A drill string vibration experiment device and method for simulating a complex constraint environment

Abstract

This invention discloses a drill string vibration experimental apparatus and method for simulating complex constraint environments, including a simulated tubing assembly system, a loading system, a vibration system, and a measurement system. The simulated tubing assembly system includes a simulated drill string, a simulated wellbore, a plastic ring, and multiple sets of servo-controlled expansion joints. The measurement system includes a computing and processing device, tensile and compressive sensors, and displacement sensors. The computing and processing device is electrically connected to the servo-controlled expansion joints. The displacement sensors are multiple sets of laser displacement sensors mounted on the simulated wellbore, corresponding to multiple measuring points on the simulated drill string. The laser displacement sensors are electrically connected to the computing and processing device, which can send the collected radial displacement data at each measuring point of the simulated drill string to the computing and processing device to calculate the vibration displacement amplitude at each measuring point. Using this invention, nonlinear geometric and mechanical boundary conditions such as irregular wellbores and drill string buckling can be reproduced, improving the realism and reliability of the experimental results.

Description

Technical Field

[0001] This invention belongs to the field of experimental technology for oil and gas drilling engineering, and specifically relates to a drill string vibration experimental device and method for simulating complex constraint environments. Background Technology

[0002] In current deep, ultra-deep, and extra-deep well drilling projects, the mechanical behavior of the drill string system exhibits highly nonlinear and non-stationary characteristics. With the development of directional and horizontal drilling technologies, wellbore trajectories often include complex build-up sections, torsion sections, and micro-dogleg regions caused by formation heterogeneity. In this engineering context, the drill string inevitably collides and rubs against the wellbore during high-speed rotation, generating complex drill string vibrations. This is a core factor leading to downhole tool fatigue failure, MWD / LWD damage, and premature drill bit wear. To effectively invert and predict the dynamic response of downhole drilling tools on the surface, numerous physical simulation experiments have been conducted both domestically and internationally. At the level of specific experimental technology, traditional test benches typically consist of a power drive module, a simulated drill string with an adjustable length-to-diameter ratio, and a multi-sensor network, focusing primarily on measuring the local vibration intensity of the drill string in straight or regularly curved wellbores with a fixed single curvature. Traditional methods often utilize accelerometers to acquire signals at specific nodes and extract frequency and amplitude characteristics using techniques such as Fast Fourier Transform to assess the critical conditions for drill string instability.

[0003] However, a deeper analysis of the current technological status reveals that existing experimental systems and evaluation methods still have significant shortcomings in terms of the realism of physical boundaries and multi-source coupling. Specifically: (1) At the level of physical constraint simulation, existing devices mostly use rigid, straight simulated wellbores with uniform inner diameters, which cannot simulate the dynamic changes in the curvature of the wellbore trajectory through physical means. This idealized rigid boundary completely ignores the significant shielding and interference effects of the real non-uniform variable curvature trajectory on the propagation of drill string vibration, resulting in the inability to accurately reproduce the severe energy attenuation, reflection, and phase distortion that occur during the upward propagation of the vibration signal. (2) Existing experimental measurements are too biased towards the vibration intensity of a local measurement point, lacking a systematic and quantitative study of the propagation characteristics of vibration energy under non-uniform constraint paths. Summary of the Invention

[0004] The purpose of this invention is to provide a drill string vibration test device and method for simulating complex constraint environments, so as to reproduce nonlinear geometric and mechanical boundary conditions such as irregular wellbore, drill string buckling and bottom hole lateral constraints, thereby improving the authenticity and reliability of the experimental results.

[0005] In a first aspect, the present invention provides a drill string vibration experimental device for simulating a complex constraint environment, comprising a simulated drill string assembly system, a loading system, a vibration system, and a measurement system. The simulated drill string assembly system includes a simulated drill string and a simulated wellbore fitted around the outside of the simulated drill string. The output end of the loading system is fixedly connected to the head end of the simulated drill string, and the output end of the vibration system is in contact with the tail end of the simulated drill string. The measurement system includes a computing processing device and a tension / compression sensor and a displacement sensor electrically connected to the computing processing device. The tension / compression sensor is installed at the tail end of the simulated drill string, acquires the axial load of the simulated drill string, and sends it to the computing processing device. The computing processing device is electrically connected to the loading system and the vibration system, and controls the operation of the loading system and the vibration system.

[0006] The simulated drill string assembly system also includes a plastic ring and multiple sets of servo-controlled expansion joints spaced apart on the outer periphery of the simulated wellbore. The simulated wellbore is a flexible, transparent wellbore with a vertical wellbore section, a directional wellbore section, and a horizontal wellbore section that are connected in sequence and can be deflected relative to each other. The plastic ring is fitted around the near end of the simulated drill string and is located inside the horizontal wellbore section, slidingly engaging with it. The computing and processing device is electrically connected to the servo-controlled expansion joints, which can control the expansion and contraction of the servo-controlled expansion joints to offset the axis of the simulated wellbore and obtain the displacement coordinates of the simulated wellbore axis fed back by the servo-controlled expansion joints.

[0007] The displacement sensor consists of multiple sets of laser displacement sensors installed on the simulated wellbore. The multiple sets of laser displacement sensors correspond to multiple measuring points (i.e. measurement points) of the simulated drill string. The laser displacement sensors are electrically connected to the computing and processing device, which can send the radial displacement data collected at each measuring point of the simulated drill string to the computing and processing device. After preprocessing the radial displacement data, the computing and processing device can calculate the vibration displacement amplitude at each measuring point based on the radial displacement.

[0008] The simulated tubing assembly system features a segmented, flexible, and transparent simulated wellbore, sequentially divided into vertical, directional, and horizontal sections, each capable of relative deflection. This replicates the composite wellbore structure of vertical, directional, and horizontal sections, overcoming the limitation of a single vertical wellbore only suitable for simple operating conditions and covering the entire wellbore operation scenario. The simulated wellbore is made of transparent, flexible material, allowing for direct observation of the dynamic processes of drill string contact friction and deformation displacement during testing. Multiple servo-controlled electric expansion joints are spaced around the simulated wellbore, with the expansion stroke uniformly controlled by a computational processing unit. This actively drives the simulated wellbore to produce varying degrees of axial displacement, accurately simulating complex downhole constraints such as wellbore dogleg, irregular wellbore deformation, and wellbore curvature. Simultaneously, the servo-controlled electric expansion joints provide real-time feedback of the wellbore axial displacement coordinates to the computational processing unit, enabling quantitative and controllable wellbore constraint deformation and traceable data. This allows for the precise quantitative construction of wellbore constraint environments with different curvatures and eccentricities, significantly improving the adjustability of test conditions and the accuracy of parameter quantification. A plastic ring is fitted to the drill string end within the horizontal wellbore section, slidingly engaging with the wellbore wall. This plastic ring effectively simulates a drill string centralizer, replicating the nonlinear friction and impact constraints between the drill string and the wellbore wall. It reproduces the local contact damping and friction-induced vibration effects of the downhole drill string, narrowing the gap between laboratory tests and actual downhole mechanical boundary conditions. Tensile and compressive force sensors are mounted at the drill string end to collect axial load data in real time and upload it to the computing device, accurately capturing changes in axial force. Multiple laser displacement sensors are deployed at various measuring points on the drill string, non-contactly collecting radial displacement data (and subsequently calculating the vibration displacement amplitude). The absence of mechanical contact prevents alteration of the original vibration boundaries of the drill string, resulting in higher displacement acquisition accuracy. This allows for the reproduction of nonlinear geometric and mechanical boundary conditions such as irregular wellbores, drill string buckling, and bottom hole lateral constraints, improving the realism and reliability of the experimental results.

