Reversible polycrystalline diamond composite drill bit

Abstract

A reversible polycrystalline diamond composite (PDC) drill bit (200, 400) is disclosed. The reversible PDC drill bit (400) includes at least one blade (401a, 401b), at least one front cutting tooth (402) disposed on a first side of at least one blade (401a), and at least one rear cutting tooth (403) disposed on a second side of at least one blade (401b), wherein the first side is opposite to the second side along the circumferential direction of the reversible PDC drill bit (400), wherein rotating the reversible PDC drill bit (400) in a clockwise direction engages at least one front cutting tooth (402) to cut into the underground formation (104), and wherein rotating the reversible PDC drill bit (400) in a counterclockwise direction engages at least one rear cutting tooth (403) to cut into the underground formation (104).

Description

Background Technology

[0001] Polycrystalline diamond composite (PDC) drill bits are a type of drill bit that uses a synthetic diamond disc (called "cutting teeth") to cut through rock through a continuous scraping motion. The cutting teeth have clusters of diamond particles that aggregate into larger, randomly oriented crystals. PDC drill bits are used to drill wells in underground formations.

[0002] PDC (Potentially Variable Density) drill bits are widely used in drilling various formations, from soft to hard, brittle to tough, and shallow to deep. PDC cutting teeth are the primary cutting elements, cutting through the formation via clockwise rotation of the bottom loader assembly (BHA), powered by a downhole motor and / or top drive. The PDC cutting teeth are primarily brazed to the drill body on the right (front) side of the cutter blades. Several other PDC cutting teeth are brazed to the top and sides of the cutter blades to provide several different functions, including depth control, secondary cutting, and protection of the cutter blades or main cutting teeth. However, traditionally, because the drill string rotates to the right (clockwise) during drilling, there are no PDC cutting teeth on the left (rear) side of the cutter blades. When a drill bit replacement is determined due to low rate of penetration (ROP) or predicted formation changes, the entire bottom loader assembly (BHA) needs to be pulled out of the wellbore, requiring a time-consuming tripping process. For example, when the drill bit is at a total depth of about 12,000 feet, it takes about 2 days to pull out the drill bit and BHA. Summary of the Invention

[0003] In general, in one aspect, the present invention relates to a reversible polycrystalline diamond composite (PDC) drill bit. The reversible PDC drill bit includes at least one blade, at least one front cutting tooth disposed on a first side of the at least one blade, and at least one rear cutting tooth disposed on a second side of the at least one blade, wherein the first side is opposite to the second side along the circumferential direction of the reversible PDC drill bit, wherein rotating the reversible PDC drill bit clockwise engages the at least one front cutting tooth to cut into the underground formation, and wherein rotating the reversible PDC drill bit counterclockwise engages the at least one rear cutting tooth to cut into the underground formation.

[0004] In general, in one aspect, the present invention relates to a bottom-of-the-hole assembly (BHA). The BHA comprises: (i) a reversible polycrystalline diamond composite (PDC) drill bit having at least one blade, at least one front cutting tooth disposed on a first side of the at least one blade, and at least one rear cutting tooth disposed on a second side of the at least one blade, wherein the first side is opposite to the second side along the circumferential direction of the reversible PDC drill bit; and (ii) a downhole motor assembly coupled to the reversible PDC drill bit and configured to rotate the reversible PDC drill bit and selectively reverse the rotation direction of the reversible PDC drill bit, wherein clockwise rotation of the reversible PDC drill bit by the downhole motor assembly engages the at least one front cutting tooth to cut into the subsurface formation, and wherein counterclockwise rotation of the reversible PDC drill bit by the downhole motor assembly engages the at least one rear cutting tooth to cut into the subsurface formation.

[0005] In general, in one aspect, the present invention relates to a method for drilling a wellbore in an underground formation. The method includes: installing a reversible polycrystalline diamond composite (PDC) drill bit in a drill string of the wellbore; the reversible PDC drill bit including at least one blade, at least one front cutting tooth disposed on a first side of the at least one blade, and at least one rear cutting tooth disposed on a second side of the at least one blade, wherein the first side is opposite to the second side along the circumferential direction of the reversible PDC drill bit; rotating the reversible PDC drill bit clockwise to engage the at least one front cutting tooth to cut into the underground formation; and rotating the reversible PDC drill bit counterclockwise to engage the at least one rear cutting tooth to cut into the underground formation.

