CN116981827A

CN116981827A - Chuck for rotary drill bit

Info

Publication number: CN116981827A
Application number: CN202280018434.7A
Authority: CN
Inventors: D·米内特-史密斯; R·塞吉曼
Original assignee: Enteq Technology Co ltd
Current assignee: Enteq Technology Co ltd
Priority date: 2021-03-02
Filing date: 2022-03-02
Publication date: 2023-10-31
Also published as: EP4301955A1; GB2605358B; GB202102954D0; BR112023017485A2; WO2022185056A1; GB2605358A; MX2023009935A; AU2022229942A1; US20230366271A1; CA3208940A1

Abstract

A chuck (100) for a drill bit of a rotary directional drilling system, the chuck comprising: a collet housing (102 a,102 b) having an inlet end (105) for receiving drilling fluid from the drill pipe and an outlet end (107) at which the drilling fluid may leave the collet housing; a diverter (106) configured to selectively control a flow direction of the drilling fluid as the drilling fluid exits the collet housing; and a bearing assembly for supporting the flow splitter; wherein the bearing assembly comprises at least one bearing (112) located at the outlet end of the cartridge housing.

Description

Chuck for rotary drill bit

The present disclosure relates to a chuck for rotating a drill bit of a directional drilling system. The collets may be used to control the direction of the wellbore in the subterranean formation. While the present disclosure is primarily focused on drilling systems for extracting hydrocarbons, wellbores may be used for extracting hydrocarbons, water, or geothermal energy, or for installing facilities. The present disclosure also relates to a kit comprising a collet and a drill bit, and a method for directionally drilling a wellbore in a subterranean formation.

Rotary drilling systems or rotary drilling systems typically include a rotary drill bit disposed at an end of a drill pipe. The drill bit is provided with a mechanical cutter for cutting the wellbore. Examples of rotary drill bits include Polycrystalline Diamond Compact (PDC) bits and roller cone bits. The drill pipe is formed from a plurality of tubular regions or pipes that are added to the drill pipe as the depth of the wellbore increases. During drilling, the entire drill pipe is rotated using a drive system located at the surface to rotate the drill bit. When rotated, the drill bit may produce cuttings as it cuts through the formation. Drilling fluid or drilling mud is pumped from the interior of the drill pipe down to the drill bit and into the wellbore through nozzles formed in the drill bit. The drilling fluid helps lubricate the drilling process, and minerals contained in the drilling fluid help seal the wellbore. Another function of the drilling fluid is to carry cuttings out of the wellbore.

Systems and methods for rotary directional drilling in subterranean formations are known. As used herein, the term "directional drilling" refers to drilling a wellbore with at least a portion of the well not being vertical. The direction of the drill pipe may be diverted or deflected from the straight vertical path to drill the wellbore in a desired direction. In the oil and gas industry, the use of directional drilling can be used to obtain more natural resources present in the mineral formations than with conventional vertical drilling. For example, the drill bit may be turned in a horizontal direction along a horizontal slot in the formation to release natural resources along the length of the horizontal slot.

To determine the position and orientation of the drill bit, tools such as Measurement While Drilling (MWD) tools may be used. Such tools would provide the data needed to drill a particular trajectory. MWD tools may use accelerometers to measure dip angle and magnetometers to determine azimuth angle to provide a three-dimensional overview of drilling progress. Data from the measurement tool is sent to an operator at the surface via a telemetry system. The tools may be powered via a connection to the surface or, more commonly, by a remote power source such as a battery or turbine generator disposed in the drilling fluid stream.

Directional drilling can be achieved by a variety of methods. The most common approach is to use a "bent joint" motor, either positive displacement or mud motor. The elbow joint is a length of pipe spool having threaded connections at both ends for connection to the drill pipe. The axis of the lower connection is slightly angularly offset (less than 3 degrees) from the axis of the upper connection. The elbow joint is introduced into the drill pipe near the downstream end of the drill pipe at a small distance from the drill bit, tilting the drill pipe angle therebelow and also tilting the axis of the drill bit. Therefore, due to the angular offset, the drill bit cannot be rotated by rotating the drill rod. Alternatively, a positive displacement motor is arranged between the elbow joint and the drill bit. In some cases, the elbow joint is integral with the positive displacement motor. The positive displacement motor has a drive shaft connected to the drill bit and generates torque by passing drilling fluid through the positive displacement motor. By pumping drilling fluid down the drill pipe and through the positive displacement motor, the drill bit may be rotated so that a deflected wellbore region may be drilled. However, once the direction of the wellbore has been changed, the elbow joint must be removed from the drill pipe in order to continue drilling in a straight line, which requires that the entire drill pipe be pulled out of the wellbore. This is time consuming and expensive.

