An intelligent analysis-based downhole directional drilling system

Abstract

The present application relates to the technical field of downhole directional drilling, and particularly relates to a downhole directional drilling system based on intelligent analysis, which comprises a trajectory deviation prediction unit, which performs trajectory extension simulation based on a current trajectory deviation feature set to determine whether there is trajectory deviation; a disturbance judgment unit, which distinguishes temporary disturbance from persistent disturbance based on time-frequency domain fluctuation characteristics of stratum natural build-up force obtained by inversion when there is trajectory deviation; a correction decision unit, which calculates tool face angle correction amplitude and build-up rate correction amplitude for persistent disturbance with the optimization target of minimizing regression trajectory length to select a correction mode; and a steering control unit, which performs single or linkage control of the centering sliding block and the push piston based on the correction mode. The present application avoids unnecessary steering actions and actuator wear through intelligent identification and classification of the causes of trajectory deviation, thereby prolonging the service life of the downhole directional drilling tool.

Description

Technical Field

[0001] This invention relates to the field of downhole directional drilling technology, and in particular to a downhole directional drilling system based on intelligent analysis. Background Technology

[0002] In drilling operations for underground geological exploration in coal mines, directional drilling technology is a crucial means to ensure the borehole trajectory accurately hits the target strata or point. Current technology uses a measurement-while-drilling (MWD) system to acquire the drill bit position and spatial attitude in real time. Operators or automatic control systems adjust the directional drilling mechanism of the underground directional drilling tool based on the deviation between the measured trajectory and the designed target trajectory, thereby controlling the drilling direction. However, the complex geological conditions in underground coal mines mean that most trajectory deviations are temporary disturbances, and the lack of intelligent analysis leads to increased ineffective directional actions.

[0003] Chinese Patent Application Publication No. CN121138824A discloses a method, system, and electronic device for intelligent real-time adjustment of the trajectory of a wellbore to be drilled. Based on the current drill bit position and actual drilling data, the method uses a directional tool build-up rate prediction model to predict the maximum dogleg angle of the drill bit toward the original design trajectory and calculates the predicted trajectory. It determines the intersection point between the predicted trajectory and the original design trajectory, and automatically generates multiple candidate trajectories of preset shapes based on the intersection point. The method uses the dogleg angle prediction model to screen the feasibility of the candidate schemes and eliminates infeasible schemes that exceed the tool's build-up capability. It constructs an evaluation function to comprehensively evaluate the feasible schemes and automatically selects the globally optimal adjustment trajectory, thereby completing the real-time, automatic, and optimized adjustment design of the wellbore trajectory.

[0004] However, the above-mentioned technical solutions rely on manual judgment or simple deviation threshold triggering mechanisms to trigger adjustment decisions. They fail to intelligently identify and classify the numerous temporary disturbances that exist during drilling. They cannot distinguish between temporary fluctuations caused by random formation disturbances and drifts originating from real trends. Consequently, the guiding actuator may make unnecessary responses to temporary disturbances that do not require intervention, thereby increasing ineffective guiding actions and actuator wear, and reducing the life of the drill string. Summary of the Invention

[0005] To address this, the present invention provides a downhole directional drilling system based on intelligent analysis to overcome the problem in the prior art where the system cannot distinguish between temporary fluctuations caused by random formation disturbances and drifts originating from true trends. This leads to the directional actuator potentially making unnecessary responses to temporary disturbances that do not require intervention, thereby increasing ineffective directional actions and actuator wear.

[0006] To achieve the above objectives, the present invention provides a downhole directional drilling system based on intelligent analysis, comprising: drill; A directional drilling tool, which is connected to the drill bit and includes a directional drilling mechanism and a measurement-while-drilling mechanism; The directional drilling mechanism responds to guidance control commands to change the drilling direction; The measurement while drilling (MWD) mechanism is used to collect the current directional parameters of the drill bit during drilling in real time and generate a real-time measurement dataset, wherein the directional parameters include drilling pressure, rotation speed, well inclination angle and azimuth angle. The drilling control system includes a trajectory deviation prediction unit, a disturbance judgment unit, a correction decision unit, and a guidance control unit. The trajectory deviation prediction unit is used to determine the current trajectory deviation feature set based on the guidance parameters of the current position of the drill bit and the designed trajectory, and to determine whether there is a trajectory deviation by simulating the trajectory extension based on the current trajectory deviation feature set. The disturbance judgment unit is used to determine the natural directional force of the formation based on the current guidance parameters of the drill bit and the natural directional characteristics of the formation when a trajectory deviation is determined. It also preliminarily determines the disturbance type based on the natural directional force of the formation and the feature set of the current trajectory deviation, and overwrites and confirms the preliminary judgment result based on the judgment results of several consecutive sampling periods to determine the final disturbance type. The disturbance type includes temporary disturbance and persistent disturbance. The correction decision unit is used to generate a corresponding correction mode based on the persistent disturbance, wherein the correction mode includes a correction tool facet angle and a correction slope. The guidance control unit is used to generate the guidance control command based on the corresponding correction mode, and to control the tilting mechanism. The guidance control includes single control of the self-aligning slider or push piston in the non-rotating sleeve of the tilting mechanism, and linkage control of the self-aligning slider and push piston in the non-rotating sleeve of the tilting mechanism.

[0007] Furthermore, the trajectory deviation prediction unit includes: The spatial deviation calculation subunit is used to extract the measured spatial coordinates, measured well inclination angle and measured azimuth angle based on the real-time measurement dataset, and to calculate the spatial position deviation vector, well inclination deviation angle and azimuth deviation angle containing the closure distance and closure azimuth based on the design value of the well depth corresponding to the design trajectory. The deviation change rate calculation subunit is used to obtain the spatial position deviation change rate, well inclination deviation change rate and azimuth deviation change rate by fitting based on the spatial position deviation vector, the well inclination deviation angle and the azimuth deviation angle of multiple consecutive measurement points. The feature set generation sub-unit is used to combine the spatial position deviation vector, the well inclination deviation angle, the azimuth deviation angle, the spatial position deviation rate of change, the well inclination deviation rate of change, and the azimuth deviation rate of change into the current trajectory deviation feature set.

[0008] Furthermore, the trajectory deviation prediction unit also includes: The simulation strategy setting subunit is used to set the tool face angle maintenance strategy and the build-up rate maintenance strategy within the simulation segment based on the current measurement point as the simulation starting point, and based on the spatial position deviation change rate, the well deviation change rate, the azimuth deviation change rate, the drilling pressure and the rotation speed. The trajectory extrapolation subunit is used to extrapolate step by step using the trajectory extrapolation model with a preset prediction extension length according to the corresponding strategy, so as to determine the predicted trajectory curve. The prediction deviation determination subunit is used to calculate the prediction position deviation vector based on the endpoint coordinates of the predicted trajectory curve and the same well depth coordinates of the designed trajectory.

[0009] Furthermore, the trajectory deviation prediction unit also includes: The trajectory deviation determination subunit is used to compare the magnitude of the predicted position deviation vector with the spatial envelope radius with the designed track as the axis to determine whether a trajectory deviation exists. Specifically, a trajectory deviation is determined to exist based on the fact that the magnitude of the predicted position deviation vector is greater than or equal to the spatial envelope radius.

[0010] Furthermore, the disturbance determination unit includes: The formation parameter acquisition subunit is used to acquire drilling formation evaluation data and determine formation lithology and anisotropy index; The actual build-up inversion subunit is used to invert the actual build-up vector of the current directional drilling tool based on the inclination change rate and azimuth change rate of the actual drilled well trajectory. The residual skew calculation subunit is used to determine the residual skew vector based on the difference between the total skew vector and the actual skew vector, wherein the total skew vector is determined based on the current set tool face angle and the designed skew rate of the skew mechanism. The natural build-up force calculation sub-unit is used to perform joint calculation based on the residual build-up vector, the lithology and anisotropy index of the formation, and the drilling pressure to obtain the magnitude and orientation of the current natural build-up force of the formation. The wave feature extraction subunit is used to calculate the wave amplitude feature and the change frequency feature based on the magnitude and orientation of the current stratum's natural orthotropic force within several sampling periods, using time-domain statistical methods and frequency-domain transformation methods respectively.

[0011] Furthermore, the disturbance determination unit also includes: The preliminary disturbance determination subunit is used to determine the disturbance type as temporary disturbance within the first confirmation period based on the fluctuation amplitude characteristics being greater than the upper limit of the allowable fluctuation amplitude, the change frequency characteristics being greater than the design value of the BHA theoretical inclination rate, and the angular deviation change rate being less than the full angle change rate of the design track; otherwise, it is determined as a persistent disturbance. The disturbance stability determination subunit is used to determine that the disturbance type is a persistent disturbance if the disturbance is initially determined to be temporary, based on the fact that the number of sampling periods corresponding to the subsequent determination of a persistent disturbance exceeds a first overwrite preset ratio. The disturbance stability determination subunit is also used to determine that the disturbance type is a temporary disturbance if the number of sampling periods corresponding to the subsequent determination of a temporary disturbance exceeds the second overwrite preset ratio, and otherwise maintain the disturbance type as a continuous disturbance if the disturbance is initially determined to be a persistent disturbance. The angular deviation rate is synthesized from the inclination deviation rate and the azimuth deviation rate through spherical geometry.