[0006] Other aspects and advantages will become apparent from the following description and embodiments of this disclosure. Attached Figure Description

[0007] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying drawings. For consistency, similar elements are indicated by similar reference numerals in the drawings.

[0008] Figure 1 and Figure 2 A system according to one or more embodiments is shown.

[0009] Figure 3 A flowchart according to one or more embodiments is shown.

[0010] Figure 4A , Figure 4B , Figure 4C , Figure 4D and Figure 4EExamples according to one or more embodiments are shown. Detailed Implementation

[0011] Numerous specific details are set forth in the following detailed description of embodiments of the present disclosure in order to provide a more thorough understanding of the present disclosure. However, it will be apparent to those skilled in the art that the present disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0012] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any noun in this application). Unless explicitly disclosed, such as by using the terms “before,” “after,” “single,” and other such terms, the use of ordinal numbers does not imply or create any particular order of elements, nor does it limit any element to a single element. Rather, the use of ordinal numbers is intended to distinguish between elements. As an example, a first element is distinct from a second element, and a first element may contain more than one element and be placed after (or before) the second element in the order of elements.

[0013] This disclosure provides a reversible polycrystalline diamond composite (PDC) drill bit and a method for drilling operations using the reversible PDC drill bit. In one or more embodiments of the invention, the reversible PDC drill bit includes PDC cutting teeth located on the right (front) and left (rear) sides of the cutter wings of the PDC drill bit. With the PDC cutting teeth mounted on both sides of the cutter wings, the PDC drill bit is configured to rotate in a clockwise or counterclockwise direction. For example, during drilling, after the front PDC cutting teeth lose their corrosiveness (i.e., become blunt or wear) or when encountering changes in formation rock, the reversible PDC drill bit can change its rotation direction.

[0014] Figure 1 A schematic diagram according to one or more embodiments is shown. Figure 1 As shown, well environment 100 includes subsurface formations (“formations”) 104 and well system 106. Formation 104 may include porous or fractured rock formations located underground, below the Earth’s surface (“surface”) 108. Formation 104 may include different rock layers with different properties (e.g., varying degrees of permeability, porosity, capillary pressure, and resistivity). In the case where well system 106 is a hydrocarbon well, formation 104 may include a hydrocarbon-bearing reservoir 102. When well system 106 is operating as a production well, well system 106 facilitates the extraction of hydrocarbons (or “products”) from reservoir 102.

[0015] In some embodiments disclosed in this specification, well system 106 includes a drilling rig 101, a wellbore 120, a subsurface well system 122, a surface well system 124, and a well control system (“control system”) 126. Well control system 126 can control various operations of well system 106, such as well production operations, drilling operations, well completion operations, well maintenance operations, and reservoir monitoring, assessment, and development operations. In some embodiments, well control system 126 includes a computer system.

[0016] Drilling rig 101 is a machine used to drill a wellbore to form a wellbore 120. The main components of drilling rig 101 include a drilling fluid tank, a drilling fluid pump (e.g., a drilling rig mixing pump), a derrick or turret, a winch, a rotary table or top drive, a drill string, power generation equipment, and auxiliary equipment. Drilling fluid (also known as "drilling mud" or simply "mud") is used to facilitate drilling wellbores in the earth, such as oil and gas wells. The main functions of drilling fluid include: providing hydrostatic pressure to prevent formation fluids from entering the wellbore; keeping the drill bit cool and clean during drilling; carrying drill cuttings; and suspending drill cuttings during drilling pauses and as drilling components are carried into and out of the wellbore.

[0017] The wellbore 120 includes a borehole (i.e., a wellbore) extending from the surface 108 to a target area (e.g., reservoir 102) in the formation 104. The upper end of the wellbore 120 terminating at or near the surface 108 may be referred to as the “upstream” end of the wellbore 120, while the lower end of the wellbore terminating in the formation 104 may be referred to as the “downstream” end of the wellbore 120. The wellbore 120 may facilitate the circulation of drilling fluids during drilling operations to extend the wellbore 120 to the target area (e.g., reservoir 102) in the formation 104, facilitate the flow of hydrocarbon products (e.g., oil and gas) from the reservoir 102 to the surface 108 during production operations, facilitate the injection of substances (e.g., water) into the hydrocarbon-bearing formation 104 or reservoir 102 during injection operations, or facilitate communication of monitoring equipment (e.g., logging tools) that have descended into the formation 104 or reservoir 102 during monitoring operations (e.g., during in-situ logging operations).