Another approach to directional drilling is to use steerable drilling systems. In one type of steerable drilling system, the elbow joint is placed very close to the drill bit such that the angle of inclination is closer to the drill bit than in conventional elbow joint assemblies, and therefore the offset of the drill bit is much less. Thus, the drill bit may also be rotated by rotating the entire drill rod from the surface. Thus, the steerable drilling system may be steered in the direction of the elbow joint by pumping drilling fluid to the drill bit and driving the drill bit using a positive displacement motor. For drilling along straight lines, the drill bit may be rotated by rotating the drill pipe while simultaneously pumping drilling fluid to the drill bit. While this will cause the drill bit to sweep around because of its relatively small offset inclination, by rotating the entire assembly, any effect of the inclination angle on the drill bit will be eliminated or averaged in all directions so that the overall drilling direction is straight. However, sweeping the drill bit in this manner may result in increased wear of the drill bit.

Because the steerable drilling system allows the drill pipe to be turned while rotating, higher penetration rates and smoother wellbores can be achieved. Other types of steerable drilling systems may use different methods to direct the drill bit in a desired direction, such as by using an actuatable thrust pad to push the drill bit in a lateral direction. However, such systems may also result in increased wear of the drill bit and other drilling components. Furthermore, the need for additional components such as positive displacement motors increases the complexity and cost of such systems and increases the likelihood of component failure.

Some other types of steerable drilling systems may use bit hydraulics to obtain steering force by controlling the flow and direction of drilling fluid out of the bit, rather than transmitting mechanical force from a remote steering unit to the formation. Heretofore, known systems and methods that would do so use specially adapted nozzles on the drill bit to obtain directional drilling effects. However, this requires extensive modification to conventional drill bits and often requires the use of rotary seals or valves, which increases the complexity of the system and makes the system more susceptible to the extreme operating conditions experienced during drilling operations. In particular, the known systems are also very susceptible to severe vibrations and axial loads experienced during drilling, and accurately controlling the fluid flow direction has proven challenging. Such systems typically require the addition of additional tubing area to the drill pipe to accommodate the flow control components, which increases the length of the drill pipe. This makes the system more susceptible to bending loads generated when the direction of the drill rod is changed.

The present disclosure takes into account the foregoing problems of known rotary directional drilling systems.

In accordance with an example of the present disclosure, a chuck for rotating a drill bit of a directional drilling system is provided. The collet includes a collet housing having an inlet end for receiving drilling fluid from the drill pipe and an outlet end at which the drilling fluid may exit the collet housing. The collet further includes a diverter configured to selectively control a flow direction of the drilling fluid as the drilling fluid exits the collet housing.

Examples of the present disclosure include a chuck for a drill bit of a rotary directional drilling system, the chuck comprising: a collet housing having an inlet end for receiving drilling fluid from the drill pipe and an outlet end at which the drilling fluid may exit the collet housing; a shunt; wherein the diverter is movable relative to the collet housing to selectively control a direction of flow of drilling fluid as the drilling fluid exits the collet housing; wherein the collet is adapted to be received within the interior space of the drill bit.

Examples of the present disclosure include a chuck for a drill bit of a rotary directional drilling system, the chuck comprising: a collet housing having an inlet end for receiving drilling fluid from the drill pipe and an outlet end at which the drilling fluid may exit the collet housing; a diverter configured to selectively control a flow direction of the drilling fluid as the drilling fluid exits the collet housing; and a bearing assembly for supporting the flow splitter; wherein the bearing assembly comprises at least one bearing located at the outlet end of the cartridge housing.

