SUBASSEMBLY FOR A DIRECTIONAL DRILLING SYSTEM

TECHNICAL FIELD

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 comprising the subassembly, and a kit of parts for forming the subassembly.

BACKGROUND

Typically, natural resources such as oil and gas can be found in subsurface formations. It has been known to use drilling systems for cutting a wellbore in subsurface formations so that the natural resources can be accessed via the wellbore. A known type of drilling system is a rotational or rotary drilling system which may comprise 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 bits. Generally, a drill string is formed of multiple tubular sections or pipes which are added to the drill string as the depth of the wellbore increases. A drill string may comprise a number of components including a drill collar and a stabilizer. In some arrangements, one or more subs are used to connect components of the drilling system. For example, a sub may be used to connect the drill bit to the drill string.

As used herein, the term “downhole” refers to a direction toward or facing the bottom of the wellbore. Furthermore, the term “uphole” refers to a direction toward or facing the top of the wellbore.

During drilling, the drill bit is rotated by rotating the entire drill string using a drive system located at the surface. Generally, the drill bit is provided with mechanical cutters such that, when the drill bit is rotated, drilling cuttings are produced as the drill bit cuts through the formation. The drilling cuttings include portions of loose material from the drilled formation. Drilling fluid or drilling mud is pumped down the inside of the drill string to the drill bit where it passes into the wellbore through nozzles or outlets formed in the drill bit. The drilling fluid helps to lubricate the drilling process and minerals contained in the drilling fluid help to seal the wellbore. Another function of drilling fluid is to carry the drilling cuttings out of the wellbore.

It is often necessary to be able to alter the trajectory of the wellbore as the wellbore is being formed. For example, in the oil and gas industry it may not be possible to drill a vertical wellbore to access natural resources in a subsurface formation. Instead, the wellbore may need to have non-vertical portions, such as horizontal portions, in order to access the natural resources. Thus, it is desirable to provide a directional drilling system in which the trajectory of the wellbore can be altered during drilling through the subsurface formation, such directional drilling can be achieved by a number of methods.

The most common method is to use a positive displacement motor, or mud motor, having a bend at a downhole end. The positive displacement motor is positioned at an uphole end of the drill bit and has a drive shaft which is connected to the drill bit. The passage of drilling fluid through the positive displacement motor causes the drill bit to rotate. The bend of the positive displacement motor causes non-straight sections of wellbore to be formed. In some arrangements, the bend in the positive displacement motor may be variable, however, it is most common to have a fixed bend. A positive displacement motor with a fixed bend means that the drilling system needs to be removed from the wellbore when straight portions of wellbore are desired. 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 costly.

WO2014177505A1 discloses another method of directional drilling which involves controlling the flow direction of drilling fluid exiting the drill bit. The system includes a flow diverter that is kept geostationary with respect to the wellbore at the same time as the drill bit rotates. As the flow diverter is geostationary, it directs an increased flow of drilling fluid in a particular direction within the wellbore. The system includes a first rotatable section that is able to rotate within bearings and that is rotatably decoupled from rotation of the drill string. The first rotatable section has a rotor that is provided with a number of blades. The rotor is caused to rotate in an opposite direction to the drill bit by the flow of drilling fluid. The rotor is connected to the flow diverter to cause rotation of the flow diverter. It is further disclosed that there is a control unit for controlling the rotational speed of a second rotatable section with respect to the first rotatable section, to thereby control the rotational speed of the first rotatable section with respect to the drill string.

The system of WO2014177505A1 is relatively complex due to the use of a rotor having rotor blades to drive the flow diverter, and the need for a complex system for controlling the speed of the rotor connected to the flow diverter. The system is also complicated by the use of bearings within which the first rotatable section rotates. The rotor blades and bearings are exposed to the drilling fluid. This may lead to degraded performance of these parts over time. For example, contamination of one or more of the bearings may result in increased friction in the bearing. This may lead to suboptimal rotation of the flow diverter.

It is desirable to provide a directional drilling system that is less complex compared to some prior art systems and that may be less susceptible to degraded performance over time.

SUMMARY OF INVENTION

According to an example of the present disclosure, there is provided a subassembly for a directional drilling system configured to drill a wellbore. The subassembly comprises a drill bit configured to rotate about a longitudinal axis of the subassembly in a first direction. The drill bit comprises an inlet for receiving drilling fluid and an outlet for allowing drilling fluid to exit the drill bit. The subassembly also comprises a flow diverter configured to rotate about the longitudinal axis of the subassembly in a second direction, wherein the flow direction of drilling fluid exiting the drill bit is determined by a rotary position of the flow diverter about the longitudinal axis of the subassembly. The subassembly also comprises a housing portion connected to the drill bit. The subassembly further comprises a motor assembly positioned within the housing portion. The motor assembly comprises a motor assembly housing rotatably fixed to the housing portion and a drive shaft rotatable relative to the motor assembly housing. The drive shaft is coupled to the flow diverter, and the motor assembly is configured to operate the drive shaft to control the rotary position of the flow diverter.

The provision of a motor assembly means that it is not necessary to provide a turbine that is connected to the flow diverter. The motor assembly housing is rotatably fixed to the housing portion. That is, the motor assembly housing is fixed to the housing portion such that the position and orientation of the motor assembly housing is fixed relative to the housing portion. This means that bearings are not required in order to mount the flow diverter rotation system. Therefore, the number of bearings that are exposed to the drilling fluid can be reduced.

The provision of a motor assembly allows the rotational speed of the flow diverter to be controlled by varying the speed of the motor. This allows for precise control over the rotary position of the flow diverter.

The provision of a motor assembly comprising a motor assembly housing also allows the components of the motor assembly to be protected from the drilling fluid as the drilling fluid flows through the housing portion. This may prolong the service life of the motor assembly components.

