Drifting drilling tool determination method, device and equipment

Abstract

The embodiment of the invention relates to the technical field of petroleum and natural gas engineering, in particular to a drifting drilling tool determining method, device and equipment, and the method comprises the steps that first drilling parameter data corresponding to a drifting drilling tool and second drilling parameter data corresponding to a borehole casing are obtained; calculating a first blocking risk factor of the drifting drilling tool according to the first drilling parameter data, wherein the first blocking risk factor is used for representing the blocking possibility of the drifting drilling tool; calculating a second blocking risk factor of the borehole casing according to the second drilling parameter data, wherein the second blocking risk factor is used for representing the blocking possibility of the borehole casing; calculating a first tripping-in capability index of the drifting drilling tool according to the rigidity of the drifting drilling tool and the first blocking risk factor; calculating a second tripping-in capability index of the borehole casing according to the rigidity of the borehole casing and the second blocking risk factor; and according to the first tripping-in capability index and the second tripping-in capability index, whether the drifting drilling tool is matched with the borehole casing is determined.

Description

Technical Field

[0001] The embodiments of this specification relate to the field of oil and gas engineering technology, and more particularly to a method, device, and equipment for determining a through-hole drilling tool. Background Art

[0002] In oil and gas drilling projects, wellbore clearance is a critical step in ensuring the smooth flow of the wellbore and the safety of subsequent extraction operations. As oil and gas resource development extends into deeper, more complex formations, and unconventional reservoirs, wellbore irregularities, such as wellbore collapse, borehole shrinkage, keyway formation, and gravel accumulation, are becoming increasingly prominent. This significantly increases the difficulty of wellbore clearance and, in turn, impacts the efficiency of subsequent operations. As the core tool for addressing these issues, the design of wellbore clearance drilling tools must comprehensively consider multiple factors, including wellbore quality, wellbore trajectory, operational efficiency, and cost control.

[0003] Existing methods primarily rely on empirical evidence or simple stiffness ratios between the ditching tool and the wellbore casing, as well as stacked stiffness ratios. However, these methods fail to consider the impact of certain drilling parameters between the ditching tool and the wellbore on the ditching tool's running process, as well as the impact of complex downhole conditions on the ditching tool's running process. Consequently, they are unable to scientifically and accurately assess the ditching tool's effectiveness.

[0004] Therefore, how to solve the problems of one-sided evaluation, low evaluation accuracy and poor adaptability to complex wellbore conditions in existing methods, and propose a method for determining wellbore drilling tools with comprehensive evaluation, high accuracy and strong adaptability to complex wellbore conditions is a key issue that needs to be solved urgently. Summary of the Invention

[0005] The purpose of the embodiments of this specification is to provide a method, device and equipment for determining a through-hole drilling tool, so as to overcome the problems of one-sided evaluation, low accuracy and poor adaptability to complex wellbore conditions in existing through-hole drilling tool determination methods.

[0006] On the one hand, an embodiment of the present specification provides a method for determining a through-well drilling tool, including: obtaining first drilling parameter data corresponding to the through-well drilling tool and second drilling parameter data corresponding to the wellbore casing; calculating a first blocking risk factor of the through-well drilling tool based on the first drilling parameter data, the first blocking risk factor being used to indicate the possibility of the through-well drilling tool being stuck; calculating a second blocking risk factor of the wellbore casing based on the second drilling parameter data, the second blocking risk factor being used to indicate the possibility of the wellbore casing being stuck; calculating a first running-in capability index of the through-well drilling tool based on the stiffness of the through-well drilling tool and the first blocking risk factor; calculating a second running-in capability index of the wellbore casing based on the stiffness of the wellbore casing and the second blocking risk factor; and determining whether the through-well drilling tool matches the wellbore casing based on the first running-in capability index and the second running-in capability index.

[0007] On the other hand, an embodiment of the present specification provides a device for determining a through-hole drilling tool, including: an acquisition module for acquiring first drilling parameter data corresponding to the through-hole drilling tool and second drilling parameter data corresponding to the wellbore casing; a first calculation module for calculating a first blocking risk factor of the through-hole drilling tool based on the first drilling parameter data, wherein the first blocking risk factor is used to indicate the possibility of blocking of the through-hole drilling tool; a second calculation module for calculating a second blocking risk factor of the wellbore casing based on the second drilling parameter data, wherein the second blocking risk factor is used to indicate the possibility of blocking of the wellbore casing; a third calculation module for calculating a first running-in capability index of the through-hole drilling tool based on the stiffness of the through-hole drilling tool and the first blocking risk factor; a fourth calculation module for calculating a second running-in capability index of the wellbore casing based on the stiffness of the wellbore casing and the second blocking risk factor; a determination module for determining whether the through-hole drilling tool matches the wellbore casing based on the first running-in capability index and the second running-in capability index.

[0008] In another aspect, a computer device is provided, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the above-mentioned method for determining a well drilling tool.

[0009] It can be seen from the technical solutions provided in the above embodiments of this specification that the embodiments of this specification can obtain first drilling parameter data corresponding to the through-hole drilling tool and second drilling parameter data corresponding to the wellbore casing; calculate the first blocking risk factor of the through-hole drilling tool based on the first drilling parameter data, and the first blocking risk factor is used to indicate the possibility of the through-hole drilling tool being stuck; calculate the second blocking risk factor of the wellbore casing based on the second drilling parameter data, and the second blocking risk factor is used to indicate the possibility of the wellbore casing being stuck; calculate the first running-in capability index of the through-hole drilling tool based on the stiffness of the through-hole drilling tool and the first blocking risk factor; calculate the second running-in capability index of the wellbore casing based on the stiffness of the wellbore casing and the second blocking risk factor; determine whether the through-hole drilling tool and the wellbore casing match based on the first running-in capability index and the second running-in capability index. Compared to existing methods, the embodiments of this specification can calculate the likelihood of sticking for the ditch drill tool and wellbore casing based on their respective drilling parameter data. This allows for a more comprehensive and accurate assessment of the runnability of the ditch drill tool and wellbore casing, combining the deformation and sticking risk during wellbore entry. Furthermore, by comparing the runnability of the ditch drill tool and wellbore casing, the compatibility of the ditch drill tool and wellbore casing can be quickly, scientifically, and accurately determined. BRIEF DESCRIPTION OF THE DRAWINGS

[0010] In order to more clearly illustrate the embodiments of this specification or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art.

[0011] Figure 1 This is a flow chart of a method for determining a well drilling tool provided in an embodiment of this specification;

[0012] Figure 2 This is a schematic diagram of the overall process of a method for determining a well drilling tool provided in an embodiment of this specification;

[0013] Figure 3 This is a flow chart of a method for constructing a card blocking risk calculation model provided in an embodiment of this specification;

[0014] Figure 4 is a schematic diagram of the mapping relationship between the wellbore clearance ratio and the mechanical resistance provided in the embodiments of this specification;

[0015] Figure 5 is a schematic diagram of the mapping relationship between wellbore curvature and mechanical resistance provided in the embodiments of this specification;

[0016] Figure 6 is a schematic diagram of the mapping relationship between well wall roughness and mechanical resistance provided in the embodiments of this specification;

[0017] Figure 7 is a schematic diagram of a mutual information matrix between drilling parameters provided in an embodiment of this specification;

[0018] Figure 8 is a schematic diagram of casing running characteristics scatter points between drilling parameters provided in the embodiments of this specification;

[0019] Figure 9 This is a schematic diagram of the structure of a well drilling tool identification device provided in an embodiment of this specification;

[0020] Figure 10 It is a schematic diagram of the structural composition of the computer device provided in the embodiment of this specification. DETAILED DESCRIPTION

[0021] The following will be combined with the drawings in the embodiments of this specification to clearly and completely describe the technical solutions in the embodiments of this specification. Obviously, the embodiments described are only part of the embodiments of this specification, not all of the embodiments. Based on the embodiments in this specification, all other embodiments obtained by ordinary technicians in this field without making creative efforts should fall within the scope of protection of this specification.

[0022] In some embodiments, drilling parameters may include wellbore trajectory parameters, tubing parameters, and wellbore parameters. Mud logging data, well logging data, drilling history, and drilling logs cover various aspects from geological conditions to drilling operations, and historical drilling parameter data may be obtained from, but not limited to, these data.

[0023] Wellbore trajectory parameters describe the wellbore's geometry and spatial position and are crucial for drilling design and operations. Wellbore trajectory parameters can include well depth, inclination, azimuth, and wellbore curvature. Well depth can be the vertical depth or measured depth from the wellhead to the target formation. Well depth can be used to determine target drilling layers, calculate tubing length, and assess drilling difficulty. Inclination is the angle between the wellbore axis and the vertical. Inclination can influence tubing force distribution, friction calculation, and wellbore stability analysis. Azimuth is the projection of the wellbore axis onto the horizontal plane. Azimuth can be used to describe the horizontal direction of the wellbore, influencing wellbore trajectory control and geological target location. Wellbore curvature is the rate of change of the wellbore trajectory, expressed as an angular change per unit length. Wellbore curvature reflects the degree of wellbore curvature and influences tubing buckling behavior and friction distribution.