[0012] Furthermore, the correction decision unit includes: A sustaining action subunit is used to maintain the current action of the skewer mechanism in the event of a determined temporary disturbance. The correction determination subunit is used to calculate the tool face angle correction magnitude and the inclination rate correction magnitude by minimizing the regression trajectory length based on the spatial position deviation vector and the angular deviation change rate when the disturbance is determined to be continuous. Based on the comparison results of the tool face angle correction magnitude and the inclination rate correction magnitude with their respective preset thresholds, the corresponding correction mode is determined from the preset correction mode set. The preset set of correction modes includes at least: a mode that adjusts only the tool face angle, a mode that adjusts only the inclination rate, and a mode that adjusts both the tool face angle and the inclination rate.

[0013] Furthermore, the guidance control unit includes: The tool face angle adjustment subunit is used to control the axial movement of the self-aligning slider in the non-rotating sleeve based on the tool face angle correction range according to the mode of adjusting only the tool face angle, so as to deflect the connecting shaft of the drill bit to the target tool face angle; The inclination rate adjustment subunit is used to control the pushing force of the pushing piston based on the inclination rate correction range according to the inclination rate adjustment mode, so that the force value of the pushing force matches the target lateral force value corresponding to the inclination rate correction range. The state holding subunit is used to control the push piston to be in a retracted or low-pressure holding state during the rotation of the non-rotating sleeve.

[0014] Furthermore, the guidance control unit also includes: The linkage control subunit is used to control the axial movement of the self-aligning slider in the non-rotating sleeve to rotate the connecting shaft of the drill bit to the target tool face angle according to the mode of simultaneously adjusting the tool face angle and the build-up rate, and to control the pushing force of the pushing piston to reach the maximum lateral force value corresponding to the build-up rate correction range in the direction of the target tool face angle, so that the magnitude of the pushing force matches the build-up rate correction range.

[0015] Furthermore, the measurement-while-drilling mechanism includes: The data acquisition unit is used to acquire the guidance parameters in real time at a fixed sampling frequency using an accelerometer, fluxgate sensor, drill pressure sensor and caliper. A data matching unit is used to synchronously match the steering parameters with the real-time well depth by depth label to form the real-time measurement dataset with depth index.

[0016] Compared with existing technologies, the advantages of this invention are as follows: It uses a real-time measurement-while-drilling (MWD) system to collect data on drilling pressure, rotational speed, inclination angle, and azimuth angle, generating a real-time measurement dataset with a depth index; a trajectory deviation prediction unit simulates trajectory extension based on a deviation feature set to predict the existence of trajectory deviation; a disturbance judgment unit inverts the natural build-up force of the formation and integrates time-frequency domain fluctuation characteristics to distinguish between temporary and persistent disturbances; a correction decision unit calculates the optimal correction amplitude and selects the correction mode for persistent disturbances; and a guidance control unit executes single or coordinated adjustments of the centering slider and the push piston to achieve trajectory regression. This invention improves the ability to identify and suppress temporary disturbances by constructing an intelligent analysis system based on the inversion of natural build-up characteristics of the formation and dynamic overwriting of disturbance types, thereby avoiding unnecessary guidance actions and actuator wear, and extending the service life of downhole directional drilling tools.

[0017] Furthermore, the spatial deviation calculation subunit extracts the measured spatial coordinates, measured well inclination angle, and measured azimuth angle and compares them with the design values ​​to obtain the spatial position deviation vector, well inclination deviation angle, and azimuth deviation angle. The deviation change rate calculation subunit fits the deviation sequence of multiple continuous measurement points to obtain the spatial position deviation change rate, well inclination deviation change rate, and azimuth deviation change rate. The feature set generation subunit combines the deviation amount and change rate to form the current trajectory deviation feature set. The simulation strategy setting subunit sets the extrapolation strategy based on the comparison results of the synthetic angle deviation change rate and the design trajectory full angle change rate. The trajectory extrapolation subunit uses the minimum curvature method to gradually extrapolate with a preset step size to obtain the predicted trajectory curve. The prediction deviation determination subunit calculates the deviation vector between the predicted endpoint and the design coordinates. The trajectory deviation determination subunit compares the magnitude of the predicted deviation vector with the spatial envelope radius to determine in advance whether there is a trajectory deviation. The deviation judgment is moved from the current state to the future prediction, expanding the response time of the correction adjustment, thereby avoiding the problem of delayed response after the actual deviation exceeds the limit.

[0018] Furthermore, the formation parameter acquisition subunit uses drilling-while-drilling formation evaluation data to determine lithology and anisotropy indices. The actual build-up vector is inverted using the actual build-up inversion subunit based on the well deviation change rate and azimuth change rate. The residual build-up vector is separated by subdividing the total build-up vector from the actual build-up vector using the residual build-up vector calculation subunit. The magnitude and azimuth of the formation's natural build-up force are calculated by combining the residual build-up vector, lithology, anisotropy index, and drilling pressure using the natural build-up force calculation subunit. Finally, the wave characteristic extraction subunit performs time-domain analysis on the formation's natural build-up force sequence. The system uses frequency domain transformation to extract fluctuation amplitude and frequency characteristics. A preliminary disturbance determination subunit compares the fluctuation amplitude characteristics, frequency characteristics, and rate of change of the composite angular deviation with their respective thresholds to preliminarily determine the disturbance type. A disturbance stability determination subunit overwrites and confirms the preliminary determination based on the determination results of subsequent continuous sampling periods to output the final disturbance type. Through analysis of the geomechanical causes of the deviation, this invention can also accurately distinguish between temporary and persistent disturbances and make differentiated treatments for different disturbance types.

[0019] Furthermore, by maintaining the current action of the directional drilling mechanism when the disturbance is determined to be temporary to avoid ineffective adjustment, and by using the correction determination subunit to calculate the tool face angle correction magnitude and the directional drilling rate correction magnitude based on the spatial position deviation vector and the rate of change of the synthetic angle deviation when the disturbance is determined to be persistent, with the goal of minimizing the regression trajectory length, the correction magnitude is compared with a preset threshold to select the corresponding correction mode from the mode set of adjusting only the tool face angle, adjusting only the directional drilling rate, and adjusting both the tool face angle and the directional drilling rate simultaneously. The tool face angle adjustment subunit and the directional drilling rate adjustment subunit respectively perform single parameter adjustment. The linkage control subunit simultaneously controls the axial movement of the self-aligning slider and the pressurization of the push piston to achieve coordinated correction of direction and magnitude. The state holding subunit retracts the push piston or maintains low pressure during non-adjustment periods to reduce ineffective power consumption and wear. The closed-loop deviation correction decision and execution mechanism, consisting of disturbance classification, correction optimization, and multi-mode execution, completes the fine control of different deviation causes, and significantly improves the reliability and service life of the downhole directional drilling tool. Attached Figure Description

[0020] Figure 1 This is a structural diagram of the downhole directional drilling system based on intelligent analysis, as described in an embodiment of the present invention. Figure 2 This is a flowchart illustrating the usage method of the downhole directional drilling system based on intelligent analysis, as described in an embodiment of the present invention. Figure 3 This is a logic decision diagram for determining the disturbance type in an embodiment of the present invention; Figure 4 This is a logic decision diagram for generating corresponding correction modes based on persistent perturbations in an embodiment of the present invention; In the diagram: 1. Guide drill string; 2. Measurement while drilling mechanism; 3. Angling mechanism; 4. Drill bit; 5. Guidance control unit; 6. Drill string. Detailed Implementation

[0021] To make the objectives and advantages of the present invention clearer, the present invention will be further described below with reference to embodiments; it should be understood that the specific embodiments described herein are merely for explaining the present invention and are not intended to limit the present invention.

[0022] Preferred embodiments of the present invention will now be described with reference to the accompanying drawings. Those skilled in the art should understand that these embodiments are merely illustrative of the technical principles of the present invention and are not intended to limit the scope of protection of the present invention.

[0023] It should be noted that in the description of this invention, the terms "upper", "lower", "left", "right", "inner", "outer", etc., which indicate directions or positional relationships, are based on the directions or positional relationships shown in the accompanying drawings. This is only for the convenience of description and is not intended to indicate or imply that the device or element must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, it should not be construed as a limitation of this invention.

[0024] Furthermore, it should be noted that, in the description of this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," and "linking" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0025] Please see Figure 1 and Figure 2 As shown, Figure 1 This is a structural diagram of the downhole directional drilling system based on intelligent analysis, according to an embodiment of the present invention. Figure 2 This is a flowchart illustrating the usage method of a downhole directional drilling system based on intelligent analysis, according to an embodiment of the present invention. The downhole directional drilling system includes: Drill bit 4 is the actuating component for breaking rocks; The directional drilling tool 1 is connected to the drill bit 4 and includes a directional drilling mechanism 3 and a measurement while drilling mechanism 2. The directional drilling mechanism 3 responds to the directional control command to change the drilling direction, and the measurement while drilling mechanism 2 is used to collect the current directional parameters of the drill bit 4 in real time during the drilling process and generate a real-time measurement dataset. The directional parameters include drilling pressure, rotation speed, well inclination angle and azimuth angle. The drilling control system includes a trajectory deviation prediction unit, a disturbance judgment unit, a correction decision unit, and a guidance control unit 5; Among them, the trajectory deviation prediction unit is used to determine the current trajectory deviation feature set based on the guidance parameters of the current position of drill bit 4 and the design trajectory, and to determine whether there is a trajectory deviation by simulating the trajectory extension based on the current trajectory deviation feature set; The disturbance judgment unit is used to determine the natural build-up force of the formation based on the current steering parameters of drill bit 4 and the natural build-up characteristics of the formation when a trajectory deviation is determined. It also preliminarily determines the disturbance type based on the natural build-up force of the formation and the current trajectory deviation feature set, and overwrites and confirms the preliminary judgment result based on the judgment results of several consecutive sampling periods to determine the final disturbance type. The disturbance type includes temporary disturbance and persistent disturbance. The correction decision unit is used to generate corresponding correction patterns based on persistent perturbations. The correction patterns include correction tool facet angle and correction slope. The guidance control unit 5 is used to generate guidance control commands based on the corresponding correction mode and to control the skew mechanism 3. The guidance control includes single control of the self-aligning slider or push piston in the non-rotating sleeve of the skew mechanism 3, and linkage control of the self-aligning slider and push piston in the non-rotating sleeve of the skew mechanism 3.