[0009] Optionally, one end of the straight section of the wellbore serves as the beginning of the simulated drill string, and the other end of the vertical section is connected to one end of the directional drilling section via a first ball joint sealing joint. The other end of the directional drilling section is connected to one end of the horizontal section of the wellbore via a second ball joint sealing joint, and the other end of the horizontal section serves as the end of the simulated drill string. The first and second ball joint sealing joints combine rotational freedom and sealing function, maintaining pipeline sealing during the bending and deflection of the simulated wellbore, preventing leakage of the test medium, and ensuring the stability of the simulated boundary conditions inside the simulated wellbore. The segmented wellbore sections are connected end-to-end to form a through channel, allowing the simulated drill string to pass through completely, fully replicating the stress and vibration state of the entire stroke of the downhole drill string, and improving the equivalence between the experiment and real (actual) drilling conditions.

[0010] Optionally, each set of servo-controlled expansion joints consists of three servo-controlled expansion joints spaced 120° apart circumferentially. The ends of the expansion rods of the servo-controlled expansion joints contact the outer wall of the simulated wellbore. Each set of three servo-controlled expansion joints spaced 120° circumferentially forms an equilateral triangle supporting the outer wall of the simulated wellbore. This allows for precise application of radial jacking force in any circumferential direction, multi-directional coordinated adjustment of the simulated wellbore's axial offset and bending deformation, and balanced offsetting of wellbore skew deviation caused by unilateral jacking. It can stably reproduce irregular wellbore constraints in any orientation. The ends of the expansion rods only contact the outer wall of the simulated wellbore, without damaging the simulated wellbore structure. At the same time, the output displacement of each servo-controlled expansion joint can be independently adjusted to adapt to different working conditions.

[0011] Optionally, each set of laser displacement sensors consists of two mutually perpendicular laser displacement sensors. The transmitting end of the laser displacement sensor is located inside the simulated wellbore and directly facing the measuring point of the simulated drill string. Each measuring point is equipped with two mutually perpendicular laser displacement sensors, with their transmitting ends built into the simulated wellbore and directly facing the measuring point of the drill string. This allows for the simultaneous acquisition of radial displacement data in the X and Y orthogonal directions, completely restoring the two-dimensional radial vibration pattern within the plane of the simulated drill string, and avoiding data distortion caused by missing vibration information in one dimension when measuring in one direction.

[0012] Optionally, the vibration system includes a vibrator and a bottom-hole limiting disk. One end face of the bottom-hole limiting disk is fixedly connected to the vibrator, and the other end face of the bottom-hole limiting disk contacts the end of the simulated drill string. The edge of the other end face of the bottom-hole limiting disk has a limiting protrusion to limit the radial displacement range of the simulated drill string during vibration, preventing the simulated drill string from slipping out of the vibration system area and thus failing to obtain vibration. The rigid connection between the vibrator and the bottom-hole limiting disk allows the dynamic excitation force to be transmitted completely and without attenuation to the end of the simulated drill string, accurately replicating the impact vibration excitation at the drill bit and ensuring controllable vibration input amplitude and frequency. The end face of the bottom-hole limiting disk directly abuts against the end of the simulated drill string, increasing the contact area and preventing excessive load at the excitation concentration point from causing local deformation of the drill string end, thus protecting the test component. The end face edge of the bottom-hole limiting disc is provided with an annular limiting protrusion, which can limit the excessive radial displacement of the simulated drill string end, prevent the drill string end from slipping or deviating from the excitation contact surface during the test, and ensure the continuous stability of the excitation transmission link.

[0013] Secondly, the present invention provides a drill string vibration test method for simulating complex constraint environments, employing the aforementioned drill string vibration test apparatus. The drill string vibration test method is used to obtain the energy attenuation coefficient, and the method includes:

[0014] Based on the wellbore trajectory data required for the experiment, corresponding control commands are generated to control the extension and retraction of multiple sets of servo-controlled expansion joints, so that the simulated wellbore has the curvature required for the experiment.

[0015] Two measuring points on a section of simulated drill string for which the vibration energy attenuation needs to be determined are selected as the starting measuring point and the ending measuring point, respectively; wherein the starting measuring point is closer to the vibration system than the ending measuring point.

[0016] The distance (simulated wellbore axial direction) between the laser displacement sensors corresponding to the starting measurement point and the laser displacement sensors corresponding to the ending measurement point is taken as the propagation distance L.

[0017] The control loading system is used to simulate the drilling pressure and rotational speed required for the drill string loading experiment.

[0018] The vibration control system applies the required vibrations to the simulated drill string.

[0019] The vibration displacement amplitude A0 at the starting measuring point is obtained by calculating the radial displacement at the starting measuring point, and the vibration displacement amplitude A at the ending measuring point is obtained by calculating the radial displacement at the ending measuring point. L .

[0020] Using the formula: The energy attenuation coefficient of this simulated drill string section was calculated. The energy attenuation coefficient of this simulated drill string. It can reflect the vibration attenuation.

[0021] Based on experimental requirements, the wellbore trajectory output control commands drive the servo-controlled electric expansion joint, flexibly adjusting the curvature of the simulated wellbore. It can construct constraint environments with different degrees of curvature and dogleg degrees as needed, adapting to the wellbore simulation requirements of various test schemes and broadening the coverage of test conditions. Along the vibration transmission direction, it distinguishes between near-end starting and far-end ending measuring points, using the axial distance between two sets of laser displacement sensors as the vibration propagation distance L, unifying the length benchmark for attenuation calculation. The loading system outputs drilling pressure, rotational speed, and vibration system excitation parameters, flexibly matching various drilling conditions under study. This facilitates single-variable and multi-variable control experiments and helps distinguish the influence of different parameters on vibration attenuation characteristics. A logarithmic attenuation model is used to calculate the energy attenuation coefficient. A quantitative mathematical relationship was established between vibration propagation distance, vibration displacement amplitude at the first and last measuring points, and energy attenuation coefficient. The obtained energy attenuation coefficient can intuitively quantify the vibration loss caused by the combined effects of drill string and well wall friction, structural damping, etc.

[0022] Thirdly, the present invention provides a drill string vibration test method for simulating complex constraint environments, using the aforementioned drill string vibration test apparatus. The drill string vibration test method is used to obtain the cumulative fatigue damage rate, and the method includes:

[0023] Based on the wellbore trajectory data required for the experiment, corresponding control commands are generated to control the extension and retraction of multiple sets of servo-controlled expansion joints, so that the simulated wellbore has the curvature required for the experiment.

[0024] The control loading system applies the required drilling pressure to the simulated drill string loading experiment; wherein, the axial load corresponding to the required drilling pressure is... , This represents the critical load at which the simulated drill string buckles.

[0025] Fatigue damage test points are screened to obtain i fatigue damage test points: if a certain test point has points that contact the well wall of the simulated wellbore within a preset distance on both sides, then the test point is regarded as a fatigue damage test point.

[0026] Measure the distance between the two points on either side of each fatigue damage test point that contact the well wall of the simulated wellbore. .

[0027] The loading system is controlled to adjust the rotational speed required for the simulated drill string loading experiment.

[0028] The vibration control system applies the required vibrations to the simulated drill string.