As used herein, the term “longitudinal axis of the 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 be coincident with a radially central axis of the subassembly. The longitudinal axis of the subassembly may be coincident with a radially central axis of the drill bit. The longitudinal axis of the subassembly may be coincident with a radially central axis of the flow diverter. The longitudinal axis of the subassembly may be coincident with a radially central axis of the housing portion. The longitudinal axis of the subassembly may be coincident with a radially central axis of the motor assembly. The longitudinal axis of the subassembly may be coincident with a radially central axis of the drive shaft.

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 collar. The housing portion may be a sub. A first end of the housing portion may be configured to connect to a drill string. A second end of the housing portion may be connected to the drill bit. The first end may be opposite the second end.

The flow diverter may be held geostationary to direct drilling fluid into a particular segment of the wellbore. As used herein, the term “geostationary” means stationary or not moving relative to the surrounding subsurface formation or wellbore. For example, the flow diverter can be held geostationary whilst the drill bit rotates about it such that the flow diverter is maintained in the same spatial position in relation to the wellbore. The flow diverter may be decoupled from the rotation of the housing portion. The flow diverter may be decoupled from the rotation of the drill bit.

The motor assembly may be configured to keep the flow diverter geostationary with respect to the wellbore when the drill bit is rotating within the wellbore. The motor assembly may be configured to keep the flow diverter geostationary with respect to the wellbore by rotating the flow diverter about the longitudinal axis of the subassembly. The motor assembly may be configured to keep the flow diverter geostationary with respect to the wellbore by adjusting a rotational speed of the flow diverter about the longitudinal axis of the subassembly. That is, while the flow diverter is rotating, the motor assembly can adjust the rotational speed of the flow diverter, such as increase or decrease the rotational speed, as required to keep the flow diverter geostationary. For example, this may be required if the rotational speed of the drill bit or the housing portion varies, such as due to changes in resistance to drilling. This may be as a result of changes in composition of the material of the subsurface formation or wellbore. Advantageously, a motor assembly may have a fast response time between a command to adjust the rotational speed of the flow diverter and the actual adjustment of the rotational speed of the flow diverter. This allows for accurately keeping the flow diverter geostationary.

The first direction about the longitudinal axis of the subassembly may be opposite to the second direction about the longitudinal axis of the subassembly. The first direction about the longitudinal axis of the subassembly may be clockwise. The second direction about the longitudinal axis of the subassembly may be anticlockwise or counter clockwise. The first direction about the longitudinal axis of the subassembly may be anticlockwise or counter clockwise. The second direction about the longitudinal axis of the subassembly may be clockwise.

The motor assembly may be configured to rotate the flow diverter in the first direction. The motor assembly may be configured to rotate the flow diverter in the second direction. The motor assembly may be configured to rotate the flow diverter in both the first direction and the second direction.

The motor assembly may be configured to rotate the flow diverter in the second direction while the drill bit rotates in the first direction. As the drill string, housing portion and/or the drill bit rotate in a first direction, rotating the flow diverter in the second direction may keep the flow diverter geostationary or may allow the flow diverter to rotate in the first direction at a slower rotational speed than the rotation of the drill string, housing portion and/or the drill bit in the first direction.

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

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.

The subassembly may comprise a sensing means. The sensing means may be configured to provide sensing signals for controlling the rotary position of the flow diverter. Advantageously, this allows the rotary position of the flow diverter to be adjusted based on the actual conditions experienced during drilling. The sensing means may be configured to provide sensing signals to the motor assembly for controlling the rotary position of the flow diverter. The sensing signals may be wirelessly sent between the sensing means and the motor assembly. Advantageously, this reduces the need for complex wiring that must take into account individual rotation of separate components of the subassembly.

The sensing means may comprise an accelerometer. The accelerometer may be for measuring inclination of the subassembly. The accelerometer may be for determining azimuth. The sensing means may comprise a magnetometer. The magnetometer may be for determining azimuth. The accelerometer and the magnetometer may be for determining azimuth. The determination of inclination and azimuth may provide a three-dimensional overview of drilling progress.

The sensing means may be configured to determine the rotational speed of the housing portion. The sensing means may be configured to determine the rotational speed of the drill bit. The sensing means may be configured to determine the rotational speed of the flow diverter. The sensing means may be configured to determine the rotational speed of the motor.

The sensing means may be configured to determine the rotary position of the housing portion about the longitudinal axis of the subassembly. The sensing means may be configured to determine the rotary position of drill bit about the longitudinal axis of the subassembly. The sensing means may be configured to determine the rotary position of the flow diverter about the longitudinal axis of the subassembly. The sensing means may be configured to determine the rotary position of the flow diverter with respect to the wellbore.

The subassembly may comprise a control unit. The control unit may be configured to provide a control signal to the motor assembly for controlling the rotary position of the flow diverter. The sensing means may be configured to provide sensing signals to the control unit. The control unit may be configured to process the sensing signals. The control signal may be based on the processed sensing signals.

The motor assembly may be positioned uphole of the flow diverter. The motor assembly may be fixed to the housing portion by a support member. The support member may be connected to the motor assembly housing.

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 by about 180 degrees from each other. The support member may have three radially extending arms. The three radially extending arms may be positioned about 120 degrees from each other. The support member may have four radially extending arms. The four radially extending arms may be positioned about 90 degrees from each other.

The support member may comprise 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 positioned between two of the plurality of radially extending arms.

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 positioned at an uphole end of the motor assembly. The support member may be positioned at a downhole end of the motor assembly. The motor assembly may be fixed to the housing portion by a plurality of support members. For example, two, three, four or five support members. Any, or each, of the plurality of support members may have any of the features of the support member described above. A first support member may be positioned at, or towards, a first end of the motor assembly housing. A second support member may be positioned at, or towards, a second end of the motor assembly housing.

