A guide and anti-sticking drill string assembly and drilling method for horizontal wells in deep thin coal and rock formations

Abstract

This invention belongs to the field of natural gas extraction technology in deep thin coal and rock formations. It discloses a directional anti-sticking drill string assembly and drilling method for horizontal wells in deep thin coal and rock formations. A closed-loop control system is formed between the drill bit trajectory control mechanism and the wellbore dressing and anti-sticking mechanism, encompassing near-bit high-precision sensing, real-time data transmission while drilling, surface analysis feedback control, active downhole directional correction, and synchronous wellbore dressing and protection. Multi-directional gamma sensors positioned near the drill bit provide high-resolution formation information; the bend structure of the downhole power drill string provides the direction of the wellbore trajectory; the non-magnetic bearing section ensures the stability of measurement while drilling and the reliability of communication; the surface control unit enables real-time decision-making and trajectory correction; and the wellbore dressing and anti-sticking mechanism simultaneously improves wellbore stability and cuttings carrying capacity. This significantly enhances the drilling throughput and resistance to coal seam collapse in complex sections of thin coal and rock formations while ensuring trajectory controllability, reducing the risk of sticking due to wellbore instability and cuttings accumulation.

Description

Technical Field

[0001] This invention relates to the field of natural gas extraction technology in deep thin coal and rock formations, and particularly to a guide anti-sticking drill string assembly and drilling method for horizontal wells in deep thin coal and rock formations. Background Technology

[0002] Horizontal coal gas wells are a type of natural gas development well that involves directional drilling into coal seams or coal-bearing reservoirs to form long horizontal well sections within the target coal seam. This significantly increases the exposed coal seam area and coal gas extraction efficiency. Their burial depth typically ranges from several hundred meters to two to three thousand meters. As the burial depth increases, issues related to formation temperature, geostress, and wellbore stability become increasingly prominent, and problems such as coal seam collapse, leakage, and difficulty in trajectory control are more likely to occur. Generally, coal seams thicker than 10 meters can be considered thick coal seams. Due to their large longitudinal thickness, the allowable deviation in the wellbore trajectory is relatively large, and the drill bit can still remain within the coal seam. However, thin coal seams are typically 3–6 meters thick, with limited reservoir space and extremely low tolerance for trajectory deviation. They are very prone to penetrating the target coal seam, requiring extremely high drilling directional accuracy.

[0003] Currently, Chinese invention patent CN113719237B discloses a drilling tool assembly and method for directional long borehole drilling in soft, thin coal seams. It uses a pre-mounted measuring sub to measure near-bit inclination and natural gamma ray, and combines a post-mounted measuring sub and a central cable drill pipe to complete data transmission and trajectory control. However, this solution is mainly suitable for shallow, soft coal seams with low formation stress, and is not suitable for deep, thin coal-rock gas wells. Firstly, the central cable structure is prone to cable fatigue and seal failure under high temperature, high torque, and strong vibration conditions in long horizontal sections, making it unsuitable for drilling long, deep horizontal coal-rock gas wells with inclination depths of 4000-7000 meters. Secondly, its drilling tool structure lacks wellbore support devices, affecting the stability of inclination during composite drilling and the trajectory adjustment performance during sliding drilling, failing to meet the precise directional control requirements for stable inclination drilling and coal seam tracking in long horizontal sections of deep, thin coal-rock formations. In addition, the pre-measurement section contains many structures, which results in a certain distance between it and the drill bit. This leads to a large spatial gap between the measurement position and the end of the drill bit, making it difficult to achieve accurate real-time perception of the trajectory and formation changes required for coal seam tracking near the drill bit.

[0004] Therefore, there is an urgent need for a directional anti-sticking drill string assembly and drilling method for horizontal wells in deep thin coal and rock formations to solve the above problems. Summary of the Invention

[0005] The purpose of this invention is to solve or at least alleviate some or all of the aforementioned problems. Therefore, the purpose of this invention is to provide a directional anti-sticking drill string assembly and drilling method for horizontal wells in deep thin coal and rock formations, suitable for oil and gas well development in these formations. It enables real-time control of the drill bit's trajectory within the deep thin coal and rock formations and real-time detection of its position along the thin coal seam. Simultaneously, it improves the drilling throughput of narrow-diameter sections, the handling of collapse and coal cuttings, and the safety and reliability of tripping operations in long horizontal sections, reducing the occurrence of sticking due to coal seam wellbore collapse.

[0006] To achieve this objective, the present invention adopts the following technical solution: A guide and anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations, comprising: A drill bit, wherein the axial length of the drill bit is not greater than 0.5m; The drill bit trajectory control mechanism includes a near-bit formation detection component, a downhole power drilling tool, a non-magnetic instrument carrier component, and a drill string assembly connected sequentially along the axial direction, as well as a surface control unit communicatively connected to the non-magnetic instrument carrier component. The near-bit formation detection component includes a carrier cylinder and at least two azimuth gamma sensors. The at least two azimuth gamma sensors are evenly spaced along the circumference of the carrier cylinder, with an axial distance of less than 0.6m from the drill bit, to acquire formation gamma information corresponding to different azimuth positions of the drill bit. The downhole power drilling tool has a bend structure at one end near the drill bit to provide direction guidance for the wellbore trajectory during drilling, thereby achieving drill bit trajectory adjustment. The non-magnetic instrument carrier component... The magnetic instrument support assembly includes a non-magnetic support section, a measurement-while-drilling (MWD) component, and a near-bit formation information receiver. The MWD component and the near-bit formation information receiver are installed within the non-magnetic support section. The near-bit formation information receiver is positioned close to the drill bit and is communicatively connected to the near-bit formation detection assembly to receive near-bit formation information measurement data. The MWD component is communicatively connected to both the near-bit formation information receiver and the surface control unit to measure downhole drilling parameters in real time, collect the near-bit formation information measurement data, and transmit both to the surface control unit for drill bit trajectory analysis and control. The drill string assembly is used to transmit drilling pressure and rotational power. The wellbore dressing and anti-jamming mechanism is installed on the drill bit, the downhole power drilling tool, the non-magnetic instrument support assembly and / or the drill string assembly, and is used to enlarge, clear and dress the wellbore to reduce the risk of jamming caused by diameter reduction and collapsed coal dust.

[0007] In some optional embodiments, the bearing cylinder is uniformly divided into two to sixteen azimuth gamma measurement areas along the circumference, and multiple azimuth gamma sensors are respectively set in different azimuth gamma measurement areas to obtain formation gamma information corresponding to different azimuth directions of the drill bit, and identify the boundary position of the target thin coal and rock layer based on the formation gamma information of different azimuth directions.

[0008] In some alternative embodiments, the bend structure of the downhole power drill is disposed at one end of the downhole power drill near the drill bit, and the axial length of the bend structure is 0.3m to 1.5m, and the angle between the axis of the bend structure and the axis of the downhole power drill body is γ, where γ is 0.75° to 1.5°.

[0009] In some alternative embodiments, the measurement while drilling (MSD) device and the surface control unit are connected via a mud pulse communication module, which includes a pulse generation unit located downhole and a signal receiving and decoding unit located on the surface.