Examples of the present disclosure include a chuck for a drill bit of a rotary directional drilling system, the chuck comprising: a collet housing having an inlet end for receiving drilling fluid from the drill pipe and an outlet end at which the drilling fluid may exit the collet housing; a diverter configured to selectively control a flow direction of the drilling fluid as the drilling fluid exits the collet housing; and a bearing assembly for supporting the flow splitter; wherein the bearing assembly comprises at least one bearing located within the cartridge housing.

The inlet end of the collet housing may include an inlet for receiving drilling fluid from the drill pipe. The inlet may be an opening in the cartridge housing. The inlet may be the only inlet of the cartridge housing. The inlet may be configured to receive at least 50% by volume of drilling fluid flowing into the drill bit. The inlet may be configured to receive at least 80% by volume of drilling fluid into the drill bit. The inlet may be configured to receive all of the drilling fluid into the drill bit.

The outlet end of the collet housing may include an outlet at which drilling fluid passing through the collet may exit the collet housing. The outlet may be an opening in the cartridge housing. The outlet may be the only outlet of the cartridge housing. The collet may be arranged such that when the collet is received in a bit of a rotary drilling system, at least 50% by volume of the drilling fluid exiting the collet will exit through the outlet of the collet housing. The collet may be arranged such that when the collet is received in a bit of a rotary drilling system, at least 80% by volume of the drilling fluid exiting the collet will exit through the outlet of the collet housing. The collet may be arranged such that when the collet is received in a bit of a rotary drilling system, all drilling fluid exiting the collet will exit through an outlet of the collet housing.

During directional drilling operations, the collets use fluid flow to change the direction of the drill bit. In particular, the collets use differential fluid flow through the nozzles of the drill bit to change direction. By diverting at least a portion of the drilling fluid in a selected direction toward a particular section of the wellbore, the drilling fluid will leave one or more drill bit nozzles in that section of the wellbore at a faster rate, creating a pressure drop at those nozzles and creating a pressure differential across the drill bit and around the sides of the drill bit in a return loop aligned with the diversion, which helps divert the drill bit in the desired direction.

The collet may be adapted to be received within the interior space of the bit. Advantageously, this allows existing steerable rotary drill bits to be converted for use in directional drilling systems without the need to produce specially designed drill bits or to modify the nozzles of the drill bit. The drill bit may be converted with relatively minor modifications, including creating an interior space within the drill bit or sizing an existing interior space to receive the collet. This can be performed quickly and easily in a machining shop. This may save time and costs for producing the steerable drill bit.

Another advantage of the collet being adapted to be received within the interior space of the drill bit is that the collet is protected from drilling operations and does not experience the same wear as other conventional components may due to physical contact with the wellbore during drilling. The collets of the present disclosure are smaller and lighter than known devices and are better supported by positioning within the drill bit. Furthermore, positioning the collet within the drill bit means that the collet moves around less than if the collet were outside the drill bit and outside a portion of the drill rod, which results in reduced stress being applied to the internal components of the collet.

The diverter may be movable relative to the collet housing to selectively control a direction of flow of drilling fluid as the drilling fluid exits the collet housing. This allows the diverter to be rotationally decoupled from the drill pipe and drill bit so that the diverter may remain geostationary to control the direction of drilling fluid into a particular section of the wellbore. But also allows for accurate control of the rotational position of the diverter. As used herein, the term "geostationary" refers to stationary or non-moving relative to a surrounding subterranean formation or wellbore. For example, the diverter may be held geostationary while the drill bit rotates about the diverter such that the diverter remains in the same spatial position relative to the wellbore.

The flow splitter may be located at or near the outlet end or downhole end of the collet housing. As used herein, the term "downhole" refers to a direction toward or facing the bottom of a wellbore. Furthermore, the term "uphole" refers to a direction toward or facing the top of the wellbore.

The collet may further comprise a bearing assembly for supporting the flow divider. The bearing assembly may include at least one bearing located at the outlet end of the cartridge housing. Advantageously, the flow divider is supported at or near the point where it receives force or pressure by using at least one bearing at the outlet end of the cartridge housing to support the flow divider. The bearings reduce the likelihood of damage to the shunt and assist in continuing the free rotation of the shunt.