[0026] The usage method of the downhole directional drilling system is as follows: Step S1: Determine the current trajectory deviation feature set based on the guidance parameters of the current position of drill bit 4 and the designed trajectory, and determine whether there is a trajectory deviation by simulating the trajectory extension based on the current trajectory deviation feature set; Step S2: If a trajectory deviation is found, the natural directional force of the formation is determined based on the current steering parameters of drill bit 4 and the natural directional force of the formation, and the disturbance type is initially determined based on the natural directional force of the formation and the current trajectory deviation feature set. Step S3: Based on the judgment results of several consecutive sampling periods, the preliminary judgment result is overwritten and confirmed to determine the final disturbance type; Step S4: Generate a corresponding correction mode based on the persistent perturbation, wherein the correction mode includes a correction tool face angle and a correction slope. Step S5: Generate guiding control commands based on the corresponding correction mode and use them to control the tilting mechanism 3.

[0027] This embodiment constructs an intelligent analysis system based on the inversion of formation natural directional drilling characteristics and dynamic overwriting of disturbance types, thereby improving the ability to identify and suppress temporary ineffective excitation disturbances, thereby reducing unnecessary guiding actions and actuator wear, and extending the life of downhole directional drilling tool 1.

[0028] In this embodiment, the measurement-while-drilling mechanism 2 includes: The data acquisition unit is used to acquire guidance parameters in real time at a fixed sampling frequency using an accelerometer, fluxgate sensor, drill pressure sensor and caliper. The data matching unit is used to synchronously match the steering parameters with the real-time well depth by depth label to form a real-time measurement dataset with depth index.

[0029] Specifically, the data acquisition unit includes a sensor array fixed inside the directional drill string 1, involving an accelerometer, a fluxgate sensor, a drill pressure sensor, and a caliper.

[0030] A triaxial accelerometer is orthogonally installed in the measurement-while-drilling (MWD) sub to sense the axial, radial, and tangential components of the Earth's gravitational field in the drill string coordinate system. During the measurement window when the drill string stops rotating, the accelerometer measures the axial, radial, and tangential components of gravitational acceleration in the drill string, and calculates the wellbore inclination angle, i.e., the angle between the drill string axis and the vertical line, using the trigonometric relationships of the gravitational field components.

[0031] The three-axis fluxgate sensor is also orthogonally installed in the measurement while drilling sub to measure the axial, radial, and tangential components of the geomagnetic field in the drill string coordinate system. Combined with the obtained well inclination angle and tool face angle information, the azimuth angle is calculated by the correspondence between the geomagnetic components and the geographic north direction. That is, the angle between the drill string's forward direction and magnetic north in the horizontal plane. After magnetic declination correction, the true azimuth angle is obtained.

[0032] The drill pressure sensor is installed at the drill bit 4 joint or near the drill bit 4 short section. It is usually a strain gauge force-sensitive element. When the drill string 6 applies an axial load to the drill bit 4, the sensor elastic body produces a small deformation. The strain gauge converts the deformation into a change in resistance. After being amplified and filtered by the bridge circuit and the downhole signal conditioning module, it outputs a voltage signal that is proportional to the axial load and is converted into a drill pressure value according to the calibration curve.

[0033] The speed sensor is integrated into the downhole turbine generator or set up separately. It obtains the number of rotations per unit time by detecting the periodic changes in the magnetic field or centrifugal effect caused by the rotation of the internal drive shaft of the guide drill string 1, and converts it into speed.

[0034] The caliper is installed on the outer side wall of the short section near the drill bit end of the directional drill string 1. It uses the principle of mechanical arm extension or ultrasonic ranging to measure the change in well diameter in real time after the drill bit 4 passes through the well wall, in order to help determine the well wall collapse or enlargement.

[0035] All of the above sensors use a uniform, fixed sampling frequency, such as once every 5 seconds or every 10 seconds, to synchronously trigger data acquisition, ensuring that the timestamps of all parameters are strictly aligned.

[0036] Specifically, the data matching unit synchronously matches the guidance parameters collected at a fixed sampling frequency with the real-time well depth according to the depth label to form a real-time measurement dataset with depth index that can be used for trajectory calculation and deviation analysis.

[0037] The real-time well depth acquisition process is as follows: The surface winch sensor measures the lowering or drilling length of the drill string 6 in real time, providing the real-time well depth. The downhole measurement-while-drilling (MWD) section integrates a depth estimation algorithm based on drill string 6 length counting or pressure pulse encoding transmission to receive and verify the real-time well depth. Specifically, when the drill bit 4 completes a rock-breaking advance and is in the measurement window at a certain moment, the data acquisition unit completes a set of parameter acquisitions, and the real-time well depth at that moment is recorded. The data matching unit binds the measured well inclination angle, measured azimuth angle, measured drilling pressure, measured rotational speed, and measured well diameter at that moment with the real-time well depth using a unified hardware timestamp corresponding to that sampling moment. Using a preset downhole data frame structure, the bound parameter values ​​are serialized into a fixed format to form a depth tag record.

[0038] During the drilling process, depth label records are continuously accumulated. The data matching unit arranges several depth label records in order from shallow to deep to establish a two-dimensional structured dataset.

[0039] It should be noted that the data matching unit also performs data rationality verification, marking and removing values ​​that exceed the physical range of the sensor or that show non-physical step jumps between adjacent sampling points, and interpolating and completing the dataset based on the valid data points before and after it to ensure the continuity and integrity of the dataset in depth.

[0040] Through the above process, the final real-time measurement dataset not only carries complete multi-dimensional steering parameters for each measurement point, but also precisely anchors each data point at the corresponding well depth, providing a depth-aligned data foundation for subsequent spatial coordinate calculation, deviation feature extraction, and trajectory extrapolation simulation, thereby ensuring the analysis accuracy and decision reliability of the entire downhole steerable drilling system.

[0041] In this embodiment, the trajectory deviation prediction unit includes: The spatial deviation calculation subunit is used to extract the measured spatial coordinates, measured well inclination angle and measured azimuth angle based on the real-time measurement dataset, and to calculate the spatial position deviation vector, well inclination deviation angle and azimuth deviation angle containing the closure distance and closure azimuth based on the design value of the well depth corresponding to the design trajectory. The deviation change rate calculation subunit is used to obtain the spatial position deviation change rate, well inclination deviation change rate, and azimuth deviation change rate by fitting based on the spatial position deviation vector, well inclination deviation angle, and azimuth deviation angle of multiple consecutive measurement points. The feature set generation sub-unit is used to generate the current trajectory deviation feature set based on the combination of spatial position deviation vector, well inclination deviation angle, azimuth deviation angle, spatial position deviation rate of change, well inclination deviation rate of change, and azimuth deviation rate of change. The simulation strategy setting sub-unit is used to set the tool face angle maintenance strategy and build-up rate maintenance strategy within the simulation segment based on the current measurement point as the simulation starting point, and based on the rate of change of spatial position deviation, the rate of change of well inclination deviation, the rate of change of azimuth deviation, drilling pressure and rotation speed. The trajectory extrapolation subunit is used to extrapolate step by step using the trajectory extrapolation model with a preset prediction extension length according to the corresponding strategy, so as to determine the predicted trajectory curve. The prediction deviation determination sub-unit is used to calculate the prediction position deviation vector based on the endpoint coordinates of the predicted trajectory curve and the same well depth coordinates of the designed trajectory. The trajectory deviation determination subunit is used to compare the magnitude of the predicted position deviation vector with the spatial envelope radius with the designed track as the axis to determine whether a trajectory deviation exists; wherein, if the magnitude of the predicted position deviation vector is greater than or equal to the spatial envelope radius, the existence of a trajectory deviation is determined.

[0042] Specifically, during the directional drilling process in a coal mine, the trajectory deviation prediction unit determines whether drilling will continue according to the current trend and exceed the allowable deviation envelope range based on the deviation between the actual drilling trajectory of drill bit 4 and the pre-designed trajectory.

[0043] The spatial deviation calculation subunit extracts the measured spatial coordinates of drill bit 4 at the current well depth from the real-time measurement dataset. These coordinates describe the true position of drill bit 4 in three-dimensional space through three components: north coordinate, east coordinate, and vertical depth. At the same time, the measured well inclination angle and measured azimuth angle are extracted to describe the extension direction of the wellbore trajectory at the current point.