The motor assembly may comprise a motor. The motor may be position within the motor assembly housing. The motor may have an output rpm (revolutions per minute) of between 2000 rpm and 3000 rpm. The motor may be an electric motor. The electric motor may be a direct current motor. The electric motor may be a brushless motor. Advantageously, a brushless motor is less susceptible to degraded performance in the high vibration environment of a drilling system.

The drive shaft may be at least partially positioned within the motor assembly housing. The drive shaft may extend from the motor assembly housing. That is, the drive shaft may extend from an inside of the motor assembly housing to an outside of the motor assembly housing. The motor assembly may comprise a seal. The drive shaft may extend through the seal. The seal may prevent fluid from entering or exiting the motor assembly housing between the seal and the drive shaft. The drive shaft may be connected to the flow diverter via a coupling. Where the flow diverter is mounted on a flow diverter shaft, the drive shaft may be connected to the flow diverter shaft via the coupling. That is, the coupling may couple the drive shaft to the flow diverter via the flow 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 flow diverter shaft may be connected to a second end of the coupling, so that the coupling couples the drive shaft to the flow diverter shaft. The coupling may be a releasable or removable coupling. That is, one or both of the flow diverter shaft and the drive shaft may be selectively disconnected from the coupling in order to decouple the flow diverter from the drive shaft. This may advantageously allow for the flow diverter and/or the motor assembly to be easily removed from the subassembly independent of one another. This may help improve the ease in which components of the subassembly can be replaced and/or removed, for example for maintenance purposes. The coupling may be a universal coupling. The coupling may be a Cardan coupling.

The motor assembly may comprise a reduction gearbox. The reduction gearbox may be positioned 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 reduction gearbox may have a gear ratio of 6:1.

The motor assembly may comprise a positional resolver. The positional resolver may be positioned within the motor assembly housing. The positional resolver may be for providing an angular position and velocity of the motor. The positional resolver may be for determining the rotary position of the flow diverter. The motor assembly may comprise a Hall effect sensor for determining the rotary position of the flow diverter. The Hall effect sensor may be positioned within the motor assembly housing. The Hall effect sensor may be positioned in proximity to the drive shaft. The sensing means may comprise the positional resolver and/or the Hall effect sensor.

The motor assembly housing may comprise a void filled with oil. The motor assembly housing may comprise a plurality of voids filled with oil. The motor assembly housing may be pressure compensated against hydrostatic pressure from the drilling fluid. The motor assembly housing may be configured to allow drilling fluid in the housing portion to flow around the motor assembly housing.

The flow diverter may be positioned within the drill bit. The flow diverter may be positioned between the inlet of the drill bit and the outlet of the drill bit.

The inlet of the drill bit may be positioned at a first end of the drill bit. The outlet of the drill bit may be positioned 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.

The outlet of the drill bit may comprise a first outlet and a second outlet. Directional drilling may be due to a difference between the flow of fluid exiting the first outlet compared to the flow of fluid exiting the second outlet. An arc measure between the centre of the first outlet and the centre of the second outlet may greater than 90 degrees. The arc measure may be greater than 120 degrees. The arc measure may be greater than 150 degrees. The first outlet and the second outlet may be positioned radially opposite each other.

The flow diverter may be configured to selectively divert drilling fluid to the first outlet of the drill bit. The flow diverter may be configured to selectively divert drilling fluid to the 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 the inlet of the drill bit and the first outlet of the drill bit and substantially prevent drilling fluid from flowing between the inlet of the drill bit and the second outlet of the drill bit.

The outlet of the drill bit may comprise a first outlet, a second outlet and 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.

The flow diverter may be positioned within a cartridge. The flow diverter may form part of the cartridge. The cartridge may be configured to be received by the drill bit.

The cartridge may comprise a cartridge housing having an inlet end for receiving drilling fluid and an outlet end at which drilling fluid can exit the cartridge housing. The cartridge may form a flow path for drilling fluid between the inlet and the outlet of the drill bit. The flow diverter may be moveable relative to the cartridge housing to selectively control the flow direction of drilling fluid as the drilling fluid exits the cartridge housing. The cartridge may be adapted to be received within an internal space of a drill bit.

The cartridge housing may be configured to rotate with the drill bit. The flow diverter may be rotatably mounted within the cartridge housing. The cartridge housing may comprise one or more components for securing the cartridge housing in a fixed position within a drill bit.

The flow diverter may be mounted on a flow diverter shaft. The flow diverter shaft may be connected to the drive shaft. The flow diverter shaft may be connected to the drive shaft via the coupling. The flow diverter shaft may be a spindle. The spindle may be fixedly attached to the flow diverter and configured to rotate with the flow diverter. The spindle may be rotatably mounted within a radial bearing. This arrangement helps the spindle resist bending and radial loads. The spindle may have a length such that the spindle does not extend outside the cartridge.

The flow diverter may be configured to divert drilling fluid with respect to the longitudinal axis of the subassembly. The flow diverter may comprise an eccentric flow-diverting aperture for diverting the drilling fluid. In this arrangement, the flow-diverting aperture is offset from the longitudinal axis of the subassembly so that drilling fluid is diverted away from the longitudinal axis, which helps to divert drilling fluid to a segment of the wellbore via the outlet in the drill bit.

The flow diverter may comprise a plate or plate member arranged to prevent flow of drilling fluid 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-diverting aperture may comprise an arcuate opening in the plate or plate member.

The flow-diverting aperture may be configured to communicate with at least one inlet of an outlet of the drill bit. The flow 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 exit the drill bit from a single outlet within a relatively narrow segment of the wellbore.

The flow diverter may be removably-couplable to the drill bit. Where the flow diverter is part of a cartridge adapted to be received within an internal space of a drill bit, the cartridge may be removably-couplable to the drill bit.