The bearing assembly may include at least one bearing located within the cartridge housing. At least one bearing located within the cartridge housing may be positioned between the inlet of the cartridge housing and the flow splitter. That is, at least one bearing may be positioned upstream of the flow splitter. In this way, at least one bearing may be positioned upstream of the outlet end of the cartridge housing. Positioning at least one bearing for the diverter within the chuck housing and upstream of the diverter helps to maintain the compactness of the equipment for the directional drilling system, and the bearing support will be placed near the diverter so that the diverter is well supported at or near the point where it receives force or pressure. This makes the arrangement stronger and therefore less bending of the shunt or the part to which the shunt is mounted. This arrangement also helps to protect the at least one bearing.

The bearing assembly may include a first thrust bearing located at the outlet end of the cartridge housing. This helps to make the diverter resistant to axial loading by the diverter due to the column of drilling fluid above it, which flows down the drill pipe and impacts the diverter before diverting.

The first thrust bearing may be a tapered bearing. Tapered thrust bearings may advantageously help the diverter resist both side and axial loads to which it is subjected during drilling. The first thrust bearing may be configured to rotate about a longitudinal axis of the collet. The longitudinal axis of the collet may be centrally located in the collet.

The first thrust bearing may comprise a pin bearing. The pin bearing may include a male pin member coupled to the shunt. The male pin member may be configured to cooperate with a female pin member for receiving and supporting the male pin member. The female pin member may be coupled to a drill bit. For example, the female pin member may be formed as a recess in the base of the shank bore of the drill bit. The male pin member may have a generally conical shape. The female pin member may be a generally conical shaped recess. The generally conical shaped recess of the female pin member may correspond to the generally conical shape of the male pin member.

The bearing assembly may include a second thrust bearing located within the cartridge housing. The second thrust bearing further assists the flow splitter against axial loads to which it is subjected.

Optionally, the second thrust bearing may comprise a biasing member for biasing the position of the shunt in the axial direction. The biasing member may comprise a resilient element. The biasing member may comprise a spring or an elastomeric element. The biasing member helps to maintain the shunt in a fixed axial position. This may help prevent any significant amount of movement (e.g., chatter or vibration) of the shunt in the axial direction during use of the collet in the wellbore. This may help reduce the likelihood of damage to the shunt and any associated components (e.g., one or more associated axial bearing surfaces) during use of the collet in a wellbore. For example, the biasing member may help to hold the diverter and any associated first thrust bearing located at the outlet end of the diverter against the corresponding bearing surface of the drill bit.

The bearing assembly may include a radial bearing located within the cartridge housing. The radial bearings may help to make the shunt resistant to bending and/or inertial loads, which in turn helps to reduce rotational resistance. The radial bearing may comprise one spacer member and two contact members arranged at both ends of the spacer member. The contact member may contact the main shaft of the chuck. The contact member may comprise one or both of tungsten carbide and polycrystalline diamond. Preferably, the surface of the contact member comprises one or both of tungsten carbide and polycrystalline diamond. Preferably, each contact member comprises a body formed of a first material and a surface coating formed of a second material, wherein the second material comprises or consists of one or more of tungsten carbide and polycrystalline diamond.

The chuck housing may be configured to rotate with the drill bit. The shunt may be rotatably mounted within the cartridge housing. This arrangement allows the diverter to be rotationally decoupled from the drill bit and drill pipe so that the diverter can remain geostationary to direct drilling fluid into a particular section of the wellbore. Thus, the cartridge housing may include one or more components for securing the cartridge housing in a fixed position within the drill bit.

The flow divider may be mounted on the spindle. The spindle may be fixedly attached to the flow splitter and configured to rotate with the flow splitter. The spindle may be rotatably mounted within a radial bearing. This arrangement helps to make the spindle resistant to bending and radial loads. The spindle may have a length such that the spindle does not extend beyond the collet.

The collet may further comprise a support cradle. The support cradle may support a radial bearing. The support cradle allows the radial bearing to be mounted centrally and close to the main shaft.

Alternatively, the support hanger may be disposed close to or adjacent to the diverter. This arrangement reduces the length of the main shaft between the support hanger and the flow splitter, which increases the robustness of the arrangement and helps reduce bending and deflection of the main shaft. This reduces the rotational resistance and also helps to free the diverter to rotate.

