Sub-assembly for directional drilling system

Abstract

A subassembly (400) for a directional drilling system configured to drill a wellbore is provided. The subassembly (400) comprises a drill bit (1) configured to rotate in a first direction about a longitudinal axis (401) of the subassembly (400). The drill bit 1 comprises an inlet (14) for receiving a drilling fluid and an outlet (24a, 24b) for allowing the drilling fluid to exit the drill bit (1). The subassembly (400) further comprises a diverter (106) configured to rotate in a second direction about a longitudinal axis (401) of the subassembly, where a direction of flow of drilling fluid out of the drill bit (1) is determined by a rotational position of the diverter (106) about the longitudinal axis (401) of the subassembly. The subassembly further comprises a housing portion (410) connected to the drill bit (1). The subassembly further includes a motor assembly (420) located within the housing portion (410). The motor assembly (420) includes a motor assembly housing (421) rotationally fixed to the housing portion (410) and a drive shaft (128) rotatable relative to the motor assembly housing (421). The drive shaft (421) is coupled to the diverter (106), and the motor assembly (420) is configured to operate the drive shaft (421) to control a rotational position of the diverter (106). A directional drilling system including the subassembly, and a kit of parts for forming the subassembly are also provided.

Description

Technical Field

[0001] The present invention relates to a subassembly for a directional drilling system configured to drill a wellbore. The present invention also relates to a directional drilling system including the subassembly, and a kit of parts for forming the subassembly. Background Art

[0002] Typically, natural resources such as oil and gas can be found in underground formations. It is known to use a drilling system to cut a wellbore in an underground formation so that the natural resources can be obtained via the wellbore. A known type of drilling system is a rotary drilling system or a rotary drilling system, which may include a rotary drill bit arranged at the end of a drill string. Examples of rotary drill bits include polycrystalline diamond compact (PDC) drill bits and roller cone drill bits. Typically, the drill string is formed by a plurality of tubular sections or pipes, which are added to the drill string as the depth of the wellbore increases. The drill string may include a plurality of components, including a drill bit collar and a stabilizer. In some arrangements, one or more joints are used to connect the components of the drilling system. For example, a joint may be used to connect the drill bit to the drill string.

[0003] As used herein, the term "downhole" refers to a direction toward or toward the bottom of a wellbore. Additionally, the term "uphole" refers to a direction toward or toward the top of a wellbore.

[0004] During drilling, the drill bit is rotated by rotating the entire drill string using a drive system located at the surface. Typically, the drill bit is provided with mechanical cutters so that, as the drill bit rotates, drill cuttings are produced as the drill bit cuts through the formations. The drill cuttings include some of the loose material from the drilled formations. A drilling fluid or drilling mud is pumped down the interior of the drill string to the drill bit where it flows into the wellbore through nozzles or outlets formed in the drill bit. The drilling fluid helps lubricate the drilling process, and the minerals contained in the drilling fluid help seal the wellbore. Another function of the drilling fluid is to carry the cuttings out of the wellbore.

[0005] It is often necessary to be able to change the trajectory of a wellbore during the wellbore formation process. For example, in the oil and gas industry, it may not be possible to access natural resources in a subterranean formation by drilling a vertical wellbore. Alternatively, the wellbore may need to have a non-vertical portion (such as a horizontal portion) in order to access the natural resources. Therefore, it is desirable to provide a directional drilling system in which the trajectory of the wellbore can be changed during drilling through a subterranean formation, and such directional drilling can be achieved by a variety of methods.

[0006] The most common method is to use a positive displacement motor or mud motor with a bend at the downhole end. The positive displacement motor is located at the uphole end of the drill bit and has a drive shaft connected to the drill bit. The drilling fluid passes through the positive displacement motor to rotate the drill bit. The bend of the positive displacement motor causes a non-straight section of the wellbore to be formed. In some arrangements, the bend in the positive displacement motor can be variable, however, the most common is to have a fixed bend. A positive displacement motor with a fixed bend means that when it is desired that the wellbore have a straight section, the drilling system needs to be removed from the wellbore. This is so that the positive displacement motor can be disconnected from the drilling system. The drilling system can then be inserted back into the wellbore to continue drilling. This is both time-consuming and expensive.

[0007] WO2014177505A1 discloses another directional drilling method, which involves controlling the flow direction of drilling fluid leaving the drill bit. The system includes a diverter that remains geostationary relative to the wellbore while the drill bit rotates. Since the diverter is geostationary, the diverter guides the flow of increased drilling fluid in a specific direction within the wellbore. The system includes a first rotatable section that can rotate in a bearing and can rotate separately from the rotation of the drill string. The first rotatable section has a rotor provided with a plurality of blades. The rotor is rotated in a direction opposite to the drill bit by the flow of drilling fluid. The rotor is connected to the diverter to rotate the diverter. A control unit is further disclosed, which is used to control the rotation speed of the second rotatable section relative to the first rotatable section, thereby controlling the rotation speed of the first rotatable section relative to the drill string.

[0008] The system of WO2014177505A1 is relatively complex because a rotor with rotor blades is used to drive the splitter, and a complex system is required to control the speed of the rotor connected to the splitter. The system is also complicated by the use of bearings in which the first rotatable section rotates. The rotor blades and bearings are exposed to the drilling fluid. This may cause the performance of these parts to deteriorate over time. For example, contamination of one or more of these bearings may cause increased friction in the bearings. This may cause the rotation of the splitter to be less than ideal.

[0009] It would be desirable to provide a directional drilling system that is less complex than some prior art systems and that may be less susceptible to performance degradation over time. Summary of the invention

[0010] According to an example of the present disclosure, a subassembly for a directional drilling system configured to drill a wellbore is provided. The subassembly includes a drill bit configured to rotate in a first direction around a longitudinal axis of the subassembly. The drill bit includes an inlet for receiving a drilling fluid and an outlet for allowing the drilling fluid to leave the drill bit. The subassembly also includes a diverter configured to rotate in a second direction around the longitudinal axis of the subassembly, wherein the flow direction of the drilling fluid leaving the drill bit is determined by the rotational position of the diverter around the longitudinal axis of the subassembly. The subassembly also includes a housing portion connected to the drill bit. The subassembly further includes a motor assembly located within the housing portion. The motor assembly includes a motor assembly housing fixed to the housing portion in a rotational sense and a drive shaft rotatable relative to the motor assembly housing. The drive shaft is coupled to the diverter, and the motor assembly is configured to operate the drive shaft to control the rotational position of the diverter.

[0011] Providing a motor assembly means that it is not necessary to provide a turbine connected to the flow splitter. The motor assembly housing is fixed to the housing part in a rotational sense. That is, the motor assembly housing is fixed to the housing part so that the position and orientation of the motor assembly housing is fixed relative to the housing part. This means that no bearings are required to mount the flow splitter rotation system. Therefore, the number of bearings exposed to the drilling fluid can be reduced.

[0012] Providing a motor assembly allows the speed of rotation of the diverter to be controlled by varying the speed of the motor. This allows precise control of the rotational position of the diverter.

[0013] Providing a motor assembly including a motor assembly housing also allows the components of the motor assembly to be protected from drilling fluids when the drilling fluids flow through the housing portion. This can extend the service life of the components of the motor assembly.