[0044] Specifically, based on the design trajectory, spatial circular interpolation calculations are performed on adjacent key control points on the design trajectory using the minimum curvature method at the same well depth to obtain the corresponding design north coordinates, design east coordinates, design vertical depth, design well inclination angle, and design azimuth angle used to determine the theoretical position and attitude of drill bit 4. Specifically, before drilling operations commence, the wellbore trajectory profile, including the vertical section, the inclination-enhancing section, and the inclination-stabilizing section, is planned and several key control points are established using the wellhead positioning coordinates and the final borehole target point coordinates. Based on these key control points, spatial circular interpolation is performed using the minimum curvature method to generate a continuous sequence of design north coordinates, design east coordinates, design vertical depth, design well inclination angle, and design azimuth angle parameters along the well depth. After full-section anti-collision scanning, curvature verification, and construction feasibility verification, the formal design trajectory is formed.

[0045] Furthermore, the closed-loop distance of the spatial position deviation vector is determined based on the square root of the sum of the squares of the north component, east component, and vertical depth component, which is used to determine the spatial distance of drill bit 4 from the designed trajectory; the closed-loop azimuth of the spatial position deviation vector is calculated based on the arctangent function of the east and north components, which is used to determine the direction of deviation in the horizontal plane; the well inclination deviation angle is determined based on the difference between the measured well inclination angle and the designed well inclination angle. When the difference is positive, it indicates that drill bit 4 is tilted upward in the vertical plane; the azimuth deviation angle is determined based on the difference between the measured azimuth angle and the designed azimuth angle. When the difference is positive, it indicates that the actual drilling direction is deflected clockwise relative to the designed direction in the horizontal plane.

[0046] Specifically, the north component is determined based on the difference between the measured north coordinates and the designed north coordinates; the east component is determined based on the difference between the measured east coordinates and the designed east coordinates; and the vertical depth component is determined based on the difference between the measured vertical depth and the designed vertical depth.

[0047] The deviation change rate calculation sub-unit is used to determine whether the deviation is accelerating, stabilizing, or decreasing.

[0048] The deviation change rate calculation subunit takes several consecutive measurement points preceding the current measurement point, typically 5 to 10 points. Each point corresponds to a well depth and the three components of the spatial position deviation vector at that point, the well inclination deviation angle, and the azimuth deviation angle. With well depth as the independent variable, least squares linear fitting is performed on each of the five sequences: north component deviation, east component deviation, vertical depth component deviation, well inclination deviation angle, and azimuth deviation angle. The slope of the resulting fitted line is the unit change rate of each deviation with well depth.

[0049] It should be noted that, based on the operational standards of drilling engineering, the above-mentioned rates of change are scaled by multiplying them by 30 meters to obtain the rate of change of spatial position deviation, well deviation deviation, and azimuth deviation per 30 meters.

[0050] The feature set generation sub-unit combines the aforementioned spatial position deviation vector, well inclination deviation angle, azimuth deviation angle, and the corresponding rates of change of spatial position deviation, well inclination deviation, and azimuth deviation into a multi-dimensional feature vector, forming the current trajectory deviation feature set. This current trajectory deviation feature set contains information on the magnitude and trend of the deviation, providing a data foundation for subsequent trajectory extension simulation and disturbance type determination.

[0051] The simulation strategy setting subunit is used to set the drilling strategy used when extrapolating the trajectory.

[0052] Specifically, the simulation strategy sets the sub-unit to combine the wellbore deviation rate and azimuth deviation rate into an angular deviation rate through spherical geometry, which is used to determine the overall rate at which the wellbore direction deviates from the design direction.

[0053] Specifically, the product of the azimuth deviation change rate and the average well inclination angle of the current well section is calculated and the sine value is taken. The sum of the sine value and the square of the well inclination deviation change rate is then calculated, and the arithmetic square root of the sum is calculated to obtain the angular deviation change rate.

[0054] Furthermore, the simulation strategy setting sub-unit is also used to compare the rate of change of angular deviation with the rate of change of the total angle of the designed trajectory.

[0055] If the rate of change of angular deviation is greater than or equal to the rate of change of the total angle of the design trajectory, it is determined that the deviation originates from the stratum pushing or abnormal stress on the drill string assembly, and its expansion rate has exceeded the natural bending capacity of the design trajectory. In this case, a relatively conservative strategy should be adopted, keeping the tool face angle of the simulation section unchanged from the current actual tool face angle, and keeping the build-up rate unchanged from the current actual output design build-up rate of the build-up mechanism 3, so as to simulate the worst situation under the continued fault state.

[0056] Among these factors, the rate of change of angular deviation is less than the rate of change of the total angle of the designed trajectory, indicating that the rate of increase in deviation is still within a controllable range. Therefore, the current guidance strategy still has room for correction, and both the tool face angle and the build-up rate remain at their design values. Meanwhile, since drill pressure and rotational speed affect the lateral cutting efficiency of drill bit 4 and the stability of the tool face angle, excessive drill pressure may lead to increased tool face angle drift. Therefore, the above strategy is fine-tuned by combining drill pressure and rotational speed.

[0057] By setting strategies based on different scenarios, the extrapolation simulation results can more closely approximate the actual trajectory that may occur.

[0058] The trajectory extrapolation subunit is used to extrapolate step by step according to the corresponding strategy using the trajectory extrapolation model with a preset prediction extension length as the step size, so as to determine the predicted trajectory curve.

[0059] Specifically, the extrapolation process of the trajectory extrapolation model is as follows: Using a preset predicted extension length as the step size, extrapolation is performed step-by-step from the current measurement point. Based on the tool face angle and build-up rate values ​​determined by the aforementioned strategy, and the known inclination angle, azimuth angle, and spatial coordinates of the current node at each step, the dogleg angle corresponding to the current step size is calculated. This dogleg angle is determined by the product of the build-up rate and the step size. Using the geometric relationship of the minimum curvature method, the inclination angle and azimuth angle of the next node are calculated from the current inclination angle, azimuth angle, and dogleg angle. Then, the coordinate increment is calculated based on the geometric characteristics of the arc and accumulated to the current coordinates to obtain the spatial position of the next step. This iterative process is repeated until the accumulated segment length reaches the preset total predicted segment length, ultimately yielding a complete predicted trajectory curve extrapolated from the current point to the total predicted segment length. The selection of the total predicted segment length needs to comprehensively consider the measurement interval and the adjustment response distance allowed by the engineering.

[0060] Specifically, the minimum curvature method approximates the continuous curvature characteristics of the actual drilling trajectory by assuming that the well section between two adjacent measuring points is a circular arc in a spatial inclined plane.

[0061] The prediction deviation determination sub-unit is used to determine the predicted position deviation vector. Specifically, the coordinates of the endpoint of the predicted trajectory curve, i.e., the predicted north coordinate, predicted east coordinate, and predicted vertical depth, are taken and subtracted from the design north coordinate, design east coordinate, and design vertical depth at the same well depth to obtain the three components of the predicted position deviation vector. The arithmetic square root of the sum of the squares of the three components of the predicted position deviation vector is then taken to obtain the modulus of the predicted position deviation vector, which is used to determine the spatial distance between drill bit 4 and the designed trajectory when drilling continues to the predicted endpoint under the current trend.

[0062] The trajectory deviation determination sub-unit is used to compare the magnitude of the predicted position deviation vector with the spatial envelope radius with the designed track as the axis to determine whether a trajectory deviation exists.

[0063] Specifically, the spatial envelope radius is determined based on the allowable trajectory deviation tolerance of the project, and then a cylindrical safety zone with the designed track as the central axis and the radius as the spatial envelope radius is determined.

[0064] The process of determining the spatial envelope radius is as follows: using the trajectory deviation limit specified in the coal mine drilling engineering specification and the allowable offset radius of the target area as the benchmark tolerance, the benchmark tolerance is matched according to the control accuracy differences of the vertical section, the inclination-building section, the stabilization section, and the target area section along the design track; the system error of the drilling measurement mechanism 2 and the execution error of the inclination-building mechanism 3 are converted into spatial offsets respectively, and the total inherent error offset is synthesized using the square root method; a construction safety margin of 10% to 20% of the benchmark tolerance is reserved to absorb small trajectory fluctuations caused by drilling pressure fluctuations and instantaneous formation disturbances; the spatial envelope radius of the corresponding well section is obtained by deducting the total inherent error offset and the construction safety margin from the benchmark tolerance of the corresponding well section, and the envelope radius of the entire well section is connected sequentially along the design track to form a continuous cylindrical safety area.

[0065] In this embodiment, the magnitude of the predicted position deviation vector is greater than or equal to the spatial envelope radius. It is determined that when drilling to the predicted endpoint according to the current trend, the drill bit 4 will touch or even exceed the boundary of the safe area, which poses a risk of crossing the boundary. Therefore, it is determined that there is a trajectory deviation, and subsequent disturbance analysis and correction decisions need to be initiated.

[0066] The magnitude of the predicted position deviation vector is less than the spatial envelope radius. Based on the current trend, the trajectory is still within the safe envelope at least within the predicted segment length, and no intervention is needed for the time being. Therefore, it is determined that there is no trajectory deviation, and the system continues to maintain the monitoring status.

[0067] Specifically, the judgment mechanism based on future state prediction can identify potential risks of exceeding limits in advance, gain more response time for correction and adjustment, and avoid the sluggish situation of passively responding only when the actual deviation has exceeded the limit.