The support hanger may include a plurality of apertures to allow drilling fluid to pass through the support hanger. This allows the support hanger to span the interior chamber of the collet housing to collectively support the main shaft of the diverter while still allowing drilling fluid to pass.

The support cradle may be disposed upstream of the flow splitter. The support hanger may be fixed relative to the collet housing. The support hanger may be secured to the interior of the collet housing.

The cartridge may further comprise a connector for connecting the flow divider to a rotation control unit for controlling the rotational position of the flow divider. The connector may be arranged at one end of the spindle. The connector may be disposed at the upstream end of the main shaft or at the uphole end. The connector may be disposed within the collet housing. This arrangement may help to protect the connector.

The diverter may be configured to divert drilling fluid relative to a longitudinal axis of the collet. The diverter may include an eccentric diversion aperture for diverting drilling fluid. In this arrangement, the diverting apertures are offset from the longitudinal axis of the collet such that the fluid is diverted away from the longitudinal axis, which helps divert drilling fluid to a section of the wellbore via the nozzles in the drill bit.

The flow splitter may include a plate or plate member arranged to occlude or close the downhole or downstream open or outlet end of the collet housing. The plate or plate member may be a disc-shaped plate. The shunt aperture may comprise an arcuate opening in the plate or plate member.

The diverter aperture may be configured to communicate with at least one inlet of a nozzle of the drill bit. The collet may be configured to direct substantially all of the drilling fluid to the inlet of a single nozzle of the drill bit. In this arrangement, substantially all of the drilling fluid will exit the drill bit from a single nozzle within a relatively narrow section of the wellbore.

The diverter aperture may be configured to communicate with a plurality of inlets of a corresponding plurality of nozzles of the drill bit. For example, the size of the diversion aperture may be larger than the space between the inlets of the nozzles in the drill bit, such that the diversion aperture spans more than one inlet. The collet may be configured to direct substantially all of the drilling fluid to the inlets of the plurality of nozzles of the drill bit. In this arrangement, substantially all of the drilling fluid will exit the drill bit from more than one nozzle within a wider section of the wellbore, as compared to an arrangement in which the fluid exits from a single nozzle.

The collet may be adapted to be received within a shank bore of a drill bit. The collet may be adapted to be fully received within a shank bore of a drill bit. This arrangement means that the collet and the flow splitting component are contained within the drill bit. No additional drill pipe area is required to accommodate these components, and thus, this arrangement provides a compact and robust directional drilling system.

The cartridge housing may comprise a single part. The cartridge housing may comprise a plurality of sections. The collet housing may include a tubular bushing. The cartridge housing may comprise a single bushing. The collet housing may include a plurality of bushings.

According to another example of the present disclosure, a kit is provided that includes any of the collets described above, as well as a drill bit of a rotary directional drilling system. The drill bit may be a PDC bit or a roller cone bit.

In accordance with another example of the present disclosure, a method for directionally drilling a wellbore in a subterranean formation is provided. The method comprises the following steps: the collet is received within the interior space of the bit. The collet includes a collet housing having an inlet end for receiving drilling fluid from the drill pipe and an outlet end at which the drilling fluid exits the collet housing. The collet further includes a diverter to selectively control the direction of flow of drilling fluid as it exits the collet housing. The method further comprises the steps of: a diverter is used to selectively direct at least a portion of the drilling fluid to one or more nozzles of the drill bit.

The method may further comprise: connecting the flow divider to the rotation control unit; rotating the diverter in a rotational direction opposite the rotational direction of the drill pipe relative to the rotation of the drill pipe; and controlling the rotational position of the diverter to selectively direct at least a portion of the drilling fluid to one or more nozzles of the drill bit.

The collet may be received in the drill bit at the drilling site or rig.

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

Fig. 1 is a longitudinal section of a rotary drill bit configured to receive a collet of the present disclosure.

Fig. 2 is a plan view of the drill bit of fig. 1.

Fig. 3 is a longitudinal section of an upper portion of the drill bit of fig. 1, showing a collet according to an embodiment of the disclosure received in the drill bit.