[0010] In some alternative embodiments, the near-bit formation detection component and the near-bit formation information receiver are connected by an electromagnetic communication component, which includes an electromagnetic transmitting unit disposed in the near-bit formation detection component and an electromagnetic receiving unit disposed in the near-bit formation information receiver.

[0011] In some optional embodiments, the wellbore dressing and anti-sticking mechanism includes a first stabilizer, a reverse reaming cutting tooth, and a micro-reamer; the first stabilizer is sleeved on the outer periphery of the downhole power drill string and arranged close to the drill bit, and is used to cooperate with the downhole power drill string to provide lateral directional force; the drill bit includes cutter wings and a gauge-keeping surface, and the reverse reaming cutting tooth is arranged on the side of the cutter wings and gauge-keeping surface opposite to the cutting end of the drill bit, and is used to dress or clear the well wall during tripping; the micro-reamer is arranged at intervals along the axial direction of the drill string assembly, and is used to enlarge, clean, and dress the well wall during drilling and tripping.

[0012] In some alternative embodiments, the wellbore dressing anti-sticking mechanism further includes a second stabilizer, wherein both the first stabilizer and the second stabilizer are configured as variable diameter stabilizers; The first stabilizer has a maximum outer diameter D1 during drilling, and shrinks to a second outer diameter D2 during tripping or lifting, and D1 is smaller than the outer diameter of the drill bit. The second stabilizer is sleeved on the outside of the non-magnetic bearing section and located on the side of the first stabilizer away from the drill bit. It has a maximum outer diameter D3 during drilling and shrinks to a fourth outer diameter D4 during tripping or lifting the drill bit, and D3 is less than D1.

[0013] In some alternative embodiments, the reverse reaming cutting teeth are also disposed on the first stabilizer and / or the second stabilizer for enlarging, clearing and trimming the wellbore during drilling or tripping.

[0014] A drilling method for a horizontal well with a directional anti-sticking drill string assembly in deep thin coal and rock formations, characterized by employing the aforementioned directional anti-sticking drill string assembly, includes the following steps: S1: Using at least two azimuth gamma sensors arranged at uniform intervals along the circumference of the bearing cylinder in the near-bit formation detection assembly, the formation gamma information at different azimuth positions around the drill bit is collected in real time; and the data collected by the azimuth gamma sensors is received through the near-bit formation information receiver. S2: The near-bit formation information receiving device transmits the near-bit formation information measurement data to the measurement-while-drilling device. The measurement-while-drilling device collects and processes the received near-bit formation information measurement data. At the same time, it measures the downhole drilling parameters in real time and transmits the near-bit formation information measurement data and the downhole drilling parameters to the surface control unit. S3: The ground control unit performs trajectory analysis based on the near-drill bit formation information measurement data and the downhole drilling engineering parameters, and combines the gamma differences in different circumferential orientations to determine the spatial orientation of the drill bit relative to the coal seam interface or formation change trend, thereby determining the position and offset direction of the drill bit in the formation and generating a trajectory correction command; the trajectory correction command is transmitted to the downhole power drill bit through the drill string assembly; the downhole power drill bit provides the direction of the wellbore trajectory during drilling through its bend structure near the drill bit end, thereby driving the drill bit to adjust its orientation according to the target trajectory or adjustment trajectory; S4: During drilling, trajectory adjustment and / or tripping, the wellbore dressing and anti-sticking mechanism installed on the drill bit, the downhole power drill, the non-magnetic instrument support assembly and / or the drill string assembly is activated to perform wellbore enlargement, dressing or coal dust removal operations to reduce the risk of stuck drill pipe caused by diameter reduction, collapse and coal dust accumulation, and to keep the wellbore open.

[0015] In some alternative embodiments, during construction, the drill bit, the drill bit trajectory control mechanism, and the wellbore dressing and anti-sticking mechanism all operate in continuous working mode and maintain continuous working status throughout the entire process of completing the construction of the entire horizontal well section in a single drilling trip.

[0016] The beneficial effects of this invention are: This invention provides a directional anti-sticking drill string assembly and drilling method for horizontal wells in deep thin coal and rock formations. Through the integrated collaborative design of the drill bit trajectory control mechanism and the wellbore dressing and anti-sticking mechanism, a closed-loop control system is formed, encompassing near-bit high-precision sensing, real-time data transmission while drilling, surface analysis feedback control, active downhole directional correction, and synchronous wellbore dressing and protection. The multi-directional gamma sensors positioned near the drill bit provide high-resolution formation information; the directional wellbore trajectory is indicated by the bend structure of the downhole power drill string; the non-magnetic bearing section ensures the stability of measurement while drilling and the reliability of communication; the surface control unit enables real-time decision-making and trajectory correction; and the wellbore dressing and anti-sticking mechanism simultaneously improves wellbore stability and cuttings carrying capacity. The coordinated operation of these units significantly enhances the drilling throughput, anti-collapse capability, and safety and reliability of long horizontal well sections in thin coal and rock formations while ensuring trajectory controllability, effectively reducing the risk of stuck drill pipe caused by wellbore instability and cuttings accumulation. Attached Figure Description

[0017] Figure 1 This is a schematic diagram of the directional anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations as described in this invention; Figure 2 This is a schematic diagram of the drill bit structure described in this invention; Figure 3 This is a graph showing the experimental data of the outer diameter of the first stabilizer described in this invention in relation to the build-up rate during directional drilling and composite drilling. Figure 4 This is a graph showing the experimental data of the outer diameter of the second stabilizer described in this invention in relation to the build-up rate during directional drilling and composite drilling. Figure 5 This is a flowchart of the drilling method for the guide and anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations as described in this invention.

[0018] In the picture: 1. Drill bit; 11. Cutting blade; 12. Diameter protection surface; 2. Drill bit trajectory control mechanism; 21. Near-bit formation detection assembly; 22. Downhole power drilling tool; 23. Non-magnetic instrument support assembly; 24. Drill string assembly; 3. Wellbore dressing and anti-sticking mechanism; 31. First stabilizer; 32. Reverse reaming cutting teeth; 33. Micro-reamer; 34. Second stabilizer. Detailed Implementation

[0019] Embodiments of the present invention are described in detail below. Examples of these embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals denote the same or similar components or components having the same or similar functions throughout. The embodiments described below with reference to the accompanying drawings are exemplary and intended to explain the present invention, and should not be construed as limiting the present invention.

[0020] In this invention, the terms "comprising," "including," "having," or any other variations thereof are intended to cover a non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitation, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0021] In this invention, the term "and / or" describes the relationship between related objects, indicating that three relationships can exist. For example, A and / or B can represent three cases: A alone, A and B simultaneously, and B alone. Additionally, in this invention, the character " / " generally indicates that the preceding and following related objects have an "and / or" relationship.

[0022] In the description of this invention, unless otherwise explicitly specified and limited, the terms "connected," "linked," "fixed," "combined," "coupled," and "installed" should be interpreted broadly. For example, they can refer to a fixed connection or a detachable connection; a direct connection or an indirect connection via an intermediate medium; or the internal communication of two components or the interaction between two components. As examples, a direct connection refers to two parts or components being connected together without the need for an intermediate medium, while an indirect connection refers to two parts or components each being connected to at least one intermediate medium, with the connection achieved through the intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances. Furthermore, "connected" and "coupled" are not limited to physical or mechanical connections or couplings, but can also include electrical connections or couplings.