[0068] Please see Figure 3 As shown, this is a logic diagram for determining the type of disturbance according to an embodiment of the present invention. The disturbance determination unit includes: The formation parameter acquisition subunit is used to acquire drilling formation evaluation data and determine formation lithology and anisotropy index; The actual build-up inversion sub-unit is used to invert the actual build-up vector of the current directional drill string 1 based on the well inclination change rate and azimuth change rate of the actual drilled well trajectory. The residual skew calculation subunit is used to determine the residual skew vector based on the difference between the total skew vector and the actual skew vector, wherein the total skew vector is determined based on the current set tool face angle and the design skew rate of the skew mechanism 3. The natural build-up force calculation sub-unit is used to perform joint calculations based on the residual build-up vector, formation lithology and anisotropy index, and drilling pressure to obtain the magnitude and orientation of the current formation's natural build-up force. The wave feature extraction subunit is used to calculate the wave amplitude features and frequency change features based on the magnitude and orientation of the current stratum’s natural orthotropic force over several sampling periods, and to perform time-domain statistical methods and frequency-domain transformation methods respectively. The preliminary disturbance determination subunit is used to determine the disturbance type as temporary disturbance within the first confirmation period based on the characteristics of fluctuation amplitude being greater than the upper limit of allowable fluctuation amplitude, the characteristics of change frequency being greater than the lateral force threshold corresponding to the design value of the BHA theoretical inclination rate, and the rate of change of angular deviation being less than the rate of change of the full angle of the design track. Otherwise, the disturbance type is determined as persistent disturbance. The disturbance stability determination subunit is used to determine the overwrite disturbance type as a persistent disturbance if the number of sampling periods corresponding to the subsequent determination as a persistent disturbance exceeds a first preset overwrite ratio when the disturbance is initially determined to be temporary; it is also used to determine the overwrite disturbance type as a temporary disturbance if the number of sampling periods corresponding to the subsequent determination as a persistent disturbance exceeds a second preset overwrite ratio when the disturbance is initially determined to be persistent, otherwise maintaining the disturbance type as a persistent disturbance.

[0069] Specifically, the disturbance judgment unit is used to distinguish between temporary and persistent disturbances by inverting the natural orogenic force of the strata and analyzing its dynamic characteristics, so as to provide a reliable basis for subsequent decision-making on whether to initiate correction.

[0070] The formation parameter acquisition subunit receives formation evaluation data from the measurement-while-drilling system, including natural gamma ray logging data and resistivity logging data. Natural gamma ray values ​​are used to determine the mudstone content of the formation; high natural gamma ray typically indicates mudstone sections, while low natural gamma ray typically indicates sandstone or limestone sections. Resistivity is used to determine the pore fluid properties and lithological compactness of the formation.

[0071] Specifically, by using the established lithological interpretation model, these well logging data are compared with the lithological database calibrated by data from adjacent wells to identify the lithology of the currently drilled formation, including sandstone, mudstone, shale, or coal seam.

[0072] The lithology interpretation model employs a lightweight gradient boosting decision tree classification architecture adapted to downhole embedded computing environments. Its construction and application process involves: constructing a training dataset using measured logging data and core lithology calibration data from completed exploration boreholes in the target mining area and adjacent areas. The dataset covers four typical lithologies: sandstone, mudstone, shale, and coal seams. Each lithology category has at least 2000 labeled samples, and each sample includes four input features: natural gamma, resistivity, borehole diameter, and drilling time, along with corresponding core lithology labels. The total sample size is at least 10,000 sets, divided into training, validation, and test sets in a 7:2:1 ratio. The lithology interpretation model uses CART regression trees as the base learning method. The model employs a configuration tree with a maximum depth of 6, 120 weak learners, a learning rate of 0.08, a subsampling ratio of 0.8, and a minimum number of samples for node splitting of 5. It uses a logarithmic loss function as the classification loss and information gain ratio as the evaluation criterion for node splitting. The input is normalized four-dimensional logging features, and the output is the probability distribution of four lithology types. During model training, five-fold cross-validation is used to iteratively optimize parameters. Lithology classification accuracy and macro-average F1 score are the core validation indicators. The overall classification accuracy and single-type lithology recognition recall on the test set meet the requirements. After training, the model is lightweighted, pruned, and deployed to the embedded computing unit of the downhole measurement-while-drilling system using fixed-point quantization. In actual drilling applications, the formation parameter acquisition subunit normalizes and preprocesses the real-time collected logging data (natural gamma, resistivity, etc.) according to the input specifications before inputting it into the lithology interpretation model to obtain the current formation's lithology type and the pre-calibrated corresponding anisotropy index.

[0073] Among them, the lateral pushing effect of drill bit 4 varies significantly depending on the lithology: mudstone and shale exhibit strong anisotropy due to their well-developed bedding and plastic flow characteristics, meaning that the drillability of drill bit 4 is inconsistent in different directions, easily leading to natural skewness; while the anisotropy of homogeneous sandstone is relatively weak. Based on the calibrated anisotropy index database, the corresponding anisotropy index is determined by the lithology, and the corresponding lateral cutting coefficient correction factor is obtained for the lithology, which is used for correction in the subsequent calculation of natural skewness.

[0074] The actual directional drilling inversion sub-unit is used to infer the actual directional drilling effect produced by the directional drill string 1 from the changes in the already drilled wellbore trajectory.

[0075] Specifically, the actual directional drilling inversion subunit uses the first and second well depths, the first and second well inclination angles, and the first and second azimuth angles of two consecutive measurement points to calculate the average well inclination angle of the two points. The well inclination rate is determined based on the ratio of the difference between the second and first well inclination angles to the difference between the second and first well depths; the azimuth rate is determined based on the ratio of the difference between the second and first azimuth angles to the difference between the second and first well depths; and both rates are then converted to a rate of change per 30 meters.

[0076] The actual build-up vector is used to determine the total change in both inclination and azimuth dimensions. It is determined by calculating the product of the azimuth change rate and the average inclination angle, taking the sine of the product, and then using the square root of the sum of the squares of the inclination change rate and the square of the sine. The tool face angle of the actual build-up vector is determined by the arctangent function of the two rate components mentioned above, and is used to determine the direction of the actual build-up force.

[0077] The residual directional calculation sub-unit is used to distinguish the directional contribution of the guiding tool from that of the formation.

[0078] Specifically, the directional drill string 1 has a known design build-up rate, which is the rated build-up capacity of the drill string in a standard homogeneous formation and the tool face angle set by the operator; based on the set tool face angle and the design build-up rate, the well inclination component and azimuth component of the total build-up vector are calculated to determine the total build-up effect that the directional drill string 1 should produce according to the current settings.

[0079] The well inclination component is determined by multiplying the designed build-up rate by the cosine of the set tool face angle; the azimuth component is calculated by multiplying the designed build-up rate by the sine of the set tool face angle and then comparing the result with the sine of the average well inclination angle. Amplitude limiting is applied when the well inclination angle is close to vertical to prevent numerical overflow.

[0080] Furthermore, the inclination component of the residual build-up vector is determined based on the difference between the inclination component of the total build-up vector and the inclination component of the actual build-up vector, and the azimuth component of the residual build-up vector is determined based on the difference between the azimuth component of the total build-up vector and the azimuth component of the actual build-up vector. The residual build-up vector is used to determine the strength of the formation's lateral pushing on the drill bit 4.

[0081] The natural build-up force calculation sub-unit is used to transform the residual build-up vector into a formation natural build-up force with definite physical dimensions. Specifically, based on the residual build-up vector, the formation lithology and anisotropy index, and drilling pressure are jointly calculated to obtain the magnitude and orientation of the current formation natural build-up force.

[0082] Specifically, the process of obtaining the magnitude and orientation of the current formation's natural build-up force is as follows: The residual build-up vector output by the residual build-up calculation subunit is obtained; the build-up rate is determined by the magnitude of the residual build-up vector, and the direction of the residual build-up vector is taken as the direction of the residual build-up force. Simultaneously, the lithology of the current drilling formation and its corresponding anisotropy index are obtained from the formation parameter acquisition subunit, and the current drill pressure is acquired by the measurement-while-drilling (MWD) unit 2. Based on the drill bit mechanics model, the lateral force on the drill bit 4 is determined to be approximately proportional to the generated build-up rate, i.e., determined based on the product of the build-up rate and the comprehensive lateral force coefficient. The lateral force on drill bit 4 is determined by solving a correlation model established in advance through indoor experiments and field calibration to determine the comprehensive lateral force coefficient. The formation natural build-up force is determined by multiplying the comprehensive lateral force coefficient with the residual build-up rate. This is used to determine the magnitude of the lateral thrust force generated by the formation natural build-up characteristics under the current drill pressure and formation conditions, which actually acts on drill bit 4 and is not compensated by the guide tool. The direction of the residual build-up force directly determines the orientation of the formation natural build-up force. This orientation is expressed in the form of tool face angle, indicating the direction of the formation natural thrust force in the plane perpendicular to the axis of drill bit 4.