Fig. 4A is a longitudinal cross-section of the splitter and the main shaft of the chuck of fig. 3.

Fig. 4B is a rear or downhole view of the diverter and spindle of the collet of fig. 3.

Fig. 5 is a perspective view of a support cradle of the cartridge of fig. 3.

Fig. 6 is a longitudinal section of an upper portion of the drill bit of fig. 1, showing a collet according to another embodiment of the disclosure received in the drill bit.

Fig. 7A is a longitudinal cross-section of the splitter and the main shaft of the chuck of fig. 6.

Fig. 7B is a rear or downhole view of the diverter and spindle of the collet of fig. 6.

Fig. 8A-8D are plan views of the drill bit and chuck assembly of fig. 3 and 6, showing different positions of the diverter aperture in the diverter relative to one or more bit windows of the nozzle of the drill bit.

Fig. 9A is a schematic illustration of the drill bit and collet assembly of fig. 3 and 6 connected to a portion of a drill pipe and disposed in a wellbore of a subterranean formation. This figure also shows the forces acting on the drill bit as a result of using the collets of the present disclosure.

Fig. 9B is an uphole view of the arrangement shown in fig. 9A.

Fig. 1 shows a rotary drill bit 1 for directional drilling of a wellbore in a subterranean formation or formation. The drill bit 1 is a Polycrystalline Diamond Compact (PDC) drill bit. However, it should be understood that the collets of the present disclosure may also be applied to other types of drill bits. 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 the downhole end of the drill bit 1. During drilling, the bit face 6 faces the bottom of the wellbore (not shown) and is located adjacent thereto. The longitudinal axis of the drill bit 1 is indicated by the 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 a drill rod (not shown). The drill bit 1 has an inlet port 14 for receiving drilling fluid from the drill rod. The inlet port 14 is an inlet to a shank bore 16 that defines an interior space 18 within the bit body 2 of the bit 1. A plurality of bit windows 20 are formed in the bottom of shank bore 16. Each bit window 20 marks the entrance to a fluid passage 22 extending from the bit window 20 to a nozzle 24 formed in the bit face 6. It should be noted that the drill bit 1 has three fluid channels 22 and associated bit windows 20 and nozzles 24, but two of them are not shown in fig. 1, as they are out of plane of the cross-section. However, three bit windows 20 marking the inlet of each of the three fluid passages can be seen in FIG. 2.

Drilling fluid (not shown) enters the drill bit 1 via the inlet port 14 and then passes through the drill bit 1 via the shank bore 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 around the outside of the drill bit between the drill bit 1 and the wall of the wellbore (not shown) and then back to the surface along the outside of the drill pipe where it is recovered. The drilling fluid helps lubricate the drilling operation and may carry cuttings out of the wellbore and back to the surface.

Fig. 2 shows a plan view of the drill bit 1 of fig. 1. Three bit windows 20 are formed at the bottom of shank bore 16 and communicate with a nozzle 24 via a fluid passage 22. Each bit window 20 is formed as a circular sector and sweeps through an angular arc of approximately 85 degrees. A bit web 26 is disposed between each pair of bit windows 20 to separate each of the fluid passages 22.

Fig. 3 shows a longitudinal section of the upper part of the drill bit 1 of fig. 1, showing the collet 100 received in the shank hole 16 of the drill bit 1. The collet 100 includes an upper collet bushing 102a and a lower collet bushing 102b that form a housing of the collet 100. The collet bushings 102a and 102b are generally tubular in shape and the outer surfaces of the bushings 102a and 102b mate with the inner surface of the shank bore 16. The collet bushes 102a and 102b rotate together with the drill bit 1. The interior spaces within liners 102a and 102b define a chamber for receiving drilling fluid from a drill pipe (not shown). Drilling fluid enters the collet 100 through an opening 104 in the uphole or inlet end 105 of the upper collet liner 102 a. Drilling fluid exits the collet 100 at the downhole or outlet end 107 of the lower collet liner 102 b.