[0029] The amplitude of the i vibration displacements at the i fatigue damage measuring points under the j-th vibration level is obtained by calculating the radial displacement at the i fatigue damage measuring points. .

[0030] Using the formula: The dynamic curvature amplitudes at the i-th fatigue damage measurement point under the j-th vibration level are calculated. .

[0031] Using the formula: Calculate the first The alternating stress amplitude at the outer wall of the simulated drill string section under each vibration level. Where E represents the elastic modulus of the simulated drill string. Indicates the simulated drill string outer diameter. Represents i dynamic curvature amplitudes The average value.

[0032] The alternating stress amplitude Substitute the preset material standard SN curve to obtain the first... Fatigue life limits of simulated drill strings under various vibration levels .

[0033] The collision frequency per unit time and the duration of the j-th vibration level are statistically analyzed; wherein, the collision frequency per unit time is equal to the number of peaks at each measuring point collected by the laser displacement sensor per unit time whose radial displacement is greater than a preset wall-attaching threshold.

[0034] Multiplying the collision frequency by the duration yields the actual number of cycles for the j-th vibration level. .

[0035] Using the formula: The cumulative fatigue damage rate D is calculated; where m represents the total number of applied vibration levels.

[0036] The servo-controlled expansion joint is adjusted according to the wellbore trajectory required for the test, flexibly changing the curvature of the simulated wellbore. This allows for the simulation of wellbore constraints with different dogleg degrees and bending levels, replicating the stress boundary of the drill string adhering to the well wall and ensuring the equivalence of the fatigue test conditions. The loading system applies axial drilling pressure exceeding the critical load for simulated drill string buckling, causing buckling deformation and reproducing the mechanical state of the downhole drill string under pressure adhering to the well wall and periodically colliding with it. This avoids the disconnect between low-load, non-buckling conditions and actual stress conditions, improving the engineering matching degree of the fatigue damage test. A quantitative measurement point selection rule is set, identifying only locations with well wall contact points within a preset range on both sides of the measurement point as fatigue damage measurement points. This accurately locates the dangerous areas of high-frequency frictional collision and stress concentration after simulated drill string buckling, eliminating invalid measurement points without alternating stress damage and reducing redundant data calculations. The dynamic curvature amplitude is calculated from the vibration amplitude. Then, by combining the drill string's elastic modulus and outer diameter parameters, the alternating stress amplitude can be calculated. By establishing a quantitative correlation between vibration deformation and alternating stress in the cross-section, the core stress input parameters for fatigue damage can be directly obtained. The alternating stress amplitude is matched to the material's SN standard curve, and the fatigue life limit of the simulated drill string under the corresponding vibration level is obtained from a table. Based on mature material fatigue theory, the life benchmark values ​​are ensured to be standardized and reliable. The number of peaks exceeding the wall-attachment threshold in the laser displacement acquisition signal is used to characterize the wall-attachment collision frequency per unit time, and the actual cycle number is obtained by multiplying the duration of each vibration level. Based on the actual vibration signal statistics, the number of alternating cycles is statistically analyzed, which differs from the theoretically assumed number of cycles, significantly reducing the statistical error of fatigue cycles. By using the linear cumulative damage theory to superimpose the damage proportion of each level of vibration condition, the cumulative fatigue damage rate D can be solved, which can quantify the degree of fatigue damage accumulation of the drill string under the superposition of multiple levels of vibration and intuitively predict the risk of drill string fatigue failure.

[0037] Optionally, the critical load at which the simulated drill string buckles. The calculation method is as follows: ;

[0038] in, This represents the moment of inertia of the cross section calculated based on the inner and outer diameters of the simulated drill string. This indicates the linear weight per unit length of the simulated drill string. Indicates the local wellbore dip angle. This represents the difference between the inner diameter of the simulated wellbore and the outer diameter of the simulated drill string in a static state (i.e., radial clearance). This represents the local curvature at any location on the simulated wellbore.

[0039] The moment of inertia I of the cross section is introduced, and the bending stiffness of the simulated drill string is characterized by the geometric parameters of its inner and outer diameters. The linear weight per unit length w is included to restore the influence of the vertical additional load caused by the drill string's self-weight, avoiding the problem of overestimating the critical load due to neglecting self-weight. Two constraint parameters, the local wellbore inclination angle θ and the radial clearance r between the wellbore and the drill string, are simultaneously coupled to quantify the regulatory effect of wellbore inclination and radial movement space on the drill string buckling instability threshold. The local curvature of the wellbore is also introduced. It adapts to the geometric characteristics of curved wellbores in the build-up and horizontal sections, breaks through the limitations of the single buckling calculation model for vertical wells, and can be adapted to working conditions of composite well sections with arbitrary curvature.

[0040] Optionally, the local wellbore inclination angle The local curvature And the dogleg angle of a simulated wellbore between two adjacent sets of servo-controlled expansion joints. The methods of obtaining it include:

[0041] Obtain the simulated wellbore axis displacement coordinates and perform curve fitting to obtain the simulated wellbore axis trajectory equation. .

[0042] right Perform first-order differentiation to obtain the corresponding Slope of the tangent line of the simulated wellbore trajectory at the location ,right Perform second derivative to obtain the corresponding Rate of change of curvature of simulated wellbore trajectory at location .

[0043] Using the formula: The local wellbore dip angle was calculated. .

[0044] Using the formula: The local curvature at any location on the simulated wellbore was calculated. .

[0045] Using the formula: The dogleg angle of a simulated wellbore between two adjacent sets of servo-controlled expansion joints was calculated. .in, This indicates the axial mechanical installation distance between two adjacent sets of servo-controlled expansion joints. This represents the average curvature of the simulated wellbore (i.e., the section of simulated wellbore between two adjacent sets of servo-controlled expansion joints).

[0046] By sequentially differentiating the fitted wellbore axis trajectory equation with first and second derivatives, the trajectory tangent slope and the rate of change of trajectory curvature are extracted. Based on differential geometry theory, the wellbore spatial morphology is characterized, and trajectory characteristic parameters at any axial position of the wellbore can be continuously output. The arctangent function is used to solve for the local wellbore inclination angle θ from the first derivative of the trajectory, accurately representing the inclination degree of the well section and completely replicating different inclination conditions for vertical, directional, and horizontal wells. The local curvature is solved by substituting the first and second derivative values ​​into the standard curvature formula of the plane curve. This method quantifies the degree of wellbore bending deformation, accurately characterizing the differences in wellbore bending caused by different servo expansion and contraction amounts, and providing core geometric foundation data for calculating buckling load, dynamic curvature, and fatigue stress. Combined with segmented axial installation spacing... With the average curvature of the corresponding segment A dedicated conversion formula for dogleg degree was developed to convert curve curvature into the dogleg degree index γ commonly used in the oil and gas drilling industry.

[0047] Fourthly, the present invention provides a drill string vibration test method for simulating complex constraint environments, using the aforementioned drill string vibration test apparatus. The drill string vibration test method is used to obtain the vibration intensity under different drilling pressure-rotation speed combinations. The method includes:

[0048] Based on the wellbore trajectory data required for the experiment, corresponding control commands are generated to control the extension and retraction of multiple sets of servo-controlled expansion joints, so that the simulated wellbore has the curvature required for the experiment.

[0049] By selecting different drilling pressures and rotation speeds, h drilling pressure-rotation speed combinations can be formed.

[0050] The control loading system loads the simulated drill string according to the b-th drill pressure-rotation speed combination. Here, b takes all integers from 1 to h.