[0023] In this invention, those skilled in the art will understand that relative terms (e.g., “about,” “approximately,” “basically,” etc.) used in conjunction with quantities or conditions are to include the value and have the meaning indicated by the context. For example, such relative terms include at least the degree of error associated with the measurement of a particular value, tolerances associated with the particular value due to manufacturing, assembly, use, etc. Such terms should also be considered as disclosing a range defined by the absolute values ​​of the two endpoints. Relative terms may refer to a certain percentage (e.g., 1%, 5%, 10% or more) of the indicated value. Numerical values ​​not using relative terms should also be disclosed as specific values ​​with tolerances. Furthermore, “basically” when expressing relative angular relationships (e.g., substantially parallel, substantially perpendicular) may refer to a certain degree (e.g., 1 degree, 5 degrees, 10 degrees or more) added to or subtracted from the indicated angle.

[0024] In this invention, those skilled in the art will understand that the function performed by a component can be performed by one component, multiple components, one part, or multiple parts. Similarly, the function performed by a part can also be performed by one part, one component, or a combination of multiple parts.

[0025] In this invention, the terms "upper," "lower," "left," "right," "front," and "rear," etc., refer to the orientations or positional relationships shown in the accompanying drawings. They are used solely for ease of description and simplification of operation, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention. Furthermore, in the context, it should be understood that when an element is mentioned as being "upper" or "lower" of another element, it can be directly connected to the other element "upper" or "lower," or indirectly connected through an intermediate element. It should also be understood that directional terms such as "upper side," "lower side," "left side," "right side," "front side," and "rear side" not only represent positive orientation but can also be understood as lateral orientation. For example, "above," "on top of," "upper side of," and "above" of the first feature and the second feature include the first feature being directly above, to the upper left, to the upper right, to the upper front, and to the upper rear of the second feature, or simply indicating that the first feature is at a higher horizontal level than the second feature. The terms "below," "under," "below," and "below" for "first feature" and "second feature" include situations where the first feature is directly below, to the lower left, to the lower right, in front of, or behind the second feature, or simply indicate that the first feature is at a lower horizontal level than the second feature. Furthermore, the terms "first" and "second" are used merely for descriptive distinction and have no specific meaning.

[0026] like Figure 1 and Figure 2As shown, this embodiment provides a horizontal well guide anti-sticking drill string assembly for deep thin coal and rock formations, including a drill bit 1, a drill bit trajectory control mechanism 2, and a wellbore dressing anti-sticking mechanism 3. The axial length of the drill bit 1 is no more than 0.5m. The drill bit trajectory control mechanism 2 includes a near-drill bit formation detection component 21, a downhole power drill string 22, a non-magnetic instrument carrier component 23, and a drill string assembly 24 connected sequentially along the axial direction, as well as a surface control unit communicatively connected to the non-magnetic instrument carrier component 23. The near-drill bit formation information detection component includes a carrier cylinder and at least two azimuth gamma sensors. The at least two azimuth gamma sensors are evenly spaced along the circumference of the carrier cylinder, and the axial distance between them and the drill bit 1 is less than 0.6m, so as to obtain formation gamma information corresponding to different azimuth positions of the drill bit 1. The downhole power drill string 22 has a bend structure at one end near the drill bit 1, which is used to provide the direction of the wellbore trajectory during drilling to achieve trajectory adjustment of the drill bit 1. The non-magnetic instrument carrier component 23 includes... The system comprises a non-magnetic bearing section, a measurement-while-drilling (MWD) component, and a near-bit formation information receiver. The MWD component and the near-bit formation information receiver are installed within the non-magnetic bearing section. The near-bit formation information receiver is positioned close to the drill bit 1 and is communicatively connected to the near-bit formation detection component 21 to receive near-bit formation information measurement data. The MWD component is communicatively connected to both the near-bit formation information receiver and the surface control unit to measure downhole drilling parameters in real time, collect near-bit formation information measurement data, and transmit the near-bit formation information measurement data and the downhole drilling parameters to the surface control unit for analysis and control of the drill bit 1 trajectory. The drill string assembly 24 is used to transmit drilling pressure and rotational power. The wellbore dressing and anti-sticking mechanism 3 is mounted on the drill bit 1, downhole power drill string 22, non-magnetic instrument bearing component 23, and / or drill string assembly 24 to enlarge the wellbore, clear obstructions, and dress the wellbore to reduce the risk of sticking caused by reduced diameter and collapsed coal cuttings.

[0027] Due to the rapid geological changes in thin coal and rock strata, by setting up a near-drill bit formation detection component 21 near drill bit 1, and separating the near-drill bit formation detection component 21 from the near-drill bit formation information receiver and transmitting data through a communication connection, the azimuth gamma sensor can be installed closer to drill bit 1. This controls the axial distance between the sensor and drill bit 1 to less than 0.6m, making the collected azimuth gamma information closer to the actual cutting interface of the formation by drill bit 1. This improves the sensitivity and response speed to changes in the formation in front of and around drill bit 1. At the same time, the near-drill bit formation information receiver transmits the near-drill bit 1 measurement data to the measurement-while-drilling (MWD) component and the ground control unit in real time, enabling rapid analysis and dynamic correction of the drill bit 1 trajectory on the ground side, thereby improving the real-time performance and accuracy of trajectory control. Meanwhile, at least two azimuth gamma sensors, evenly arranged around the circumference of the bearing cylinder, can acquire formation gamma data of at least the upper and lower layers of the target thin coal and rock strata where drill bit 1 is located, thereby enabling the identification of changes in the top and bottom plates of the coal seam and lateral formation heterogeneity. Combined with the well inclination, tool face, and drilling parameters acquired in real time by the measurement-while-drilling system, a comprehensive judgment of the position of drill bit 1 in the thin coal and rock strata can be made, thus providing continuous and dynamic formation guidance for the surface control unit to improve the geological tracking accuracy of drilling in thin coal and rock strata.

[0028] By installing a wellbore dressing and anti-sticking mechanism 3 on the drill bit 1, downhole power drilling tool 22, non-magnetic instrument support assembly 23 and / or drill string assembly 24, the wellbore can be actively enlarged, dressed and cleaned of coal cuttings during drilling. This can reshape the irregular wellbore formed by the loose collapse of the coal seam, reduce the retention and accumulation of rock cuttings, improve wellbore flow conditions and well clearance space, and thus reduce the risk of sticking during the tripping and drilling of long horizontal sections.