[0014] As used herein, the term "longitudinal axis of a subassembly" refers to an axis extending between an uphole end of the subassembly and a downhole end of the subassembly. The longitudinal axis of the subassembly may coincide with a radial center axis of the subassembly. The longitudinal axis of the subassembly may coincide with a radial center axis of the drill bit. The longitudinal axis of the subassembly may coincide with a radial center axis of the diverter. The longitudinal axis of the subassembly may coincide with a radial center axis of the housing portion. The longitudinal axis of the subassembly may coincide with a radial center axis of the motor assembly. The longitudinal axis of the subassembly may coincide with a radial center axis of the drive shaft.

[0015] The housing portion may be a tubular housing portion. The housing portion may be a pipe section. The housing portion may be a collar. The housing portion may be a drill bit collar. The housing portion may be a joint. The first end of the housing portion may be configured to be connected to a drill string. The second end of the housing portion may be connected to a drill bit. The first end may be opposite to the second end.

[0016] The flow diverter can remain geostationary to direct the drilling fluid into a specific section of the wellbore. As used herein, the term "geostationary" means stationary or non-moving relative to the surrounding underground formations or wellbore. For example, the flow diverter can be kept geostationary while the drill bit rotates around the flow diverter so that the flow diverter is maintained in the same spatial position relative to the wellbore. The flow diverter can be decoupled from the rotation of the housing portion. The flow diverter can be decoupled from the rotation of the drill bit.

[0017] The motor assembly can be configured to keep the diverter geostationary relative to the wellbore when the drill bit rotates in the wellbore. The motor assembly can be configured to keep the diverter geostationary relative to the wellbore by rotating the diverter around the longitudinal axis of the subassembly. The motor assembly can be configured to keep the diverter geostationary relative to the wellbore by adjusting the rotational speed of the diverter around the longitudinal axis of the subassembly. That is, when the diverter rotates, the motor assembly can adjust the rotational speed of the diverter (such as increasing or decreasing the rotational speed) as needed to keep the diverter geostationary. For example, this may be required in the case of a change in the rotational speed of the drill bit or housing portion (such as due to a change in drilling resistance). This may be the result of a change in the material composition of the underground formation or wellbore. Advantageously, the motor assembly can have a fast response time between receiving a command to adjust the rotational speed of the diverter and actually adjusting the rotational speed of the diverter. This allows the diverter to be accurately kept geostationary.

[0018] The first direction of the longitudinal axis of the winding subassembly may be opposite to the second direction of the longitudinal axis of the winding subassembly. The first direction of the longitudinal axis of the winding subassembly may be clockwise. The second direction of the longitudinal axis of the winding subassembly may be counterclockwise or counterclockwise. The first direction of the longitudinal axis of the winding subassembly may be counterclockwise or counterclockwise. The second direction of the longitudinal axis of the winding subassembly may be clockwise.

[0019] The motor assembly may be configured to rotate the diverter in a first direction.The motor assembly may be configured to rotate the diverter in a second direction.The motor assembly may be configured to rotate the diverter in both the first direction and the second direction.

[0020] The motor assembly can be configured to rotate the flow diverter in a second direction while the drill bit is rotating in a first direction. Rotating the flow diverter in the second direction may keep the flow diverter geostationary when the drill string, housing portion, and / or drill bit are rotating in the first direction, or may allow the flow diverter to rotate in the first direction at a slower rotational speed than the drill string, housing portion, and / or drill bit are rotating in the first direction.

[0021] The motor assembly may be configured to rotate the diverter at the same rotational speed as the drill bit. The motor assembly may be configured to rotate the diverter in the second direction at the same rotational speed as the drill bit in the first direction. This means that the diverter and the drill bit may rotate at the same speed but in opposite directions.

[0022] The housing portion may be configured to rotate in the same direction as the drill bit. The housing portion may be configured to rotate at the same rotational speed as the drill bit.

[0023] The subassembly may include a sensing device. The sensing device may be configured to provide a sensing signal for controlling the rotational position of the shunt. Advantageously, this allows the rotational position of the shunt to be adjusted based on the actual conditions experienced during drilling. The sensing device may be configured to provide a sensing signal to the motor assembly for controlling the rotational position of the shunt. The sensing signal may be transmitted wirelessly between the sensing device and the motor assembly. Advantageously, this reduces the need for complex wiring that must account for the independent rotation of the various components of the subassembly.

[0024] The sensing device may include an accelerometer. The accelerometer may be used to measure the inclination of the subassembly. The accelerometer may be used to determine the azimuth. The sensing device may include a magnetometer. The magnetometer may be used to determine the azimuth. The accelerometer and magnetometer may be used to determine the azimuth. Determining the inclination and azimuth may provide a three-dimensional overview of the drilling progress.

[0025] The sensing device may be configured to determine a rotational speed of the housing portion. The sensing device may be configured to determine a rotational speed of the drill bit. The sensing device may be configured to determine a rotational speed of the diverter. The sensing device may be configured to determine a rotational speed of the motor.

[0026] The sensing device may be configured to determine a rotational position of the housing portion about the longitudinal axis of the subassembly. The sensing device may be configured to determine a rotational position of the drill bit about the longitudinal axis of the subassembly. The sensing device may be configured to determine a rotational position of the diverter about the longitudinal axis of the subassembly. The sensing device may be configured to determine a rotational position of the diverter relative to the wellbore.

[0027] The subassembly may include a control unit. The control unit may be configured to provide a control signal to the motor assembly for controlling the rotational position of the diverter. The sensing device may be configured to provide a sensing signal to the control unit. The control unit may be configured to process the sensing signal. The control signal may be based on the processed sensing signal.

[0028] The motor assembly may be located on the well of the diverter. The motor assembly may be secured to the housing portion by a support member. The support member may be connected to the motor assembly housing.

[0029] The support member may have a plurality of radially extending arms. The support member may have two radially extending arms. The two radially extending arms may be spaced approximately 180 degrees apart from each other. The support member may have three radially extending arms. The three radially extending arms may be positioned approximately 120 degrees apart from each other. The support member may have four radially extending arms. The four radially extending arms may be positioned approximately 90 degrees apart from each other.

[0030] The support member may include one or more apertures for allowing drilling fluid to flow through the housing portion to the inlet of the drill bit. Advantageously, this allows the support member to span the internal chamber of the housing portion. Each of the one or more apertures may be located between two radially extending arms of the plurality of radially extending arms.

[0031] The support member may be configured to position the motor assembly radially centrally within the housing portion. The support member may be a support hanger. The support member may be a bracket. The support member may be located at the uphole end of the motor assembly. The support member may be located at the downhole end of the motor assembly. The motor assembly may be secured to the housing portion by a plurality of support members. For example, two, three, four, or five support members. Any one or each of the plurality of support members may have any of the features of the support members described above. The first support member may be located at or positioned toward a first end of the motor assembly housing. The first support member may be located at or positioned toward a second end of the motor assembly housing.

[0032] The motor assembly may include a motor. The motor may be located within a motor assembly housing. The output speed (rpm) of the motor may be between 2000 rpm and 3000 rpm. The motor may be an electric motor. The electric motor may be a DC motor. The electric motor may be a brushless motor. Advantageously, a brushless motor is less susceptible to performance degradation in the high vibration environment of a drilling system.