[0051] The vibration control system applies the required vibrations to the simulated drill string.

[0052] The vibration displacement amplitude at each measuring point is obtained by calculating the radial displacement at each measuring point.

[0053] Using the formula: The root mean square value of vibration under the b-th drilling pressure-speed combination was calculated. Where M represents the total number of measurement points within the preset sliding window. This represents the vibration displacement amplitude at the d-th measuring point within the sliding window.

[0054] Using the formula: The kurtosis index under the b-th drilling pressure-rotation speed combination was calculated. ;in, This represents the average vibration displacement amplitude at M measuring points within the sliding window. This represents the standard deviation of the vibration displacement amplitude at M measuring points within the sliding window.

[0055] Using the formula: The comprehensive vibration intensity index of the b-th drilling pressure-rotation speed combination was calculated. .in, This represents the root mean square value under preset baseline or safe operating conditions. This represents the kurtosis reference value under preset baseline or safe operating conditions. This represents the preset root mean square weighting coefficient. This represents the preset kurtosis weighting coefficient. =1.

[0056] The system batch sets up h groups of differentiated drill pressure and rotation speed combinations, and conducts comparative tests by cyclically loading each combination. This allows for a systematic traversal of different drilling process parameter combinations, fully covering commonly used operating ranges in the field, facilitating a comprehensive analysis of the impact of drill pressure and rotation speed coupling on drill string vibration. Under the same operating conditions, the system uniformly applies the same excitation vibration, and uses a laser displacement sensor to collect radial displacement and calculate vibration amplitude. This non-contact measurement method eliminates additional damping interference, and the raw vibration data accurately reflects the actual deformation characteristics of the drill string. A sliding window is introduced to statistically analyze the amplitude data of measurement points. The root mean square (RMS) value of vibration characterizes the overall energy level of vibration, intuitively reflecting the average severity of drill string vibration. Simultaneously, a kurtosis index is calculated. Kurtosis can sensitively capture instantaneous abrupt vibration signals such as impacts and wall collisions, compensating for the limitation of the RMS in identifying local impact damage vibrations. These two indices respectively cover steady-state vibration energy and pulse impact characteristics. By setting standardized benchmark conditions and corresponding reference root mean square and reference kurtosis, the two sets of vibration characteristic indicators are dimensionlessly normalized, eliminating the calculation bias caused by dimensional differences. Then, a weighted fusion is performed, allowing for flexible adjustment of the evaluation ratio of steady-state vibration and impact vibration according to the test focus, adapting to different drilling risk assessment needs, and finally outputting a comprehensive vibration intensity index with unified dimensions. .

[0057] Optionally, using h comprehensive vibration intensity indices corresponding to h drill pressure-rotation speed combinations, a three-dimensional response map or contour map of the drill pressure-rotation speed-comprehensive vibration intensity index can be plotted.

[0058] If the comprehensive vibration intensity index of a certain drilling pressure-speed combination is greater than If the drill pressure-speed combination is deemed to have a high vibration risk, then the drill pressure-speed combination is considered to have a high vibration risk. If the comprehensive vibration intensity index of a certain drill pressure-speed combination is less than or equal to... If the drilling pressure-rotation speed combination is within a relatively safe operating range, then it is determined that the drilling pressure-rotation speed combination is in a relatively safe operating range; where, This indicates the preset vibration intensity threshold.

[0059] By plotting three-dimensional response maps or contour maps using h comprehensive vibration intensity indices corresponding to all h drill pressure-speed combinations, the continuous distribution of vibration intensity under the coupled effects of drill pressure and speed can be visually presented. Compared to discrete data tables, this method can quickly locate regions of abrupt changes and peak values ​​in vibration intensity, facilitating intuitive observation of the changing trends in vibration risk caused by small parameter variations. A uniform vibration intensity threshold is set. As a risk demarcation standard, it establishes a clear binary judgment logic, avoids errors caused by subjective human judgment, and the judgment results are reproducible and standardized. Attached Figure Description

[0060] Figure 1 This is a drill string vibration experimental device for simulating complex constraint environments in an embodiment of the present invention.

[0061] Figure 2 This is a schematic diagram of the arrangement of a set of servo-controlled telescoping devices in an embodiment of the present invention.

[0062] Figure 3 This is a schematic diagram of the second ball joint sealing joint in an embodiment of the present invention.

[0063] Figure 4 This is a schematic diagram illustrating the interaction between the simulated drill string, simulated wellbore, and vibration system in an embodiment of the present invention.

[0064] Figure 5 This is a schematic diagram illustrating the fit between the plastic ring and the simulated drill string and simulated wellbore in an embodiment of the present invention.

[0065] Figure 6 This is a schematic diagram of the arrangement of a set of laser displacement sensors in an embodiment of the present invention.

[0066] Figure 7 This is a flowchart of the first drill string vibration test method for simulating a complex constraint environment in an embodiment of the present invention.

[0067] Figure 8 This is a flowchart of the second drill string vibration test method for simulating complex constraint environments in an embodiment of the present invention.

[0068] Figure 9 This is a flowchart of the third drill string vibration test method for simulating complex constraint environments in this embodiment of the invention. Detailed Implementation

[0069] The embodiments of this application will be described in further detail below with reference to the accompanying drawings and examples. The detailed description of the following embodiments and the accompanying drawings are used to illustrate the principles of this application by way of example, but should not be used to limit the scope of this application, that is, this application is not limited to the described embodiments.

[0070] like Figures 1 to 6As shown, the drill string vibration experimental device simulating a complex constraint environment in this embodiment of the invention includes a simulated drill string assembly system, a loading system, a vibration system, and a measurement system. The simulated drill string assembly system includes a simulated drill string 11 and a simulated wellbore 12 sleeved outside the simulated drill string 11. The output end of the loading system is fixedly connected to the head end of the simulated drill string 11, and the output end of the vibration system is in contact with the tail end of the simulated drill string 11. The measurement system includes a computing and processing device 41 (including a computer and a data processing device), and a tension / compression sensor 42 and a displacement sensor electrically connected to the computing and processing device 41. The tension / compression sensor 42 is installed at the tail end of the simulated drill string 11, acquires the axial load of the simulated drill string 11, and sends it to the computing and processing device 41. The computing and processing device 41 is electrically connected to the loading system and the vibration system, and controls the operation of the loading system and the vibration system.

[0071] The simulated drill string assembly system also includes a plastic ring 13 and multiple sets of servo-controlled expansion joints 14 spaced around the periphery of the simulated wellbore 12. The simulated wellbore 12 is a flexible, transparent wellbore with a vertical wellbore section 121, a directional wellbore section 122, and a horizontal wellbore section 123 connected in sequence and capable of relative deflection. The plastic ring 13 is fitted around the near-end portion of the simulated drill string 11, and the plastic ring 13 is located within the horizontal wellbore section 123 and slides within it (see [reference]). Figure 5 From a cross-sectional perspective, the plastic ring 13 stably constrains the tail end of the simulated drill string to the geometric center of the simulated wellbore, accurately simulating the centering effect of the centralizer on the bottom drill string assembly. The computational processing unit 41 is electrically connected to the servo-controlled expansion joint 14, which can control the expansion and contraction of the servo-controlled expansion joint 14 to offset the axis of the simulated wellbore, and obtain the displacement coordinates of the simulated wellbore axis fed back by the servo-controlled expansion joint 14.