[0083] In this embodiment, the quantitative correlation model between the comprehensive lateral force coefficient, drill pressure, and anisotropy index is based on the product of drill pressure and formation build-up coefficient. The comprehensive lateral force coefficient is determined by the ratio of this product to a correction term including the anisotropy index. The process of establishing the correlation model is as follows: standard rock samples or standard formations with similar or identical geological conditions to the section to be drilled, including various typical lithologies and different anisotropy index ranges, are selected as experimental objects. For each standard sample with each lithology and anisotropy index combination, the drill pressure applied to the drill bit 4 is changed sequentially. For each set of drill pressure values, a series of lateral forces of known magnitude are applied to the drill bit 4 through a lateral force loading device to simulate the lateral action of the guide tool 1 or formation pushing on the drill bit 4. Drilling is carried out under the action of this lateral force, and the well inclination change rate and azimuth change rate generated after drilling a certain footage are measured. The actual build-up rate generated under the lateral force was calculated, and a series of corresponding data pairs of lateral force and build-up rate were obtained under the conditions of determined lithology, anisotropy index, and drilling pressure. Linear regression analysis was performed on the lateral force-build-up rate data pairs under the same drilling pressure condition to verify that the lateral force and build-up rate approximately satisfy a proportional relationship. The slopes obtained under different drilling pressures, different lithologies, and different anisotropy indices were summarized, i.e., the comprehensive lateral force coefficient, and a coefficient database was established. The variation law of the comprehensive lateral force coefficient with drilling pressure was analyzed. Based on the qualitative law, a quantitative correlation model between the comprehensive lateral force coefficient and drilling pressure and anisotropy index was constructed.

[0084] Among them, the formation tilt coefficient is determined by inverting actual drilling data of the target block.

[0085] The process involves calculating the product of the anisotropy index and the correction factor, and then summing the result with the baseline value to determine the correction term that includes the anisotropy index. Specifically, the correction factor is calibrated through indoor bench experiments. Standard rock samples with various anisotropy indices are selected, and a series of known lateral forces are applied under the same drilling pressure conditions, with corresponding build-up rates measured. Data pairs between the anisotropy index and build-up rate are established, substituted into the correlation model, and nonlinear fitting is performed using the least squares method to back-calculate the correction factor that minimizes the model error. Specifically, when the formation anisotropy index is 0, there is no shift in build-up efficiency due to anisotropy, and the correction term should not amplify or attenuate the basic relationship; therefore, the correction term value is equal to the baseline value and is set to 1.

[0086] Through the above joint calculation process, the natural build-up force calculation subunit inverts and isolates the formation natural build-up force, which cannot be directly measured, from the actual drilling wellbore trajectory changes, directional tool setting parameters, and formation characteristic parameters. This achieves a quantitative characterization of the intensity and direction of formation disturbance, providing a quantitative input with clear physical meaning for subsequent disturbance type determination.

[0087] The fluctuation feature extraction sub-unit extracts the criteria for distinguishing between temporary and persistent disturbances by performing dynamic feature analysis on the natural orogenic force sequence of strata.

[0088] Specifically, the fluctuation feature extraction sub-unit takes the most recent continuous sampling period, with each sampling period corresponding to the magnitude of a natural formation orogenic force. In the time domain, the standard deviation and range of the sequence are calculated as fluctuation amplitude features. The standard deviation reflects the dispersion of the natural formation orogenic force around its mean, while the range reflects the maximum fluctuation range of the force within the sampling window. In the frequency domain, a Fast Fourier Transform is performed on the sequence to convert the time-domain signal into a frequency-domain spectrum. The amplitude corresponding to the frequency component with the largest amplitude in the frequency-domain spectrum is extracted as the frequency variation feature, and the corresponding dominant frequency can be determined.

[0089] The preliminary disturbance determination subunit is used to make an initial determination of the disturbance type during the first confirmation period.

[0090] Specifically, the preliminary disturbance determination subunit presets three determination conditions.

[0091] In this embodiment, when the three conditions are met simultaneously—the fluctuation amplitude characteristic being greater than the upper limit of the allowable fluctuation amplitude, the change frequency characteristic being greater than the lateral force threshold, and the change rate of angular deviation being less than the change rate of the full angle of the designed track—it is determined that although the current natural descent force of the strata fluctuates violently and frequently, this fluctuation has not been transformed into a continuous expansion trend of the trajectory deviation. The disturbance is self-limiting and temporary, and therefore is initially determined to be a temporary disturbance.

[0092] If any one of the following conditions is not met, it is determined that the fluctuation amplitude is not large but there is a stable bias, or the fluctuation frequency is low and has formed a trend, or the rate of change of angular deviation has exceeded the design capacity, and the disturbance may not disappear on its own. Therefore, it is initially determined to be a persistent disturbance.

[0093] Specifically, the upper limit of the allowable fluctuation amplitude is set as an empirical threshold based on the mechanical characteristics of the drill string assembly where the downhole directional drill string 1 is located and historical operation data; the theoretical build-up rate design value of BHA is obtained through calibration experiments to determine the upper limit of the drill string's own guiding capability; the full angle change rate of the design trajectory is obtained by combining the well deviation change rate and the azimuth deviation change rate through spherical geometry.

[0094] The process of determining the upper limit of allowable fluctuation amplitude is as follows: Historical measurement-while-drilling data from completed wells in the target block or similar geological conditions are collected, including data from well sections explicitly marked as normal drilling, encountering temporary disturbances while passing through nodules, and encountering continuous build-up trends when entering inclined bedding. Using the natural build-up force calculation method, the historical well section data is back-calculated to obtain the formation natural build-up force sequence under different operating conditions. For well sections with normal drilling and good trajectory control, and well sections confirmed to have experienced temporary disturbances, the standard deviation and range of the formation natural build-up force sequence are calculated, along with other fluctuation amplitude statistics. Through comparative analysis of a large number of statistical samples, the upper limit of allowable fluctuation amplitude that can effectively separate these two types of operating conditions is determined. Specifically, the principle is that the upper limit of allowable fluctuation amplitude should be greater than the fluctuation amplitude of more than 95% of normally drilled well sections. The upper limit of allowable fluctuation amplitude can be customized and updated according to the block and formation, continuously optimizing its distinguishing ability.

[0095] The process of determining the lateral force threshold corresponding to the theoretical build-up rate design value of BHA is as follows: Based on factors such as drill string geometry, stabilizer size and location, and drill bit type, the theoretical build-up rate design value of BHA is obtained through mechanical analysis or standard formation testing; the theoretical build-up rate design value is substituted into the mapping relationship between build-up rate and lateral force to calculate the lateral force threshold corresponding to the theoretical build-up rate design value of BHA required for the drill string assembly to achieve its rated build-up capacity under standard conditions.

[0096] The mapping relationship between build-up rate and lateral force is a linear proportional quantitative relationship established based on drill bit-formation interaction mechanics and BHA bending mechanics. Under the benchmark conditions of standard homogeneous formation and rated drill pressure, the build-up rate is the product of the lateral force at four points on the drill bit and the standard build-up ratio coefficient. Specifically, standard formation samples with the same physical properties as the target block are selected, and the rated drill pressure and rotation speed are kept constant. Lateral forces with known gradients are applied step by step, and the corresponding build-up rates are measured. The lateral force-build-up rate data are linearly fitted using the least squares method to obtain the build-up ratio coefficient under standard conditions.

[0097] The process of determining the total angle variation rate of the design trajectory is as follows: for any well depth segment on the design trajectory, the total angle variation rate is obtained by combining the well inclination deviation variation rate and azimuth deviation variation rate at both ends of the segment using spherical geometry.

[0098] By combining three conditions for judgment, the intensity, frequency and trajectory effect of the disturbance are taken into account, thereby reducing the probability of misjudgment caused by relying on a single indicator.

[0099] The disturbance stability determination subunit is used to address the issue that the determination of a single sampling window may be affected by measurement noise or transient anomalies, resulting in a transitional state between temporary and continuous disturbances, thus ensuring the robustness of the final determination result.

[0100] Specifically, after the initial determination is made, the disturbance stability determination subunit continues to track the determination results for several consecutive sampling periods.

[0101] In this embodiment, if the disturbance is initially determined to be temporary, and the number of sampling periods corresponding to the subsequent determination of the disturbance as a persistent disturbance exceeds the first overwrite preset ratio, it is determined that the initially observed temporary disturbance is not an isolated event, but a precursor or intermittent manifestation in the process of the formation of a persistent disturbance trend. Therefore, the disturbance type is overwritten as a persistent disturbance.

[0102] If the number of sampling periods corresponding to a persistent disturbance does not exceed the first overwrite preset ratio, the determination result of a temporary disturbance is maintained.

[0103] In this embodiment, if the disturbance is initially determined to be a persistent disturbance, and the sampling period corresponding to the subsequent determination of a temporary disturbance exceeds the second overwrite preset ratio, it is determined that what the initial window captures may only be a temporary anomaly with a slightly longer duration, rather than a true trend drift. Therefore, the disturbance type is overwritten as a temporary disturbance.

[0104] Based on the fact that the sampling period corresponding to the subsequent determination of temporary disturbance did not exceed the second overwrite preset ratio, and the characteristic of determination of persistence was indeed continued, the determination result of persistent disturbance was maintained.

[0105] The process for determining the first preset overwrite ratio is as follows: Collect historical drilling data of completed wells in the target block or under similar geological conditions, and screen out well sections with temporary and persistent disturbances as analysis samples; perform back-calculation simulation on the analysis samples, keeping the sampling period length and the number of tracking and judgment periods consistent with the actual working conditions in the simulation, and set different candidate ratio values, and respectively calculate the recognition recall rate for persistent disturbance samples and the false overwrite rate for temporary disturbance samples under each candidate ratio; establish a dual-index change curve with the candidate ratio as the abscissa and the recognition recall rate and false overwrite rate as the ordinate, both of which decrease as the candidate ratio increases; adopt the dual-index trade-off method, and under the constraint that the recognition recall rate is not lower than the preset engineering requirement lower limit, select the candidate ratio value that minimizes the false overwrite rate as the first preset overwrite ratio.