A valve or diverter 106 is located at a downhole or outlet end 107 of the lower jaw bushing 102b and is rotatably mounted on a main shaft 108 such that the diverter 106 may be separated from the rotation of the drill bit 1 and rotated independently of the drill bit 1. The spindle 108 is fixedly attached within a central collar disposed at the uphole side of the diverter 106 and rotates with the diverter 106. The shunt 106 is disk-shaped or shallow cylindrical and has a length less than its diameter. The cylindrical outer surface of the shunt 106 forms a tight fit with the inner surface of the lower cartridge bushing 102 b. The diverter 106 has an eccentrically positioned diverter orifice 110 to allow drilling fluid to flow out of the collet 100 to one or more flow passages 22 formed in the drill bit 1. The diverter 106 diverts drilling fluid toward the diversion aperture 110 relative to the longitudinal axis A-A of the collet 100 and drill bit 1. The diverter closes the outlet end 107 of the collet 100, but drilling fluid may pass through the diverter orifice 110.

The diverter 106 is mounted on a first thrust bearing 112 that is located at the outlet end 107 of the lower cartridge bushing 102 b. The first thrust bearing 112 comprises a pin bearing having a male pin member 112a disposed in a central bore formed in the downhole end of the shunt 106 and a female pin member 112b mounted within a central recess formed in the bottom of the shank bore 16 for receiving and supporting the male pin member 112 a. The first thrust bearing 112 helps to maintain the diverter 106 against axial hydraulic loads exerted on the diverter by the column of drilling fluid above the diverter 106. This arrangement helps to allow the diverter 106 to rotate freely even when subjected to high hydraulic loads during drilling operations. It has been found that using a centrally mounted thrust bearing as the first thrust bearing 112 may provide better performance than a circumferentially mounted thrust bearing.

The bottom region of the lower cartridge bushing 102b has a recess 114 surrounding the inner surface of the lower cartridge bushing 102 b. Recess 114 may receive the cylindrical wall of diverter 106 such that the inner surface of the cylindrical wall of diverter 106 is flush with the inner surface of the uphole region of the cylindrical lower liner. This arrangement reduces obstruction of fluid flow through the collet 100 and reduces hydraulic loading on the flow divider 106.

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 main shaft passes and an outer tubular member 120 that is received in a recessed portion of the abutment of the upper and lower collet bushings 102a, 102 b. The support hanger 116 rotates with the collet bushes 102a and 102b, and the collet bushes 102a and 102b rotate with the drill bit 1. Three support legs 122 (only two are shown in fig. 3) 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 spaces between the three support legs 122 allow drilling fluid to pass through the annular gap between the inner tubular member 118 and the outer tubular member 120 of the support hanger 116.

Radial bearings 124 are disposed inside hanger support 116 between inner tubular member 118 and main shaft 108. Radial bearings 124 help to support diverter 106 against bending and side loads imposed on diverter 106 and main shaft 108 during drilling operations. This reduces rotational resistance on the diverter 106 and helps to allow the diverter 106 to freely rotate even when subjected to high gravitational and vibratory loads during drilling operations. Radial bearings 124 also help support spindle 108 and isolate spindle 108 and diverter 106 from supporting hanger 116 and rotation of drill bit 1.

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

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

The uphole end of the spindle 108 is connected to a drive connection 128 for connecting the spindle 108 and the diverter 106 to a rotation control unit (not shown). The rotation control unit is used to control the rotational position of the diverter 106 and to separate the diverter 106 from the rotation of the drill bit 1. The rotary control unit may be used to keep the flow divider geostationary while the drill bit 1 rotates around the flow divider. Thus, the rotary control unit may be used to control the angular position of the diverting orifice 110 from which the drilling fluid exits the shank hole 16 of the drill bit 1.

The collet 100 is adapted to be fully received within the shank bore 16 of the drill bit 1 and retained in the shank bore 16 by a retention clip 130 that can be quickly attached or removed. The shank aperture 16 may be modified to receive the collet 100. The collet 100 can be conveniently and quickly assembled to a properly fitted drill bit 1 at the drilling site.