[0018] In some embodiments, the well system 106 is provided with a bottom hole assembly (BHA) 151, which is attached to the drill string 150 and suspended within the wellbore 120 for performing drilling operations. The bottom hole assembly (BHA) is the lowest part of the drill string and includes the drill bit, drill collars, stabilizer, mud motor, etc. The mud motor is a drilling motor that uses the hydraulic power of drilling fluid to drive the drill bit during drilling operations. Details of the BHA 151 are referenced below. Figure 2 Describe it.

[0019] Go to Figure 2 , Figure 2Further details of the BHA 151 suspended in the wellbore 120 according to one or more embodiments disclosed in this specification are shown. In one or more embodiments, elements may be omitted, repeated, combined, and / or substituted. Figure 2 The embodiments shown herein are one or more modules and / or elements. Therefore, the embodiments disclosed herein should not be considered as limited to... Figure 2 The specific arrangement of the modules and / or elements shown.

[0020] like Figure 2 As shown, BHA151 includes a reversible polycrystalline diamond composite (PDC) drill bit 200, which is connected to a downhole motor assembly 204 via a drill pipe (e.g., a portion of drill pipe 150). In some embodiments, the reversible PDC drill bit 200 is driven by a surface motor, in which case the downhole motor assembly 204 can be omitted. In one or more embodiments of the invention, the reversible PDC drill bit 200 includes one or more blades, such as blades 201. Compared to conventional PDC drill bits that carry PDC cutting teeth only on one side of each blade, the blades 201 of the reversible PDC drill bit 200 are brazed with PDC cutting teeth on both sides. In particular, at least one front cutting tooth (i.e., front cutting tooth 202) is provided on a first side of the blade 201, while at least one rear cutting tooth (i.e., rear cutting tooth 203) is provided on a second side of the blade 201. The first side is opposite to the second side along the circumferential direction of the reversible PDC drill bit 200. (See below...) Figure 4A An example is shown where PDC cutting teeth are brazed to both sides of the cutter blade along the circumferential direction of the reversible PDC drill bit.

[0021] In one or more embodiments, the downhole motor assembly 204 is configured to rotate the reversible PDC drill bit 200 and selectively reverse the direction of rotation of the reversible PDC drill bit 200. For example, rotating the reversible PDC drill bit 200 clockwise via the downhole motor assembly 204 engages the front cutting teeth 202 to cut into the formation rock 104a, while rotating the reversible PDC drill bit 200 counterclockwise via the downhole motor assembly 204 engages the rear cutting teeth 203 to cut into the formation rock 104a. In one or more embodiments, the front cutting teeth 202 and the rear cutting teeth 203 have the same material grade and the same geometry. In such embodiments, the service life of the reversible PDC drill bit 200 is twice that of a conventional drill bit with only one set of cutting teeth. In one or more embodiments, the front cutting teeth 202 and the rear cutting teeth 203 have different material grades and different geometries. In such an embodiment, the material grade and / or geometry of the front cutting tooth 202 can be designed or otherwise selected for cutting one type of formation rock 104a, while the material grade and / or geometry of the rear cutting tooth 203 can be designed or otherwise selected for cutting different types of formation rock 104a. For example, when encountering different types of formation rock 104a (e.g., soft versus hard, brittle versus tough, shallow versus deep, etc.) during drilling operations, the need for tripping out of the hole can be reduced by simply reversing the rotation direction of the PDC drill bit and switching between the front cutting tooth 202 and the rear cutting tooth 203.

[0022] Those skilled in the art will understand that the configuration of the front and rear cutting teeth may differ from that described above without departing from the scope of this disclosure. For example, the material grade and / or geometry of the front and rear cutting teeth may be the same. Alternatively, the material grade of the front and rear cutting teeth may be the same, but their geometries may be different. In other embodiments, the material grades of the front and rear cutting teeth may be different, but their geometries may be the same.