The subassembly may comprise 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 positioned within the housing portion. The generator may be rotatably fixed to the housing portion. The generator may be positioned uphole of the motor assembly. The generator may comprise a turbine. The turbine may be configured to be driven by the drilling fluid. The generator may comprise a stator. The stator may be rotatably fixed relative to the generator.

According to another example of the present disclosure, there is provided a directional drilling system comprising the subassembly described herein. The drilling system may comprise a drill string.

According to a further example of the present disclosure, there is provided a kit of parts for forming the subassembly described herein. The kit of parts comprising a drill bit, a flow diverter and a housing portion, wherein the housing portion comprises a motor assembly.

BRIEF DESCRIPTION OF THE FIGURES

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

FIG. 1 depicts a schematic diagram of the subassembly according to the present disclosure positioned within a wellbore;

FIG. 2 is a longitudinal cross-section of a rotary drill bit of the subassembly which is configured to receive a cartridge comprising a flow diverter;

FIG. 3 is a plan view of the drill bit of FIG. 2.

FIG. 4 is a longitudinal cross-section of an upper part of the drill bit of FIG. 2 showing a cartridge received in the bit;

FIG. 5A is a longitudinal cross-section of a flow diverter and spindle of the cartridge of FIG. 4;

FIG. 5B is a rear or downhole view of a flow diverter and spindle of the cartridge of FIG. 4;

FIG. 6 is a perspective view of the support hanger of the cartridge of FIG. 4.

FIG. 7 is a longitudinal cross-section of an upper part of the drill bit of FIG. 2 showing a cartridge received in the bit;

FIG. 8A is a longitudinal cross-section of a flow diverter and spindle of the cartridge of FIG. 7;

FIG. 8B is a rear or downhole view of a flow diverter and spindle of the cartridge of FIG. 7;

FIGS. 9A to 9D are plan views of the drill bit and cartridge assembly of FIGS. 4 and 7 showing different positions of the flow-diverting aperture in the flow diverter relative to one or more bit windows of the nozzles of the drill bit;

FIG. 10A is a schematic illustration of the drill bit and cartridge assembly of FIGS. 4 and 7 connected to a housing portion and arranged in a wellbore of a subsurface formation. This figure also shows the forces acting on the drill bit as a result of using a flow diverter;

FIG. 10B is an uphole view of the arrangement shown in FIG. 10A;

FIG. 11 depicts a control system diagram for operation of the flow diverter of FIG. 1.

DETAILED DESCRIPTION OF THE FIGURES

FIG. 1 depicts a schematic diagram of the subassembly 400 according to the present disclosure. The subassembly 400 is positioned within a wellbore 301. The subassembly 400 comprises a drill bit 1 configured to rotate about a longitudinal axis 401 of the subassembly 400 in a first direction. The drill bit 1 comprises an inlet 14 for receiving drilling fluid and nozzles 24a, 24b for allowing drilling fluid to exit the drill bit 1. The drill bit 1 includes mechanical cutting means 4 for drilling the wellbore. The subassembly 400 also comprises a flow diverter 106 configured to rotate about the longitudinal axis 401 of the subassembly 400 in a second direction, wherein the flow direction of drilling fluid exiting the drill bit 1 is determined by a rotary position of the flow diverter 106 about the longitudinal axis 401 of the subassembly. The subassembly 400 also comprises 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 components of the subassembly 400.

A drill string 200 is connected to an uphole end of the housing portion 410. During use, the drill string 200 is configured to rotate in the first direction, thereby causing the housing portion 410 and the drill bit 1 to rotate in the first direction. The drill string 200 also supplies drilling fluid to the housing portion 410 at an 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 exits the nozzles 24a, 24b of the drill bit 1 at a downhole 403 end of the subassembly 400. The subassembly 400 further comprises a motor assembly 420 positioned within the housing portion 410. The motor assembly 420 comprises a motor assembly housing 421 rotatably fixed to the housing portion 410 by a support hanger 411a. The support hanger 411a has a plurality of apertures (not shown) for allowing drilling fluid to flow through the housing portion 410 to the inlet 14 of the drill bit 1. The motor assembly 420 also comprises a drive shaft 128 rotatable relative to the motor assembly housing 421. An uphole end of the drive shaft 128 is coupled to a direct current brushless motor that is configured to rotate the drive shaft 128 in a second direction. A downhole end of the drive shaft 128 is coupled to the flow diverter 106 such that the drive shaft 128 and the flow diverter 106 rotate together. The subassembly 400 further comprises a control unit 430 positioned within the housing portion 410 that provides control signals to the motor assembly 420 for controlling the rotary position of the flow diverter 106. The control unit 430 is rotatably fixed to the housing portion 410 by a support hanger 411b. The subassembly 400 further comprises a generator 440 for powering the motor assembly 420. The generator 440 is positioned within the housing portion 410 and is rotatably fixed to the housing portion 410 by a support hanger 411c. The generator 440 includes a turbine 441 that is configured to be driven by the drilling fluid flowing through the housing portion 410.

FIG. 2 shows the rotary drill bit 1 of the subassembly 400 in more detail. The drill bit 1 is a polycrystalline diamond compact (PDC) bit. However, it will be appreciated that the subassembly 400 of the present disclosure may include other types of drill bit. The drill bit 1 comprises a bit body or shank 2 provided with mechanical cutting means in the form of PDC cutters 4. The cutters 4 form a bit face 6 at a downhole end of the drill bit 1. During drilling, the bit face 6 is facing and located near the bottom of the wellbore 301. A longitudinal axis of the drill bit 1 is indicated by line A-A.