[0072] The displacement sensor consists of multiple sets of laser displacement sensors 43 installed on the simulated wellbore. The multiple sets of laser displacement sensors 43 correspond to multiple measuring points (i.e. measurement points) of the simulated drill string 11. The laser displacement sensors 43 are electrically connected to the computing and processing device 41, and can send the radial displacement data collected at each measuring point of the simulated drill string 11 to the computing and processing device 41. After preprocessing the radial displacement data, the computing and processing device 41 can calculate the vibration displacement amplitude at each measuring point based on the radial displacement.

[0073] The computational processing device 41 preprocesses the axial load data collected by the tension / compression sensor 42 and the radial displacement data collected by the laser displacement sensor 43 by using the interquartile range (IQR) method to denoise the original sampling sequence and remove "outliers" caused by electrical pulses or transient sensor malfunctions. ;in, This represents the lower quartile (25th percentile) of the data sample. This represents the upper quartile (75th percentile). The interval is the interquartile range. All isolated points falling outside this interval are smoothed using piecewise cubic Hermitian interpolation (PCHIP) to ensure data integrity.

[0074] In some embodiments, one end of the vertical wellbore section 121 serves as the beginning of the simulated drill string 11, and the other end of the vertical wellbore section 121 is connected to one end of the directional wellbore section 122 via a first ball joint sealing joint 15. The other end of the directional wellbore section 122 is connected to one end of the horizontal wellbore section 123 via a second ball joint sealing joint 16, and the other end of the horizontal wellbore section 123 serves as the end of the simulated drill string 11. The use of the first ball joint sealing joint 15 and the second ball joint sealing joint 16 allows for large-angle deflection between adjacent wellbore sections without pressure relief.

[0075] like Figure 2 , Figure 6 As shown, in some embodiments, each set of servo-controlled telescopic joints 14 consists of three servo-controlled telescopic joints 14 distributed at 120° intervals along the circumference, with the telescopic rod ends of the servo-controlled telescopic joints 14 contacting the outer wall of the simulated wellbore 12. Each set of laser displacement sensors 43 consists of two mutually perpendicular laser displacement sensors 43, with the emitting end of the laser displacement sensor 43 located inside the simulated wellbore 12 and facing the measuring point of the simulated drill string 11.

[0076] like Figure 1 As shown, in some embodiments, the loading system includes a servo motor top drive 21 and a hydraulic loading head 22. The servo motor top drive 21 is electrically connected to the computing processing device 41. One end of the hydraulic loading head 22 is fixedly connected to the output shaft of the servo motor top drive 21, and the other end of the hydraulic loading head 22 is fixedly connected to the head end of the simulated drill string 11.

[0077] like Figure 4As shown, in some embodiments, to simulate the bottom boundary of the well, an independent vibration system is set outside the tail end of the simulated wellbore to simulate the axial and radial excitation forces generated by the drill bit breaking the rock. The vibration system includes an exciter 31 and a bottom-end limiting disk 32. The exciter 31 is electrically connected to the computing processing device 41. One end face of the bottom-end limiting disk 32 is fixedly connected to the exciter 31, and the other end face of the bottom-end limiting disk 32 contacts the end of the simulated drill string 11. The edge of the other end face of the bottom-end limiting disk 32 has a limiting protrusion 321. The inner diameter of the limiting protrusion 321 is proportionally equivalent to the constraint boundary of the actual bottom rock contour. The end of the simulated drill string 11 is machined into a smooth cylindrical surface that contacts the end face of the bottom-end limiting disk 32, and there is no rigid mechanical connection between the two. This sliding sleeve structure allows the simulated drill string end to slide freely in the axial direction to transmit axial vibration waves. However, in the event of lateral displacement, it is rigidly blocked by the limiting protrusion 321, thus strictly limiting it to a set radial displacement range. This design prevents the simulated drill string 11 from detaching, replicating the three-dimensional confined state of the bottom hole drill string assembly in an extremely narrow space.

[0078] Since the experiment needs to simulate the wall-attaching and collision behavior of the drill string 11 under different bending trajectories, the material of the simulated wellbore 12 needs to possess both high elastic recovery capability and high transparency. In some embodiments, modified transparent polyurethane (TPU) with high modulus and low hysteresis loss is used as the main material of the simulated wellbore, with a Shore hardness range of 85A-95A and a light transmittance ≥85%. Utilizing the high elasticity characteristics of TPU in conjunction with the first and second ball joint sealing joints, stress relaxation and geometric reconstruction of the simulated wellbore axis under continuous bending conditions are achieved.

[0079] To ensure that the simulated wellbore does not suffer plastic damage during the simulated directional drilling process, the simulated wellbore 12 must adhere to the maximum bending stress criterion: ;in, This represents the maximum full stress in the simulated wellbore. This represents the elastic modulus of the material in the simulated wellbore. Indicates the simulated wellbore outer diameter. This represents the local curvature at any location on the simulated wellbore. This indicates the material's proportional limit. The maximum simulated incline rate supported by the system is calibrated using this formula to ensure the linear elastic background of the experimental data, guaranteeing that the material remains within the linear elastic range at the maximum incline rate and does not undergo permanent plastic deformation.

[0080] like Figure 7 As shown in the embodiment of the present invention, the drill string vibration test method for simulating a complex constraint environment uses the aforementioned drill string vibration test apparatus for simulating a complex constraint environment. The drill string vibration test method is used to obtain the energy attenuation coefficient, and the method includes the following steps:

[0081] S11. Generate corresponding control commands based on the wellbore trajectory data required for the experiment, and control multiple sets of servo-controlled telescoping devices 14 to extend and retract, so that the simulated wellbore has the curvature required for the experiment. As an example, the wellbore trajectory required for the experiment can be a real wellbore trajectory.

[0082] S12. Select two measuring points on a section of the simulated drill string from which the vibration energy attenuation needs to be determined, as the starting measuring point and the ending measuring point, respectively. The starting measuring point is closer to the exciter 31 than the ending measuring point.

[0083] S13. The distance between the laser displacement sensor 43 corresponding to the starting measurement point and the laser displacement sensor 43 corresponding to the ending measurement point is taken as the propagation distance L.

[0084] S14. The servo electric top drive 21 is controlled to apply the required drilling pressure and rotational speed to the simulated drill string 11 via the hydraulic loading head 22. As an example, the required drilling pressure and rotational speed can be obtained from the actual drilling pressure and rotational speed through a preset similarity ratio.

[0085] S15. The control exciter 31 applies the required vibration to the simulated drill string 11 through the bottom-hole limiting disk 32. As an example, the vibration frequency and vibration displacement amplitude (corresponding vibration level) of the required vibration can be obtained from the vibration data of actual drilling through a preset similarity ratio conversion.

[0086] S16. The vibration displacement amplitude A0 at the starting measuring point is obtained based on the radial displacement at the starting measuring point, and the vibration displacement amplitude A at the ending measuring point is obtained based on the radial displacement at the ending measuring point. L .

[0087] S17. Using the formula: The energy attenuation coefficient of this simulated drill string section was calculated. (Unit: m) −1 ).

[0088] In addition, by setting different excitation parameters for the servo electric top drive 21 and the vibrator 31, and using multiple sets of servo-controlled telescoping devices 14, the sections of the simulated wellbore 12 are adjusted to different curvatures (corresponding to dogleg degrees). ).different The values ​​represent spatial geometric boundaries of varying degrees of intensity, forcing the drill string 11 to undergo different degrees of bending and wall-attaching friction in the simulation. Based on this, different... Under constraints The value can provide gain compensation suggestions for downhole acoustic telemetry technology, ensuring the stability of data transmission of measurement while drilling (MWD) instruments under complex geometric constraints.