[0023] An exemplary configuration of the downhole motor assembly 204 for selectively reversing the rotation direction of the reversible PDC drill bit 200 is described below. Figures 4B to 4E Describe it.

[0024] Turn Figure 3 , Figure 3 A process flowchart according to one or more embodiments is shown. Figure 3 One or more boxes in the middle can be used as follows Figure 1 and Figure 2 It is performed by one or more components as described herein. Although Figure 3The boxes in the document are presented and described in sequence, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and may be executed in parallel and / or iteratively. Furthermore, these boxes may be executed actively or passively.

[0025] First, within block 300, a reversible polycrystalline diamond composite (PDC) drill bit is installed in the drill string of the wellbore. In one or more embodiments of the invention, the reversible PDC drill bit is installed in a bottom loader assembly (BHA) and includes at least one cutter wing, at least one front cutting tooth disposed on a first side of the at least one cutter wing, and at least one rear cutting tooth disposed on a second side of the at least one cutter wing. In particular, the first side is opposite to the second side along the circumferential direction of the reversible PDC drill bit.

[0026] In box 301, the rotation direction of the reversible PDC drill bit is selected from clockwise and counterclockwise directions based on the type of rock / formation to be cut by the reversible PDC drill bit. The front and rear cutting teeth have different material types or geometries selected according to different rock types in the underground formation.

[0027] In block 302, the reversible PDC drill bit rotates along a direction selected from block 301 to engage corresponding cutting teeth to cut into the subsurface formation. For example, if a clockwise direction is selected in block 301, the front cutting teeth can be engaged to cut into the subsurface formation. Alternatively, if a counterclockwise direction is selected in block 301, the rear cutting teeth can be engaged to cut into the subsurface formation. In other embodiments, a clockwise direction may correspond to the engagement of the rear cutting teeth, while a counterclockwise rotation direction may correspond to the engagement of the front cutting teeth. In one or more embodiments, the reversible PDC drill bit is driven by a downhole motor assembly to rotate along the selected direction.

[0028] In block 303, by adjusting the downhole motor assembly coupled to the reversible PDC bit, the rotation direction of the reversible PDC bit reverses between clockwise and counterclockwise, or vice versa, depending on the orientation initially selected in block 301. In one or more embodiments, block 303 may be triggered by a change in the subsurface formation for which the material grade and / or geometry of the opposite side cutting teeth will be more efficient when cutting the subsurface formation. In one or more embodiments, the determination of reversing the rotation direction of the reversible PDC bit may be triggered by wear on the cutting teeth on one side of the reversible PDC bit that has been engaged so far during drilling. For example, the leading cutting teeth may have lost their corrosiveness, or the sharpness of the cutting teeth may have worn down. In this case, drilling into the formation can continue by reversing the rotation direction of the reversible PDC bit, thereby avoiding the complete removal of the drill string to replace the PDC bit.

[0029] Continuing with block 303, in one or more embodiments, the downhole motor assembly includes a clockwise mud motor, a counterclockwise mud motor, and a sliding sleeve system. In such an embodiment, reversing the rotation direction of the reversible PDC bit includes adjusting the sliding sleeve system to guide drilling fluid flow selectively around one of the clockwise and counterclockwise mud motors, thereby changing the rotation direction of the reversible PDC bit.

[0030] In one or more embodiments, the downhole motor assembly includes a single mud motor and a sliding sleeve system. In such an embodiment, reversing the rotation direction of the reversible PDC bit includes adjusting the sliding sleeve system to guide drilling fluid selectively through the mud motor in one of two opposite directions, thereby changing the rotation direction of the reversible PDC bit.

[0031] In one or more embodiments, the downhole motor assembly includes a clutch system, a clockwise mud motor, and a counterclockwise mud motor. The clutch system includes an actuator for controlling the engagement disc, a clockwise disc coupled to the clockwise mud motor, and a counterclockwise disc coupled to the counterclockwise mud motor. In such an embodiment, reversing the rotation direction of the reversible PDC bit includes adjusting the actuator to selectively couple the engagement disc to one of the clockwise and counterclockwise discs, thereby changing the rotation direction of the reversible PDC bit.

[0032] In one or more embodiments, the downhole motor assembly includes a downhole DC electric motor powered by a surface power source or a downhole generator system. In such embodiments, reversing the rotation direction of the reversible PDC drill bit includes adjusting the polarity of the power supplied to the downhole DC electric motor, thereby changing the rotation direction of the reversible PDC drill bit.