[0029] In summary, this embodiment achieves a closed-loop control system by integrating the drill bit trajectory control mechanism 2 and the wellbore dressing and anti-sticking mechanism 3. This system enables high-precision sensing near the drill bit 1, real-time data transmission while drilling, surface analysis feedback control, active downhole directional correction, and synchronous wellbore dressing and protection. The multi-directional gamma sensors near the drill bit 1 provide high-resolution formation information, the bend structure of the downhole power drill string 22 provides the direction of the wellbore trajectory, the non-magnetic bearing section ensures the stability of measurement while drilling and the reliability of communication, the surface control unit enables real-time decision-making and trajectory correction, and the wellbore dressing and anti-sticking mechanism 3 simultaneously improves wellbore stability and cuttings carrying capacity. The cooperation of these units significantly enhances the drilling throughput, anti-collapse capability, and safety and reliability of long horizontal sections in complex wells with thin coal and rock formations while ensuring trajectory controllability. This effectively reduces the risk of stuck drill pipe caused by wellbore instability and cuttings accumulation.

[0030] Optionally, drill bit 1 may be a PDC drill bit or a roller cone drill bit, etc., without specific limitations; PDC drill bits are preferred, and the total length of the selected PDC drill bit shall not exceed 0.5 meters, usually between 0.2 meters and 0.3 meters.

[0031] The non-magnetic bearing section can utilize non-magnetic drill collars or non-magnetic weighted drill pipes to improve the overall mechanical performance of the drill string assembly while ensuring a non-magnetic environment. Non-magnetic drill collars or non-magnetic weighted drill pipes effectively increase the weight of the drill string assembly, providing stable and sufficient drilling pressure for drill bit 1, thereby improving its rock-breaking efficiency and trajectory control stability. Simultaneously, they possess high strength, stiffness, and fatigue resistance, adapting to the complex cyclic compression, tension, and torsional loads encountered during horizontal well drilling in deep, thin coal and rock formations, reducing the risk of drill string fatigue failure. Furthermore, non-magnetic drill collars or non-magnetic weighted drill pipes provide a low-magnetic-interference working environment for measurement-while-drilling (MWD) components and near-bit formation information receivers, preventing magnetic field interference from affecting measurement accuracy and signal transmission stability, thus improving the accuracy and reliability of downhole measurement data. Moreover, typically 1 to 3 non-magnetic drill collars or non-magnetic weighted drill pipes are installed to balance drilling pressure requirements, measurement accuracy, and the overall structural stability of the drill string assembly.

[0032] It is understandable that the measurement while drilling (MWD) tool measures downhole drilling parameters in real time, including but not limited to inclination angle, azimuth angle, and tool face.

[0033] In some optional embodiments, the bearing cylinder is uniformly divided into two to sixteen azimuth gamma measurement zones along its circumference. Multiple azimuth gamma sensors are respectively set in different azimuth gamma measurement zones to acquire formation gamma information corresponding to different azimuths of drill bit 1, and to identify the boundary position of the target thin coal and rock strata based on the formation gamma information of different azimuths. This is equivalent to forming multiple independent observation windows around drill bit 1 to simultaneously acquire the differences in formation gamma response corresponding to different azimuths of drill bit 1. Since thin coal and rock strata usually have rapidly changing heterogeneous geological features such as roof, floor, and interbedded rock, gamma signals in a single direction are easily affected by local disturbances or formation dip angles, resulting in misjudgments. Multi-azimuth zone measurement can effectively eliminate this directional deviation, making the formation responses in different quadrants form a comparative relationship, thereby improving the sensitivity of identifying changes in the roof and floor interfaces and lateral boundaries of the coal seam. By comprehensively comparing and analyzing the gamma information measured from all directions, the direction and degree of deviation of drill bit 1 relative to the target thin coal and rock layer can be determined, enabling more accurate identification of the coal seam boundary position. This provides a more reliable geological basis for the directional adjustment of the downhole power drilling tool 22 and the trajectory correction of the surface control unit. Specifically, the bearing cylinder can be divided into two, four, six, eight, or sixteen measurement areas, each equipped with an azimuth gamma sensor. The distance between the azimuth gamma sensor and drill bit 1 is between 0.3 meters and 0.6 meters.

[0034] Specifically, the bend structure of the downhole power drill string 22 is located at the end of the downhole power drill string 22 closest to the drill bit 1, and the axial length of the bend structure is 0.3m to 1.5m. The angle between the axis of the bend structure and the axis of the downhole power drill string 22 body is γ, which is 0.75° to 1.5°. By placing the bend structure at the end of the downhole power drill string 22 closest to the drill bit 1, its position of action is as close as possible to the cutting end of the drill bit 1. From a mechanical transmission perspective, this significantly shortens the transmission path of the lateral build-up force from its generation position to the point of action of the drill bit 1, thereby reducing the mechanical attenuation and deflection error in the intermediate drill string section. This allows the drill bit 1 to respond more directly to the build-up command, improving the real-time performance and sensitivity of trajectory adjustment. Secondly, limiting the axial length of the bend structure to between 0.3m and 1.5m achieves a reasonable balance between the length and stiffness of the build-up section while ensuring structural strength and manufacturability. The included angle γ of the bend structure is limited to 0.75° to 1.5°, which falls within the range of small-angle fine-tuning drilling. This allows the structure to provide a continuous wellbore trajectory direction while avoiding trajectory abrupt changes or coal seam penetration risks caused by excessively large included angles. This achieves a gradual and controllable trajectory correction method, which is beneficial for maintaining stable drilling along the strata in thin coal and rock formations and reducing the probability of accidentally entering the roof or floor or causing wellbore disturbance. The included angle γ is preferably 1.0° or 1.25°, but no specific limitation is made here.

[0035] In some embodiments, the measurement-while-drilling (MWD) instrument and the surface control unit communicate via a mud pulse communication module. This module includes a pulse generation unit located downhole and a signal receiving and decoding unit located on the surface. The mud pulse communication module uses circulating drilling mud as the transmission medium, transmitting pressure pulses upwards to the surface signal receiving and decoding unit for real-time analysis. This enables continuous, real-time transmission of downhole engineering parameters and azimuth measurement data back to the surface control unit. This transmission method eliminates the need for additional cables or complex wired transmission structures, avoiding the risk of cable breakage or connector failure during long horizontal drilling operations. It also improves the system's reliability and adaptability under high temperature, high pressure, and complex well conditions. Furthermore, mud, as a natural circulating medium, has a stable transmission path and covers a wide well depth range, ensuring effective communication even in deep, thin coal and rock formations in horizontal wells. This guarantees that the surface control unit can promptly acquire downhole status information and perform trajectory analysis and control decisions.

[0036] In some embodiments, the near-bit formation detection component 21 and the near-bit formation information receiver are connected via an electromagnetic communication component. This component includes an electromagnetic transmitting unit within the near-bit formation detection component 21 and an electromagnetic receiving unit within the near-bit formation information receiver. This allows azimuth gamma measurement data of the near-bit area to be transmitted in real time via the electromagnetic transmitting unit and synchronously received by the electromagnetic receiving unit within the near-bit formation information receiver, thus achieving short-distance, high-frequency data transmission. Compared to traditional rigid connections or long-path wired transmission methods, this design avoids the problems of difficult signal cable laying and numerous joints in complex drill string structures, which can result in a long distance between the measuring end and the drill bit. Meanwhile, since this electromagnetic communication method is suitable for short-distance, high-real-time transmission, it can ensure that the azimuth gamma data is quickly relayed near the drill bit 1, and then uploaded to the ground by the non-magnetic bearing section and the measurement while drilling component. This realizes a hierarchical communication architecture of rapid acquisition near the drill bit 1, near-end receiving and relay, and stable transmission over a long distance, thereby improving the continuity and real-time performance of data transmission and enhancing the response speed and accuracy of ground trajectory control decisions.