[0089] The sinusoidal or helical buckling of the simulated drill string under pressure-inducing drilling (PDI) causes frequent collisions between the simulated drill string and the wellbore, generating extremely high-frequency alternating stress, which is a major cause of fatigue failure in the bottom hole assembly (BHA). This method precisely applies axial loads through a top-mounted servo-electric drive 21 and a hydraulic loading head 22. In conjunction with the rotational speed, the bottom-hole limiting disk 32 and the plastic ring 13 (equivalent to a centralizer) at the end of the simulated drill string are used to construct a real bottom-hole constraint, thereby reproducing the collision and friction process between the simulated drill string 11 and the well wall under multiple constraint couplings.

[0090] like Figure 8 As shown in the embodiment of the present invention, the drill string vibration test method simulating a complex constraint environment uses the aforementioned drill string vibration test apparatus to simulate a complex constraint environment. The drill string vibration test method is used to obtain the cumulative fatigue damage rate, and the method includes the following steps:

[0091] S21. Generate corresponding control commands based on the wellbore trajectory data required for the experiment, and control multiple sets of servo-controlled telescoping devices 14 to extend and retract, so that the simulated wellbore has the curvature required for the experiment. As an example, the wellbore trajectory required for the experiment can be a real wellbore trajectory.

[0092] S22, the servo electric top drive 21 is controlled to apply the experimental drilling pressure to the simulated drill string 11 via the hydraulic loading head 22. The axial load corresponding to the experimental drilling pressure is... , This represents the critical load at which the simulated drill string buckles.

[0093] In some embodiments, the critical load simulating drill string buckling is used. The calculation method is as follows: .in, This represents the moment of inertia of the cross section calculated based on the inner and outer diameters of the simulated drill string. This represents the linear weight per unit length of the simulated drill string (obtained by measuring known quantities). Indicates the local wellbore dip angle. This represents the difference between the inner diameter of the simulated wellbore and the outer diameter of the simulated drill string in a static state (i.e., radial clearance). This represents the local curvature at any location on the simulated wellbore. The critical load at which the drill string buckles is simulated. The calculation method takes into account local curvature The additional constraint moment generated is controlled by adjusting the axial load corresponding to the drilling pressure required for the experiment. This induces controlled buckling and adhesion of the tubing string to the wall in a specific curvature section, simulating the high-friction, multi-point-constrained vibration propagation environment in a real wellbore.

[0094] In some embodiments, the local wellbore dip angle Local curvature And the dogleg degree of a simulated wellbore between two adjacent sets of servo-controlled expansion joints 14. The method for obtaining it includes the following steps:

[0095] First, the simulated wellbore axis displacement coordinates are obtained, and curve fitting is performed to obtain the equation of the simulated wellbore axis trajectory. .

[0096] Secondly, for Perform first-order differentiation to obtain the corresponding Slope of the tangent line of the simulated wellbore trajectory at the location ,right Perform second derivative to obtain the corresponding Rate of change of curvature of simulated wellbore trajectory at location .

[0097] Next, using the formula: The local wellbore dip angle was calculated. .

[0098] Then, using the formula: The local curvature at any location on the simulated wellbore was calculated. .

[0099] Finally, using the formula: The dogleg angle of a simulated wellbore between two adjacent sets of servo-controlled expansion joints 14 was calculated. .in, This indicates the axial mechanical installation distance between two adjacent sets of servo-controlled expansion joints 14. This represents the average curvature of the simulated wellbore section (i.e., the section of simulated wellbore between two adjacent sets of servo-controlled expansion joints 14). After calculating the dogleg degree of each section of the entire simulated wellbore, a continuous dogleg degree distribution curve can be formed. This curve gives a clear geometric value to the originally abstract and complex constraint environment (such as setting the inclination rate of a certain section to a specific 15° / 30m).

[0100] S23. Perform fatigue damage measurement point screening to obtain i fatigue damage measurement points. The fatigue damage measurement point screening method is as follows: if there are points that contact the well wall of the simulated wellbore within a preset distance on both sides of a certain measurement point, then the measurement point is regarded as a fatigue damage measurement point.

[0101] S24. Measure the distance between the two points on both sides of each fatigue damage test point that contact the well wall of the simulated well. .

[0102] S25. The servo electric top drive 21 is controlled to apply the required rotational speed to the simulated drill string 11 via the hydraulic loading head 22. As an example, the required rotational speed can be obtained by converting the actual drilling pressure and rotational speed through a preset similarity ratio.

[0103] S26. The control exciter 31 applies the required vibration to the simulated drill string 11 through the bottom-hole limiting disk 32. The vibration frequency and vibration displacement amplitude (corresponding to the vibration level) of the required vibration can be obtained from actual drilling vibration data through a preset similarity ratio conversion.

[0104] S27. Based on the radial displacement calculation at the i fatigue damage measurement points, the vibration displacement amplitude at the i fatigue damage measurement points under the j-th vibration level is obtained. .

[0105] S28. Use formula: The dynamic curvature amplitudes at the i-th fatigue damage measurement point under the j-th vibration level are calculated. .

[0106] S29. Using the formula: Calculate the first The alternating stress amplitude at the outer wall of the simulated drill string section under each vibration level. Where E represents the elastic modulus of the simulated drill string. Indicates the simulated drill string outer diameter. Represents i dynamic curvature amplitudes The average value.

[0107] S210, Adjusting the alternating stress amplitude Substitute the preset material standard SN curve to obtain the first... Fatigue life limits of simulated drill strings under various vibration levels .

[0108] S211. Statistically calculate the collision frequency per unit time and the duration of the j-th vibration level. The collision frequency per unit time is equal to the number of peaks at each measuring point acquired by the laser displacement sensor per unit time whose radial displacement exceeds a preset wall-attaching threshold.

[0109] S212. Multiply the collision frequency by the duration to obtain the actual number of cycles for the j-th vibration level. .

[0110] S213. Using the formula: The cumulative fatigue damage rate D is calculated. Where m represents the total number of applied vibration levels.

[0111] like When D approaches the critical value of 1, an early warning is issued, suggesting the replacement of the bottom drill string assembly (BHA) to effectively prevent major accidents such as downhole string breakage.

[0112] During drilling, the selection of combinations of mechanical rate of penetration (ROP), weight on bit (WOB), and rotational speed (RPM) must avoid parameter ranges that could cause severe lateral instability, rubbing impact, or amplified axial vibration. The method in this embodiment of the invention can directly observe the dynamic response of the simulated drill string under different combinations of WOB and RPM (refer to the comprehensive vibration intensity index) under conditions of variable curvature, variable axial load, and end-positioning constraints.

[0113] like Figure 9 As shown in the embodiment of the present invention, the drill string vibration test method for simulating a complex constraint environment uses the aforementioned drill string vibration test device for simulating a complex constraint environment. The drill string vibration test method is used to obtain the vibration intensity under different drilling pressure-rotation speed combinations, and includes the following steps:

[0114] S31. Generate corresponding control commands based on the wellbore trajectory data required for the experiment, and control multiple sets of servo-controlled telescoping devices 14 to extend and retract, so that the simulated wellbore has the curvature required for the experiment. As an example, the wellbore trajectory required for the experiment can be a real wellbore trajectory.

[0115] S32. Select different drilling pressures and rotation speeds to form h drilling pressure-rotation speed combinations.