[0033] In block 304, the reversible PDC bit is rotated counterclockwise to engage opposite side cutting teeth (i.e., depending on the initial selection made in block 301, either the rear cutting tooth or the front cutting tooth) to cut into the subsurface formation. Similar to rotation in the first selected direction (e.g., clockwise), the reversible PDC bit is driven by a downhole motor assembly to rotate in the opposite direction (e.g., counterclockwise).

[0034] As Figure 3 As a result of the process shown, drilling operations using reversible PDC bits are extended without the interruptions caused by tripping the PDC bit. Those skilled in the art will understand that the aforementioned changes in rotation direction can be mutual, and Figure 3 The process can be repeated more than once. That is, the rotation direction can be changed as many times as the operator deems necessary. For example, instead of fully wearing down one side of the cutting teeth on the cutter blades before reversing the rotation direction of the reversible PDC drill bit, the operator can choose to wear down both sides more evenly by changing the rotation direction more frequently. Alternatively, if encountering various types of formations, the rotation direction can be changed more frequently.

[0035] Figures 4A to 4E Examples according to one or more embodiments are shown. Figures 4A to 4E The example shown is based on the above reference. Figures 1 to 3 The systems and methods described. In particular, Figure 4A An example of a reversible PDC drill bit is shown. Figures 4B to 4E An example of a downhole motor assembly for a reversible PDC drill bit is shown. While reversible PDC drill bits... Figures 4B to 4E While not always explicitly shown, it should be understood that the reversible PDC drill bit is coupled to the downhole motor assembly via the drill pipe, as described above. Figure 2 As shown.

[0036] like Figure 4A As shown, the reversible PDC drill bit 400 includes six blades, such as blade A 401a and blade B 401b, which are located on the top... Figure 2 The example shown is of the cutter wing 201. The front PDC cutting tooth 402 is mainly brazed to the drill body on the right (front) side of the cutter wing A401a. Additionally, the rear PDC cutting tooth 403 is mainly brazed to the drill body on the left (rear) side of the cutter wing A401a. The front PDC cutting tooth 402 and the rear PDC cutting tooth 403 are referred to as the main cutting teeth, and are respectively as shown above. Figure 2 Examples of the front cutting tooth 202 and rear cutting tooth 203 are shown. Furthermore, additional PDC cutting teeth are brazed to the top and sides of the blade wing to provide different functions, including depth of cut control, secondary cutting, and protection of the blade wing or main cutting tooth.

[0037] Figure 4B A longitudinal cross-sectional view of an exemplary downhole motor assembly is shown, which is based on two downhole mud motors that alternately rotate a reversible PDC drill bit in opposite directions. In this example, a sliding sleeve system is used to change the direction of drilling fluid flow (shown as arrows according to Figure 500) from the clockwise motor / valve / sleeve assembly 412 of the first mud motor (i.e., clockwise motor 450) to the counterclockwise motor / valve / sleeve assembly 413 of the second mud motor (i.e., counterclockwise motor 451) and vice versa, thereby changing the rotation direction of the reversible PDC drill bit. In particular, the clockwise motor 450 includes a clockwise motor / valve / sleeve assembly 412 (i.e., rotor 412a, valve 412b, and sliding sleeve 412c), which together rotate the reversible PDC drill bit in a clockwise direction 410a. The counterclockwise motor 451 includes a counterclockwise motor / valve / sleeve assembly 413 (i.e., rotor 413a, valve 413b, and sliding sleeve 413c), which together rotate the reversible PDC drill bit in the counterclockwise direction 401b.