[0033] The drive shaft may be at least partially located within the motor assembly housing. The drive shaft may extend from the motor assembly housing. That is, the drive shaft may extend from the inside of the motor assembly housing to the outside of the motor assembly housing. The motor assembly may include a seal. The drive shaft may extend through the seal. The seal may prevent fluid from entering or leaving the motor assembly housing between the seal and the drive shaft. The drive shaft may be connected to the diverter via a coupling. In the case where the diverter is mounted on the diverter shaft, the drive shaft may be connected to the diverter shaft via a coupling. That is, the coupling may couple the drive shaft to the diverter via the diverter shaft. For example, one end of the drive shaft may be connected to a first end of the coupling, and one end of the diverter shaft may be connected to a second end of the coupling, so that the coupling couples the drive shaft to the diverter shaft. The coupling may be a releasable or removable coupling. That is, one or both of the diverter shaft and the drive shaft may be selectively disconnected from the coupling so as to separate the diverter from the drive shaft. This may advantageously allow the diverter and / or the motor assembly to be easily removed from the subassembly independently of each other. This may help to increase the ease with which components of the subassembly may be replaced and / or removed, for example for maintenance purposes.The coupling may be a universal coupling.The coupling may be a universal coupling.

[0034] The motor assembly may include a reduction gearbox. The reduction gearbox may be located within the motor assembly housing. The reduction gearbox may be operably connected to the motor. The reduction gearbox may be operably connected to the drive shaft. The reduction gearbox may be configured to increase the torque supplied from the motor to the drive shaft. The transmission ratio of the reduction gearbox may be 6:1.

[0035] The motor assembly may include a position resolver. The position resolver may be located within the motor assembly housing. The position resolver may be used to provide the angular position and speed of the motor. The position resolver may be used to determine the rotational position of the shunt. The motor assembly may include a Hall effect sensor for determining the rotational position of the shunt. The Hall effect sensor may be located within the motor assembly housing. The Hall effect sensor may be located near the drive shaft. The sensing device may include a position resolver and / or a Hall effect sensor.

[0036] The motor assembly housing may include a void filled with oil. The motor assembly housing may include a plurality of voids filled with oil. The motor assembly housing may pressure compensate for hydrostatic pressure from drilling fluid. The motor assembly housing may be configured to allow drilling fluid in the housing portion to flow around the motor assembly housing.

[0037] The flow diverter may be located within the drill bit. The flow diverter may be located between an inlet of the drill bit and an outlet of the drill bit.

[0038] The inlet of the drill bit may be located at a first end of the drill bit. The outlet of the drill bit may be located at a second end of the drill bit. The first end may be an uphole end of the drill bit. The second end may be a downhole end of the drill bit.

[0039] The outlet of the drill bit may include a first outlet and a second outlet. Directional drilling may be caused by a difference between the fluid flow leaving the first outlet and the fluid flow leaving the second outlet. The arc measurement between the center of the first outlet and the center of the second outlet is greater than 90 degrees. The arc measurement may be greater than 120 degrees. The arc measurement may be greater than 150 degrees. The first outlet and the second outlet may be positioned diametrically opposite to each other.

[0040] The flow diverter may be configured to selectively divert drilling fluid to a first outlet of the drill bit. The flow diverter may be configured to selectively divert drilling fluid to a second outlet of the drill bit. The flow diverter may be configured to selectively divert drilling fluid to one of the first outlet of the drill bit and the second outlet of the drill bit. The flow diverter may be configured to allow drilling fluid to flow between an inlet of the drill bit and the first outlet of the drill bit, and substantially prevent drilling fluid from flowing between an inlet of the drill bit and the second outlet of the drill bit.

[0041] The outlet of the drill bit may include a first outlet, a second outlet, and a third outlet. The flow diverter may be configured to divert drilling fluid to the first outlet and the second outlet. The flow diverter may be configured to allow drilling fluid to flow between the inlet of the drill bit, the first outlet of the drill bit, and the second outlet of the drill bit; and substantially prevent drilling fluid from flowing between the inlet of the drill bit and the third outlet of the drill bit.

[0042] The flow diverter may be located within the chuck. The flow diverter may form a part of the chuck. The chuck may be configured to be received by a drill bit.

[0043] The chuck may include a chuck housing having an inlet end for receiving a drilling fluid, and an outlet end at which the drilling fluid may exit the chuck housing. The chuck may form a flow path for the drilling fluid between the inlet and outlet of the drill bit. The flow diverter may be movable relative to the chuck housing to selectively control the flow direction of the drilling fluid when the drilling fluid exits the chuck housing. The chuck may be adapted to be received within an interior space of the drill bit.

[0044] The chuck housing may be configured to rotate with the drill bit. The flow diverter may be rotatably mounted within the chuck housing. The chuck housing may include one or more components for securing the chuck housing in a fixed position within the drill bit.

[0045] The flow divider can be mounted on a flow divider shaft. The flow divider shaft can be connected to a drive shaft. The flow divider shaft can be connected to the drive shaft via a coupling. The flow divider shaft can be a main shaft. The main shaft can be fixedly attached to the flow divider and configured to rotate with the flow divider. The main shaft can be rotatably mounted in a radial bearing. This arrangement helps to make the main shaft resist bending loads and radial loads. The length of the main shaft can be such that the main shaft does not extend beyond the chuck.

[0046] The diverter may be configured to divert drilling fluid relative to the longitudinal axis of the subassembly. The diverter may include an eccentric diverter orifice for diverting drilling fluid. In this arrangement, the diverter orifice is offset from the longitudinal axis of the subassembly so that the drilling fluid is diverted away from the longitudinal axis, which helps divert the drilling fluid to a section of the wellbore via an outlet in the drill bit.

[0047] The flow diverter may comprise a plate or plate member arranged to prevent the drilling fluid from flowing between the inlet of the drill bit and the outlet of the drill bit. The plate or plate member may be a disc-shaped plate. The flow diverter orifice may comprise an arc-shaped opening in the plate or plate member.

[0048] The diverter orifice may be configured to communicate with at least one inlet of an outlet of the drill bit. The diverter may be configured to direct substantially all of the drilling fluid to the inlet of a single outlet of the drill bit. In this arrangement, substantially all of the drilling fluid will leave the drill bit from a single outlet within a relatively narrow section of the wellbore.

[0049] The flow diverter may be removably coupled to the drill bit. Where the flow diverter is part of a collet adapted to be received within an interior space of the drill bit, the collet may be removably coupled to the drill bit.

[0050] The subassembly may include a generator for powering the motor assembly. The generator may be configured to generate electrical power for powering the motor assembly. The generator may be electrically connected to the motor assembly. The generator may be located within the housing portion. The generator may be rotationally fixed to the housing portion. The generator may be located above the well of the motor assembly. The generator may include a turbine. The turbine may be configured to be driven by drilling fluid. The generator may include a stator. The stator may be rotationally fixed relative to the generator.

[0051] According to another example of the present disclosure, a directional drilling system including the subassembly described herein is provided.The drilling system may include a drill string.