[0116] S33. The servo electric top drive 21 is controlled to load the simulated drill string 11 through the hydraulic loading head 22 according to the b-th drilling pressure-speed combination. Here, b takes all integers from 1 to h.

[0117] S34. The control exciter 31 applies the required vibration to the simulated drill string 11 through the bottom-hole limiting disk 32. As an example, the vibration frequency and vibration displacement amplitude (corresponding vibration level) of the required vibration can be obtained from the vibration data of actual drilling through a preset similarity ratio conversion.

[0118] S35. The vibration displacement amplitude at each measuring point is obtained by calculating the radial displacement at each measuring point.

[0119] S36. Using the formula: The root mean square value of vibration under the b-th drilling pressure-speed combination was calculated. Where M represents the total number of measurement points within the preset sliding window. This represents the vibration displacement amplitude at the d-th measuring point within the sliding window. It is used to characterize the continuous vibration displacement amplitude level of the simulated drill string under the b-th drill pressure-speed combination. By comparing the difference of the root mean square values ​​of vibration at M measuring points in different axes, the energy attenuation amplitude of the vibration wave when passing through different curvature gradient paths can be quantitatively calculated.

[0120] S37. Using the formula: The kurtosis index under the b-th drilling pressure-rotation speed combination was calculated. .in, This represents the average vibration displacement amplitude at M measuring points within the sliding window. This represents the standard deviation of the vibration displacement amplitude at M measuring points within the sliding window. Kurtosis index. This parameter is used to characterize the intensity of instantaneous collisions or impacts between the drill string and the wellbore. A larger kurtosis index indicates a more intense instantaneous collision between the drill string and the wellbore. The combination of these two parameters provides a data foundation for evaluating the rubbing state and damping effects under complex constraints. Furthermore, after calculating the root mean square value of vibration and the kurtosis index, the rubbing intensity can be measured and analyzed.

[0121] S38. Using the formula: The comprehensive vibration intensity index of the b-th drilling pressure-rotation speed combination was calculated. .in, This represents the root mean square value under preset baseline or safe operating conditions. This represents the kurtosis reference value under preset baseline or safe operating conditions. This represents the preset root mean square weighting coefficient. This represents the preset kurtosis weighting coefficient. =1. To facilitate a unified comparison of simulated drill string vibration states under different drill pressure-speed combinations, a comprehensive vibration intensity index was constructed in this embodiment of the invention. When the primary focus is on the amplitude of continuous vibration displacement, it can improve... When the primary focus is on impact or transient instability, it can improve... .

[0122] In some embodiments, a corresponding comprehensive vibration intensity index can be obtained for each drill pressure-speed combination. Based on this, a three-dimensional response map or contour map of the drill pressure-speed-comprehensive vibration intensity index can be plotted using the h comprehensive vibration intensity indices corresponding to h drill pressure-speed combinations. In the figure, areas with significantly increased comprehensive vibration intensity indices correspond to dangerous parameter ranges indicating enhanced simulated drill string vibration, intensified rubbing impact, or increased risk of instability; areas with lower and more gradual changes in comprehensive vibration intensity indices correspond to safe operating windows with weaker vibration and relatively stable operating conditions.

[0123] In some embodiments, if the combined vibration intensity index of a certain drilling pressure-rotation speed combination is greater than If the drill pressure-speed combination is deemed to have a high vibration risk, then the drill pressure-speed combination is considered to have a high vibration risk. If the comprehensive vibration intensity index of a certain drill pressure-speed combination is less than or equal to... If the drilling pressure-rotation speed combination is within a relatively safe operating range, then it is determined that the drilling pressure-rotation speed combination is in a relatively safe operating range; where, This represents the preset vibration intensity threshold. Therefore, this invention can provide reproducible and quantifiable indoor experimental data for optimizing drilling parameters, developing vibration isolation construction plans, and selecting the drill pressure-speed combination parameter window.

Claims

1. A drill string vibration experimental device for simulating a complex constraint environment, comprising a simulated drill string assembly system, a loading system, a vibration system, and a measurement system. The simulated drill string assembly system comprises a simulated drill string (11) and a simulated wellbore (12) fitted around the outside of the simulated drill string. The output end of the loading system is fixedly connected to the head end of the simulated drill string (11), and the output end of the vibration system is in contact with the end end of the simulated drill string (11). The measurement system comprises a calculation processing device (41) and a tension / compression sensor (42) and a displacement sensor electrically connected to the calculation processing device (41). The tension / compression sensor (42) is installed at the end of the simulated drill string (11) to acquire the axial load of the simulated drill string and send it to the calculation processing device (41). The calculation processing device (41) is electrically connected to the loading system and the vibration system to control the operation of the loading system and the vibration system. The device is characterized in that: The simulated tubing assembly system also includes a plastic ring (13) and multiple sets of servo-controlled expansion joints (14) spaced apart on the outer periphery of the simulated wellbore (12). The simulated wellbore (12) is a flexible transparent wellbore with a vertical wellbore section (121), a directional wellbore section (122), and a horizontal wellbore section (123) connected in sequence and capable of relative deflection. The plastic ring (13) is fitted around the end of the simulated drill string (11) and is located inside the horizontal wellbore section (123) and slides in fit with the horizontal wellbore section (123). The calculation and processing device (41) is electrically connected to the servo-controlled expansion joints (14) and can control the expansion and contraction of the servo-controlled expansion joints (14) to offset the axis of the simulated wellbore and obtain the feedback displacement coordinates of the axis of the simulated wellbore. The displacement sensor is a set of laser displacement sensors (43) installed on the simulated wellbore. The set of laser displacement sensors (43) corresponds to multiple measuring points of the simulated drill string (11). The laser displacement sensors (43) are electrically connected to the computing and processing device (41) and can send the radial displacement data collected at each measuring point of the simulated drill string (11) to the computing and processing device (41). The computing and processing device (41) can preprocess the radial displacement data and calculate the vibration displacement amplitude at each measuring point based on the radial displacement.

2. The drill string vibration experimental device for simulating complex constraint environments according to claim 1, characterized in that: One end of the vertical section wellbore (121) serves as the head end of the simulated drill string (11). The other end of the vertical section wellbore (121) is connected to one end of the directional section wellbore (122) through the first ball joint sealing joint (15). The other end of the directional section wellbore (122) is connected to one end of the horizontal section wellbore (123) through the second ball joint sealing joint (16). The other end of the horizontal section wellbore (123) serves as the end of the simulated drill string (11).

3. The drill string vibration experimental device for simulating complex constraint environments according to claim 1, characterized in that: Each set of servo-controlled telescopic joints (14) consists of three servo-controlled telescopic joints (14) distributed at 120° intervals along the circumference. The telescopic rod end of the servo-controlled telescopic joint (14) contacts the outer wall of the simulated well shaft (12). Each set of laser displacement sensors (43) consists of two mutually perpendicular laser displacement sensors (43). The emitting end of the laser displacement sensor (43) is located inside the simulated wellbore (12) and is directly opposite the measuring point of the simulated drill string (11).

4. The drill string vibration experimental apparatus for simulating complex constraint environments according to any one of claims 1 to 3, characterized in that: The vibration system includes an exciter (31) and a bottom-hole limiting disk (32). One end face of the bottom-hole limiting disk (32) is fixed to the exciter (31), and the other end face of the bottom-hole limiting disk (32) is in contact with the end of the simulated drill string (11), and its edge has a ring of limiting protrusions (321).