A threaded pin connection 10 is provided at an 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 inlet to shank bore 16 which defines an internal space 18 within the bit body 2 of the drill bit 1. A plurality of bit windows 20 are formed in the bottom of shank bore 16. Each bit window 20 marks the inlet to a fluid channel 22, which extends from the bit window 20 to a nozzle 24 formed in the bit face 6. It should be noted that drill bit 1 has three fluid channels 22 and associated bit windows 20 and nozzles 24 but two of fluid channels are not shown in FIG. 2 because they are outside the plane of the cross-section. However, three bit windows 20 marking the inlet to each of the three fluid channels can be seen in FIG. 3.

Drilling fluid (not shown) enters the drill bit 1 via inlet port 14 and flows through the drill bit 1 via shank bore 16 and each of the plurality of fluid channels 22 to nozzles 24, where it is ejected from the drill bit 1. The drilling fluid flows around the outside of the drill bit between the drill bit 1 and the walls of the wellbore (not shown) and back up the outside of the drill string to the surface, where it is recycled. The drilling fluid helps to lubricate the drilling operation and carry drill cuttings out of the wellbore and back to the surface.

FIG. 3 shows a plan view of the drill bit 1 of FIG. 2. Three bit windows 20 are formed at the bottom of shank bore 16 and communicate with nozzles 24 via fluid channels 22. Each bit window 20 is formed as a circle sector and sweeps an angular arc of approximately 85 degrees. A bit web 26 is arranged between each pair of bit windows 20 to separate each of the fluid channels 22.

FIG. 4 shows a longitudinal cross-section of an upper part of the drill bit 1 of FIG. 2 showing a cartridge 100 received in the shank bore 16 of the drill bit 1. The cartridge 100 comprises an upper cartridge sleeve 102a and a lower cartridge sleeve 102b which forms a housing of the cartridge 100. The cartridge sleeves 102a and 102b are generally tubular in form and an outer surface of the sleeves 102a and 102b makes a close fit with the internal surface of the shank bore 16. The cartridge sleeves 102a and 102b rotate with the drill bit 1. An internal space within the sleeves 102a and 102b defines a chamber for receiving drilling fluid from drill string (not shown) via the housing portion 410. Drilling fluid enters the cartridge 100 via an opening 104 in the uphole end or inlet end 105 of the upper cartridge sleeve 102a. Drilling fluid exits the cartridge 100 at a downhole end or outlet end 107 of the lower cartridge sleeve 102b.

A flow diverter 106 is located at a downhole end or outlet end 107 of the lower cartridge sleeve 102b and is rotatably mounted on a spindle 108 so that the flow diverter 106 can be decoupled from the rotation of the drill bit 1 and rotate independently of the drill bit 1. The spindle 108 is fixedly attached within a central collar arranged at an uphole side of the flow diverter 106 and turns with the flow diverter 106. The flow diverter 106 takes the form of a disc or shallow cylinder and has a length which is less than its diameter. An outer cylindrical surface of the flow diverter 106 forms a close fit with an inner surface of the lower cartridge sleeve 102b. The flow diverter 106 has an eccentrically located flow-diverting aperture 110 for allowing drilling fluid to pass out of the cartridge 100 to one of more flow channels 22 formed in the drill bit 1. The flow diverter 106 diverts drilling fluid with respect to a longitudinal axis A-A of the cartridge 100 and drill bit 1 towards the flow-diverting aperture 110. The flow diverter 106 closes the outlet end 107 of the cartridge 100 with the exception of drilling fluid that can pass through the flow-diverting aperture 110.

The flow diverter 106 is mounted on a first thrust bearing 112 located at the outlet end 107 of the lower cartridge sleeve 102b. The first thrust bearing 112 comprises a pin bearing having a male pin part 112a arranged in a central bore formed in the downhole end of the flow diverter 106 and a female part 112b for receiving and supporting the male pin part 112a located within a central recess formed in the bottom of the shank bore 16. The first thrust bearing 112 helps the flow diverter 106 withstand the axial hydraulic load placed upon the flow diverter 106 by the column of drilling fluid above it. This arrangement helps the flow diverter 106 to turn freely even under the high hydraulic loads experienced during a drilling operation. Using a centrally mounted thrust bearing as the first thrust bearing 112 has been found to provide better performance compared to a circumferentially mounted thrust bearing.

A bottom section of the lower cartridge sleeve 102b has a recess 114 which circumscribes the inner surface of the lower cartridge sleeve 102b. The recess 114 accommodates the cylindrical wall of the flow diverter 106 such that the inner surface of the cylindrical wall of the flow diverter 106 is flush with the inner surface of the uphole section of the lower cylindrical sleeve. This arrangement reduces hindrances to fluid flow through the cartridge 100 and also reduces the hydraulic load on the flow diverter 106.

The spindle 108 is supported along its length by a bearing hanger or support hanger 116. The support hanger 116 comprises an inner tubular member 118, through which the spindle passes, and an outer tubular member 120, which is received in recessed portions of the adjoining parts of the upper 102a and lower 102b cartridge sleeves. The support hanger 116 rotates with the cartridge sleeves 102a and 102b, which in turn rotate with the drill bit 1. Three support legs 122 (only two shown in FIG. 4) span an annular gap between the inner 118 and outer 120 tubular members and support the inner tubular member 118. The three support legs 122 are equally circumferentially spaced apart around the inner tubular member 118 and the spaces between the three support legs 122 allow drilling fluid to pass through the annular gap between the inner 118 and outer 120 tubular members of the support hanger 116.

A radial bearing 124 is arranged inside the hanger support 116 between the inner tubular member 118 and the spindle 108. The radial bearing 124 helps the flow diverter 106 withstand bending and lateral loads placed on the flow diverter 106 and spindle 108 during drilling operations. This reduces rotational drag on the flow diverter 106 and helps the flow diverter 106 to turn freely even under the high gravitational and vibrational loads experienced during a drilling operation. The radial bearing 124 also helps to support the spindle 108 and isolate the spindle 108 and flow diverter 106 from rotating with the support hanger 116 and drill bit 1.