[0106] The process for determining the second preset overwrite ratio is as follows: Historical drilling data from completed wells in the target block or under similar geological conditions are collected, and persistently disturbed well sections and temporarily disturbed well sections are selected as analysis samples. Back-calculation simulations are performed on the analysis samples, maintaining the sampling period length and the number of tracking and judgment periods consistent with actual working conditions. Different candidate ratio values ​​are set, and the recognition recall rate for temporarily disturbed samples and the false overwrite rate for persistently disturbed samples are statistically analyzed for each candidate ratio. A dual-index curve is established with the candidate ratio as the abscissa and the recognition recall rate and false overwrite rate as the ordinates; both decrease as the candidate ratio increases. Using a dual-index trade-off method, under the constraint that the false overwrite rate of persistently disturbed samples does not exceed the preset engineering safety limit, the candidate ratio value that maximizes the recognition recall rate of temporary disturbances is selected as the second preset overwrite ratio.

[0107] Through this two-stage determination mechanism based on time series consistency, the disturbance determination unit effectively suppresses misjudgment of disturbance type caused by local stratigraphic abrupt changes or measurement noise, providing a stable and reliable classification basis for corrective decisions.

[0108] Please see Figure 4 As shown, it is a logic decision diagram for generating corresponding correction modes based on persistent perturbations in an embodiment of the present invention. The correction decision unit includes: The action subunit is used to maintain the current action of the skewing mechanism 3 in the event of a determined temporary disturbance. The correction determination sub-unit is used to calculate the tool face angle correction magnitude and the inclination rate correction magnitude by minimizing the regression trajectory length based on the spatial position deviation vector and the rate of change of angular deviation when the disturbance is determined to be continuous. Based on the comparison results of the tool face angle correction magnitude and the inclination rate correction magnitude with their respective preset thresholds, the corresponding correction mode is determined from the preset correction mode set. The preset set of correction modes includes at least: a mode that adjusts only the tool face angle, a mode that adjusts only the inclination rate, and a mode that adjusts both the tool face angle and the inclination rate.

[0109] The correction decision unit is used to determine the correction mode corresponding to the type of disturbance.

[0110] In this embodiment, when the disturbance judgment unit finally determines that the disturbance type is a temporary disturbance, since the temporary disturbance originates from a local anomaly in the formation, after the drill bit 4 passes through the abnormal section, the natural build-up force of the formation will naturally dissipate, and the wellbore trajectory will gradually return to the vicinity of the designed trajectory under the existing guidance settings. Therefore, the maintenance action subunit outputs an instruction to keep the current tool face angle and build-up rate settings unchanged, thereby suppressing invalid guidance actions and extending the life of the drill string.

[0111] When the disturbance judgment unit finally determines that the disturbance type is a persistent disturbance, it indicates that the natural formation tilting force has formed a stable and continuous bias, and the trajectory deviation will accumulate and expand in a trending manner, so active correction must be carried out.

[0112] The correction determines the sub-unit based on the current spatial position deviation vector including the closure distance and closure azimuth, as well as the rate of change of angular deviation, by constructing a tool to minimize the regression trajectory length calculation of the face angle correction magnitude and the slope correction magnitude.

[0113] Specifically, the process of determining the minimum regression trajectory length is as follows: For each set of candidate tool face angle correction amplitude and build-up rate correction amplitude, starting from the current drill bit position 4, the minimum curvature method known in the art is used to extrapolate step by step according to a preset step size to calculate the total arc length required for the current point to regress to the design trajectory as the regression trajectory length; in the two-dimensional parameter space composed of the tool face angle correction amplitude and build-up rate correction amplitude, with the physical limit of the actuator as the boundary and the maximum allowable dogleg degree as the constraint, a discrete grid traversal search is performed according to a preset step size, and the candidate set that minimizes the regression length is taken as the minimum regression trajectory length.

[0114] Furthermore, after determining the tool face angle correction range and the slope correction range, the correction determination subunit is also used to compare them with preset correction thresholds to determine the correction mode.

[0115] The tool face angle correction range threshold and the inclination rate correction range threshold are used to determine the minimum adjustment resolution that the guide mechanism can accurately perform and the limits that are considered necessary to adjust separately in engineering.

[0116] In this embodiment, when the tool face angle correction range is greater than or equal to the tool face angle correction range threshold and the sloping rate correction range is less than the sloping rate correction range threshold, it is determined that the trajectory deviation is mainly caused by the skewness of the guiding force direction. Therefore, the correction mode is determined to be the mode that only adjusts the tool face angle.

[0117] When the tool face angle correction range is less than the tool face angle correction range threshold and the inclination rate correction range is greater than or equal to the inclination rate correction range threshold, it is determined that the current guiding force direction is roughly correct, but the guiding force is insufficient to overcome the continuous disturbance. The trajectory drifts slowly due to insufficient inclination. Therefore, the correction mode is determined to be the mode that only adjusts the inclination rate.

[0118] When the tool face angle correction range is greater than or equal to the tool face angle correction range threshold and the inclination rate correction range is greater than or equal to the inclination rate correction range threshold, it is determined that there are significant deviations in the direction and magnitude of the guiding force. Coordinated adjustment is required for efficient regression. Therefore, the correction mode is determined to be the mode of simultaneously adjusting the tool face angle and the inclination rate.

[0119] When the tool face angle correction range is less than the tool face angle correction range threshold and the inclination rate correction range is less than the inclination rate correction range threshold, the required correction amount is extremely small and may still be within the measurement error or control dead zone. In order to maintain system stability, the correction mode is still the tool face angle fine-tuning mode or no adjustment is made for the time being.

[0120] Specifically, the correction decision-making unit uses the aforementioned sub-mode decision-making mechanism to achieve refined adjustment of the causes of different deviations.

[0121] In this embodiment, the guide control unit 5 includes: The tool face angle adjustment subunit is used to control the axial movement of the self-aligning slider in the non-rotating sleeve based on the tool face angle correction range according to the mode of adjusting only the tool face angle, so as to deflect the connecting shaft of the drill bit 4 to the target tool face angle; The inclination rate adjustment subunit is used to control the pushing force of the pushing piston based on the inclination rate correction range according to the mode of adjusting only the inclination rate, so that the force value of the pushing force matches the target lateral force value corresponding to the inclination rate correction range. The state holding subunit is used to control the push piston to be in a retracted or low-pressure holding state during the rotation of the non-rotating sleeve. The linkage control subunit is used to control the axial movement of the self-aligning slider in the non-rotating sleeve to rotate the connecting shaft of the drill bit 4 to the target tool face angle according to the mode of simultaneously adjusting the tool face angle and the build-up rate, and to control the pushing force of the pushing piston to reach the maximum lateral force value corresponding to the build-up rate correction range in the direction of the target tool face angle, so that the magnitude of the pushing force matches the build-up rate correction range.

[0122] In this embodiment, the tool face angle adjustment subunit receives the tool face angle correction range from the correction determination subunit according to the mode of adjusting only the tool face angle. Through the calibration curve of the self-aligning slider displacement and the change in tool face angle preset in the system, the tool face angle correction range is converted into the axial displacement required by the self-aligning slider in the non-rotating sleeve. The control signal is output to drive the self-aligning slider to move axially. The self-aligning slider pushes the connecting shaft of the drill bit 4 to deflect until the tool face angle of the drill bit 4 reaches the target tool face angle.

[0123] The build-up rate adjustment subunit receives the build-up rate correction range according to the mode of adjusting only the build-up rate. Based on the mapping relationship between lateral force and build-up rate established in advance through mechanical modeling and experimental calibration, it calculates the push force required to achieve the target build-up rate, outputs a control signal to adjust the hydraulic pressure of the push piston, thereby changing the lateral cutting amount of drill bit 4 and realizing precise adjustment of the build-up rate.

[0124] The state holding subunit corresponds to the command of the holding action subunit. During temporary disturbances or when guidance adjustment is not required, it controls the push piston to switch to a low-pressure holding state, so that the piston does not contact the wellbore or only contacts it with extremely low pressure, in order to minimize the ineffective power consumption and mechanical wear of the downhole tool.

[0125] The linkage control subunit outputs commands to the tool face angle adjustment subunit and the build-up rate adjustment subunit simultaneously, based on the mode of simultaneously adjusting the tool face angle and the build-up rate. This coordinates the two actions of axial movement of the self-aligning slider and pressurization of the push piston. As the connecting shaft of the drill bit 4 deflects to the target tool face angle, the push piston outputs the maximum lateral force in the target direction that matches the build-up rate correction magnitude. This achieves synchronous correction of the build-up direction and build-up size, ensuring the efficiency and smoothness of the return trajectory.

[0126] In this embodiment, the process of determining the tool face angle correction amplitude threshold is as follows: by measuring the full stroke control error of the self-aligning slider from receiving the command to completing the axial displacement and stabilizing at the target position, the tool face angle control accuracy of the actuator is obtained through bench testing. The tool face angle control accuracy is used as the baseline. The tool face angle correction amplitude threshold must be set to be greater than or equal to the tool face angle control accuracy; otherwise, the control system cannot be effectively executed. In actual engineering, the tool face angle correction amplitude threshold is usually set to 2 to 3 times the tool face angle control accuracy to ensure that the correction action can be effectively executed and produce an observable trajectory response.