[0052] According to another example of the present disclosure, a kit of parts for forming the subassembly described herein is provided. The kit of parts includes a drill bit, a flow diverter, and a housing portion, wherein the housing portion includes a motor assembly. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] Embodiments of the present disclosure are described in more detail below, by way of example only, with reference to the accompanying drawings, in which:

[0054] Figure 1 depicts a schematic diagram of a subassembly according to the present disclosure located within a wellbore;

[0055] Figure 2 is a longitudinal cross-section of a rotary drill bit of the subassembly, the rotary drill bit being configured to receive a chuck including a flow diverter;

[0056] Figure 3 yes Figure 2 Plan view of the drill bit.

[0057] Figure 4 yes Figure 2 A longitudinal section of an upper portion of a drill bit showing a chuck received in the drill bit;

[0058] Figure 5A yes Figure 4 A longitudinal section of the chuck's flow divider and spindle;

[0059] Figure 5B yes Figure 4 A rear or downhole view of the chuck's diverter and spindle;

[0060] Figure 6 yes Figure 4 A perspective view of the support hanger of the chuck.

[0061] Figure 7 yes Figure 2 A longitudinal section of an upper portion of a drill bit showing a chuck received in the drill bit;

[0062] Fig. 8A yes Figure 7 A longitudinal section of the chuck's flow divider and spindle;

[0063] Figure 8B yes Figure 7 A rear or downhole view of the chuck's diverter and spindle;

[0064] 9A to 9D yes Figure 4 and Figure 7 a plan view of an assembly of a drill bit and a chuck showing different positions of a flow diverter orifice in a flow diverter relative to one or more drill bit windows of a nozzle of the drill bit;

[0065] Fig. 10A yes Figure 4 and Figure 7 A schematic illustration of a drill bit and chuck assembly connected to a housing portion and arranged in a wellbore in a subterranean formation. The figure also illustrates the forces acting on the drill bit due to the use of a flow diverter;

[0066] Fig. 10B yes Fig. 10A an above-the-hole view of the arrangement shown;

[0067] Fig.11 Describes the operation Figure 1 Control system diagram of the shunt. DETAILED DESCRIPTION

[0068] Figure 1 A schematic diagram of a subassembly 400 according to the present disclosure is depicted. The subassembly 400 is located within a wellbore 301. The subassembly 400 includes a drill bit 1 configured to rotate in a first direction about a longitudinal axis 401 of the subassembly 400. The drill bit 1 includes an inlet 14 for receiving a drilling fluid and nozzles 24a, 24b for allowing the drilling fluid to exit the drill bit 1. The drill bit 1 includes a mechanical cutting device 4 for drilling a wellbore. The subassembly 400 also includes a diverter 106 configured to rotate in a second direction about a longitudinal axis 401 of the subassembly 400, wherein the flow direction of the drilling fluid exiting the drill bit 1 is determined by the rotational position of the diverter 106 about the longitudinal axis 401 of the subassembly. The subassembly 400 also includes a housing portion 410 connected to the drill bit 1 at a downhole end of the housing portion 410 via a threaded connection 412. The housing portion 410 is in the form of a tubular collar which encloses a space for the components of the subassembly 400 .

[0069] The drill string 200 is connected to the uphole end of the housing portion 410. During use, the drill string 200 is configured to rotate in a first direction, thereby rotating the housing portion 410 and the drill bit 1 in the first direction. The drill string 200 also supplies drilling fluid to the housing portion 410 at the uphole end 402 of the subassembly 400. The drilling fluid flows through the housing portion 410 to the inlet 14 of the drill bit 12. The drilling fluid leaves the nozzles 24a, 24b of the drill bit 1 at the downhole 403 end of the subassembly 400. The subassembly 400 further includes a motor assembly 420 located within the housing portion 410. The motor assembly 420 includes a motor assembly housing 421, which is fixed to the housing portion 410 in a rotational sense by a support hanger 411a. The support hanger 411a has a plurality of orifices (not shown) that are used to allow the drilling fluid to flow through the housing portion 410 to the inlet 14 of the drill bit 1. The motor assembly 420 also includes a drive shaft 128 that is rotatable relative to the motor assembly housing 421. The uphole end of the drive shaft 128 is coupled to a DC brushless motor that is configured to rotate the drive shaft 128 in a second direction. The downhole end of the drive shaft 128 is coupled to the diverter 106 so that the drive shaft 128 and the diverter 106 rotate together. The subassembly 400 further includes a control unit 430 located within the housing portion 410, which provides control signals to the motor assembly 420 for controlling the rotational position of the diverter 106. The control unit 430 is rotationally fixed to the housing portion 410 by a support hanger 411b. The subassembly 400 further includes a generator 440 for powering the motor assembly 420. The generator 440 is located within the housing portion 410 and is rotationally fixed to the housing portion 410 by a support hanger 411c. The generator 440 includes a turbine 441 configured to be driven by drilling fluid flowing through the housing portion 410 .

[0070] Figure 2 The rotary drill bit 1 of the subassembly 400 is shown in more detail. The drill bit 1 is a polycrystalline diamond compact (PDC) drill bit. However, it should be understood that the subassembly 400 of the present disclosure may include other types of drill bits. The drill bit 1 includes a drill bit body or shank 2, which is provided with a mechanical cutting device in the form of a PDC cutter 4. The cutter 4 forms a drill bit face 6 at the downhole end of the drill bit 1. During drilling, the drill bit face 6 faces the bottom of the wellbore 301 and is located near it. The longitudinal axis of the drill bit 1 is indicated by line AA.

[0071] A threaded pin connection 10 is provided at the uphole end 12 of the drill bit 1 for connecting the drill bit 1 to the housing portion 410. The drill bit 1 has an inlet port 14 for receiving drilling fluid from the drill string 200 via the housing portion 410. The inlet port 14 is the entrance to a shank bore 16 which defines an interior space 18 within the drill body 2 of the drill bit 1. A plurality of drill bit windows 20 are formed in the bottom of the shank bore 16. Each drill bit window 20 marks the entrance to a fluid passage 22 which extends from the drill bit window 20 to a nozzle 24 formed in the drill bit face 6. It should be noted that the drill bit 1 has three fluid passages 22 and associated drill bit windows 20 and nozzles 24, but two of the fluid passages are not in the drill bit face 6. Figure 2 are shown in the figure because they are out of the plane of the section. Figure 3 Three drill windows 20 can be seen marking the entrance to each of the three fluid channels.

[0072] Drilling fluid (not shown) enters the drill bit 1 via the inlet port 14, then flows through the drill bit 1 via the shank hole 16 and each of the plurality of fluid passages 22 to the nozzles 24, where the drilling fluid is ejected from the drill bit 1. The drilling fluid flows between the drill bit 1 and the wall of the wellbore (not shown), around the outside of the drill bit, and then flows back along the outside of the drill string to the surface, where it is recycled. The drilling fluid helps lubricate the drilling operation and carries drill cuttings out of the wellbore and back to the surface.

[0073] Figure 3 Shows Figure 2 1. Three drill windows 20 are formed at the bottom of the shank hole 16 and communicate with the nozzle 24 via the fluid passage 22. Each drill window 20 is formed as a circular sector and sweeps an angular arc of about 85 degrees. A drill web 26 is arranged between each pair of drill windows 20 to separate each of the fluid passages 22.