A second thrust bearing 126 is arranged between the radial bearing 124 and the flow diverter 106. The second thrust bearing 126 helps the flow diverter 106 to withstand axial loads generated by the vibration and bounce of the drill bit 1 during drilling operations.

The first thrust bearing 112, second thrust bearing 126 and radial bearing form a bearing assembly of the cartridge 100.

An uphole end of the spindle 108 is connected to the drive shaft 128 for connecting the spindle 108 and flow diverter 106 to the motor assembly 420. The motor assembly is used to control the rotational position of the flow diverter 106. The motor assembly 420 can be used to hold the flow diverter geostationary whilst the drill bit 1 rotates about it. Consequently, the motor assembly 420 can be used to control an angular position of the flow-diverting aperture 110 from which drilling fluid exits the shank bore 16 of the drill bit 1.

The cartridge 100 is adapted to be received entirely 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 may be modified to receive the cartridge 100. The cartridge 100 can be easily and quickly fitted to a properly adapted drill bit 1 at a drilling site.

FIGS. 5A and 5B show the flow diverter 106 and spindle 108 of FIG. 4 in more detail. FIG. 5A is an uphole perspective longitudinal cross-sectional view of the spindle 108 and flow diverter 106. The flow-diverting aperture 110 is formed in a downhole end 106b of the flow diverter 106 and is radially offset from the longitudinal axis of the flow diverter 106 and spindle 108 indicated by line A-A. The flow-diverting aperture 110 is formed as a circle sector and sweeps an angular arc of approximately 85 degrees. However, it will be appreciated that the angular arc of the flow-diverting aperture 110 can be varied or tuned depending on the drill bit the cartridge 100 is to be fitted to and the performance required. The remaining portion of the downhole end 106b of the flow diverter 106 is closed and forms a flow-blocking portion 111 which prevents drilling fluid from flowing through this portion of the flow diverter 106.

A recess 132 is formed in the downhole end 106b of the flow diverter 106 at a location substantially diametrically opposite the flow-diverting aperture 110. The recess 132 reduces the weight of this part of the flow diverter 106 and helps to balance the flow diverter 106 when it is rotating by reducing out-of-balance rotational forces. This also helps to reduce rotational drag on the flow diverter 106 during a drilling operation. A cylindrical wall 134 of the flow diverter 106 extends in an uphole direction away from the downhole end 106b of the flow diverter 106. The spindle 108 is fixedly attached with a central collar 136 arranged on an uphole side of the flow diverter 106. A central bore 133 is provide in the downhole end 106b of the flow diverter 106 to accommodate the male pin part of the first thrust bearing (not shown).

FIG. 5B is a downhole perspective view of the flow diverter 106 and spindle 108 of FIG. 4. The cylindrical wall 134 defines an opening 138 at an uphole end 106a of the flow diverter 106 for receiving drilling fluid. A protrusion or peak 140 is formed at an uphole side of the flow diverter 106 which corresponds to, and overlies, the recess 132 formed on the downhole side (see FIG. 5A). The internal profile of the uphole side of the flow diverter 106 slopes towards the downhole end 106b of the flow diverter 106 on either side of the peak 140 towards the flow-diverting aperture 110. Therefore a gradient is formed between the peak 140 and the flow-diverting aperture 110 on either side of the peak 140, which assists in diverting drilling fluid flow incident on the uphole side of the flow diverter 106 towards the flow-diverting aperture 110. Compared to a flat surface perpendicular to the direction of fluid flow, the gradient prevents drilling fluid from being brought to an abrupt halt at the uphole side of the flow converter 106, which reduces axial hydraulic loads on the flow diverter 106.

FIG. 6 shows the support hanger 116 of the cartridge 100 of FIG. 5 in more detail. The support hanger 116 comprises an inner tubular member 118 having an internal passage 119 for mounting the radial bearing (not shown), which in turn holds the spindle (not shown). An outer tubular member 120 is also provided and three support legs 122 span an annular gap between the inner 118 and outer 120 tubular members. The three support legs 122 support the inner tubular member 118 and are equally circumferentially spaced apart around the inner tubular member 118. The spaces or apertures 123 between the three support legs 122 allow drilling fluid to pass through the annular gap between the inner 118 and outer 120 tubular members of the support hanger 116.

FIG. 7 shows a longitudinal cross-section of an upper part of the drill bit 1 of FIG. 2 showing another embodiment of a cartridge 100 received in the shank bore 16 of the drill bit 1. The construction of the cartridge 100 in FIG. 7 is similar to that of the cartridge 100 of FIG. 4 and like references numerals have been used in FIG. 7 to refer to the same parts. The main differences between the cartridge 100 of FIG. 7 and that of FIG. 4 is the configuration of the flow diverter 106, the second thrust bearing 126 and the radial bearing 124. The differences with the flow diverter are discussed below in reference to FIGS. 8A and 8B.

Similar to FIG. 4, the second thrust bearing 126 of the cartridge 100 of FIG. 7 is arranged between the radial bearing 124 and the flow diverter 106. The second thrust bearing 126 helps the flow diverter 106 to withstand axial loads generated by the vibration and bounce of the drill bit 1 during drilling operations. In FIG. 7, the second thrust bearing 126 comprises a spring 127 which acts as a biasing member and biases the position of the flow diverter 106 in an axial direction. The spring acts in two directions: i) biasing the flow diverter 106 towards the outlet end 107 of the cartridge 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 flow diverter in a fixed position at the outlet end 107 of the cartridge 100 and to reduce the vibration or bounce experienced by the flow diverter 106, which can lead to damage of the flow diverter 106.