[0037] Thin coal and rock formations typically exhibit characteristics such as low strength, poor stability, fragility, and creep. During drilling, phenomena like wellbore spalling, localized diameter reduction, and cuttings deposition can easily occur, leading to a smaller wellbore diameter and increased friction between the drill string and the wellbore. In severe cases, this can cause stuck drill, pressure buildup, or even drill bit burial. To mitigate the impact of these problems on drilling, in this embodiment, the wellbore dressing and anti-sticking mechanism 3 includes a first stabilizer 31, reverse reaming cutting teeth 32, and a micro-reamer 33; the first stabilizer... The device 31 is fitted around the periphery of the downhole power drill string 22 and arranged close to the drill bit 1, and is used to cooperate with the downhole power drill string 22 to provide lateral directional force; the drill bit 1 includes a cutter wing 11 and a gauge protection surface 12, and the reverse reaming cutting teeth 32 are arranged on the side of the cutter wing 11 and the gauge protection surface 12 away from the cutting end of the drill bit 1, and are used to trim or clear obstacles from the well wall during tripping; the micro-reamer 33 is arranged at intervals along the axial direction of the drill string assembly 24, and is used to enlarge the diameter, clear obstacles and trim the well wall during drilling and tripping. The first stabilizer 31 provides radial support and straightening to the drill bit 1 during drilling, suppressing lateral swaying and vibration of the drill string, thereby reducing the risk of uneven extrusion and secondary damage to the wellbore by the drill bit 1 and improving trajectory stability. The reverse reaming cutting teeth 32 can perform reverse scraping and trimming of the formed wellbore under drilling or micro-torque conditions, promptly removing protrusions and irregular structures formed by coal seam collapse or local diameter reduction, thereby improving wellbore roundness and reducing local jamming points. The micro-reamer 33 can perform segmented micro-diameter enlargement treatment on different well sections during tripping in and out of the drilling rig, gradually releasing wellbore constraints, cleaning loose coal cuttings, and increasing wellbore diameter margin, thereby reducing friction accumulation and the risk of stuck drill bit during tripping in long horizontal sections. By introducing corresponding anti-jamming and trimming mechanisms during the drilling, wellbore formation, and tripping in and out stages, the wellbore maintains a relatively regular geometric shape and stable diameter conditions, significantly improving the drilling throughput and operational safety of deep, thin coal and rock formation horizontal wells.

[0038] The drill string assembly 24 includes drill collars or weighted drill pipes, which are used to increase the overall weight of the drill string assembly and provide the required drilling pressure to the drill bit 1 to ensure rock breaking efficiency and drilling stability. The drill string assembly also enables power transmission and connection with the surface drilling rig, thereby forming a complete surface-to-downhole drilling operation link.

[0039] Considering the characteristics of long horizontal sections and high wellbore friction resistance in deep, thin coal and rock formations, heavy-duty drill pipes or a combination of a small number of drill collars and heavy-duty drill pipes are usually preferred to reduce contact friction between the drill string assembly and the wellbore, as well as tripping resistance. This reduces overall rigidity and friction load while meeting drilling pressure requirements. In addition, drill collars of different sizes can be combined according to the actual needs of wellbore trajectory control. By adjusting the axial weight distribution and stiffness characteristics, the stress state and trajectory control performance of the drill string assembly can be optimized, thereby adapting to the drilling requirements under complex thin coal and rock formations.

[0040] In some embodiments, the wellbore dressing and anti-sticking mechanism 3 further includes a second stabilizer 34. Both the first stabilizer 31 and the second stabilizer 34 are variable-diameter stabilizers. The first stabilizer 31 has a maximum outer diameter D1 during drilling and contracts to a second outer diameter D2 during tripping or hoisting, with D1 being smaller than the outer diameter of the drill bit 1. The second stabilizer 34 is sleeved on the outside of the non-magnetic bearing section, located on the side of the first stabilizer 31 away from the drill bit 1. It has a maximum outer diameter D3 during drilling and contracts to a fourth outer diameter D4 during tripping or hoisting, with D3 being smaller than D1. The first stabilizer 31 is positioned close to the drill bit 1 and maintains a large working outer diameter D1 during drilling, providing strong radial straightening and stabilizing support to the drill string near the drill bit 1, thereby suppressing drill bit swaying, reducing wellbore deviation fluctuations, and improving trajectory control stability. Simultaneously, since D1 is smaller than the outer diameter of the drill bit 1, the first stabilizer 31 will not exceed the wellbore size formed by the drill bit 1, avoiding additional expansion of the wellbore disturbance range. During tripping or hoisting, the first stabilizer 31 can retract to a smaller second outer diameter D2, reducing the overall outer diameter of the drill string. This improves its ability to traverse narrowed-diameter sections, collapsed sections, and cuttings accumulation areas, reducing the risk of jamming during tripping. The second stabilizer 34 is located outside the non-magnetic bearing section and on the side of the first stabilizer 31 furthest from the drill bit 1. During drilling, it forms a smaller working outer diameter D3, which is smaller than D1. This creates a strong front-weak rear stable support structure along the axial direction of the drill string assembly, improving its stability during composite drilling and its directional drilling capability. A larger stable support is used near the drill bit 1 to enhance directional control during directional drilling, while a relatively smaller stable support is used in the rear region to avoid excessive overall rigidity of the drill string leading to increased wellbore friction. This reduces sliding resistance and pressure build-up in long horizontal sections, improving the stability during composite drilling. Meanwhile, the second stabilizer 34 can further retract to the fourth outer diameter D4 during tripping to continue reducing the resistance at the rear of the drill string and improve overall throughput in complex well sections. By setting up two variable-diameter stabilizers in stages at different axial positions and coordinating different outer diameter parameters, the drill string can achieve good trajectory control during drilling, and actively reduce the outer diameter during tripping to reduce friction and sticking risk, thus balancing precise guidance, wellbore protection, and wellbore safety under complex well conditions.

[0041] like Figure 3 and Figure 4As shown, during directional drilling, directional drilling and combined drilling perform different trajectory control functions: directional drilling is used to actively build up the wellbore trajectory and adjust its direction, relying on the bend structure of the downhole power drill string 22 to provide continuous lateral pointing force; combined drilling, on the other hand, averages the bend effect through the overall rotation of the drill string assembly, used to achieve stable drilling or maintain the trajectory after correction, making the wellbore trajectory smoother and more stable. Therefore, the two working conditions together constitute a collaborative control mode for wellbore trajectory adjustment and maintenance.

[0042] Because the first stabilizer 31 is positioned close to the drill bit 1, it forms a near-drill bit mechanical coupling relationship with the bend structure of the downhole power drilling tool 22. The bend structure causes the drill bit to tend to deflect, and when it is not installed or is insufficiently supported, the section of the drilling tool assembly near the drill bit is prone to swaying, making it difficult to stably transmit the lateral force generated by the bend to the drill bit 1, thereby weakening the directional effect. As the outer diameter D1 of the first stabilizer 31 increases, its radial support and straightening effect on the section near the drill bit is enhanced, allowing the lateral thrust of the bend structure to act more effectively on the drill bit 1. Therefore, under directional drilling conditions, the build-up force increases with the increase of D1, and the directional control capability is enhanced.