[0038] like Figure 4B As shown in the upper part, during conventional drilling, the downhole motor assembly is configured in a clockwise configuration 411a, with valve 412b in the open flow position to allow drilling fluid to flow through rotor 412a, while valve 413b is in the blocked flow position to force drilling fluid into the annular space of the downhole motor assembly, thus bypassing the counterclockwise motor / valve / sleeve assembly 413. The hydraulic power of the drilling fluid flowing through the clockwise motor / valve / sleeve assembly 412 drives the rotor 412a of the clockwise motor 450 to rotate the reversible PDC bit clockwise 410a. The counterclockwise motor 451 is stationary because the counterclockwise motor / valve / sleeve assembly 413 does not receive any hydraulic power from the drilling fluid flow to drive the reversible PDC bit. Specifically, the user configures (e.g., by sliding) sliding sleeves 412c and 413c to allow drilling fluid to flow around the annular space of the downhole motor assembly at position “A” upstream of the counterclockwise motor / valve / sleeve assembly 413, thereby bypassing the counterclockwise motor / valve / sleeve assembly 413. In the clockwise configuration 411a, the downhole motor assembly drives the drill pipe to rotate the reversible PDC drill bit clockwise 410a, wherein the front PDC cutting teeth 402 are used to cut the formation rock.

[0039] like Figure 4BAs shown in the lower half, when the user decides to change the drill bit rotation direction, the user sets the downhole motor assembly to a counter-clockwise configuration 411b, where valve 412b is in a flow-blocking position to direct drilling fluid flow into the annular space of the downhole motor assembly, bypassing the clockwise motor / valve / sleeve assembly 412, while valve 413b is in a flow-open position to allow drilling fluid flow through the counter-clockwise motor / valve / sleeve assembly 413. Specifically, the user sets (e.g., by sliding) a sliding sleeve 412c to allow drilling fluid flow to bypass the clockwise motor / valve / sleeve assembly 412 at position "B" upstream of the clockwise motor / valve / sleeve assembly 412 into the annular space of the downhole motor assembly. Simultaneously, the user sets (e.g., by sliding) the sliding sleeve 413c to allow drilling fluid flow to return from the annular space of the downhole motor assembly to the counterclockwise motor / valve / sleeve assembly 413 at position "C" upstream of the counterclockwise motor / valve / sleeve assembly 413. In the counterclockwise configuration 411b, the downhole motor assembly drives the drill pipe to rotate the reversible PDC drill bit in a counterclockwise direction 410b, wherein the rear PDC cutting teeth 403 are used to cut the formation rock.

[0040] In the example above, valve on / off control can be achieved by dropping an object (e.g., a ball or dart) from the ground. These objects can be made of soluble or insoluble materials. When these objects fall and land on the valve seat, the pressure differential across the valve changes, triggering the valve to rotate in a preset step, thereby closing / opening the valve accordingly. When valve on / off control is achieved, the pressure differential can drive the sliding sleeve. Additionally, a shear pin system with different shear values ​​can be configured to control the pressure window of each sliding sleeve. In the example above, although the clockwise motor 450 is upstream of the counterclockwise motor 451, in other dual mud motor and sliding sleeve arrangements, the clockwise motor 450 can also be positioned downstream of the counterclockwise motor 451.

[0041] Figure 4C A longitudinal cross-sectional view of an exemplary downhole motor assembly is shown, based on a downhole mud motor with a bypass via a sliding sleeve. In this example, the sliding sleeve system is used to guide drilling fluid flow between two opposite directions (shown as arrows according to Figure 500), thereby changing the rotation direction of a reversible PDC drill bit. Specifically, the motor / valve / sleeve assembly 422 of the mud motor includes a rotor 422a, a first valve 422b, a first sliding sleeve 422c, a second valve 422d, and a second sliding sleeve 422f.

[0042] like Figure 4CAs shown in the upper part, during conventional drilling in clockwise configuration 421a, drilling fluid flows through the motor / valve / sleeve assembly 422 of the mud motor, causing the reversible PDC bit to rotate clockwise 420a. Specifically, the drill pipe below the downhole motor assembly causes the reversible PDC bit to rotate clockwise 420a to cut the formation rock using the front PDC cutting teeth 402. When a change in rotation direction is required, the operator sets the first valve 422b and the second valve 422d to counterclockwise configuration 421b to block the normal flow of drilling fluid upstream and downstream of the motor / valve / sleeve assembly 422. Additionally, the user slides the first sliding sleeve 422c and the second sliding sleeve 422f to allow the drilling fluid to flow around into the annular space of the downhole motor assembly, causing the flow direction of the drilling fluid through the motor / valve / sleeve assembly 422 to be opposite to that in clockwise configuration 421a. As a result, the drill pipe below the downhole motor assembly causes the reversible PDC drill bit to rotate counterclockwise to use the rear PDC cutting teeth 403 to cut the formation rock.