Similar to FIG. 4, the radial bearing 124 of the cartridge 100 of FIG. 7 is arranged inside the support hanger 116 and holds the spindle 108. The radial bearing 124 helps the flow diverter 106 withstand bending and lateral loads placed on the flow diverter 106 and spindle 108 during drilling operations. In FIG. 7, the radial bearing 124 comprises a spacing member 124c and two contact members 124a and 124b arranged at each longitudinal end of the spacing member 124c. The contact members 124a and 124b contact the spindle to provide bearing support. The spacing member 124c does not contact the spindle 108 but merely provide structural support to the contact member 124a and 124b. This arrangement reduces the area of the radial bearing 124 in contact with spindle 108 which helps to reduce friction between the radial bearing 124 and the spindle 108. The contact members 124a and 124b are made of tungsten carbide and/or polycrystalline diamond. The length of the spindle 108 within the radial bearing 124 is coated with tungsten carbide to provide a hard wearing surface and improve the longevity of the cartridge 100.

FIGS. 8A and 8B show the flow diverter 106 and spindle 108 of FIG. 7 in more detail. FIG. 8A is an uphole perspective longitudinal cross-sectional view of the flow diverter 106 and spindle 108. The flow diverter 106 comprises substantially disc-shaped plate 109 arranged at a 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 flow-diverting aperture 110, which is radially offset from the longitudinal axis of the flow diverter 106 and spindle 108 indicated by line A-A. The outer circumference of the disc-shaped plate 109 is arranged to closely conform to the internal circumference of the housing of the cartridge 100 (see FIG. 7) such that substantially all the drilling fluid passes through the flow diverting aperture 110. A central bore 133 is provide in the downhole end 106b of the flow diverter 106 to accommodate the male pin part of the first thrust bearing (not shown).

FIG. 8B is a downhole perspective view of the flow diverter 106 and spindle 108 of FIG. 7. As can be seen in this figure, the flow-diverting aperture 110 is formed as a circle sector and sweeps an angular arc of approximately 85 degrees. However, it will be appreciated that the angular arc of the flow-diverting aperture 110 can be varied or tuned depending on the drill bit the cartridge 100 is to be fitted to and the performance required. The remaining portion of the downhole end 106b of the flow diverter 106 is closed and forms a flow-blocking portion 111 which prevents drilling fluid from flowing through this portion of the flow diverter 106. A central collar or hub 136 is arranged at an uphole end 106a of the disc-shaped plate 109 and extends in an uphole direction. The spindle 108 is fixedly attached to the central hub 136. An annular recess 137 is formed at an uphole end of the central hub 136 to accommodate the spring and part of the second thrust bearing (not shown).

FIGS. 9A to 9D are plan views of the drill bit 1 and cartridge 100 assembly of FIGS. 4 and 7 each showing the flow-diverting aperture 110 of the flow diverter 106 in a different position relative to one or more of the bit windows 20 and bit webs 26 of the drill bit 1 shown in FIG. 3.

In FIG. 9A, the flow-diverting aperture 110 in the flow diverter 106 and one bit window 20 of the drill bit 1 are fully aligned. The flow area of the fluid pathway through the aperture 110 and bit window 20 is at a maximum. Therefore, the flow velocity of the drilling fluid through the fluid pathway is at a minimum and this configuration results in the lowest pressure drop. The other two bit windows (not shown) of the drill bit 1 are blocked or obstructed by the flow-blocking portion 111 of the flow diverter 106 such that substantially no drilling fluid passes through these bit windows.

In FIG. 9B, the flow diverter 106 has rotated a small angular distance counter-clockwise and now the flow-diverting aperture 110 in the flow diverter 106 is partially obscured by one of the bit webs 26 of the drill bit 1. The flow area of the fluid pathway through the flow-diverting aperture 110 and bit window 20 has decreased compared to that shown in FIG. 9A. Therefore, the flow velocity of the drilling fluid through the fluid pathway has increased and the pressure drop has increased.

In FIG. 9C, the flow diverter 106 has rotated a further small angular distance counter-clockwise and now the full width of the bit web 26 falls within flow-diverting aperture 110 in the flow diverter 106, that is, the bit window is obscured to the maximum extent by the bit web 26. The flow area of the fluid pathway through the flow-diverting aperture 110 and bit window 20 is at a minimum. Therefore, the flow velocity of the drilling fluid through the fluid pathway is at a maximum and this configuration results in the highest pressure drop.

In FIG. 9D, the flow diverter 106 has rotated yet a further small angular distance counter-clockwise. As in FIG. 9C, the full width of the bit web 26 falls within aperture 110 in the flow diverter 106, that is, the bit window is again obscured to the maximum extent by the bit web 26. However, this time the flow-diverting aperture 110 spans two bit windows 20. The flow area of the fluid pathway through the aperture 110 and bit windows 20 is at a minimum. Therefore, the flow velocity of the drilling fluid through the fluid pathway is at a maximum and this configuration results in the highest pressure drop but this time the fluid flow is spread over two bit windows, which in turn communicate with their respective nozzles in the drill bit 1.

FIGS. 9A to 9D show the flow diverter 106 rotating to show how it can communicate with the bit windows 20 of the drill bit 1. However, during a directional drilling operation, the flow diverter 106 will be held geostationary in a fixed angular position relative to a particular sector of the wellbore while the drill bit 1 rotates about the flow diverter. Rotation of the drill bit will successively rotate the bit windows 20 of the drill bit 1 into momentary alignment with the flow-diverting aperture 110. Therefore, as the bit windows 20 are each communicated with the flow-diverting aperture 110, drilling fluid will be discharged from the rotating drill bit 1 either as a single stream from a single nozzle, as in FIGS. 9A to 9C, or as a dual stream from two nozzles, as in FIG. 9D. However, each of these streams is sequentially discharged only into the particular sector of the wellbore corresponding to the angular position of the flow-diverting aperture 110.