[0024] Tubular string parameters describe the geometric and mechanical properties of the casing or drill string and form the basis for analyzing string stresses and optimizing design. These parameters include casing size, centralizer size, and bending stiffness. Casing size characterizes the outer diameter, inner diameter, and wall thickness of the casing. Casing size can affect casing stiffness, weight, and clearance with the wellbore. Centralizer size characterizes the outer diameter, length, and spacing of the centralizers. Centralizer size can be used to control the alignment of the casing with the wellbore, reducing friction and buckling risk. Bending stiffness characterizes the string's ability to resist bending deformation and is related to the material's elastic modulus and section moment of inertia. Bending stiffness can influence the deformation behavior and force distribution of the string in a curved wellbore.

[0025] Wellbore parameters can describe the geometry and surface characteristics of the wellbore and are key to analyzing the interaction between the wellbore and the tubing. Wellbore parameters can include wellbore diameter, wellbore roughness, and wellbore clearance ratio. Wellbore diameter refers to the diameter of the wellbore and may vary depending on the well section. Wellbore diameter affects the clearance between the casing and the wellbore, which in turn affects friction and contact pressure. Wellbore roughness refers to the degree of unevenness of the wellbore surface and can be expressed as the height of microscopic bumps. Wellbore roughness can affect the friction coefficient and contact pressure between the casing and the wellbore. The wellbore clearance ratio represents the ratio of the outer diameter of the casing to the wellbore diameter. The wellbore clearance ratio can reflect the degree of matching between the casing and the wellbore, affecting the casing's centering and friction.

[0026] Figure 1 This is a flow chart of a method for determining a well drilling tool provided in an embodiment of this specification. Figure 2This is a schematic diagram of the overall process of a method for determining a well drilling tool provided in an embodiment of this specification. The specific implementation includes the following steps:

[0027] S101: Acquire first drilling parameter data corresponding to the wellbore drilling tool and second drilling parameter data corresponding to the wellbore casing.

[0028] In some embodiments, a drilling tool is a tool used to trim a wellbore. During drilling operations, the drilling tool can be used to trim the wellbore first, and then the wellbore casing can be lowered into the trimmed wellbore. The drilling tool and the wellbore casing must be compatible to ensure smooth lowering of the wellbore casing into the wellbore trimmed using the drilling tool without causing any sticking. First drilling parameter data corresponding to the drilling tool and second drilling parameter data corresponding to the wellbore casing can be obtained.

[0029] By systematically acquiring drilling parameter data related to the wellbore drilling tools and wellbore casing, a data foundation is laid for the subsequent calculation of the possibility of wellbore drilling tools and wellbore casing getting stuck.

[0030] The first drilling parameter data corresponding to the wellbore assembly may include drilling parameter data such as wellbore curvature, wellbore roughness, and wellbore clearance ratio, calculated based on the structure of the wellbore assembly. Wellbore curvature can indicate the degree of curvature of the wellbore trajectory and can be expressed as a change in well inclination angle (° / 30m) or a curvature radius (m) at fixed intervals (e.g., every 30 meters). If the wellbore curvature exceeds the permissible curvature of the drilling tool assembly (such as the maximum bending radius of a rigid drill pipe), the flexibility of the drilling tool can be adjusted during wellbore assembly (such as by using a weighted drill pipe or a flexible pup joint). Borehole roughness can quantify the degree of irregularity on the wellbore surface and reflect the wellbore cleanliness or erosion condition. It can be expressed as an average roughness (or irregularity index). Specifically, the wellbore roughness is obtained by calculating the deviation between the local wellbore diameter and the theoretical diameter using caliper logging data (such as the multi-arm caliper CAL). Highly rough wellbores can easily cause vibration of the wellbore drilling tool, difficulty in mud carrying rock, and thus increase the mechanical resistance of the wellbore. The wellbore drilling tool can be equipped with stabilizers or reaming tools to smooth the wellbore wall and reduce the wellbore roughness. The wellbore clearance ratio refers to the ratio of the outer diameter of the wellbore drilling tool to the wellbore diameter, which can reflect the active space of the drill tool in the wellbore. If the critical clearance ratio (for example, 15% to 20%) is too small, it is easy to cause pipe sticking, and if it is too large, it may cause difficulty in drilling tool control. In the design of wellbore drilling tools, small-diameter drilling tools can be used in the diameter reduction section and stabilizers can be added in the diameter expansion section to ensure a reasonable clearance ratio.

[0031] The second drilling parameter data corresponding to the wellbore casing may include drilling parameter data such as wellbore curvature, wellbore roughness and wellbore clearance ratio calculated based on the structure of the wellbore casing. The wellbore curvature is the degree of curvature of the wellbore trajectory that the wellbore casing needs to pass through, which can be expressed as the maximum dogleg degree (° / 30m) or the minimum curvature radius (m). The curvature that conventional wellbore casing can pass through is usually ≤10° / 30m, and flexible casing (such as expansion casing) can adapt to higher curvatures. Wellbore roughness can characterize the effect of wellbore irregularities on the friction force of casing installation, which can be quantified by the equivalent friction coefficient or the standard deviation of wellbore diameter fluctuation. High roughness (such as keyways and spiral wellbores) will significantly increase the friction resistance of casing installation, and may even cause resistance or casing deformation. The wellbore clearance ratio can represent the ratio of the outer diameter of the wellbore casing to the wellbore diameter.

[0032] The first drilling parameter data and the second drilling parameter data are associated with each other. For example, the wellbore drilling tool corresponding to the first drilling parameter and the wellbore casing corresponding to the second drilling parameter correspond to the same wellbore. Therefore, the first drilling parameter data and the second drilling parameter data are parameter data corresponding to the wellbore drilling tool and the wellbore casing, respectively, calculated for the same wellbore.

[0033] S102: Calculating a first sticking risk factor of the through-hole drilling tool based on the first drilling parameter data, where the first sticking risk factor is used to indicate the possibility of the through-hole drilling tool getting stuck.

[0034] In some embodiments, a first stuck risk factor of the through-hole drilling tool may be calculated based on the first drilling parameter data, where the first stuck risk factor is used to indicate the possibility of the through-hole drilling tool getting stuck.

[0035] By using the first sticking risk factor to quantify the possibility of stuck drilling tools, a data foundation is laid for further quantifying the running capability of the drilling tools based on the first sticking risk factor.

[0036] After obtaining the first drilling parameter data for the through-hole drilling tool, a preset sticking risk calculation model can be used to calculate the first sticking risk factor for the through-hole drilling tool. The first sticking risk factor is a parameter that quantitatively assesses the resistance and sticking risk that the through-hole drilling tool may encounter in the wellbore. It can be used to indicate the possibility of the through-hole drilling tool becoming stuck. Drilling parameters such as wellbore curvature, wellbore wall roughness, and wellbore clearance ratio are closely related to the resistance and sticking risk that the through-hole drilling tool may encounter in irregular wellbores. For example, the greater the curvature (dogleg) of the wellbore, the greater the resistance to the through-hole drilling tool during passage. The rougher the wellbore wall, the greater the friction between the drill tool and the wellbore wall. The smaller the ratio of the wellbore diameter to the drill tool outer diameter, the greater the resistance to the drill tool during passage. The preset sticking risk calculation model can, for example, be an LSTM neural network trained based on historical drilling parameter data. Using downhole sensors (such as pressure while drilling and real-time torque / friction monitoring) and surface data (such as mud rheological parameters and mechanical penetration rate), the first drilling parameter input (such as wellbore curvature and roughness) can be dynamically updated. The weighting of different first drilling parameter data can be automatically adjusted based on the characteristics of the well section. For example, in a salt-gypsum layer, wellbore creep may cause a sharp decrease in the wellbore clearance ratio. In this case, the weighting of the wellbore clearance ratio can be automatically increased, thereby obtaining a more accurate first sticking risk factor.

[0037] S103: Calculating a second stuck risk factor of the wellbore casing according to the second drilling parameter data, where the second stuck risk factor is used to indicate the possibility of the wellbore casing being stuck.

[0038] In some embodiments, a second stuck risk factor of the wellbore casing may be calculated based on the second drilling parameter data, where the second stuck risk factor is used to indicate the possibility of the wellbore casing being stuck.

[0039] By using the second sticking risk factor to quantify the possibility of wellbore casing sticking, a data foundation is laid for further quantifying the wellbore casing running capability based on the second sticking risk factor.

[0040] After obtaining the second drilling parameter data of the wellbore casing, the second sticking risk factor of the wellbore casing can be calculated using a preset sticking risk calculation model. The second sticking risk factor is a parameter that quantitatively assesses the resistance and stuck risk that the casing may encounter in an irregular wellbore. It can be used to indicate the possibility of wellbore casing getting stuck. Drilling parameters such as wellbore curvature, wellbore wall roughness, and wellbore clearance ratio are closely related to the resistance and stuck risk that the casing may encounter in an irregular wellbore. For example, the greater the curvature (dogleg) of the wellbore, the greater the resistance to the casing passing through. The rougher the wellbore wall, the greater the friction between the casing and the wellbore wall. The smaller the ratio of the wellbore diameter to the outer diameter of the casing, the greater the resistance to the casing passing through. The preset sticking risk calculation model can be, for example, an LSTM neural network trained based on historical drilling parameter data. Similarly, the second drilling parameter data (such as wellbore curvature and roughness) can be dynamically updated through downhole sensors (such as pressure while drilling and real-time monitoring of torque / friction) and surface data (such as mud rheological parameters and mechanical penetration rate), and the weights of different second drilling parameter data can be automatically adjusted according to the characteristics of the well section, thereby obtaining a more accurate second obstruction risk factor.