[0043] In the above example, valve on / off control can be achieved by dropping an object (e.g., a ball or dart) from the ground. These objects can be made of soluble or insoluble materials. When these objects fall and land on the valve seat, the pressure differential across the valve changes, triggering the valve to rotate in a preset step, thereby closing / opening the valve accordingly. When valve on / off control is achieved, the pressure differential can drive the sliding sleeve. Additionally, a shear pin system with different shear values ​​can be configured to control the pressure window of each sliding sleeve. Furthermore, in the above example, although drilling fluid flows through the motor / valve / sleeve assembly 422 in a clockwise configuration 421a, in other single mud motor and sliding sleeve arrangements, drilling fluid can flow through the motor / valve / sleeve assembly 422 in a counter-clockwise configuration 421b.

[0044] Figure 4D A longitudinal cross-sectional view of an exemplary downhole motor assembly is shown, which is based on two downhole mud motors with a clutch. Figure 4D As shown, the downhole motor assembly includes a clockwise motor 432a and a counterclockwise motor 433a, respectively coupled to a clockwise disc 432 and a counterclockwise disc 433 of the clutch. The clutch engagement disc 431 is coupled to an actuator 436 via a spindle 435 for driving a reversible PDC drill bit.

[0045] In neutral configuration 421, engagement disc 431 is controlled by actuator 436 to disengage from the clockwise disc 432 and counterclockwise disc 433 of the clutch. Therefore, the reversible PDC drill bit remains stationary and does not rotate. In one or more embodiments, engagement between the clutch actuator and either clockwise disc 432 or counterclockwise disc 433 can be achieved by electromagnetic force therebetween, with both engaged connected downhole via a drill string or additional cable. A surface operator can remotely control the power and polarity based on the timing and option of engagement. Alternatively, a pressure-actuated piston system can be designed to control the position of the actuator. A surface operator can pump different flow rates to generate different pressure levels through these components, thereby achieving engagement control between the actuator and either disc.

[0046] In the clockwise configuration 421a, the engagement disc 431 is controlled by the actuator 436 to couple to the clutch clockwise disc 432. Therefore, the reversible PDC drill bit is driven by the clockwise motor 432a and rotates in a clockwise direction.

[0047] In the counter-clockwise configuration 421b, the engagement disc 431 is controlled by the actuator 436 to couple to the clutch as a counter-clockwise disc 433. Therefore, the reversible PDC drill bit is driven by the counter-clockwise motor 433a and rotates in a counter-clockwise direction.

[0048] In the example above, although the clockwise motor 432a and actuator 436 are located on opposite sides of the clutch, while the counterclockwise motor 433a and actuator 436 are located on the same side of the clutch, in other dual mud motor and clutch arrangements, the positions of the clockwise motor 432a and counterclockwise motor 433a can be reversed.

[0049] Figure 4E A schematic diagram of an exemplary downhole motor assembly based on a downhole electric motor is shown. Figure 4E As shown, the reversible PDC drill bit 400 is connected to and driven by a downhole DC electric motor 440 via drill pipe 470. Power can be transmitted from the surface to operate the downhole DC electric motor 440. The rotation direction of the downhole DC electric motor 440 and the reversible PDC drill bit 400 is controlled by the polarity of the power transmitted from the surface to the downhole DC electric motor. Alternatively, the downhole DC electric motor 440 can be powered by a downhole generator 460, which is powered by a set of piezoelectric generators 441 and capacitors 442. To change the rotation direction of the downhole DC electric motor 440 and the reversible PDC drill bit 400, the surface operator changes the polarity of the power transmitted from the downhole generator 460 to the downhole DC electric motor 440.

[0050] For example, embodiments of the invention advantageously reduce the number of drill bit changes and the time required for them (e.g., due to low rate of penetration (ROP) during drilling operations or anticipated formation changes). Changing conventional drill bits requires pulling the entire bottom loader assembly (BHA) out of the wellbore, a very time-consuming process. With reversible PDC drill bits, the service life is significantly extended due to the presence of two sets of cutting teeth, thus greatly reducing the need for tripping out of the well. Simultaneously, when changes in formation rock properties are anticipated, ROP can be significantly improved by using new cutting teeth on the second side of the cutter wings.