[0074] Figure 4 Shows Figure 21, which shows a chuck 100 received in the shank bore 16 of the drill bit 1. The chuck 100 includes an upper chuck bushing 102a and a lower chuck bushing 102b, which form the housing of the chuck 100. The chuck bushings 102a and 102b are generally tubular in form, and the outer surfaces of the bushings 102a and 102b are closely matched with the inner surface of the shank bore 16. The chuck bushings 102a and 102b rotate with the drill bit 1. The internal space within the bushings 102a and 102b defines a chamber for receiving drilling fluid from a drill string (not shown) via the housing portion 410. The drilling fluid enters the chuck 100 via an opening 104 in an uphole end or inlet end 105 of the upper chuck bushing 102a. The drilling fluid exits the chuck 100 at the downhole or outlet end 107 of the lower chuck bushing 102b.

[0075] The flow diverter 106 is located at the downhole end or outlet end 107 of the lower chuck bushing 102b and is rotatably mounted on a spindle 108 so that the flow diverter 106 can be separated from the rotation of the drill bit 1 and rotated independently of the drill bit 1. The spindle 108 is fixedly attached to a central shaft ring arranged at the uphole side of the flow diverter 106 and rotates with the flow diverter 106. The flow diverter 106 takes the form of a disk or shallow cylinder, and the length of the flow diverter is less than its diameter. The cylindrical outer surface of the flow diverter 106 forms a close fit with the inner surface of the lower chuck bushing 102b. The flow diverter 106 has an eccentrically positioned diverter orifice 110 to allow the drilling fluid to flow out of the chuck 100 and reach one or more flow channels 22 formed in the drill bit 1. The flow diverter 106 diverts the drilling fluid to the diverter orifice 110 relative to the longitudinal axis AA of the chuck 100 and the drill bit 1. The flow diverter 106 closes the outlet end 107 of the chuck 100 , but the drilling fluid can pass through the diverter orifice 110 .

[0076] The flow diverter 106 is mounted on a first thrust bearing 112, which is located at the outlet end 107 of the lower chuck bushing 102b. The first thrust bearing 112 includes a pin bearing having a male pin component 112a and a female pin component 112b for receiving and supporting the male pin component 112a, the male pin component being arranged in a central hole formed in the downhole end of the flow diverter 106, and the female pin component being located in a central recess formed in the bottom of the shank hole 16. The first thrust bearing 112 helps the flow diverter 106 to withstand the axial hydraulic loads applied to the flow diverter by the columnar drilling fluid above the flow diverter 106. This arrangement helps the flow diverter 106 to rotate freely even under high hydraulic loads experienced during drilling operations. It has been found that the use of a centrally mounted thrust bearing as the first thrust bearing 112 provides better performance than a circumferentially mounted thrust bearing.

[0077] The bottom section of the lower collet bushing 102b has a recess 114 that surrounds the inner surface of the lower collet bushing 102b. The recess 114 receives the cylindrical wall of the diverter 106 so that the inner surface of the cylindrical wall of the diverter 106 is flush with the inner surface of the upper section of the cylindrical lower bushing. This arrangement reduces the obstruction of fluid flow through the collet 100 and reduces the hydraulic load on the diverter 106.

[0078] The spindle 108 is supported along its length by a bearing hanger or support hanger 116. The support hanger 116 includes an inner tubular member 118 through which the spindle passes and an outer tubular member 120 which is received in recessed portions of the abutments of the upper and lower chuck bushings 102a, 102b. The support hanger 116 rotates with the chuck bushings 102a and 102b which in turn rotate with the drill bit 1. Three support legs 122 ( Figure 4 The support legs 122 (only two support legs are shown) span the annular gap between the inner tubular member 118 and the outer tubular member 120 and support the inner tubular member 118. The three support legs 122 are evenly spaced circumferentially around the inner tubular member 118, and the spacing between the three support legs 122 allows drilling fluid to flow through the annular gap between the inner tubular member 118 and the outer tubular member 120 of the support hanger 116.

[0079] A radial bearing 124 is disposed within the hanger support 116 between the inner tubular member 118 and the main shaft 108. The radial bearing 124 helps the diverter 106 withstand the bending and side loads imposed on the diverter 106 and the main shaft 108 during drilling operations. This reduces the rotational resistance on the diverter 106 and helps the diverter 106 to rotate freely even under high gravity loads and vibration loads experienced during drilling operations. The radial bearing 124 also helps support the main shaft 108 and prevent the main shaft 108 and the diverter 106 from rotating with the support hanger 116 and the drill bit 1.

[0080] The second thrust bearing 126 is disposed between the radial bearing 124 and the diverter 106. The second thrust bearing 126 helps the diverter 106 to withstand the axial load generated by the vibration and bounce of the drill bit 1 during the drilling operation.

[0081] The first thrust bearing 112 , the second thrust bearing 126 and the radial bearing form a bearing assembly of the chuck 100 .

[0082] The uphole end of the main shaft 108 is connected to a drive shaft 128 for connecting the main shaft 108 and the diverter 106 to a motor assembly 420. The motor assembly is used to control the rotational position of the diverter 106. The motor assembly 420 can be used to keep the diverter stationary relative to the ground while the drill bit 1 rotates around the diverter. Therefore, the motor assembly 420 can be used to control the angular position of the diverter orifice 110 from which the drilling fluid exits the shank hole 16 of the drill bit 1.

[0083] The chuck 100 is adapted to be fully received within the shank bore 16 of the drill bit 1 and is retained in the shank bore 16 by a retaining clip 130, which can be quickly attached or removed. The shank bore 16 can be modified to receive the chuck 100. The chuck 100 can be easily and quickly assembled to a properly adapted drill bit 1 at the drilling site.

[0084] Figure 5A and Figure 5B Shown in more detail Figure 4 The flow divider 106 and the main shaft 108 are provided. Figure 5A 1 is an uphole perspective longitudinal cross-sectional view of the main shaft 108 and the diverter 106. The diverter orifice 110 is formed in the downhole end 106b of the diverter 106 and is radially offset from the longitudinal axis of the diverter 106 and the main shaft 108 indicated by line AA. The diverter orifice 110 is formed as a circular sector and sweeps an angular arc of approximately 85 degrees. However, it should be understood that the angular arc of the diverter orifice 110 can be changed or adjusted depending on the drill bit to which the chuck 100 is to be assembled and the required performance. The remainder of the downhole end 106b of the diverter 106 is closed and forms a flow-blocking portion 111, which prevents drilling fluid from flowing through this portion of the diverter 106.

[0085] A recess 132 is formed in the downhole end 106b of the diverter 106, which is located substantially diametrically opposite to the diverter orifice 110. The recess 132 reduces the weight of this portion of the diverter 106 and helps to balance the diverter 106 when rotating by reducing unbalanced rotational forces. This also helps to reduce the rotational resistance acting on the diverter 106 during drilling operations. The cylindrical wall 134 of the diverter 106 extends away from the downhole end 106b of the diverter 106 in the uphole direction. The main shaft 108 is fixedly attached to the center shaft ring 136 arranged on the uphole side of the diverter 106. A center hole 133 is provided in the downhole end 106b of the diverter 106 to accommodate the male pin component of the first thrust bearing (not shown).

