadow intensity value of the perforation cluster to calculate the net pressure compensation of each perforation cluster. The method for determining the shadow intensity value of the perforation cluster is as follows: The Euclidean distance between the spatial locations of different perforation clusters is denoted as the inter-cluster distance of different perforation clusters. The ratio of the preset crack scale to the inter-cluster distance of different perforation clusters is denoted as the shadow contribution of different perforation clusters. The sum of the shadow contributions of the same perforation cluster and all other perforation clusters is denoted as the shadow intensity value of the same perforation cluster. Step 2: Determine the order of fracturing each perforation cluster based on the net pressure compensation value of the perforation cluster. Fracture each perforation cluster in descending order of net pressure compensation value, and select high-compensation clusters from the perforation clusters. Determine the specific fracturing process based on the net pressure compensation value of the high-compensation clusters. Inject fluid into the high-compensation clusters in descending order of net pressure compensation value. Simultaneously, release temporary plugging agent and collect bottom hole pressure while fracturing each perforation cluster. The specific method for obtaining the volume of the temporary plugging agent is as follows: For the fractured but not yet blown-out sections, a temporary plugging agent is injected at the preset design displacement and the bottom hole pressure is collected in real time until the temporary plugging agent reaches the perforation. The volume of the temporary plugging agent injected at this time is recorded as the first volume. The difference between the bottom hole pressure at this time and the bottom hole pressure at the beginning of the injection of the temporary plugging agent is recorded as the bottom hole pressure difference. The ratio of the first volume to the bottom hole pressure difference is recorded as the first ratio and set as the calibration coefficient. The product of the net pressure compensation of the perforation cluster and the first ratio is recorded as the volume of temporary plugging agent injected into the perforation cluster. Step 3: Collect pump pressure curves during fracturing, and collect backflow particle concentrations during fracturing and after pump shutdown to locate microseismic events. Combine the pump pressure curves and backflow particle concentrations to determine whether high-compensation clusters are activated. If so, the operation is deemed to have met the standards. If not, the calibration coefficients of Step 1 and Step 2 are updated in reverse.

2. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific method for determining the selected standard perforation cluster is as follows: The perforation cluster with the highest shadow intensity value is designated as the standard perforation cluster.

3. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific method for obtaining the closure pressure increment of the standard perforation cluster is as follows: Micro-fracturing experiments were conducted on a standard perforation cluster to obtain the instantaneous shut-in pressure response after pump shutdown. The G function was then used to obtain the closure pressure increment of the standard perforation cluster.

4. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific method for obtaining the net pressure compensation amount of the perforation cluster is as follows: The ratio of the closing pressure increment of the standard perforation cluster to the shadow intensity value is denoted as the standard ratio. The product of the shadow intensity value of the perforation cluster and the standard ratio is denoted as the net pressure compensation of the perforation cluster.

5. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific method for determining the order of fracturing each perforation cluster based on the net pressure compensation value of the perforation cluster, and for selecting high-compensation clusters from the perforation clusters, includes: Round up 20% of the total number of perforation clusters in the oil perforation operation and denote it as the first value. The perforation cluster with the largest net pressure compensation of the first value is denoteed as the high compensation cluster.

6. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific fracturing process includes: Confirm wellbore integrity; pump in all pre-flush fluid; assign a short-duration, high-flow-rate pulse window for each high-compensation cluster and pump in sand-mixing fluid for the pulse window; arrange a transition section; compensate the high-compensation cluster; complete the remaining fracture fracturing; pump in displacement fluid.

7. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific steps involved in determining whether a high-compensation cluster is activated are as follows: The average pump pressure is calculated based on the pump pressure. When a continuous rise in pressure occurs for a duration greater than one-third of the pulse window, and the rise in pressure is greater than or equal to half of the net pressure compensation amount of the pulse window, the compensation is considered successful. When the compensation is considered successful, it is recorded as the first criterion being met. The average backflow particle concentration is calculated based on the backflow particle concentration before fracturing pump shutdown. The relative proportion of the peak area of ​​a cluster to the total cumulative backflow sand is recorded as the first proportion of the cluster. When the backflow particle concentration of the tracer particle size segment or fluorescence channel corresponding to the cluster is greater than or equal to twice the average backflow particle concentration, and the first proportion of the cluster is greater than the sum of the average of the first proportions of other clusters and the standard deviation of the first proportions of all clusters, it is determined that the cluster has absorbed proppant and participated in flow. When the cluster has absorbed proppant and participated in flow, it is recorded that the second criterion is met. To locate microseismic events, obtain microseismic cloud maps distributed along the wellbore, and determine whether fractures have been initiated, the event density per 100 meters of the entire section is used as the background value. If the number of microseismic events within ±25 meters of the target well section is more than twice the background density, and at the same time, the maximum magnitude event appears in the regional magnitude distribution, fractures are determined to have been initiated. When fractures are initiated, it is recorded that the third criterion is met. The high-compensation cluster is activated when at least two criteria are met.

8. The wellbore fracture control method for oil perforation operations according to claim 1, characterized in that, The specific steps for reversing the calibration coefficient update are as follows: The calibration coefficients include the standard ratio and the first ratio; Increase the standard ratio of the high-compensation clusters corresponding to the criteria where compensation failure did not occur; Increase the first ratio of the high-compensation clusters corresponding to the determination that no clusters have been observed to have inhaled proppant and participated in the diversion.

9. A wellbore fracture control system for oil perforation operations, comprising a memory, a processor, and a computer program stored in the memory and running on the processor, characterized in that, When the processor executes the computer program, it implements the steps of the method as claimed in any one of claims 1-8.

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