[0041] S104: Calculating a first running capability index of the drilling tool according to the stiffness of the drilling tool and the first sticking risk factor.

[0042] In some embodiments, based on the stiffness of the well drilling tool and the first sticking risk factor, the following formula can be used to calculate the first running capability index of the well drilling tool:

[0043] A 通井钻具 =c 通井钻具 ×EI 通井钻具

[0044] Where, EI 通井钻具 is the stiffness of the well drilling tool, c 通井钻具 It is the first risk factor of drilling tools stuck in the well.

[0045] By using the first sticking risk factor as a correction factor for the stiffness of the ditch drilling tool, the stiffness and sticking risk are coupled. This allows for a more comprehensive and accurate assessment of the ditch drilling tool's running capacity by integrating its deformation and stress profile during running into the wellbore. This also facilitates a quantitative comparison of the running capacity of the ditch drilling tool and wellbore casing.

[0046] The stiffness of a through-hole drilling tool represents its ability to resist deformation when subjected to stress, and can be expressed using the elastic modulus or bending stiffness. The magnitude of the stiffness directly affects the tool's ability to pass through the wellbore. High-rigidity drilling tools tend to generate greater contact forces with the wellbore wall when passing through a high-curvature wellbore, increasing the risk of drill sticking. Low-rigidity drilling tools are more flexible and can adapt to the curvature and deformation of the wellbore, but may affect operational performance due to insufficient strength. The bending stiffness (EI) of the drilling tool can be calculated based on the elastic modulus (E) and geometric parameters (such as the moment of inertia I) of the through-hole drilling tool material. For combined through-hole drilling tools (such as drilling tools with centralizers), the stiffness characteristics of the overall structure can be considered. For example, the stiffness of each component of the combined through-hole drilling tool can be summed as the stiffness of the combined through-hole drilling tool.

[0047] Based on drilling parameters such as wellbore curvature, wellbore roughness, and wellbore clearance ratio, a first sticking risk factor for the wellbore can be calculated using a sticking risk calculation model. The first sticking risk factor is a positive number greater than 1 and can be used as a weight / correction factor for the wellbore stiffness. Based on the wellbore stiffness and the first sticking risk factor, a first running capability index for the wellbore can be calculated. The first running capability index indicates the wellbore's ability to withstand not only the external forces generated by wellbore bending and deformation, but also additional mechanical forces generated by drilling parameters such as wellbore curvature, wellbore roughness, and wellbore clearance ratio. Specifically, the first running capability index can be calculated by multiplying the wellbore stiffness and the first sticking risk factor. The first capability index converts the deformation and force applied to the wellbore during wellbore operation into a running capability index. A higher index indicates a greater running capability for the wellbore.

[0048] S105: Calculating a second running capability index of the wellbore casing according to the rigidity of the wellbore casing and the second sticking risk factor.

[0049] In some embodiments, based on the stiffness of the wellbore casing and the second sticking risk factor, the second running capability index of the wellbore casing can be calculated using the following formula:

[0050] A 套管 =c 套管 ×EI 套管

[0051] Where, EI 套管 is the stiffness of the wellbore casing, c 套管 It is the second risk factor of wellbore casing sticking.

[0052] By using the second sticking risk factor as a correction factor for wellbore casing stiffness, the stiffness and sticking risk are coupled. This allows for a more comprehensive and accurate measurement of the casing's runnability, taking into account its deformation and stress during running into the wellbore. This also facilitates a quantitative comparison of the runnability of wellbore drilling tools and wellbore casing. Runnability refers to the ability of tools (such as wellbore drilling tools and wellbore casing) to be successfully run into the wellbore without getting stuck.

[0053] The stiffness of the wellbore casing can indicate the ability of the wellbore casing to resist deformation when subjected to stress, and can also be expressed by the elastic modulus or bending stiffness. The magnitude of the stiffness directly affects the ability of the casing to pass through irregular wellbores. When passing through a high-curvature wellbore, high-rigidity casing is prone to generate a large contact force with the wellbore wall, increasing the risk of drill sticking. Low-rigidity casing has better flexibility and can adapt to the bending and deformation of the wellbore. Based on the elastic modulus (E) and geometric parameters (such as the moment of inertia I) of the casing material, the bending stiffness (EI) of the casing can be calculated. For combined casing (such as drilling tools with stabilizers), the stiffness characteristics of the overall structure can also be considered, which will not be repeated here.

[0054] Based on drilling parameters such as wellbore curvature, borehole roughness, and borehole clearance ratio, a second sticking risk factor for the wellbore casing can be calculated using a sticking risk calculation model. The second sticking risk factor is a positive number greater than 1 and can be used as a weight / correction factor for the stiffness of irregular wellbore casing. Based on the wellbore casing stiffness and the second sticking risk factor, a second running capability index (SCI) for the casing during wellbore passage can be calculated. The SCI indicates that the casing can withstand not only the external forces generated by borehole bending and deformation when running into a complex wellbore, but also the additional mechanical forces generated by drilling parameters such as borehole curvature, borehole roughness, and borehole clearance ratio. Specifically, the SCI can be calculated as the product of the wellbore casing stiffness and the second sticking risk factor. The SCI converts the deformation and stress conditions of the casing during running into the wellbore into a running capability index. A higher SCI indicates a greater running capability of the casing.

[0055] S106: Determine whether the well drilling tool matches the wellbore casing according to the first running capability index and the second running capability index.

[0056] In some embodiments, if the first running capability index is greater than or equal to the second running capability index, the drilling tool can be determined to be compatible with the wellbore casing. The first running capability index is a quantitative assessment of the drilling tool's ability to pass through the wellbore. It comprehensively considers complex wellbore geometric characteristics such as wellbore curvature, wellbore wall roughness, and wellbore clearance ratio, as well as the drilling tool's physical parameters (including outer diameter, length, flexibility, etc.). A larger first running capability index indicates a greater ability of the drilling tool to pass through the wellbore. The second running capability index is a quantitative assessment of the drilling tool's ability to pass through the casing in the wellbore. The second running capability index also comprehensively considers complex wellbore geometric characteristics such as wellbore curvature, wellbore wall roughness, and wellbore clearance ratio, as well as the physical parameters of the casing. If the first running capability index is greater than or equal to the second running capability index, it indicates that the drilling tool can be run through the casing in an irregular wellbore, meaning that the drilling tool meets the wellbore's passing requirements. The drilling tool can then be directly determined to be compatible with the wellbore casing, meaning that the drilling tool can be used as the drilling tool for the wellbore. Wherein, under the condition that the first running capability index is equal to the second running capability index, it can be considered that the well drilling tool and the wellbore casing have equivalent running capabilities.

[0057] In some embodiments, the structure of the through-hole drilling tool can be pre-configured, and then the first drilling parameter is obtained based on the pre-configured structure of the through-hole drilling tool. For example, the structure of the through-hole drilling tool can be configured according to the wellbore structure. Of course, the through-hole drilling tool can also have a default pre-configured structure. Therefore, if the first running capability index is less than the second running capability index, the structure of the through-hole drilling tool can be adjusted; drilling parameter data corresponding to the adjusted through-hole drilling tool can be obtained as new first drilling parameter data; based on the stiffness of the through-hole drilling tool and the first obstruction risk factor, the new first running capability index of the through-hole drilling tool is calculated; the above steps are iteratively performed until the first running capability index is greater than or equal to the second running capability index; and it is determined that the adjusted through-hole drilling tool matches the wellbore casing.

[0058] By adjusting the structure of the drilling tool, calculating the initial running capability index, and determining whether it matches the automated decision-making closed-loop control, proactive optimization of the wellbore stage can be achieved. In addition, low-cost fine-tuning of the drilling tool structure greatly improves dynamic adaptability in complex and irregular wellbore conditions.

[0059] If the first running capability index is less than the second running capability index, the drilling tool cannot be lowered into the wellbore. This indicates that the drilling tool's running capability is insufficient and requires adjustment and optimization. Specifically, the drilling tool's structure can be adjusted by, but is not limited to, the following methods: 1) optimizing the tool's physical parameters (e.g., reducing its outer diameter and increasing its flexibility); 2) adding auxiliary tools (e.g., stabilizers and friction-reducing joints) to reduce the risk of sticking; and 3) adjusting the drilling fluid's properties to improve wellbore cleaning.

[0060] The first obstruction risk factor and the first running capability index are related to the structure of the drilling tool. After adjusting the structure of the drilling tool, the new first obstruction risk factor and the new first running capability index can be recalculated and compared with the second running capability index again. This process can be iteratively executed until the new first running capability index is greater than or equal to the second running capability index. When the iteratively optimized drilling tool satisfies the condition that the first running capability index is greater than or equal to the second running capability index, it can be determined that the adjusted drilling tool is a drilling tool for irregular wellbores. At this point, the drilling tool has sufficient passing / running capability to effectively cope with the complex conditions of the wellbore and ensure the smooth progress of the drilling operation.