[0127] In this embodiment, the process of determining the inclination rate correction magnitude threshold is as follows: the minimum adjustable lateral force increment that can be stably output by the hydraulic valve group and the push piston system is used to convert the minimum adjustable lateral force increment into the corresponding minimum executable inclination rate increment using the above-mentioned mapping relationship between lateral force and inclination rate, so as to serve as the physical lower limit of the inclination rate correction magnitude threshold.

[0128] The technical solution of the present invention has been described above with reference to the preferred embodiments shown in the accompanying drawings. However, it will be readily understood by those skilled in the art that the scope of protection of the present invention is obviously not limited to these specific embodiments. Without departing from the principles of the present invention, those skilled in the art can make equivalent changes or substitutions to the relevant technical features, and the technical solutions after these changes or substitutions will all fall within the scope of protection of the present invention.

Claims

1. A downhole directional drilling system based on intelligent analysis, characterized in that, include: drill; A directional drilling tool, which is connected to the drill bit and includes a directional drilling mechanism and a measurement-while-drilling mechanism; The directional drilling mechanism responds to guidance control commands to change the drilling direction; The measurement while drilling (MWD) mechanism is used to collect the current directional parameters of the drill bit during drilling in real time and generate a real-time measurement dataset, wherein the directional parameters include drilling pressure, rotation speed, well inclination angle and azimuth angle. The drilling control system includes a trajectory deviation prediction unit, a disturbance judgment unit, a correction decision unit, and a guidance control unit. The trajectory deviation prediction unit is used to determine the current trajectory deviation feature set based on the guidance parameters of the current position of the drill bit and the designed trajectory, and to determine whether there is a trajectory deviation by simulating the trajectory extension based on the current trajectory deviation feature set. The disturbance judgment unit is used to determine the natural directional force of the formation based on the current guidance parameters of the drill bit and the natural directional characteristics of the formation when a trajectory deviation is determined. It also preliminarily determines the disturbance type based on the natural directional force of the formation and the feature set of the current trajectory deviation, and overwrites and confirms the preliminary judgment result based on the judgment results of several consecutive sampling periods to determine the final disturbance type. The disturbance type includes temporary disturbance and persistent disturbance. The correction decision unit is used to generate a corresponding correction mode based on the persistent disturbance, wherein the correction mode includes a correction tool facet angle and a correction slope. The guidance control unit is used to generate the guidance control command based on the corresponding correction mode, and to control the tilting mechanism. The guidance control includes single control of the self-aligning slider or push piston in the non-rotating sleeve of the tilting mechanism, and linkage control of the self-aligning slider and push piston in the non-rotating sleeve of the tilting mechanism.

2. The downhole directional drilling system based on intelligent analysis according to claim 1, characterized in that, The trajectory deviation prediction unit includes: The spatial deviation calculation subunit is used to extract the measured spatial coordinates, measured well inclination angle and measured azimuth angle based on the real-time measurement dataset, and to calculate the spatial position deviation vector, well inclination deviation angle and azimuth deviation angle containing the closure distance and closure azimuth based on the design value of the well depth corresponding to the design trajectory. The deviation change rate calculation subunit is used to obtain the spatial position deviation change rate, well inclination deviation change rate and azimuth deviation change rate by fitting based on the spatial position deviation vector, the well inclination deviation angle and the azimuth deviation angle of multiple consecutive measurement points. The feature set generation sub-unit is used to combine the spatial position deviation vector, the well inclination deviation angle, the azimuth deviation angle, the spatial position deviation rate of change, the well inclination deviation rate of change, and the azimuth deviation rate of change into the current trajectory deviation feature set.

3. The downhole directional drilling system based on intelligent analysis according to claim 2, characterized in that, The trajectory deviation prediction unit further includes: The simulation strategy setting subunit is used to set the tool face angle maintenance strategy and the build-up rate maintenance strategy within the simulation segment based on the current measurement point as the simulation starting point, and based on the spatial position deviation change rate, the well deviation change rate, the azimuth deviation change rate, the drilling pressure and the rotation speed. The trajectory extrapolation subunit is used to extrapolate step by step using the trajectory extrapolation model with a preset prediction extension length according to the corresponding strategy, so as to determine the predicted trajectory curve. The prediction deviation determination subunit is used to calculate the prediction position deviation vector based on the endpoint coordinates of the predicted trajectory curve and the same well depth coordinates of the designed trajectory.

4. The downhole directional drilling system based on intelligent analysis according to claim 3, characterized in that, The trajectory deviation prediction unit further includes: The trajectory deviation determination subunit is used to compare the magnitude of the predicted position deviation vector with the spatial envelope radius with the designed track as the axis to determine whether a trajectory deviation exists. Specifically, a trajectory deviation is determined to exist based on the fact that the magnitude of the predicted position deviation vector is greater than or equal to the spatial envelope radius.

5. The downhole directional drilling system based on intelligent analysis according to claim 4, characterized in that, The disturbance determination unit includes: The formation parameter acquisition subunit is used to acquire drilling formation evaluation data and determine formation lithology and anisotropy index; The actual build-up inversion subunit is used to invert the actual build-up vector of the current directional drilling tool based on the inclination change rate and azimuth change rate of the actual drilled well trajectory. The residual skew calculation subunit is used to determine the residual skew vector based on the difference between the total skew vector and the actual skew vector, wherein the total skew vector is determined based on the current set tool face angle and the designed skew rate of the skew mechanism. The natural build-up force calculation sub-unit is used to perform joint calculation based on the residual build-up vector, the lithology and anisotropy index of the formation, and the drilling pressure to obtain the magnitude and orientation of the current natural build-up force of the formation. The wave feature extraction subunit is used to calculate the wave amplitude feature and the change frequency feature based on the magnitude and orientation of the current stratum's natural orthotropic force within several sampling periods, using time-domain statistical methods and frequency-domain transformation methods respectively.

6. The downhole directional drilling system based on intelligent analysis according to claim 5, characterized in that, The disturbance determination unit further includes: The preliminary disturbance determination subunit is used to determine the disturbance type as temporary disturbance within the first confirmation period based on the fluctuation amplitude characteristics being greater than the upper limit of the allowable fluctuation amplitude, the change frequency characteristics being greater than the design value of the BHA theoretical inclination rate, and the angular deviation change rate being less than the full angle change rate of the design track; otherwise, it is determined as a persistent disturbance. The disturbance stability determination subunit is used to determine that the disturbance type is a persistent disturbance if the disturbance is initially determined to be temporary, based on the fact that the number of sampling periods corresponding to the subsequent determination of a persistent disturbance exceeds a first overwrite preset ratio. The disturbance stability determination subunit is also used to determine that the disturbance type is a temporary disturbance if the disturbance is initially determined to be a persistent disturbance, based on the fact that the sampling period corresponding to the subsequent determination of a temporary disturbance exceeds the second overwrite preset ratio; otherwise, the disturbance type is maintained as a persistent disturbance. The angular deviation rate is synthesized from the inclination deviation rate and the azimuth deviation rate through spherical geometry.

7. The downhole directional drilling system based on intelligent analysis according to claim 6, characterized in that, The correction decision unit includes: A sustaining action subunit is used to maintain the current action of the skewer mechanism in the event of a determined temporary disturbance. The correction determination subunit is used to calculate the tool face angle correction magnitude and the inclination rate correction magnitude by minimizing the regression trajectory length based on the spatial position deviation vector and the angular deviation change rate when the disturbance is determined to be continuous. Based on the comparison results of the tool face angle correction magnitude and the inclination rate correction magnitude with their respective preset thresholds, the corresponding correction mode is determined from the preset correction mode set. The preset set of correction modes includes at least: a mode that adjusts only the tool face angle, a mode that adjusts only the inclination rate, and a mode that adjusts both the tool face angle and the inclination rate.

8. The downhole directional drilling system based on intelligent analysis according to claim 7, characterized in that, The guidance control unit includes: The tool face angle adjustment subunit is used to control the axial movement of the self-aligning slider in the non-rotating sleeve based on the tool face angle correction range according to the mode of adjusting only the tool face angle, so as to deflect the connecting shaft of the drill bit to the target tool face angle; The inclination rate adjustment subunit is used to control the pushing force of the pushing piston based on the inclination rate correction range according to the inclination rate adjustment mode, so that the force value of the pushing force matches the target lateral force value corresponding to the inclination rate correction range. The state holding subunit is used to control the push piston to be in a retracted or low-pressure holding state during the rotation of the non-rotating sleeve.

9. The downhole directional drilling system based on intelligent analysis according to claim 7, characterized in that, The guidance control unit also includes: The linkage control subunit is used to control the axial movement of the self-aligning slider in the non-rotating sleeve to rotate the connecting shaft of the drill bit to the target tool face angle according to the mode of simultaneously adjusting the tool face angle and the build-up rate, and to control the pushing force of the pushing piston to reach the maximum lateral force value corresponding to the build-up rate correction range in the direction of the target tool face angle, so that the magnitude of the pushing force matches the build-up rate correction range.

10. The downhole directional drilling system based on intelligent analysis according to claim 1, characterized in that, The measurement-while-drilling mechanism includes: The data acquisition unit is used to acquire the guidance parameters in real time at a fixed sampling frequency using an accelerometer, fluxgate sensor, drill pressure sensor and caliper. A data matching unit is used to synchronously match the steering parameters with the real-time well depth by depth label to form the real-time measurement dataset with depth index.

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