Claims

1. A reversible polycrystalline diamond composite drill bit, comprising: At least one blade; At least one front cutting tooth is disposed on the first side of the at least one blade; as well as At least one rear cutting tooth is disposed on the second side of the at least one blade. The first side is opposite to the second side along the circumferential direction of the reversible polycrystalline diamond composite drill bit. Rotating the reversible polycrystalline diamond composite drill bit clockwise engages at least one front cutting tooth to cut into the underground formation. Specifically, rotating the reversible polycrystalline diamond composite drill bit counterclockwise engages at least one rear cutting tooth to cut into the underground formation. The reversible polycrystalline diamond composite drill bit is coupled to a downhole motor assembly configured to reverse the rotation direction of the reversible polycrystalline diamond composite drill bit. The downhole motor assembly includes: mud motors; and A sliding sleeve system configured to guide drilling fluid to selectively flow through the mud motor in one of two opposite directions, thereby changing the rotation direction of the reversible polycrystalline diamond composite drill bit.

2. The reversible polycrystalline diamond composite drill bit according to claim 1, in, The at least one front cutting tooth and the at least one rear cutting tooth have different material types or different geometries selected according to different rock types in the underground strata.

3. A bottom drilling assembly, comprising: Reversible polycrystalline diamond composite drill bit, the reversible polycrystalline diamond composite drill bit comprising: At least one blade; At least one front cutting tooth is disposed on a first side of the at least one blade; and At least one rear cutting tooth is disposed on the second side of the at least one blade. Wherein, the first side is opposite to the second side along the circumferential direction of the reversible polycrystalline diamond composite drill bit; and A downhole motor assembly coupled to the reversible polycrystalline diamond composite drill bit and configured to: Rotate the reversible polycrystalline diamond composite drill bit; and The downhole motor assembly selectively reverses the rotation direction of the reversible polycrystalline diamond composite drill bit, and includes: mud motors; and A sliding sleeve system configured to guide drilling fluid to selectively flow through the mud motor in one of two opposite directions, thereby altering the rotation direction of the reversible polycrystalline diamond composite drill bit. Specifically, the reversible polycrystalline diamond composite drill bit, rotated clockwise by the downhole motor assembly, engages at least one front cutting tooth to cut into the underground formation. Specifically, the reversible polycrystalline diamond composite drill bit, rotated counterclockwise by the downhole motor assembly, engages at least one back cutting tooth to cut into the underground formation.

4. The bottom drill assembly according to claim 3, in, The at least one front cutting tooth and the at least one rear cutting tooth have different material types or different geometries selected according to different rock types in the underground strata.

5. A method for drilling a wellbore in underground strata, comprising: A reversible polycrystalline diamond composite drill bit is installed in the drill string of the wellbore, the reversible polycrystalline diamond composite drill bit comprising: At least one blade; At least one front cutting tooth is disposed on a first side of the at least one blade; and At least one rear cutting tooth is disposed on the second side of the at least one blade. Wherein, the first side is opposite to the second side along the circumferential direction of the reversible polycrystalline diamond composite drill bit; The reversible polycrystalline diamond composite drill bit is rotated clockwise to engage at least one front cutting tooth to cut into the underground formation. The reversible polycrystalline diamond composite drill bit is rotated counterclockwise to engage at least one rear cutting tooth to cut into the underground formation. The rotation direction of the reversible polycrystalline diamond composite drill bit is selected from the clockwise and counterclockwise directions, depending on the type of rock to be cut by the reversible polycrystalline diamond composite drill bit, wherein the at least one front cutting tooth and the at least one rear cutting tooth have different material types or different geometries selected according to the type of rock in the underground strata.

6. The method according to claim 5, further comprising: By adjusting the downhole motor assembly coupled to the reversible polycrystalline diamond composite drill bit, the rotation direction of the reversible polycrystalline diamond composite drill bit is reversed between the clockwise and counterclockwise directions.

7. The method according to claim 6, wherein, Reversing the rotation direction of the reversible polycrystalline diamond composite drill bit includes: Adjusting the sliding sleeve system to selectively guide drilling fluid through the mud motor in one of two opposite directions alters the rotation direction of the reversible polycrystalline diamond composite drill bit. The downhole motor assembly includes the mud motor and the sliding sleeve system.

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