[0061] Figure 3 This is a flowchart of a method for constructing a card blocking risk calculation model provided in an embodiment of this specification. The specific implementation includes the following steps:

[0062] S301: Constructing a second casing running mechanical model for the irregular wellbore based on the first casing running mechanical model for the regular wellbore and the mechanical resistance model for the irregular wellbore.

[0063] In some embodiments, a regular wellbore can be defined as one with a regular circular cross-section, a wellbore wall roughness less than or equal to a preset roughness threshold, and a wellbore wall diameter variance less than or equal to a preset variance threshold. An irregular wellbore can be defined as one with an irregular circular cross-section, a wellbore wall roughness greater than a preset roughness threshold, or a wellbore wall diameter variance greater than a preset variance threshold. A regular wellbore has a regular circular or near-circular cross-section, a smooth wellbore wall, and a generally consistent diameter, meeting design expectations. During drilling operations, stable drill bit dimensions, optimized drilling parameters (speed, weight on bit, mud properties), and homogeneous and stable formations contribute to the formation of a regular wellbore. The wellbore wall diameter variance can be expressed as the variance of the wellbore wall diameter within a segment or multiple segments. Specifically, for a segment of wellbore wall containing multiple equally spaced sampling points, the wellbore wall diameter at each sampling point can be obtained. The wellbore wall diameter variance can be calculated for all sampling points. Similarly, for multiple wellbore wall segments, the wellbore wall diameter at each sampling point within each segment can be obtained. The diameter of the wellbore corresponding to all sampling points in each section of the wellbore can be calculated to obtain the diameter variance of the wellbore. Regular wellbores are easy to perform subsequent operations such as casing and cementing. Regular wellbores have good wellbore cleaning effects and can reduce the risk of drill sticking. The cross-section of an irregular wellbore deviates from the circle and exhibits irregular deformations (such as elliptical, candied haws-shaped, spiral, etc.), or the wellbore has defects such as severe erosion and keyways. For example, uneven formation stress can cause the wellbore to be squeezed, thereby forming an elliptical irregular wellbore; the spiral trajectory formed by drill string vibration or drill bit deviation during drilling operations can lead to the formation of a spiral irregular wellbore; downhole mud erosion or formation water absorption and expansion can lead to an irregular wellbore with abnormal local diameter; and drill string friction can form an irregular wellbore with grooves on the wellbore wall.

[0064] In some embodiments, the mechanical resistance model of the irregular wellbore can be used as a correction term of the first casing running mechanical model to construct the following second casing running mechanical model:

[0065]

[0066] Where, F is the axial force of the drill string; s is the well depth; EI is the bending stiffness of the drill string; k is the wellbore curvature; q is the drill string line weight; q is the well inclination angle; m0 is the axial friction coefficient; N0 is the contact distribution force; F m is a correction term constructed according to the mechanical resistance model of the irregular wellbore, representing the mechanical resistance encountered when the casing of the irregular wellbore is lowered.

[0067] By using the formula By constructing a mechanical model for second casing running, we can comprehensively and accurately simulate the dynamic casing running process in irregular wellbores by integrating factors such as the complex trajectory, wellbore roughness, and gap changes in complex irregular wellbores, and then accurately calculate the mechanical resistance during the casing running process in irregular wellbores.

[0068] The mechanical model of the first casing running in a regular wellbore can be described as Where F is the axial force of the drill string; s is the well depth; EI is the bending stiffness of the drill string; k is the wellbore curvature; q is the drill string linear weight; q is the well inclination angle; m0 is the axial friction coefficient; and N0 is the contact distribution force.

[0069] The first casing running mechanical model for a regular wellbore is mainly based on the following assumptions: 1) Regular wellbore trajectory: The wellbore is assumed to be a straight line or a simple curve, and the complex trajectories in the actual wellbore (such as high curvature and spiral trajectories) are ignored; 2) Smooth wellbore: The wellbore is assumed to be smooth, and the roughness and irregularities of the wellbore are ignored; 3) Uniform gap: The gap between the casing and the wellbore is assumed to be uniform, and the effect of gap changes on the running process is ignored; 4) Simple downhole environment: The effect of complex downhole conditions (such as wellbore collapse, cuttings accumulation, sand bridges, etc.) on casing running is ignored.

[0070] The above assumptions lead to the following problems in the application of regular wellbore models: 1) Underestimation of resistance: The mechanical resistance (such as friction resistance and contact force) in irregular wellbores cannot be accurately calculated; 2) Ignoring the risk of drill sticking: The risk of casing getting stuck in complex wellbores cannot be predicted. 3) Insufficient model accuracy: It is difficult to guide parameter optimization and risk control in actual operations. Irregular wellbores will significantly affect the casing lowering process. Specifically, curvature or spiral wellbores will increase the bending stress and friction resistance of the casing, the unevenness of the wellbore will increase the contact force and friction between the casing and the wellbore, and the change in wellbore diameter will cause uneven clearance between the casing and the wellbore, increasing the lowering resistance. These irregularities will not only increase the resistance during the casing lowering process, but may also cause the casing to get stuck, deformed, or even damaged, seriously affecting operational efficiency and safety.

[0071] Therefore, in order to more accurately describe the mechanical behavior of casing running in irregular wellbore, the mechanical resistance correction term can be added to the first casing running mechanical model of regular wellbore to construct the second casing running mechanical model of irregular wellbore. F m is a correction term constructed according to the mechanical resistance model, which represents the sum of the mechanical resistances caused / affected by various drilling parameters when the casing is run into the irregular wellbore.

[0072] S302: Solving the weight coefficients of the drilling parameters in the irregular wellbore mechanical resistance model and the sticking force of the regular wellbore.

[0073] In some embodiments, an orthogonal table can be generated based on the number of levels of the weight coefficient and the number of levels of the resistance force; a row in the orthogonal table represents a value of the weight coefficient and the resistance force; based on historical drilling parameter data, the second casing running mechanical model can be used to generate a hook load prediction result corresponding to each value of the weight coefficient and the resistance force; based on the difference between the hook load prediction result and the hook load actual measurement result, the value of the weight coefficient and the resistance force can be selected in the orthogonal table.

[0074] The values of the weight coefficient and the sticking force were determined through orthogonal experiments. On the one hand, the partial experiments covering all factor combinations significantly reduced the amount of calculation and helped improve the accuracy of the mechanical resistance model. On the other hand, through the inversion of historical drilling parameter data, the weight coefficient and the sticking force were made more in line with the actual working conditions.

[0075] In orthogonal experimental design, the number of levels refers to the number of values each parameter can take. The weight coefficient is a parameter used to adjust the mechanical model for running the second casing in irregular wellbores, accounting for factors such as wellbore trajectory, wellbore roughness, and gap variations. The first level represents the number of values the weight coefficient can take. For example, if the weight coefficient ranges from 0.8 to 1.2 and is divided into five levels, the first level is 5. The sticking force is the resistance encountered when running the casing in a regular wellbore, typically caused by factors such as wellbore friction and debris accumulation, and can be considered an unknown constant. The second level represents the number of values the sticking force can take. For example, if the sticking force ranges from 10kN to 50kN and is divided into five levels, the second level is 5. An orthogonal table is a table used in multifactor experimental design that can cover all parameter combinations with a minimum number of experiments. The corresponding orthogonal table can be generated based on the first level of the weight coefficient and the second level of the sticking force. Each row of an orthogonal table represents a test condition, including a value for the weight coefficient and a value for the blocking force. Each column corresponds to a parameter (such as the weight coefficient or blocking force), and the value in the column represents the level of that parameter. Depending on the number of parameters and levels, you can choose an appropriate orthogonal table type (such as L9, L16, etc.).

[0076] For example, for the weight coefficient a of wellbore curvature, the weight coefficient b of wellbore roughness, the weight coefficient g of wellbore clearance ratio and the blocking force F g0, an L16 orthogonal table can be designed. Assume that the borehole curvature weight coefficient includes four levels: 0.8, 0.9, 1.0, and 1.1; the borehole roughness correction coefficient includes four levels: 0.7, 0.8, 0.9, and 1.0; the borehole clearance ratio weight coefficient includes four levels: 0.9, 1.0, 1.1, and 1.2; and the sticking force includes four levels: 10kN, 20kN, 30kN, and 40kN. The L16 orthogonal table is an orthogonal table that applies to four parameters and four levels for each parameter. It has 16 rows (number of tests) and 4 columns (parameters). Fill the corresponding columns of the orthogonal table with the values of the borehole curvature weight coefficient, borehole roughness weight coefficient, borehole clearance ratio weight coefficient, and sticking force, as shown in Table 1.