[0043] However, when the outer diameter D1 of the first stabilizer 31 is further increased, its constraint effect on the drill string assembly is enhanced. The drill bit 1 is suppressed by the well wall constraint and the sinking effect of its own weight, which weakens the overall eccentric driving ability of the drill string assembly. As a result, the natural downward trend under the composite drilling condition is gradually weakened. At the same time, the composite drilling build-up rate changes from negative to zero or even positive as the outer diameter D1 increases.

[0044] Therefore, in the selection of the outer diameter D1 of the first stabilizer 31, it is necessary to coordinate and optimize the build-up rate under both directional drilling and composite drilling conditions: on the one hand, it should be ensured that directional drilling has sufficient inclination-increasing capacity, that is, the build-up rate is positive and meets the directional requirements; on the other hand, it should be made to present a slight inclination reduction or close to a stable inclination state under composite drilling conditions, that is, the build-up rate is slightly less than 0, in order to offset the uncertain effects caused by factors such as actual formation heterogeneity, wellbore disturbance and gravity sagging.

[0045] Based on the above principles, the preferred size is typically the outer diameter D1 of the first stabilizer 31, which corresponds to a build-up rate slightly less than 0 for composite drilling and a build-up rate greater than 0 for directional drilling. This configuration provides sufficient ramp-up and directional capabilities during directional drilling, while maintaining overall stable or slightly reduced ramp rates during composite drilling. This achieves a balance between stability and controllability in trajectory control, improving the predictability of the wellbore trajectory and engineering safety.

[0046] Since the second stabilizer 34 is located far from the drill bit 1, its main function is to constrain the overall bending shape of the drill string assembly, improve the axial stiffness of the downhole power drill string 22 and the non-magnetic bearing section, and optimize the bending moment distribution, thereby achieving rear inclination stabilization and structural balance. As the outer diameter D3 of the second stabilizer 34 increases, its radial constraint effect on the non-magnetic bearing section and the rear of the drill string is enhanced, increasing the overall stiffness of the drill string assembly. Simultaneously, it shortens the effective transmission length of the bend structure, thereby reducing the transmission efficiency of the lateral deflection to the drill bit caused by the bend of the downhole power drill string 22. This constraint effect manifests as a suppression of the bend's guiding effect in directional drilling conditions, and as an averaged weakening of the overall eccentricity effect and natural bending tendency in composite drilling conditions. Therefore, the build-up rate for both directional and composite drilling decreases with increasing D3, exhibiting a monotonically decreasing trend.

[0047] Based on the need for decoupling and balancing the inclination stabilization and directional drilling capabilities, the selection of the outer diameter D3 of the second stabilizer 34 requires optimization by comprehensively considering the trajectory response characteristics under both operating conditions. Typically, the preferred size is D3 that results in a near-zero build-up rate during composite drilling and a positive build-up rate during directional drilling, while also ensuring that D3 is less than D1. This configuration allows for maintaining a stable or near-stable trajectory under composite drilling conditions, reducing the cumulative deviation caused by formation heterogeneity and disturbance factors; simultaneously, it retains the active inclination build-up capability dominated by the downhole power drill bit's bend structure under directional drilling conditions to meet directional control requirements.

[0048] If D3 is too small, the overall stiffness of the drilling assembly will be insufficient, and the composite drilling may produce uncontrollable directional increases, resulting in decreased trajectory stability. If D3 is too large, the suppression of the bending angle effect will be too strong, leading to insufficient directional drilling directional build-up capacity and reduced directional efficiency. Therefore, by selecting the D3 corresponding to the above critical equilibrium point, it is possible to retain the necessary active directional build-up capacity in the sliding condition while ensuring stable and controllable directional drilling under composite conditions, thus achieving the optimal balance between trajectory control stability and engineering operability.

[0049] In actual experiments, when the outer diameter of the drill bit is 215.9 mm, D1 is preferably 212 mm to 214 mm, and D3 is preferably 208 mm to 212 mm.

[0050] Furthermore, the reverse reaming cutting teeth 32 are also disposed on the first stabilizer 31 and / or the second stabilizer 34, and are used to perform wellbore enlargement and dressing during drilling or tripping. Since the first stabilizer 31 and the second stabilizer 34 are located at different axial positions of the drill string assembly, the reverse reaming cutting teeth 32 on them can continuously scrape and dress the wellbore in different sections during drilling, tripping, or hoisting, and promptly remove local protrusions and narrowing areas caused by coal seam collapse, wellbore creep, or rock cuttings accumulation, thereby improving wellbore roundness and diameter conditions; at the same time, the first stabilizer 31 and the second stabilizer 34 themselves have a high probability of contact with the wellbore, so placing the reverse reaming cutting teeth 32 on the outer periphery of the stabilizer can improve the wellbore dressing coverage and contact efficiency, making the wellbore enlargement and dressing effect more uniform and continuous.

[0051] In addition, at least one drill collar or weighted drill rod is provided between the second stabilizer 34 and the adjacent micro-reamer 33 to form the necessary axial spacing structure; the adjacent micro-reamers 33 are also connected by a certain number of drill collars or weighted drill rods at intervals, so as to ensure the reasonable distribution and uniform force of each functional component in the axial direction of the drill string.

[0052] In some embodiments, the reaming cutting teeth 32 adopt a polycrystalline diamond composite sheet structure, which can be cylindrical or ridge-shaped, with a cylindrical structure being the main type, to improve stress stability and wear resistance. Furthermore, the reaming cutting teeth 32 protrude outward from the corresponding surface by a preset height, ranging from 1mm to 20mm, preferably from 3mm to 8mm. This allows the reaming cutting teeth 32 to effectively cut into the narrow-diameter well wall and collapsed protruding areas during drilling, tripping, or reaming, actively cutting, scraping, and trimming the well wall to improve wellbore regularity and duct capacity, and reduce friction and stuck drill risk during long horizontal section construction.

[0053] To address the inconsistency in joint dimensions and connection specifications among drill bit 1, drill bit trajectory control mechanism 2, and wellbore dressing and anti-sticking mechanism 3, in some embodiments, the horizontal well guide anti-sticking drill string assembly in deep thin coal and rock formations also includes various conversion joints, which are set between adjacent components to achieve transitional connections between joints of different sizes, thread specifications, and structural forms. This ensures reliable docking between the various modules of the drill string assembly and continuous transmission of mechanical loads, improving the structural compatibility, connection reliability, and operational stability of the entire drill string assembly under complex downhole conditions.