5. A method for simulating drill string vibration under complex constraint environments, characterized in that: The drill string vibration test apparatus as described in any one of claims 1 to 4, wherein the drill string vibration test method is used to obtain the energy attenuation coefficient, includes: Based on the wellbore trajectory data required for the experiment, corresponding control commands are generated to control the extension and retraction of multiple sets of servo-controlled telescoping devices (14) so ​​that the simulated wellbore has the curvature required for the experiment. Two measuring points on a section of simulated drill string for which the vibration energy attenuation needs to be determined are selected as the starting measuring point and the ending measuring point, respectively; wherein the starting measuring point is closer to the vibration system than the ending measuring point; The distance between the laser displacement sensor (43) corresponding to the starting measurement point and the laser displacement sensor (43) corresponding to the ending measurement point is taken as the propagation distance L; The loading system controls the drilling pressure and rotational speed required for the simulated drill string (11) during the loading experiment. The vibration control system applies the required vibration to the simulated drill string (11); The vibration displacement amplitude A0 at the starting measuring point is obtained by calculating the radial displacement at the starting measuring point, and the vibration displacement amplitude A at the ending measuring point is obtained by calculating the radial displacement at the ending measuring point. L ; Using the formula: The energy attenuation coefficient of this simulated drill string section was calculated. .

6. A method for simulating drill string vibration under complex constraint environments, characterized in that: The drill string vibration testing apparatus as described in any one of claims 1 to 4, wherein the drill string vibration testing method is used to obtain the cumulative fatigue damage rate, includes: Based on the wellbore trajectory data required for the experiment, corresponding control commands are generated to control the extension and retraction of multiple sets of servo-controlled telescoping devices (14) so ​​that the simulated wellbore has the curvature required for the experiment. The control loading system applies experimental drilling pressure to the simulated drill string (11); wherein, the axial load corresponding to the experimental drilling pressure is... , This represents the critical load at which the simulated drill string buckles. Fatigue damage test points are screened to obtain i fatigue damage test points: if a test point has points that contact the well wall of the simulated wellbore within a preset distance on both sides, then the test point is regarded as a fatigue damage test point. Measure the distance between the two points on either side of each fatigue damage test point that contact the well wall of the simulated wellbore. ; Control the rotational speed required by the loading system for the simulated drill string (11) loading experiment; The vibration control system applies the required vibration to the simulated drill string (11); The amplitude of the i vibration displacements at the i fatigue damage measuring points under the j-th vibration level is obtained by calculating the radial displacement at the i fatigue damage measuring points. ; Using the formula: The dynamic curvature amplitudes at the i-th fatigue damage measurement point under the j-th vibration level are calculated. ; Using the formula: Calculate the first The alternating stress amplitude at the outer wall of the simulated drill string section under each vibration level. Where E represents the elastic modulus of the simulated drill string. Indicates the simulated drill string outer diameter. Represents i dynamic curvature amplitudes The average value; The alternating stress amplitude Substitute the preset material standard SN curve to obtain the first... Fatigue life limits of simulated drill strings under various vibration levels ; The collision frequency per unit time and the duration of the j-th vibration level are statistically analyzed; wherein, the collision frequency per unit time is equal to the number of peaks at each measuring point collected by the laser displacement sensor per unit time that are greater than a preset wall-attaching threshold. Multiplying the collision frequency by the duration yields the actual number of cycles for the j-th vibration level. ; Using the formula: The cumulative fatigue damage rate D is calculated; where m represents the total number of applied vibration levels.

7. The test method for simulating drill string vibration in a complex constraint environment according to claim 6, characterized in that, The critical load at which the simulated drill string buckles. The calculation method is as follows: ; in, This represents the moment of inertia of the cross section calculated based on the inner and outer diameters of the simulated drill string. This indicates the linear weight per unit length of the simulated drill string. Indicates the local wellbore dip angle. This represents the difference between the inner diameter of the simulated wellbore and the outer diameter of the simulated drill string in a static state. This represents the local curvature at any location on the simulated wellbore.

8. The test method for simulating drill string vibration in a complex constraint environment according to claim 7, characterized in that: The local wellbore inclination angle The local curvature And the dogleg degree of a simulated wellbore between two adjacent sets of servo-controlled expansion joints (14). The methods of obtaining it include: Obtain the simulated wellbore axis displacement coordinates and perform curve fitting to obtain the simulated wellbore axis trajectory equation. ; right Perform first-order differentiation to obtain the corresponding Slope of the tangent line of the simulated wellbore trajectory at the location ,right Perform second derivative to obtain the corresponding Rate of change of curvature of simulated wellbore trajectory at location ; Using the formula: The local wellbore dip angle was calculated. ; Using the formula: The local curvature at any location on the simulated wellbore was calculated. ; Using the formula: The dogleg degree of a simulated wellbore between two adjacent sets of servo-controlled expansion joints (14) was calculated. ;in, This indicates the axial mechanical installation distance between two adjacent sets of servo-controlled expansion joints (14). This represents the average curvature of the simulated wellbore section.

9. A method for simulating drill string vibration under complex constraint environments, characterized in that: The drill string vibration testing apparatus as described in any one of claims 1 to 4, wherein the drill string vibration testing method is used to obtain the vibration intensity under different drilling pressure-speed combinations, includes: Based on the wellbore trajectory data required for the experiment, corresponding control commands are generated to control the extension and retraction of multiple sets of servo-controlled telescoping devices (14) so ​​that the simulated wellbore has the curvature required for the experiment. By selecting different drilling pressures and rotation speeds, h drilling pressure-rotation speed combinations can be formed; The control loading system loads the simulated drill string (11) according to the b-th drilling pressure-rotation speed combination; where b takes all integers from 1 to h in sequence; The vibration control system applies the required vibration to the simulated drill string (11); The vibration displacement amplitude at each measuring point is obtained by calculating the radial displacement at each measuring point. Using the formula: The root mean square value of vibration under the b-th drilling pressure-speed combination was calculated. Where M represents the total number of measurement points within the preset sliding window; This represents the vibration displacement amplitude at the d-th measuring point within the sliding window; Using the formula: The kurtosis index under the b-th drilling pressure-rotation speed combination was calculated. ;in, This represents the average vibration displacement amplitude at M measuring points within the sliding window. This represents the standard deviation of the vibration displacement amplitude at M measuring points within the sliding window; Using the formula: The comprehensive vibration intensity index of the b-th drilling pressure-rotation speed combination was calculated. ;in, This represents the root mean square value under preset baseline or safe operating conditions. This represents the kurtosis reference value under preset baseline or safe operating conditions. This represents the preset root mean square weighting coefficient. This represents the preset kurtosis weighting coefficient. =1.

10. The test method for simulating drill string vibration in a complex constraint environment according to claim 9, characterized in that: Using h comprehensive vibration intensity indices corresponding to h drilling pressure-rotation speed combinations, plot a three-dimensional response map or contour map of the drilling pressure-rotation speed-comprehensive vibration intensity index; If the comprehensive vibration intensity index of a certain drilling pressure-speed combination is greater than If the drill pressure-speed combination is deemed to have a high vibration risk, then the drill pressure-speed combination is considered to have a high vibration risk. If the comprehensive vibration intensity index of a certain drill pressure-speed combination is less than or equal to... If the drilling pressure-rotation speed combination is within a relatively safe operating range, then it is determined that the drilling pressure-rotation speed combination is in a relatively safe operating range; where, This indicates the preset vibration intensity threshold.

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