[0077] Table 1

[0078]

[0079] Based on a designed orthogonal table and historical drilling parameter data from past wellbores, a second casing running mechanics model for irregular wellbores can be used to generate hook load predictions. The historical drilling parameter data for past wellbores can include historical operating values of drilling parameters such as weight on bit, rotational speed, drilling fluid flow rate, and wellbore trajectory. For each row in the orthogonal table (i.e., each test condition), the weight coefficient and sticking force values can be substituted into the mechanical resistance correction term of the second casing running mechanics model for irregular wellbores. The historical drilling parameter data is input into the second casing running mechanics model for irregular wellbores, and the predicted hook load value for the current test condition is output. The predicted hook load results for each test condition can be recorded, and the optimal values for the weight coefficient and sticking force can be determined based on the difference between the predicted hook load results and the measured hook load results. Specifically, for each test condition, the difference (e.g., absolute error or mean square error) between the predicted hook load results and the measured results can be calculated. The differences between the different test conditions are compared to identify the test condition with the smallest difference. The weight coefficient and sticking force values corresponding to this test condition are then considered the optimal values. The second casing running mechanics model for irregular wellbores can be rerun using the optimal values to verify the accuracy of the hook load predictions. If the predictions agree well with the measured results, the weight coefficients and sticking force values are determined; otherwise, further parameter adjustments are made. By generating an orthogonal table, the effects of weight coefficients for drilling parameters such as wellbore curvature, wellbore roughness, and borehole clearance ratio, as well as the weight coefficient for sticking force, on the casing running process can be efficiently evaluated. This orthogonal testing not only reduces the number of tests but also improves the accuracy and reliability of the model.

[0080] S303: Constructing a blocking risk calculation model based on the weight coefficient and the blocking force.

[0081] In some embodiments, the weight coefficient and the sticking force may be substituted into the mechanical resistance model of the irregular wellbore to obtain the following sticking risk calculation model:

[0082]

[0083] Where k is the wellbore curvature; a Irr is the value of the weight coefficient of the wellbore curvature; d is the roughness of the wellbore wall; b Irr is the weight coefficient of the wellbore roughness; x is the wellbore clearance ratio; g Irr is the value of the weight coefficient of the wellbore clearance ratio.

[0084] Considering the mapping relationship between wellbore curvature and mechanical resistance, it can be expressed as F(k)=F g0 The mapping relationship between (1+ak), well wall roughness and mechanical resistance can be expressed as F(d)=F g0 (1+bd) and the mapping relationship between the borehole clearance ratio and the mechanical resistance can be expressed as F(x)=F g0 e -gx , the mechanical resistance model of irregular wellbore can be further expressed as:

[0085] F m =F g0 (2+ak+bd+e -gx );

[0086] Considering the blocking force F of the regular wellbore g0 It can be a constant, and a jam risk factor can be introduced. The relationship between the jam risk factor and mechanical resistance can be defined as:

[0087] F m =kc;

[0088] Where k is a constant. The weight coefficient a of the wellbore curvature obtained can be Irr , weight coefficient b of wellbore roughness Irr , weight coefficient g of wellbore clearance ratio Irr and the blocking force F of the regular wellbore g0 Substitute F m = kc, and obtain the blocking risk calculation model At this time, k=3F g0 .

[0089] In some embodiments, the drilling parameter values of the well drilling tool can be substituted into the blocking risk calculation model Then the first sticking risk factor is obtained. Similarly, the drilling parameter values of the wellbore casing can be substituted into the sticking risk calculation model The second blocking risk factor is obtained.

[0090] In some embodiments, a mapping relationship between drilling parameters and mechanical resistance can be obtained based on a finite element model of casing running in an irregular wellbore. Based on the mapping relationship between drilling parameters and mechanical resistance, the following mechanical resistance model for the irregular wellbore can be constructed using the plowing traction resistance theory:

[0091] F m =F(k)+F(d)+F(x);

[0092] Where F(k)=F g0 (1+ak) represents the mapping relationship between wellbore curvature and mechanical resistance; F g0 is the blocking force of a regular wellbore; k is the wellbore curvature; a is the weight coefficient of the wellbore curvature; F(d) = F g0 (1+bd) represents the mapping relationship between wellbore roughness and mechanical resistance; d is the wellbore roughness; b is the weight coefficient of wellbore roughness; F(x)=F g0 e -gx It represents the mapping relationship between the borehole clearance ratio and the mechanical resistance; x is the borehole clearance ratio; g is the weight coefficient of the borehole clearance ratio.

[0093] Based on the plowing traction resistance theory, the total mechanical resistance encountered during casing installation in irregular wellbores can be considered as the sum of all static mechanical resistances and all dynamic mechanical resistances caused by various drilling parameters. Furthermore, the mapping relationship between different drilling parameters and mechanical resistances can be integrated to more comprehensively and accurately describe the mechanical resistance encountered during casing installation in irregular wellbores.

[0094] A localized casing finite element model of a historical wellbore can be constructed based on historical drilling parameter data. Wellbore geometry can exhibit irregularities (e.g., elliptical, spiral, or partially tapered) due to factors such as geological conditions and drilling techniques. Therefore, it is necessary to accurately restore the wellbore's three-dimensional shape based on well logging data or wellbore imaging. Specifically, the localized casing finite element model of a historical wellbore can be modeled based on its actual dimensions and structure to ensure that the model accurately reflects the mechanical properties of the casing.

[0095] Once a localized finite element model of the historical wellbore casing run is established, the material properties of the casing, wellbore, and drilling fluid can be defined. The casing material properties include elastic modulus, Poisson's ratio, and density, which affect the casing's stiffness and deformation behavior. The wellbore material properties can be defined based on the formation lithology; for example, the mechanical properties of sandstone, mudstone, or limestone vary significantly and require separate definitions. Furthermore, the rheological properties of the drilling fluid, such as density and viscosity, can be incorporated into the model, as the drilling fluid not only creates buoyancy on the casing but also influences its motion through viscous drag.

[0096] The contact behavior between the casing and the wellbore wall is the primary cause of mechanical drag, necessitating precise contact conditions. A frictional contact model can be used to define the friction coefficient between the casing and the wellbore wall. The value of the friction coefficient depends on the roughness of the wellbore wall, the lubricating properties of the drilling fluid, and the surface characteristics of the casing. Furthermore, the contact type (such as hard or soft contact) can be considered to simulate the actual interaction between the casing and the wellbore wall.

[0097] Appropriate boundary conditions and loads can be applied to the localized casing running finite element model of the historical wellbore to ensure accurate simulation results. Specifically, the wellbore boundaries can be set as fixed constraints to simulate the support provided by the formation. Axial forces (such as lowering or lifting forces) can be applied to the top of the casing to simulate the actual running operation. In addition, drilling fluid pressure and gravity loads can be applied to account for buoyancy and lateral pressure on the casing and simulate the casing's deadweight.

[0098] Fine meshing of the wellbore and casing can be performed, especially in contact areas and stress concentration regions, to improve calculation accuracy. After meshing, finite element software (such as ANSYS and Abaqus) can be used for numerical solution to obtain the stress distribution, deformation, and contact force distribution of the casing. This allows the mapping relationship between each drilling parameter and mechanical resistance to be obtained. Figure 4 The mapping relationship between the borehole clearance ratio and the mechanical resistance is shown, where the change in casing size is used to represent the change in borehole clearance. Figure 5 The mapping relationship between wellbore curvature and mechanical resistance is shown. Figure 6 The mapping relationship between wellbore roughness and mechanical resistance is shown, where the wellbore roughness is characterized by the wellbore change rate.

[0099] According to the mapping relationship between each drilling parameter and the mechanical resistance, the mechanical resistance caused / affected by each drilling parameter can be expressed as the product of the sticking force of the regular wellbore and the correction term.

[0100] For example, for the wellbore curvature, its mapping relationship with the mechanical resistance can be expressed as:

[0101] F(k)=F g0 (1+ak);

[0102] Where, F g0 is the sticking force of a regular wellbore, k is the wellbore curvature, and a is the weight coefficient of the wellbore curvature.

[0103] For example, for the well wall roughness, the mapping relationship between it and mechanical resistance can be expressed as:

[0104] F(d)=F g0 (1+bd);

[0105] Where, F g0 is the sticking force of a regular wellbore, d is the roughness of the wellbore wall, and b is the weight coefficient of the wellbore wall roughness.

[0106] For example, for the well wall roughness, the mapping relationship between it and mechanical resistance can be expressed as:

[0107] F(x)=F g0 e -gx ;

[0108] Where, F g0 is the sticking force of a regular wellbore, x is the wellbore clearance ratio, and g is the weight coefficient of the wellbore clearance ratio.

[0109] The plowing traction resistance theory describes the resistance exerted by the soil on the plow during tillage. Its core principle is to decompose traction resistance into two components: static resistance and dynamic resistance. Static resistance can be composed of soil shear resistance, soil lift resistance, and soil friction resistance. Soil shear resistance arises from the shearing action of the plow blades when they cut into the soil; soil lift resistance is related to the weight of the soil turned over by the plow blades; and soil friction resistance is generated by the friction between the soil and the plow blade surface. Dynamic resistance can be composed of soil crushing resistance and inertial resistance. Soil crushing resistance is the resistance exerted by the plow blades when breaking up soil clumps; and inertial resistance is the inertial force of the soil when it is accelerated by the plow blades.

[0110] Based on the plowing and traction resistance theory, the total mechanical resistance encountered during casing installation in irregular wellbores can also be considered the sum of all static and dynamic mechanical resistances caused by various drilling parameters. For example, the mechanical resistance encountered during casing installation in irregular wellbores is primarily related to three drilling parameters: wellbore curvature, wellbore roughness, and borehole clearance ratio. Therefore, the total mechanical resistance encountered during casing installation in irregular wellbores can be considered the sum of the mechanical resistances caused by these three drilling parameters. The mapping relationship between these three drilling parameters and mechanical resistance can be integrated to construct a mechanical resistance model for irregular wellbores.