[0054] In addition, depending on the actual drilling conditions, the guide anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations can also be selectively configured with a variety of functional downhole tools to improve adaptability to complex working conditions and operational safety. This includes, but is not limited to, installing downhole shock absorbers to provide impact loads in case of stuck pipe or obstruction, enabling unsticking operations; installing bypass circulation subs to establish bypass circulation channels under lost circulation conditions, ensuring stable drilling fluid circulation; configuring shock absorbers to reduce vibration and impact loads on the downhole tubing during drilling, improving drill string fatigue life; adding a drilling geological survey device to identify the lithology and reservoir location of the drilled formation in real time, improving geological steering accuracy; also installing temperature and pressure measuring instruments to monitor changes in downhole formation temperature and pressure, improving the ability to judge operating conditions; deploying vibration detectors to monitor the vibration status of the downhole tubing in real time; and configuring hydraulic oscillators to improve drilling pressure transmission efficiency, reduce friction, and enhance the extension drilling capability of the drill string assembly, thereby comprehensively enhancing the adaptability and reliability of the drill string assembly in complex well conditions of deep, thin coal and rock formations.

[0055] like Figure 5 As shown, this embodiment also provides a drilling method for a horizontal well with a directional anti-sticking drill string assembly in a deep thin coal and rock formation. The method employs the directional anti-sticking drill string assembly in any of the above embodiments and includes the following steps: S1: Using at least two azimuth gamma sensors evenly spaced along the circumference of the bearing cylinder in the near-bit formation detection component 21, the formation gamma information in different azimuth directions of the drill bit 1 is collected in real time; and the data collected by the azimuth gamma sensors is received through the near-bit formation information receiver. S2: The near-bit formation information receiver transmits the near-bit formation information measurement data to the measurement-while-drilling (MSW) unit. The MSW unit collects and processes the received near-bit formation information measurement data. At the same time, it measures the downhole drilling parameters in real time and transmits the near-bit formation information measurement data and downhole drilling parameters to the surface control unit. S3: The surface control unit performs trajectory analysis based on near-bit formation information measurement data and downhole drilling engineering parameters, and combines the gamma differences in different circumferential orientations to determine the spatial orientation of drill bit 1 relative to the coal seam interface or formation change trend, thereby determining the current formation position and offset direction of drill bit 1, and generating trajectory correction commands; the trajectory correction commands are transmitted to the downhole power drill string 22 through the drill string assembly 24; the downhole power drill string 22 provides the direction of the wellbore trajectory during drilling through its bend structure near the drill bit 1, thereby driving drill bit 1 to adjust its orientation according to the target trajectory or adjustment trajectory; S4: During drilling, trajectory adjustment and / or tripping, activate the wellbore dressing and anti-sticking mechanism 3 installed on the drill bit 1, downhole power drill tool 22, non-magnetic instrument support assembly 23 and / or drill string assembly 24 to perform wellbore enlargement dressing or coal dust removal operations to reduce the risk of stuck drill caused by diameter reduction, collapse and coal dust accumulation, and keep the wellbore open.

[0056] This drilling method achieves simultaneous trajectory control and anti-sticking management during the drilling of horizontal wells in deep thin coal and rock formations by using a process-oriented and coordinated approach, including real-time formation sensing near the drill bit, real-time transmission of drilling parameters, dynamic analysis of surface trajectory, active downhole guidance and correction, and synchronous wellbore dressing to prevent sticking. This significantly improves the trajectory stability, coal seam tracking capability, and safety and reliability of long horizontal section operations during the drilling of horizontal wells in deep thin coal and rock formations, and enhances the guidance accuracy and operational safety in complex thin coal and rock formations.

[0057] Specifically, during construction, drill bit 1, drill bit trajectory control mechanism 2, and wellbore dressing and anti-sticking mechanism 3 all operate in continuous working mode, maintaining continuous operation throughout the entire horizontal well section construction process in a single drilling trip. Continuous drilling by drill bit 1 maintains stable cutting conditions at the bottom of the well, reducing drill pressure fluctuations and abrupt changes in wellbore trajectory caused by frequent start-stop cycles. Continuous operation of drill bit trajectory control mechanism 2 allows for real-time response to changes in thin coal and rock formations, enabling the surface control unit to continuously acquire drill bit 1's azimuth and engineering parameter information and promptly correct the trajectory, thereby improving drilling stability along thin coal and rock formations. Simultaneously, continuous operation of wellbore dressing and anti-sticking mechanism 3 allows for simultaneous wellbore dressing, diameter enlargement, and coal cuttings removal during drilling, preventing diameter reduction, collapse, and gradual accumulation of cuttings in local well sections, thus reducing friction and the risk of stuck drill bits during long horizontal section construction. In addition, completing the entire horizontal well section in a single drilling trip can reduce the number of trips and trips, reduce the disturbance and damage to the wellbore caused by the drill string repeatedly passing through complex well sections, and improve the continuity of construction and operational efficiency.

[0058] Understandably, the operation time for completing the entire horizontal well section in a single drilling trip is mainly determined by the drilling speed of drill bit 1 and the length of the horizontal well section. Therefore, before construction, a comprehensive evaluation of the design length of the target well section and the expected drilling parameters can be conducted. Based on this, and combined with the expected construction time, a matching configuration scheme and component specifications for drill bit 1, drill bit trajectory control mechanism 2, and wellbore dressing and anti-sticking mechanism 3 can be selected to reduce the number of trips and trips, reduce the disturbance and damage to the wellbore caused by the drill string repeatedly passing through complex well sections, and improve construction continuity and operational efficiency.

[0059] Specifically, the length of the horizontal well section is denoted as Lh in meters, the expected drilling speed of the horizontal well section is denoted as R in meters per hour, the continuous working time of the downhole power drill string 22 is denoted as H1 in hours, and when the target is a single-trip drilling operation of the horizontal well section, the following condition must be met: H1 ≥ Lh / R; the length of the casing section of the oil layer drilled is denoted as Lp in meters, the continuous working time of the drill string assembly 24 is denoted as H2 in hours, and when the target is a single-trip drilling operation of the casing section of the oil layer, the following condition must be met: H2 ≥ Lp / R.

[0060] Typically, the length of the horizontal section in a coal and rock gas horizontal well is 1500m to 2000m, and the drilling speed in the horizontal section is generally 8m / h to 12m / h. Accordingly, the continuous working time of H1, H2, drill bit 1, near-drill bit formation detection component 21, and non-magnetic instrument carrier component 23 is usually not less than 200h. When the length of the horizontal section exceeds 2000m, the continuous working time of H1, H2, drill bit 1, near-drill bit formation detection component 21, and non-magnetic instrument carrier component 23 is usually not less than 300h.

[0061] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not intended to limit the implementation of the present invention. Those skilled in the art will be able to make various obvious changes, readjustments, and substitutions without departing from the scope of protection of the present invention. It is neither necessary nor possible to exhaustively describe all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention should be included within the scope of protection of the claims of the present invention.