[0086] Figure 5B yes Figure 41 and 108. The cylindrical wall 134 defines an opening 138 at the uphole end 106a of the diverter 106 for receiving drilling fluid. A protrusion or peak 140 is formed at the uphole side of the diverter 106, which aligns with a recess 132 formed on the downhole side (see FIG. Figure 5A ). On both sides of the peak 140 facing the diverter orifice 110, the internal profile of the uphole side of the diverter 106 is inclined toward the downhole end 106b of the diverter 106. Therefore, a gradient is formed between the peak 140 (on either side of the peak 140) and the diverter orifice 110, which helps to divert the drilling fluid flow incident on the uphole side of the diverter 106 toward the diverter orifice 110. Compared with a flat surface perpendicular to the fluid flow direction, the gradient prevents the drilling fluid from stopping suddenly at the uphole side of the flow converter 106, thereby reducing the axial hydraulic load on the diverter 106.

[0087] Figure 6 The support hanger 116 of the chuck 100 of FIG. 5 is shown in more detail. The support hanger 116 includes an inner tubular member 118 having an internal passage 119 for mounting a radial bearing (not shown) which in turn holds a spindle (not shown). An outer tubular member 120 is also provided and three support legs 122 span the annular gap between the inner tubular member 118 and the outer tubular member 120. The three support legs 122 support the inner tubular member 118 and are evenly spaced circumferentially around the inner tubular member 118. The spacing or orifices 123 between the three support legs 122 allow drilling fluid to flow through the annular gap between the inner tubular member 118 and the outer tubular member 120 of the support hanger 116.

[0088] Figure 7 Shows Figure 2 1 , which shows another embodiment of a chuck 100 received in the shank hole 16 of the drill bit 1 . Figure 7 The structure of the chuck 100 is Figure 4 The chuck 100 is similarly constructed and Figure 7 The same reference numerals are used throughout to refer to the same parts. Figure 7 The chuck 100 with Figure 4 The main difference between the chucks of is the configuration of the diverter 106, the second thrust bearing 126 and the radial bearing 124. Fig. 8A and Figure 8B The differences between shunts are discussed.

[0089] Similar to Figure 4 , Figure 7The second thrust bearing 126 of the chuck 100 is arranged between the radial bearing 124 and the diverter 106. The second thrust bearing 126 helps the diverter 106 to withstand the axial load generated by the vibration and bounce of the drill bit 1 during the drilling operation. Figure 7 1 , the second thrust bearing 126 includes a spring 127 that acts as a biasing member and biases the position of the diverter 106 in the axial direction. The spring acts in two directions: i) biasing the diverter 106 toward the outlet end 107 of the chuck 100 to engage the first thrust bearing 112; and ii) biasing the second thrust bearing 126 against the radial bearing 124. This helps to keep the diverter in a fixed position at the outlet end 107 of the chuck 100, and helps to reduce vibration or bounce experienced by the diverter 106, which may otherwise cause damage to the diverter 106.

[0090] Similar to Figure 4 , Figure 7 The radial bearing 124 of the chuck 100 is disposed within the support hanger 116 and holds the spindle 108. The radial bearing 124 helps the diverter 106 withstand the bending loads and side loads imposed on the diverter 106 and the spindle 108 during drilling operations. Figure 7 , the radial bearing 124 includes a spacing member 124c and two contact members 124a and 124b, which are arranged at each longitudinal end of the spacing member 124c. The contact members 124a and 124b contact the main shaft to provide bearing support. The spacing member 124c does not contact the main shaft 108, but only provides structural support to the contact members 124a and 124b. This arrangement reduces the contact area of ​​the radial bearing 124 with the main shaft 108, which helps to reduce the friction between the radial bearing 124 and the main shaft 108. The contact members 124a and 124b are made of tungsten carbide and / or polycrystalline diamond. The length of the main shaft 108 in the radial bearing 124 is coated with tungsten carbide to provide a wear-resistant surface and extend the service life of the chuck 100.

[0091] Fig. 8A and Figure 8B Shown in more detail Figure 7 The flow divider 106 and the main shaft 108 are provided. Fig. 8A 1 is an uphole perspective longitudinal cross-sectional view of the flow diverter 106 and the spindle 108. The flow diverter 106 includes a generally disc-shaped plate 109 disposed at the downhole end 106b of the flow diverter 106. A notch is formed in the outer circumference of the disc-shaped plate 109 to form a diverter orifice 110 that is radially offset from the longitudinal axis of the flow diverter 106 and the spindle 108 indicated by line AA. The outer circumference of the disc-shaped plate 109 is disposed to align with the chuck 100 (see FIG. 1 ). Figure 7) is closely conformed to the inner circumference of the housing so that substantially all of the drilling fluid flows through the diverter orifice 110. A central hole 133 is provided in the downhole end 106b of the diverter 106 to accommodate the male pin component of the first thrust bearing (not shown).

[0092] Figure 8B yes Figure 7 106 and the main shaft 108 of the downhole stereogram. As can be seen in this figure, the diverter orifice 110 is formed as a circular sector and sweeps an angular arc of approximately 85 degrees. However, it should be understood that the angular arc of the diverter orifice 110 can be changed or adjusted depending on the drill bit to which the chuck 100 is to be assembled and the required performance. The remainder of the downhole end 106b of the diverter 106 is closed and forms a flow blocking portion 111, which prevents drilling fluid from flowing through this portion of the diverter 106. The central shaft ring or hub 136 is arranged at the uphole end 106a of the disc plate 109 and extends in the uphole direction. The main shaft 108 is fixedly attached to the central hub 136. An annular recess 137 is formed at the uphole end of the central hub 136 to accommodate a spring and a portion of a second thrust bearing (not shown).

[0093] 9A to 9D yes Figure 4 and Figure 7 A plan view of an assembly of a drill bit 1 and a chuck 100, each showing the diverter orifice 110 of the diverter 106 relative to Figure 3 The drill bit 1 is shown with one or more of the drill window 20 and the drill belly 26 being located at different positions.

[0094] exist Fig.9A 1, the flow diverter orifice 110 in the flow diverter 106 is fully aligned with one of the drill bit windows 20 of the drill bit 1. The flow area of ​​the fluid path through the orifice 110 and the drill bit window 20 is maximized. Therefore, the flow rate of the drilling fluid flowing through the fluid path is minimized, and this configuration minimizes the pressure drop. The other two drill bit windows (not shown) of the drill bit 1 are blocked or blocked by the flow blocking portion 111 of the flow diverter 106, so that substantially no drilling fluid flows through these drill bit windows.

[0095] exist Fig. 9B In the embodiment, the flow diverter 106 rotates counterclockwise by a small angular distance, and at this time, the flow diverter orifice 110 in the flow diverter 106 is partially blocked by one of the drill bit bellies 26 of the drill bit 1. Fig.9A Compared to the situation shown in FIG. 1 , the flow area of ​​the fluid path through the diverter orifice 110 and the drill bit window 20 is reduced. Therefore, the flow rate of the drilling fluid flowing through the fluid path increases, and the pressure drop increases.

[0096] exist Fig. 9CIn the embodiment of the present invention, the flow divider 106 is further rotated counterclockwise by a smaller angular distance, and at this time, the entire width of the drill bit belly 26 falls into the flow divider orifice 110 in the flow divider 106, that is, the drill bit window is blocked to the maximum extent by the drill bit belly 26. The flow area of ​​the fluid path passing through the flow divider orifice 110 and the drill bit window 20 is the smallest. Therefore, the flow rate of the drilling fluid flowing through the fluid path is the largest, and this configuration makes the pressure drop the highest.