[0111] In some embodiments, mutual information values among multiple drilling parameters may be calculated based on historical drilling parameter data; and a master drilling parameter may be selected based on the mutual information values among the multiple drilling parameters.

[0112] By using mutual information to quantify the correlation between multiple drilling parameters, multiple master drilling parameters with the greatest impact on the drilling process can be selected, greatly reducing the interference of irrelevant factors in the subsequent calculation of the sticking risk factor and the running capability index.

[0113] Mutual information can be used to measure the correlation between two random variables. In drilling parameter analysis, the mutual information value can reflect the dependency between different drilling parameters. Specifically, for two drilling parameters X and Y, their mutual information value I(X; Y) can be defined as:

[0114]

[0115] Where p(x, y) represents the joint probability distribution of drilling parameters X and Y, and p(x) and p(y) represent the marginal probability distributions of drilling parameters X and Y, respectively. Based on historical drilling parameter data, we can estimate the marginal probability distribution of each parameter and the joint probability distribution of parameter pairs. Based on the mutual information formula, we can calculate the mutual information value between each pair of drilling parameters and obtain the mutual information matrix. Figure 7 A schematic diagram of the mutual information matrix between drilling parameters is shown.

[0116] Based on the calculated mutual information values, the master drilling parameters with the greatest impact on the drilling process can be selected. A high mutual information value indicates a strong correlation between the two parameters, significantly impacting the drilling process. A low mutual information value indicates a strong independence between the two parameters, with a smaller impact on the drilling process. Drilling parameters can be ranked based on their mutual information values to identify those with strong correlations with other parameters. For example, a mutual information threshold can be set to select drilling parameters with mutual information values greater than or equal to the preset threshold as the master drilling parameters. These parameters typically have a significant impact on drilling efficiency, safety, or cost.

[0117] In some embodiments, a casing running characteristic scatter plot can be generated for multiple drilling parameters based on historical drilling parameter data. As a basic statistical chart, a scatter plot's core function is to intuitively and clearly reveal the underlying relationship between two variables. Specifically, a scatter plot can be created by positioning two drilling parameters on the X-axis and Y-axis, respectively, so that each data point represents the corresponding relationship between the two drilling parameters at a specific observed value. The distribution of points in a casing running characteristic scatter plot can reveal rich information about the relationship between the two drilling parameters. If the distribution of points exhibits a clear linear trend, this generally indicates a linear relationship between the two drilling parameters—that is, changes in one drilling parameter proportionally predict changes in the other. When the distribution of points in a casing running characteristic scatter plot no longer follows a linear trend but instead exhibits a curved, U-shaped, inverted U-shaped, or other more complex shape, it can be inferred that a nonlinear relationship exists between the two drilling parameters. This nonlinear relationship means that changes in one drilling parameter cannot be simply predicted by a linear function of the other, but requires a more complex mathematical model to describe it. In addition, the identification of this nonlinear relationship is of great significance for a deeper understanding of the drilling process, optimizing drilling strategies, and improving drilling efficiency. Figure 8 A scatter plot of the casing running characteristics between drilling parameters is shown. If multiple drilling parameters are nonlinearly correlated, the mutual information value between them can be calculated. Based on this mutual information value, the master drilling parameter can be selected to construct a mechanical resistance model for irregular wellbores.

[0118] In some embodiments, based on a sliding time window, the mutual information value between multiple drilling parameters can be calculated; according to the change rate of the mutual information values between the multiple drilling parameters, the preset mutual information threshold can be adjusted; based on the adjusted mutual information threshold, the main control drilling parameter can be selected.

[0119] Traditional mutual information analysis is typically based on static historical datasets, assuming that the statistical properties of drilling parameters remain constant throughout the operation. However, the actual drilling process is significantly time-varying and nonlinear. For example, the correlation between parameters such as weight on bit and torque can change suddenly as the drill bit traverses different rock formations (such as sandstone and shale). Bit blunting weakens the coupling relationship between ROP and rotational speed as drilling depth increases. Operations such as tripping and drilling fluid circulation can introduce transient interference, temporarily invalidating parameter correlations.

[0120] To address this issue, a dynamic mutual information algorithm can be introduced. This algorithm uses a sliding time window to update the mutual information matrix between parameters in real time. Specifically, the real-time acquired drilling parameters can be divided into continuous time windows based on fixed durations (e.g., 5 minutes) or event triggers (e.g., encountering a new formation). Within each window, the joint probability distribution of parameter pairs is calculated using kernel density estimation or maximum entropy models. This allows for dynamic updating of the mutual information value, generating a time-varying mutual information matrix.

[0121] Based on the time-varying mutual information matrix, the mutual information threshold can be dynamically calibrated using an exponentially weighted moving average method. Specifically, when the mutual information of a parameter pair is greater than or equal to the mutual information threshold, it is determined to be the primary control parameter pair for the current window; otherwise, it is downgraded to a secondary parameter. Based on the updated mutual information matrix and threshold, a list of primary control parameters is output in real time. If the rate of change of the mutual information of a parameter exceeds a preset tolerance (e.g., 10%), an abnormality warning is triggered and a control strategy is recommended (e.g., "a sudden increase in the drilling pressure-torque mutual information suggests reducing the rotational speed to suppress stick-slip vibration").

[0122] Traditional fixed thresholds (e.g., mutual information > 0.7) can miss key parameters when drilling into hard formations. Dynamic thresholds, however, automatically tighten or loosen the criteria as lithology changes. Furthermore, a sliding window reduces computational load, ensuring real-time operation on edge devices (e.g., downhole sensors), significantly improving operational efficiency and safety in complex formations.

[0123] In some embodiments, a mechanical resistance model for an irregular wellbore can be constructed based on the master drilling parameters. The master drilling parameters may include wellbore curvature, wellbore wall roughness, and wellbore clearance ratio. The master drilling parameters can be used to perform finite element simulation on the irregular wellbore to obtain a mapping relationship between the drilling parameters and the mechanical resistance. Based on the mapping relationship between the master drilling parameters and the mechanical resistance, the plowing traction resistance theory can be used to construct a mechanical resistance model for the irregular wellbore: F m =F(k)+F(d)+F(x), where F(k)=F g0 (1+ak) represents the mapping relationship between wellbore curvature and mechanical resistance; F g0 is the blocking force of a regular wellbore; k is the wellbore curvature; a is the weight coefficient of the wellbore curvature; F(d) = F g0 (1+bd) represents the mapping relationship between wellbore roughness and mechanical resistance; d is the wellbore roughness; b is the weight coefficient of wellbore roughness; F(x)=F g0 e -gx It represents the mapping relationship between the borehole clearance ratio and the mechanical resistance; x is the borehole clearance ratio; g is the weight coefficient of the borehole clearance ratio.

[0124] In some embodiments, if the first running capability index is less than the second running capability index, a genetic algorithm may be used to calculate Pareto front solutions corresponding to various well drilling tool structures, and the structure of the well drilling tool may be adjusted based on the Pareto front solutions.

[0125] By using genetic algorithms to calculate the Pareto front solutions corresponding to various well drilling tool structures, on the one hand, it can replace manual trial and error and shorten the design cycle of well drilling tools. On the other hand, it can avoid falling into local optimality and improve the running capacity of well drilling tools.

[0126] In traditional methods, single-objective optimization (i.e., optimizing only the first entry capability index) may lead to a deterioration in drilling rate or cost. By introducing a genetic algorithm, multiple objectives can be considered simultaneously in the iterative optimization of through-hole drilling tools, thereby avoiding a deterioration in drilling rate or cost. For example, 1) technical objective: maximizing the first entry capability index; 2) efficiency objective: increasing drilling rate; 3) economic objective: reducing operating costs (such as drill tool wear and time costs). Multiple sets of drilling tool parameter combinations (such as stiffness, length, and number of short sections) can be randomly generated, and based on the mapping relationship between different drilling tool parameters and drilling tool parameter combinations, the first drilling parameter data corresponding to different drilling tool parameter combinations can be obtained. Parameters such as the first entry capability index, drilling rate, and cost are calculated for each set of parameters and normalized into a multi-objective fitness function. In each iteration, the Pareto front solution (non-dominated solution) can be retained, and through continuous crossover and mutation—that is, continuously generating a new generation of parameter combinations.

[0127] The method for determining a through-hole drilling tool provided in the embodiments of this specification can obtain first drilling parameter data corresponding to the through-hole drilling tool and second drilling parameter data corresponding to the wellbore casing; calculate a first blocking risk factor of the through-hole drilling tool based on the first drilling parameter data, and the first blocking risk factor is used to indicate the possibility of the through-hole drilling tool being stuck; calculate a second blocking risk factor of the wellbore casing based on the second drilling parameter data, and the second blocking risk factor is used to indicate the possibility of the wellbore casing being stuck; calculate a first running-in capability index of the through-hole drilling tool based on the stiffness of the through-hole drilling tool and the first blocking risk factor; calculate a second running-in capability index of the wellbore casing based on the stiffness of the wellbore casing and the second blocking risk factor; and determine whether the through-hole drilling tool matches the wellbore casing based on the first running-in capability index and the second running-in capability index. Compared to existing methods, the embodiments of this specification can calculate the likelihood of sticking for the ditch drill tool and wellbore casing based on their respective drilling parameter data. This allows for a more comprehensive and accurate assessment of the runnability of the ditch drill tool and wellbore casing, combining the deformation and sticking risk during wellbore entry. Furthermore, by comparing the runnability of the ditch drill tool and wellbore casing, the compatibility of the ditch drill tool and wellbore casing can be quickly, scientifically, and accurately determined.