FIG. 10A is a schematic side view of the drill bit 1 and cartridge (not shown) assembly of FIGS. 4 and 7 in operation at a particular point in time. The drill bit 1 is connected to the housing portion 410 and arranged in a wellbore 301 of a subsurface formation 300. FIG. 10B is an uphole view of the arrangement of FIG. 10A showing the cutters 4 and drilling fluid nozzles 24a, 24b and 24c arranged on the bit face 6 of the drill bit 1.

In FIGS. 10A and 10B, the drill bit 1 is being rotated by the drill string 200 using either a drive system (not shown) located at the surface or a downhole mud motor (not shown) or both. The flow diverter is connected to the motor assembly which is housed in the housing portion 410. The motor assembly is counter-rotating the flow diverter (not shown) at substantially the same rotational speed as the drill bit 1 such that the flow diverter is being held geostationary in a constant angular position relative to the wellbore 301. The flow-diverting aperture (not shown) of the flow diverter is angled in the azimuthal direction of arrow B in FIG. 10A which corresponds to the desired direction of travel. Therefore, drilling fluid will be discharged from the drill bit 1 into the particular sector of the wellbore 301 corresponding to the angular position of the flow-diverting aperture of the flow diverter as the nozzles successively align with the flow-diverting aperture. At this particular point in time, drilling fluid is exiting the drill bit 1 as a single high-velocity stream via nozzle 24a in FIG. 10B. The stream of drilling fluid strikes the bottom of the wellbore 301 and rapidly reverses direction to return to the surface via the annular space formed between the housing portion 410 and the wellbore 301. The diversion of drilling fluid in this manner causes the drill bit 1 to steer in the direction of arrow B.

Without being bound by theory, it is believed that four physical mechanisms are 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. Fluid flow at high velocity has a lower static head pressure when compared to fluid flowing at lower velocity. This phenomenon is well understood and governed by Bernoulli's fluid energy equation. As such, the diverted return flow around the face of one segment of the drill bit 1 produces a pressure differential around the rotating drill bit circumference which pulls the drill bit 1 in the direction of arrow B in FIG. 10A towards the diverted flow (which is at a lower pressure relative to the remainder of the bit circumference). In effect, the drill bit 1 is pulled against the formation providing side force to bias the bit.

The second physical mechanism is also a hydraulic effect and occurs in addition to the Bernoulli effect. This mechanism occurs as the diverted fluid flow jets out of the nozzle 24a and encounters the subsurface formation 300 prior to rapidly changing direction and flowing around the bit as described above. This causes rapid acceleration of the drilling fluid at the boundary of the formation 300, which in turn causes a high positive pressure which acts on a segment of the bit face 6 as denoted by arrow A in FIG. 10A. This creates a bending moment denoted by arrow C in FIG. 9A which deflects the drill string above the drill bit 1, producing an angle between the bit face 6 and the formation 300.

The above two hydraulic effects; Bernoulli and high bit face pressure, are complimentary and serve to offset and tilt the bit towards the desired tool face.

The third physical mechanism is preferential erosion at the bit face 6 and is a product of biased fluid in one bit segment. The high fluid velocity caused by jetting at the bit face as described above produces an abrasion imbalance at the bit face 6. Abrasion rate is proportional to fluid velocity, hence the bit face region of high fluid velocity experiences a higher abrasion rate when compared to regions of lower fluid velocity. In simple terms, material is eroded or washed away ahead of the bit which results in a reduced ‘cutting’ requirement and a more general biased direction as the bit proceeds in the ‘path of least resistance’.

The fourth physical mechanism is similar to the third mechanism but in this case it relates to erosion around the shoulder or side of the drill bit 1. As the discharged drilling fluid turns and heads back toward the surface in the low pressure region (see first physical mechanism above), an erosion imbalance will occur at the bit face due to a region of high fluid acceleration. These abrasion and erosion effects will preferentially remove formation material at bit face regions of high velocity and acceleration. This causes the drill bit 1 to bias towards regions of preferentially reduced formation.

Once the directional drilling operation has finished and the subassembly and drill string have been pointed in the desired direction, the drill bit can return to drilling in a straight line. To drill in a straight line, the flow diverter is rotated at a controlled absolute rotational speed so that drilling fluid is delivered to the nozzles of the drill bit in substantially all angular positions such that there is no overall lateral resultant force on the drill bit.

FIG. 11 depicts a control system diagram for operation of the flow diverter of FIG. 1. As shown in FIG. 11, the housing portion 410 is coupled to a sensor assembly 500 comprising multiple sensing means or sensors, namely an accelerometer 501, a magnetometer 502 and a gyrometer 503. Each of these sensors is arranged to measure positional parameters of the housing portion 410 and relay these to a processing unit 504 for further calculation and/or analysis. The data output from the processing unit 504 is then relayed to a proportional-integral (PI) controller 505. This PI controller also receives a feedback signal from a sensor 507 coupled to the drive shaft 128 of the motor assembly. The sensor 507 may be a hall effect sensor or positional resolver, which detects the rotational position of the drive shaft 128. The PI controller 505 is therefore provided with positional parameters for the housing portion 410 and positional parameters for the drive shaft 128, which enables the PI controller 505 to output a continuously modulated control signal for the motor. This output signal is fed to a control unit 508, which is coupled to the motor assembly 420. The control unit 420 can thereby provide a control signal to the motor assembly for controlling the rotary position of the drive shaft 128 and hence the rotary position of the flow diverter 106.

	Number	Date	Country
Parent	PCT/GB2023/051938	Jul 2023	WO
Child	19029870		US

SUBASSEMBLY FOR A DIRECTIONAL DRILLING SYSTEM

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