[0097] exist Fig.9D In the embodiment, the diverter 106 is further rotated counterclockwise by a smaller angular distance. Fig. 9C As in the previous embodiment, the full width of the drill bit belly 26 falls into the orifice 110 in the diverter 106, i.e. the drill bit window is also maximally blocked by the drill bit belly 26. However, this time, the diverter orifice 110 spans across two drill bit windows 20. The flow area of ​​the fluid path through the orifice 110 and the drill bit window 20 is minimal. Therefore, the flow rate of the drilling fluid through the fluid path is the greatest, and this configuration gives the highest pressure drop, but this time, the fluid flow is distributed over the two drill bit windows, which in turn communicate with corresponding nozzles in the drill bit 1.

[0098] 9A to 9D The rotation of the diverter 106 is shown to illustrate how the diverter can be communicated with the drill bit window 20 of the drill bit 1. However, during directional drilling operations, the diverter 106 will remain geostationary at a fixed angular position relative to a particular sector of the wellbore while the drill bit 1 rotates about the diverter. The rotation of the drill bit will successively rotate the drill bit window 20 of the drill bit 1 into temporary alignment with the diverter orifice 110. Therefore, as the drill bit windows 20 are each communicated with the diverter orifice 110, the drilling fluid will be 9A to 9C As shown as a single stream from a single nozzle out of the rotating drill head 1, or as Fig.9D As shown, dual streams are discharged from two nozzles from the rotating drill bit. However, each of these streams is discharged sequentially only into a specific sector of the wellbore corresponding to the angular position of the diverter orifice 110.

[0099] Fig. 10A yes Figure 4 and Figure 7 Schematic side view of an assembly of a drill bit 1 and a chuck (not shown) in operation at a particular point in time. The drill bit 1 is connected to a housing portion 410 and arranged in a wellbore 301 of an underground formation 300. Fig. 10B yes Fig. 10A 4 and 5. An uphole view of an arrangement of the drill bit 1 showing the cutter 4 and the drilling fluid nozzles 24a, 24b and 24c arranged on the drill face 6 of the drill bit 1.

[0100] exist Fig. 10A and Fig. 10BIn the present invention, the drill bit 1 is rotated by the drill string 200 using a drive system (not shown) located at the surface, or a mud motor (not shown) downhole, or both. The diverter is connected to a motor assembly, which is contained in the housing portion 410. The motor assembly rotates the diverter (not shown) in the opposite direction at substantially the same rotational speed as the drill bit 1, so that the diverter remains stationary relative to the wellbore 301 at a constant angular position. The diverter orifice (not shown) of the diverter is located at Fig. 10A The drilling fluid is angled in the azimuth direction of the arrow B in FIG. 1 , which corresponds to the desired direction of travel. Thus, as the nozzles are successively aligned with the diverter orifices, the drilling fluid will be discharged from the drill bit 1 into a specific sector of the wellbore 301 corresponding to the angular position of the diverter orifice of the diverter. At this specific point in time, the drilling fluid is discharged as a single high velocity stream through Fig. 10B The nozzle 24a in the wellbore 301 leaves the drill bit 1. The drilling fluid flow hits the bottom of the wellbore 301, then quickly reverses direction and flows back to the surface through the annular space formed between the housing part 410 and the wellbore 301. Diverting the drilling fluid in this way causes the drill bit 1 to turn in the direction of arrow B.

[0101] Without being limited by theory, it is believed that there are four physical mechanisms involved in steering the drill bit 1. The first physical mechanism is a hydraulic effect caused by a pressure differential around the circumference of the drill bit 1. A fluid flow with a high velocity has a lower static head pressure when compared to a fluid flow with a lower velocity. This phenomenon is well understood and governed by Bernoulli's fluid energy equation. Thus, the backflow of the face diversion around a section of the drill bit 1 creates a pressure differential around the circumference of the rotating drill bit, which is directed along the Fig. 10A The direction of arrow B in FIG. 1 pulls the drill bit 1 toward the diverted flow (whose pressure is lower relative to the rest of the drill bit circumference). In fact, the drill bit 1 is pulled against the formation, thereby providing a side force that biases the drill bit.

[0102] The second physical mechanism is also a hydraulic effect, which occurs in addition to the Bernoulli effect. This mechanism occurs when the split fluid flow ejects the nozzle 24a and hits the underground formation 300, then quickly changes direction and flows around the drill bit (as described above). This causes the drilling fluid to accelerate rapidly at the boundary of the formation 300, which in turn causes high positive pressure to act on sections of the drill bit face 6, such as Fig. 10A This is indicated by the arrow A in Fig.9A The bending moment represented by the arrow C in the figure deflects the drill string above the drill bit 1, thereby creating an angle between the drill bit face 6 and the formation 300.

[0103] The two hydraulic effects described above (ie, Bernoulli and high bit face pressure) are complementary and serve to deflect and tilt the drill bit toward a desired tool face.

[0104] The third physical mechanism is preferential erosion at the drill bit face 6, which is caused by the fluid being biased in one drill head section. The high fluid flow rate caused by the injection at the drill bit face as described above will produce an abrasive imbalance at the drill bit face 6. The abrasive rate is proportional to the fluid flow rate, so the drill bit face areas with high fluid flow rate experience higher abrasive rates than areas with lower fluid flow rate. In simple terms, material in front of the drill bit is eroded or washed away, which reduces the "cutting" requirements and the bias direction is more global as the drill bit advances in the "path of least resistance".

[0105] The fourth physical mechanism is similar to the third mechanism, but in this case it involves erosion around the shoulder or side of the drill bit 1. In the case where the discharged drilling fluid is diverted in a low pressure area and returned to the surface (see the first physical mechanism above), there will be an erosion imbalance at the drill bit face due to areas of high fluid acceleration. These abrasive and erosive effects will preferentially remove formation material at areas of high flow velocity and acceleration at the drill bit face. This causes the drill bit 1 to be biased towards areas where the formation is preferentially reduced.

[0106] Once the directional drilling operation is complete and the subassembly and drill string are pointed in the desired direction, the drill bit can be returned to drilling in a straight line. To drill in a straight line, the diverter is rotated at a controlled absolute rotational speed so that the drilling fluid is delivered to the nozzles of the drill bit at substantially all angular positions so that there is no overall lateral force on the drill bit.

[0107] Fig.11 Describes the operation Figure 1 The control system diagram of the shunt. Fig.11As shown, the housing portion 410 is coupled to a sensor assembly 500, which includes a plurality of sensing devices or sensors, namely an accelerometer 501, a magnetometer 502 and a gyroscope 503. Each of these sensors is arranged to measure the position parameters of the housing portion 410 and relay these position parameters to a processing unit 504 for further calculation and / or analysis. Then, the data output from the processing unit 504 is relayed to a proportional integral (PI) controller 505. The PI controller also receives a feedback signal from a sensor 507, which is coupled to the drive shaft 128 of the motor assembly. The sensor 507 can be a Hall effect sensor or a position resolver, which detects the rotational position of the drive shaft 128. Therefore, the PI controller 505 is provided with the position parameters of the housing portion 410 and the position parameters of the drive shaft 128, which enables the PI controller 505 to output a continuously modulated control signal for the motor. The output signal is fed to a control unit 508, which is coupled to the motor assembly 420. The control unit 420 may thereby provide a control signal to the motor assembly to control the rotational position of the drive shaft 128 , thereby controlling the rotational position of the diverter 106 .