[0128] Based on the above-mentioned method for determining a well drilling tool, this specification also proposes an embodiment of a well drilling tool determination device. Figure 9 As shown, the well drilling tool determination device 900 may specifically include the following modules:

[0129] The acquisition module 901 may be used to acquire first drilling parameter data corresponding to the wellbore drilling tool and second drilling parameter data corresponding to the wellbore casing.

[0130] The first calculation module 902 may be configured to calculate a first sticking risk factor of the through-hole drilling tool based on the first drilling parameter data, where the first sticking risk factor is used to indicate a possibility of the through-hole drilling tool being stuck.

[0131] The second calculation module 903 may be used to calculate a second stuck risk factor of the wellbore casing according to the second drilling parameter data, where the second stuck risk factor is used to indicate the possibility of the wellbore casing being stuck.

[0132] The third calculation module 904 may be configured to calculate a first running capability index of the drilling tool according to the stiffness of the drilling tool and the first sticking risk factor.

[0133] The fourth calculation module 905 may be configured to calculate a second running capability index of the wellbore casing according to the stiffness of the wellbore casing and the second sticking risk factor.

[0134] The determination module 906 may be configured to determine whether the well drilling tool matches the wellbore casing according to the first running capability index and the second running capability index.

[0135] In some embodiments, the above-mentioned acquisition module 901 can be specifically used to construct a second casing lowering mechanical model for an irregular wellbore based on the first casing lowering mechanical model for a regular wellbore and the mechanical resistance model for an irregular wellbore; the regular wellbore represents a wellbore with a regular circular cross-section, a wellbore wall roughness less than or equal to a preset roughness threshold, and a wellbore wall diameter variance less than or equal to a preset variance threshold; the irregular wellbore represents a wellbore with an irregular circular cross-section, or a wellbore wall roughness greater than a preset roughness threshold, or a wellbore wall diameter variance greater than a preset variance threshold; solve the weight coefficients of the drilling parameters in the mechanical resistance model for the irregular wellbore and the sticking force of the regular wellbore; and construct a sticking risk calculation model based on the weight coefficients and the sticking force.

[0136] In some embodiments, the acquisition module 901 may be further configured to use the mechanical resistance model of the irregular wellbore as a correction term of the first casing running mechanical model to construct the following second casing running mechanical model:

[0137]

[0138] Where, F is the axial force of the drill string; s is the well depth; EI is the bending stiffness of the drill string; k is the wellbore curvature; q is the drill string line weight; q is the well inclination angle; m0 is the axial friction coefficient; N0 is the contact distribution force; F m is a correction term constructed according to the mechanical resistance model of the irregular wellbore, representing the mechanical resistance encountered when the casing of the irregular wellbore is lowered.

[0139] In some embodiments, the acquisition module 901 can also be used to generate an orthogonal table based on the horizontal number of the weight coefficient and the horizontal number of the resistance force; a row in the orthogonal table represents a value of the weight coefficient and the resistance force; based on historical drilling parameter data, the second casing running mechanical model is used to generate a hook load prediction result corresponding to each value of the weight coefficient and the resistance force; based on the difference between the hook load prediction result and the hook load actual measurement result, the value of the weight coefficient and the resistance force are selected from the orthogonal table.

[0140] In some embodiments, the acquisition module 901 may be further configured to substitute the weight coefficient and the sticking force into the mechanical resistance model of the irregular wellbore to obtain the following sticking risk calculation model:

[0141]

[0142] Where k is the wellbore curvature; a Irr is the value of the weight coefficient of the wellbore curvature; d is the roughness of the wellbore wall; b Irr is the weight coefficient of the wellbore roughness; x is the wellbore clearance ratio; g Irr is the value of the weight coefficient of the wellbore clearance ratio.

[0143] In some embodiments, the acquisition module 901 may be further configured to acquire a mapping relationship between drilling parameters and mechanical resistance based on a finite element model of casing running in an irregular wellbore. Based on the mapping relationship between drilling parameters and mechanical resistance, the plowing traction resistance theory is used to construct the following mechanical resistance model for the irregular wellbore:

[0144] F m =F(k)+F(d)+F(x);

[0145] Where F(k)=F g0 (1+ak) represents the mapping relationship between wellbore curvature and mechanical resistance; F g0 is the sticking force of a regular wellbore; k is the wellbore curvature; a is the weight coefficient of the wellbore curvature; F(d) = F g0(1+bd) represents the mapping relationship between wellbore roughness and mechanical resistance; d is the wellbore roughness; b is the weight coefficient of wellbore roughness; F(x)=F g0 e -gx It represents the mapping relationship between the borehole clearance ratio and the mechanical resistance; x is the borehole clearance ratio; g is the weight coefficient of the borehole clearance ratio.

[0146] In some embodiments, the determination module 906 may be specifically configured to determine that the wellbore drilling tool matches the wellbore casing if the first running capability index is greater than or equal to the second running capability index.

[0147] In some embodiments, the above-mentioned determination module 906 can also be specifically used to adjust the structure of the well drilling tool if the first running capability index is less than the second running capability index; obtain drilling parameter data corresponding to the adjusted well drilling tool as new first drilling parameter data; calculate the new first running capability index of the well drilling tool based on the stiffness of the well drilling tool and the first blocking risk factor; iteratively perform the above steps until the first running capability index is greater than or equal to the second running capability index; and determine that the adjusted well drilling tool matches the wellbore casing.

[0148] The above-mentioned through-hole drilling tool determination device provided in the embodiment of this specification can obtain first drilling parameter data corresponding to the through-hole drilling tool and second drilling parameter data corresponding to the wellbore casing; calculate the first blocking risk factor of the through-hole drilling tool based on the first drilling parameter data, and the first blocking risk factor is used to indicate the possibility of the through-hole drilling tool being stuck; calculate the second blocking risk factor of the wellbore casing based on the second drilling parameter data, and the second blocking risk factor is used to indicate the possibility of the wellbore casing being stuck; calculate the first running-in capability index of the through-hole drilling tool based on the stiffness of the through-hole drilling tool and the first blocking risk factor; calculate the second running-in capability index of the wellbore casing based on the stiffness of the wellbore casing and the second blocking risk factor; determine whether the through-hole drilling tool and the wellbore casing match based on the first running-in capability index and the second running-in capability index. Compared to existing methods, the embodiments of this specification can calculate the likelihood of sticking for the ditch drill tool and wellbore casing based on their respective drilling parameter data. This allows for a more comprehensive and accurate assessment of the runnability of the ditch drill tool and wellbore casing, combining the deformation and sticking risk during wellbore entry. Furthermore, by comparing the runnability of the ditch drill tool and wellbore casing, the compatibility of the ditch drill tool and wellbore casing can be quickly, scientifically, and accurately determined.

[0149] It should be noted that the units, devices or modules described in the above embodiments can be implemented by computer chips or entities, or by products with certain functions. For the convenience of description, the above devices are described in terms of functions and are divided into various modules and described separately. Of course, when implementing this specification, the functions of each module can be implemented in the same or multiple software and / or hardware, or the module that implements the same function can be implemented by a combination of multiple sub-modules or sub-units. The device embodiments described above are merely schematic. For example, the division of the units is only a logical function division. In actual implementation, there may be other division methods, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the mutual coupling or direct coupling or communication connection shown or discussed can be through some interfaces, indirect coupling or communication connection of devices or units, which can be electrical, mechanical or other forms.

[0150] An embodiment of the present specification also provides a computer device for a method for determining a through-hole drilling tool, comprising a processor and a memory for storing instructions executable by the processor, wherein the processor can perform the following steps according to the instructions when implemented: obtaining first drilling parameter data corresponding to the through-hole drilling tool and second drilling parameter data corresponding to the wellbore casing; calculating a first blocking risk factor of the through-hole drilling tool according to the first drilling parameter data, wherein the first blocking risk factor is used to indicate the possibility of blocking of the through-hole drilling tool; calculating a second blocking risk factor of the wellbore casing according to the second drilling parameter data, wherein the second blocking risk factor is used to indicate the possibility of blocking of the wellbore casing; calculating a first running capability index of the through-hole drilling tool according to the stiffness of the through-hole drilling tool and the first blocking risk factor; calculating a second running capability index of the wellbore casing according to the stiffness of the wellbore casing and the second blocking risk factor; and determining whether the through-hole drilling tool matches the wellbore casing according to the first running capability index and the second running capability index.

[0151] In order to complete the above instructions more accurately, refer to Figure 10 As shown, the embodiment of this specification also provides another specific computer device 1000, wherein the computer device 1000 includes a network communication port 1001, a processor 1002 and a memory 1003, and the above structures are connected through internal cables so that each structure can perform specific data interaction.