Claims

1. A guide and anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations, characterized in that, include Drill bit (1), wherein the axial length of the drill bit (1) is not greater than 0.5m; The drill bit trajectory control mechanism (2) includes a near-bit formation detection component (21), a downhole power drill string (22), a non-magnetic instrument carrier component (23), and a drill string assembly (24) connected sequentially along the axial direction, and a ground control unit communicatively connected to the non-magnetic instrument carrier component (23); wherein, the near-bit formation detection component (21) includes a carrier cylinder and at least two azimuth gamma sensors; the at least two azimuth gamma sensors are evenly spaced along the circumference of the carrier cylinder, and the axial distance between them and the drill bit (1) is less than 0.6m, so as to obtain formation gamma information corresponding to different azimuth positions of the drill bit (1) respectively; the downhole power drill string (22) has a bend structure at one end near the drill bit (1), which is used to provide the direction of the wellbore trajectory during drilling, so as to The drill bit trajectory is adjusted; the non-magnetic instrument support assembly (23) includes a non-magnetic support section, a measurement-while-drilling (MWD) component, and a near-bit formation information receiver. The MWD component and the near-bit formation information receiver are installed in the non-magnetic support section. The near-bit formation information receiver is positioned close to the drill bit (1) and is communicatively connected to the near-bit formation detection assembly (21) to receive near-bit formation information measurement data. The MWD component is communicatively connected to the near-bit formation information receiver and the ground control unit to measure downhole drilling parameters in real time, collect the near-bit formation information measurement data, and transmit both to the ground control unit for drill bit trajectory analysis and control on the ground. The drill string assembly (24) is used to transmit drilling pressure and rotational power. The wellbore trimming and anti-jamming mechanism (3) is installed on the drill bit (1), the downhole power drill (22), the non-magnetic instrument carrier assembly (23) and / or the drill string assembly (24) to enlarge the wellbore, clear obstacles and trim it, so as to reduce the risk of jamming caused by shrinkage and collapsed coal dust.

2. The guide and anti-sticking drill string assembly for deep thin coal and rock formations according to claim 1, characterized in that, The bearing cylinder is evenly divided into two to sixteen azimuth gamma measurement areas along the circumference. Multiple azimuth gamma sensors are respectively set in different azimuth gamma measurement areas to obtain the formation gamma information corresponding to different azimuth directions of the drill bit (1), and identify the boundary position of the target thin coal and rock layer based on the formation gamma information of different azimuth directions.

3. The guide and anti-sticking drill string assembly for deep thin coal and rock formations according to claim 1, characterized in that, The bend structure of the downhole power drill (22) is located at one end of the downhole power drill (22) near the drill bit (1), and the axial length of the bend structure is 0.3m to 1.5m. The angle between the axis of the bend structure and the axis of the downhole power drill (22) is γ, where γ is 0.75° to 1.5°.

4. The guide and anti-sticking drill string assembly for deep thin coal and rock formations according to claim 1, characterized in that, The measurement while drilling (MSD) device and the surface control unit are connected via a mud pulse communication module, which includes a pulse generation unit located downhole and a signal receiving and decoding unit located on the surface.

5. The guide and anti-sticking drill string assembly for deep thin coal and rock formations according to claim 1, characterized in that, The near-bit formation detection component (21) and the near-bit formation information receiver are connected by an electromagnetic communication component, which includes an electromagnetic transmitting unit disposed in the near-bit formation detection component (21) and an electromagnetic receiving unit disposed in the near-bit formation information receiver.

6. The guide and anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations according to any one of claims 1-5, characterized in that, The wellbore trimming and anti-jamming mechanism (3) includes a first stabilizer (31), a reverse reaming cutting tooth (32), and a micro-reamer (33). The first stabilizer (31) is sleeved on the outer periphery of the downhole power drill (22) and arranged close to the drill bit (1) to cooperate with the downhole power drill (22) to provide lateral directional force. The drill bit (1) includes a cutter wing (11) and a gauge protection surface (12). The reverse reaming cutting tooth (32) is located on the side of the cutter wing (11) and the gauge protection surface (12) away from the cutting end of the drill bit (1) to trim or clear the well wall during tripping. The micro-reamer (33) is arranged at intervals along the axial direction of the drill string assembly (24) to enlarge, clean, and trim the well wall during drilling and tripping.

7. The guide and anti-sticking drill string assembly for deep thin coal and rock formations according to claim 6, characterized in that, The wellbore dressing and anti-jamming mechanism (3) also includes a second stabilizer (34), and both the first stabilizer (31) and the second stabilizer (34) are configured as variable diameter stabilizers; The first stabilizer (31) has a maximum outer diameter D1 during drilling and shrinks to a second outer diameter D2 during tripping or lifting, and D1 is smaller than the outer diameter of the drill bit (1). The second stabilizer (34) is sleeved on the outside of the non-magnetic bearing section and is located on the side of the first stabilizer (31) away from the drill bit (1). It has a maximum outer diameter D3 during drilling and shrinks to a fourth outer diameter D4 during the tripping or lifting of the drill bit, and D3 is less than D1.

8. The guide and anti-sticking drill string assembly for deep thin coal and rock formations according to claim 7, characterized in that, The reverse-cutting teeth (32) are also provided on the first stabilizer (31) and / or the second stabilizer (34) for enlarging, clearing and repairing the well wall during drilling or tripping.

9. A drilling method for horizontal wells in deep, thin coal and rock formations using a directional anti-sticking drill string assembly, characterized in that... The method of using the directional anti-sticking drill string assembly for deep thin coal and rock formations as described in any one of claims 1 to 8 includes the following steps: S1: Using at least two azimuth gamma sensors arranged at uniform intervals along the circumference of the bearing cylinder in the near-bit formation detection component (21), the formation gamma information of the drill bit (1) in different azimuth directions is collected in real time; and the data collected by the azimuth gamma sensors is received through the near-bit formation information receiver. S2: The near-bit formation information receiver transmits the near-bit formation measurement data to the measurement-while-drilling (MSW) unit. The MSW unit collects and processes the received near-bit formation information measurement data. Simultaneously, it measures downhole drilling parameters in real time and transmits the near-bit formation information measurement data and the downhole drilling parameters to the surface control unit. S3: The ground control unit performs trajectory analysis based on the near-drill bit formation information measurement data and the downhole drilling engineering parameters, and determines the spatial orientation of the drill bit (1) relative to the coal seam interface or formation change trend by combining the gamma differences of different circumferential orientations. This determines the position and offset direction of the drill bit (1) in the formation at its current location, and generates a trajectory correction command. The trajectory correction command is transmitted to the downhole power drill bit (22) through the drill string assembly (24). The downhole power drill bit (22) provides the direction of the wellbore trajectory during drilling through its bend structure near the drill bit (1), thereby driving the drill bit (1) to adjust its orientation according to the target trajectory or adjustment trajectory. S4: During drilling, trajectory adjustment and / or tripping, the wellbore trimming and anti-sticking mechanism (3) installed on the drill bit (1), the downhole power drill (22), the non-magnetic instrument support assembly (23) and / or the drill string assembly (24) is activated to perform wellbore enlargement, trimming or coal dust removal operations to reduce the risk of stuck drill caused by narrowing, collapse and coal dust accumulation, and to keep the wellbore open.

10. The drilling method for the guide and anti-sticking drill string assembly for horizontal wells in deep thin coal and rock formations according to claim 9, characterized in that, During the construction process, the drill bit (1), the drill bit trajectory control mechanism (2) and the wellbore dressing and anti-sticking mechanism (3) all operate in continuous working mode and maintain continuous working status throughout the entire process of completing the construction of the entire horizontal well section in a single drilling trip.

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