Claims

1. A subassembly for a directional drilling system configured to drill a wellbore, the subassembly comprising: a drill bit configured to rotate in a first direction about a longitudinal axis of the subassembly, the drill bit comprising an inlet for receiving a drilling fluid and an outlet for allowing the drilling fluid to exit the drill bit; a flow diverter configured to rotate in a second direction about the longitudinal axis of the subassembly, wherein a flow direction of drilling fluid exiting the drill bit is determined by a rotational position of the flow diverter about the longitudinal axis of the subassembly; a housing portion connected to the drill bit; a motor assembly located within the housing portion, the motor assembly including a motor assembly housing rotatably fixed to the housing portion and a drive shaft rotatable relative to the motor assembly housing, the drive shaft coupled to the diverter; and Wherein, the motor assembly is configured to operate the drive shaft to control the rotational position of the diverter.

2. The subassembly according to claim 1, wherein: The flow splitter is mounted on a flow splitter shaft, and wherein the flow splitter shaft is connected to the drive shaft via a releasable coupling.

3. The subassembly according to claim 2, wherein: The releasable coupling is a universal coupling.

4. The subassembly according to claim 2, wherein: The releasable coupling is a universal coupling.

5. A subassembly according to any preceding claim, wherein: The flow diverter is located within a collet that is configured to be received within an interior space of the drill bit.

6. The subassembly according to claim 5, wherein: The collet is removably coupled to the drill bit.

7. A subassembly according to any preceding claim, wherein: The motor assembly is configured to maintain the flow diverter geostationary relative to the wellbore while the drill bit rotates within the wellbore.

8. The subassembly according to claim 7, wherein: The motor assembly is configured to maintain the flow diverter geostationary relative to the wellbore by rotating the flow diverter about a longitudinal axis of the subassembly.

9. The subassembly according to claim 7 or 8, wherein: The motor assembly is configured to maintain the flow diverter geostationary relative to the wellbore by adjusting a rotational speed of the flow diverter about a longitudinal axis of the subassembly.

10. A subassembly according to any preceding claim, wherein: The motor assembly is configured to rotate the diverter in the first direction; and / or Wherein, the motor assembly is configured to rotate the diverter in the second direction.

11. The subassembly according to claim 10, wherein: The motor assembly is configured to rotate the diverter in the second direction when the drill bit rotates in the first direction.

12. A subassembly according to any preceding claim, wherein: The motor assembly is configured to rotate the flow diverter at the same rotational speed as the drill bit.

13. A subassembly according to any preceding claim, wherein: The motor assembly is configured to rotate the diverter in the second direction at a same rotational speed as a rotational speed of the drill bit in the first direction.

14. A subassembly according to any preceding claim, comprising a sensing device configured to provide a sense signal to the motor assembly for controlling the rotational position of the shunt.

15. The subassembly of claim 14, wherein: The sensing device is configured to determine the rotational speed of the drill bit; and / or wherein the sensing device is configured to determine a rotational speed of the diverter; wherein the sensing device is configured to determine a rotational position of the diverter about a longitudinal axis of the subassembly; and / or Wherein, the sensing device is configured to determine the rotational position of the diverter relative to the wellbore.

16. A subassembly according to any preceding claim, wherein: The motor assembly is secured to the housing portion by a support member.

17. The subassembly of claim 16, wherein: The support member includes one or more apertures for allowing drilling fluid to flow through the housing portion to an inlet of the drill bit.

18. A subassembly according to claim 16 or 17, wherein: The support member is configured to radially center the motor assembly within the housing portion.

19. A subassembly according to any one of claims 16 to 18, wherein: The support member is a support hanger.

20. A subassembly according to any preceding claim, wherein: The drive shaft is at least partially located within the motor assembly housing; and / or Wherein, the drive shaft extends from the motor assembly housing.

21. A subassembly according to any preceding claim, wherein: The motor assembly includes an electric motor.

22. The subassembly of claim 21, wherein: The electric motor is a DC motor; and / or Wherein, the electric motor is a brushless motor.

23. A subassembly according to any preceding claim, wherein: The motor assembly comprises a reduction gearbox, and optionally wherein the reduction gearbox is located within the motor assembly housing.

24. A subassembly according to any preceding claim, wherein: The motor assembly comprises a position resolver, and optionally wherein the position resolver is located within the motor assembly housing.

25. A subassembly according to any preceding claim, wherein: The motor assembly housing includes one or more voids that are filled with oil.

26. A subassembly according to any preceding claim, wherein: The motor assembly housing pressure compensates for hydrostatic pressure from the drilling fluid.

27. A subassembly according to any preceding claim, wherein: The flow diverter is located within the drill bit, and optionally, wherein the flow diverter is located between an inlet of the drill bit and an outlet of the drill bit.

28. A subassembly according to any preceding claim, wherein: The inlet of the drill bit is located at a first end of the drill bit; and / or Wherein, the outlet of the drill bit is located at the second end of the drill bit.

29. A subassembly according to any preceding claim, wherein: The outlet of the drill bit includes a first outlet and a second outlet.

30. The subassembly of claim 29, wherein: An arc measurement between a center of the first outlet and a center of the second outlet is greater than 90 degrees.

31. A subassembly according to any one of claims 29 to 30, wherein: The first outlet and the second outlet are located diametrically opposite each other.

32. A subassembly according to any one of claims 29 to 31, wherein: The flow diverter is configured to selectively divert drilling fluid to one of a first outlet of the drill bit and a second outlet of the drill bit.

33. A subassembly according to any one of claims 29 to 32, wherein: The diverter is configured to allow drilling fluid to flow between an inlet of the drill bit and a first outlet of the drill bit, and to substantially prevent drilling fluid from flowing between the inlet of the drill bit and a second outlet of the drill bit, when the diverter is in a first rotational position and the drill bit is in a first rotational position.

34. A subassembly according to any preceding claim, wherein: The flow diverter includes an eccentric flow diverting orifice for diverting the drilling fluid.

35. A subassembly according to any preceding claim, wherein: The flow diverter is removably coupled to the drill bit.

36. A subassembly according to any preceding claim, comprising a generator for powering the motor assembly.

37. The subassembly of claim 36, wherein: The generator is located within the housing portion; and / or Therein, the generator is rotatably fixed to the housing portion.

38. A subassembly according to any one of claims 36 to 37, wherein: The generator is located uphole from the motor assembly.

39. A subassembly according to any one of claims 36 to 38, wherein: The generator includes a turbine configured to be driven by the drilling fluid.

40. A directional drilling system comprising the subassembly of any one of claims 1 to 39.

41. The directional drilling system of claim 40, comprising a drill string.

42. A kit of parts for forming a subassembly as claimed in any one of claims 1 to 39, the kit of parts comprising a drill bit, a flow diverter and a housing portion, wherein: The housing portion includes a motor assembly.

Images