[0152] The processor 1002 can be specifically used to obtain first drilling parameter data corresponding to the through-hole drilling tool and second drilling parameter data corresponding to the wellbore casing; calculate a first blocking risk factor of the through-hole drilling tool based on the first drilling parameter data, and the first blocking risk factor is used to indicate the possibility of the through-hole drilling tool being stuck; calculate a second blocking risk factor of the wellbore casing based on the second drilling parameter data, and the second blocking risk factor is used to indicate the possibility of the wellbore casing being stuck; calculate a first running capability index of the through-hole drilling tool based on the stiffness of the through-hole drilling tool and the first blocking risk factor; calculate a second running capability index of the wellbore casing based on the stiffness of the wellbore casing and the second blocking risk factor; and determine whether the through-hole drilling tool and the wellbore casing match based on the first running capability index and the second running capability index.

[0153] The memory 1003 may be specifically used to store corresponding instruction programs.

[0154] In this embodiment, the network communication port 1001 can be a virtual port that is bound to different communication protocols, thereby being capable of sending or receiving different data. For example, the network communication port can be a port responsible for web data communication, a port responsible for FTP data communication, or a port responsible for email data communication. Furthermore, the network communication port can also be a physical communication interface or communication chip. For example, it can be a wireless mobile network communication chip, such as GSM or CDMA; it can also be a Wi-Fi chip; or it can be a Bluetooth chip.

[0155] In this embodiment, the processor 1002 may be implemented in any suitable manner. For example, the processor may take the form of a microprocessor or a processor and a computer-readable medium storing computer-readable program code (e.g., software or firmware) executable by the (micro)processor, a logic gate, a switch, an application-specific integrated circuit (ASIC), a programmable logic controller, an embedded microcontroller, etc. This specification is not intended to limit this.

[0156] In this embodiment, the memory 1003 includes volatile memory and non-volatile memory. The memory 1003 can include multiple levels. In digital systems, anything that can store binary data can be considered a memory. In integrated circuits, a circuit with a storage function that does not have a physical form is also called a memory, such as RAM and FIFO. In systems, a physical storage device is also called a memory, such as a memory stick or TF card.

[0157] It will be understood by those skilled in the art that embodiments of the present invention may be provided as methods, systems, or computer program products. Thus, the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment, or an embodiment combining software and hardware. Furthermore, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to magnetic disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0158] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowcharts and / or block diagrams, as well as combinations of processes and / or blocks in the flowcharts and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowcharts and / or block diagrams. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0159] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0160] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operational steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0161] The specific embodiments described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific embodiment of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for determining a well drilling tool, characterized in that: The method comprises: Acquiring first drilling parameter data corresponding to the well drilling tool and second drilling parameter data corresponding to the wellbore casing; Calculating a first stuck risk factor of the through-hole drilling tool based on the first drilling parameter data, wherein the first stuck risk factor is used to indicate the possibility of the through-hole drilling tool being stuck; Calculating a second stuck risk factor for the wellbore casing based on the second drilling parameter data, wherein the second stuck risk factor is used to indicate the possibility of the wellbore casing being stuck; Calculating the first running capability index of the drilling tool based on the stiffness of the drilling tool and the first sticking risk factor; Calculating a second running capability index of the wellbore casing based on the wellbore casing's stiffness and the second sticking risk factor; Whether the well drilling tool matches the wellbore casing is determined according to the first running capability index and the second running capability index.

2. The method according to claim 1, characterized in that The method further comprises: Based on the first casing running mechanical model for a regular wellbore and the mechanical resistance model for an irregular wellbore, a second casing running mechanical model for an irregular wellbore is constructed; the regular wellbore refers to a wellbore with a regular circular cross-section, a wellbore wall roughness less than or equal to a preset roughness threshold, and a wellbore wall diameter variance less than or equal to a preset variance threshold; the irregular wellbore refers to a wellbore with an irregular circular cross-section, or a wellbore wall roughness greater than a preset roughness threshold, or a wellbore wall diameter variance greater than a preset variance threshold; Solving the weight coefficients of drilling parameters in the irregular wellbore mechanical resistance model and the sticking force of the regular wellbore; Constructing a blocking risk calculation model based on the weight coefficient and the blocking force; Calculating a first stuck risk factor of the drilling tool according to the first drilling parameter data includes: Calculating the first stuck risk factor using the stuck risk calculation model according to the first drilling parameter data; Calculating the second stuck risk factor of the wellbore casing according to the second drilling parameter data includes: The second stuck risk factor is calculated based on the second drilling parameter data using the stuck risk calculation model.

3. The method according to claim 2, characterized in that The method of constructing a second casing running mechanical model for an irregular wellbore based on the first casing running mechanical model for a regular wellbore and the mechanical resistance model for an irregular wellbore comprises: The mechanical resistance model of the irregular wellbore is used as a correction term of the first casing running mechanical model to construct the following second casing running mechanical model: Where, F is the axial force of the drill string; s is the well depth; EI is the bending stiffness of the drill string; κ is the wellbore curvature; q is the drill string linear weight; q is the well inclination; m0 is the axial friction coefficient; N0 is the contact distribution force; F m is a correction term constructed according to the mechanical resistance model of the irregular wellbore, representing the mechanical resistance encountered when the casing of the irregular wellbore is lowered.

4. The method according to claim 2, characterized in that The method of solving the weight coefficients of the drilling parameters in the irregular wellbore mechanical resistance model and the sticking force of the regular wellbore includes: An orthogonal table is generated according to the number of levels of the weight coefficient and the number of levels of the blocking force; a row in the orthogonal table represents a value of the weight coefficient and the blocking force; Based on historical drilling parameter data, using the second casing running mechanics model, a hook load prediction result corresponding to each value of the weight coefficient and the sticking force is generated; According to the difference between the hook load prediction result and the hook load actual measurement result, the value of the weight coefficient and the value of the blocking force are selected in the orthogonal table.

5. The method according to claim 2, characterized in that: The step of constructing a blocking risk calculation model based on the weight coefficient and the blocking force includes: Substituting the weight coefficient and the sticking force into the mechanical resistance model of the irregular wellbore, the following sticking risk calculation model is obtained: Where, κ is the wellbore curvature; a Irr is the value of the weight coefficient of the wellbore curvature; d is the roughness of the wellbore wall; b Irr is the weight coefficient of the wellbore roughness; x is the wellbore clearance ratio; g Irr is the value of the weight coefficient of the wellbore clearance ratio.

6. The method according to claim 2, characterized in that: The method further comprises: Based on the finite element model of casing running in irregular wells, the mapping relationship between drilling parameters and mechanical resistance is obtained; According to the mapping relationship between the drilling parameters and mechanical resistance, the following mechanical resistance model for irregular wellbore is constructed using the plowing traction resistance theory: F m =F(κ)+F(d)+F(x); Where F(κ)=F g0 (1+aκ) represents the mapping relationship between wellbore curvature and mechanical resistance; F g0 is the blocking force of a regular wellbore; κ is the wellbore curvature; a is the weight coefficient of the wellbore curvature; F(d) = F g0 (1+bd) represents the mapping relationship between wellbore roughness and mechanical resistance; d is the wellbore roughness; b is the weight coefficient of wellbore roughness; F(x)=F g0 e -gx It represents the mapping relationship between the borehole clearance ratio and the mechanical resistance; x is the borehole clearance ratio; g is the weight coefficient of the borehole clearance ratio.

7. The method according to claim 1, characterized in that: The determining whether the well drilling tool matches the wellbore casing according to the first running capability index and the second running capability index includes: If the first running capability index is greater than or equal to the second running capability index, it is determined that the well drilling tool matches the wellbore casing.

8. The method according to claim 1, characterized in that: The determining whether the well drilling tool matches the wellbore casing according to the first running capability index and the second running capability index includes: If the first running capability index is less than the second running capability index, adjusting the structure of the well drilling tool; Acquire drilling parameter data corresponding to the adjusted drilling tool as new first drilling parameter data; Calculating a new first running capability index of the drilling tool based on the stiffness of the drilling tool and the first sticking risk factor; Iteratively executing the above steps until the first running capability index is greater than or equal to the second running capability index; It is determined that the adjusted drilling tool matches the wellbore casing.

9. A device for determining a well drilling tool, characterized in that: The device comprises: An acquisition module, configured to acquire first drilling parameter data corresponding to the wellbore drilling tool and second drilling parameter data corresponding to the wellbore casing; a first calculation module, configured to calculate a first sticking risk factor of the through-hole drilling tool based on the first drilling parameter data, wherein the first sticking risk factor is used to indicate a possibility of the through-hole drilling tool being stuck; a second calculation module, configured to calculate a second stuck risk factor of the wellbore casing based on the second drilling parameter data, wherein the second stuck risk factor is used to indicate a possibility of the wellbore casing being stuck; A third calculation module is configured to calculate a first running capability index of the drilling tool based on the stiffness of the drilling tool and the first sticking risk factor; A fourth calculation module is configured to calculate a second running capability index of the wellbore casing according to the stiffness of the wellbore casing and the second sticking risk factor; The determination module is used to determine whether the well drilling tool matches the wellbore casing according to the first running capability index and the second running capability index.

10. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein: When the processor executes the computer program, the method according to any one of claims 1 to 8 is implemented.

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