Fig. 4A and 4B illustrate the diverter 106 and the spindle 108 of fig. 3 in more detail. Fig. 4A is an uphole perspective longitudinal cross-sectional view of the main shaft 108 and the shunt 106. A diverter aperture 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 spindle 108 indicated by line A-A. The shunt aperture 110 is formed as a circular sector and sweeps through an angular arc of about 85 degrees. However, it should be appreciated that the angular arc of the shunt aperture 110 may be varied or adjusted depending on the drill bit to which the collet 100 is to be fitted and the desired performance. The remainder of the downhole end 106b of the diverter 106 is closed and forms a flow blocking portion 111 that prevents drilling fluid from flowing through this portion of the diverter 106.

A recess 132 is formed in the downhole end 106b of the shunt 106 at a location substantially diametrically opposite the shunt aperture 110. The recess 132 reduces the weight of this portion of the shunt 106 and helps to balance the shunt 106 when rotated 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 shunt 106 extends uphole away from the downhole end 106b of the shunt 106. The main shaft 108 is fixedly attached to a central collar 136 arranged on the uphole side of the shunt 106. A central bore 133 is provided in the downhole end 106b of the shunt 106 to receive a male pin component of a first thrust bearing (not shown).

Fig. 4B is a downhole perspective view of the diverter 106 and the spindle 108 of fig. 3. The cylindrical wall 134 defines an opening 138 at the uphole end 106a of the diverter 106 for receiving drilling fluid. At the uphole side of the shunt 106, a protrusion or peak 140 is formed that corresponds to and overlies the recess 132 (see fig. 4A) formed at the downhole side. On both sides of the peak 140 toward the shunt aperture 110, the interior profile of the uphole side of the shunt 106 is sloped toward the downhole end 106b of the shunt 106. Thus, a gradient is formed between the peak 140 and the shunt apertures 110 on either side of the peak 140, which helps divert drilling fluid flow incident on the uphole side of the shunt 106 toward the shunt apertures 110. This gradient prevents the drilling fluid from stopping abruptly at the uphole side of the flow converter 106, compared to a flat surface perpendicular to the direction of fluid flow, thereby reducing the axial hydraulic load on the diverter 106.

Fig. 5 shows the support hanger 116 of the collet 100 of fig. 3 in more detail. The support hanger 116 includes an inner tubular member 118 having an inner passage 119 for mounting a radial bearing (not shown) which in turn retains 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 circumferentially spaced about the inner tubular member 118. The spacing or apertures 123 between the three support legs 122 allow drilling fluid to pass through the annular gap between the inner tubular member 118 and the outer tubular member 120 of the support hanger 116.

Fig. 6 shows a longitudinal section of the upper part of the drill bit 1 of fig. 1, which shows a further embodiment of the collet 100 received in the shank hole 16 of the drill bit 1. The configuration of the collet 100 in fig. 6 is similar to the configuration of the collet 100 of fig. 3, and like reference numerals are used to refer to like parts in fig. 6. The primary difference between the cartridge 100 of fig. 6 and the cartridge of fig. 3 is the configuration of the shunt 106, the second thrust bearing 126, and the radial bearing 124. The differences in the flow splitters are discussed below with reference to fig. 7A and 7B.

Similar to fig. 3, a second thrust bearing 126 of the collet 100 of fig. 6 is disposed between the radial bearing 124 and the shunt 106. The second thrust bearing 126 helps to withstand the axial loads generated by the vibration and bounce of the drill bit 1 during drilling operations by the diverter 106. In fig. 6, the second thrust bearing 126 includes a spring 127 that serves as a biasing member and biases the position of the shunt 106 in the axial direction. The springs act in two directions: i) Biasing the shunt 106 toward the outlet end 107 of the collet 100 to engage the first thrust bearing 112; and ii) biasing the second thrust bearing 126 against the radial bearing 124. This helps to maintain the shunt in a fixed position at the outlet end 107 of the cartridge 100 and also helps to reduce the vibration or bounce experienced by the shunt 106, which may cause damage to the shunt 106.

Similar to fig. 3, radial bearings 124 of collet 100 of fig. 6 are disposed inside hanger support 116 and retain spindle 108. Radial bearings 124 help to support diverter 106 against bending and side loads imposed on diverter 106 and main shaft 108 during drilling operations. In fig. 6, the radial bearing 124 includes a spacing member 124c and two contact members 124a and 124b disposed at each longitudinal end of the spacing member 124 c. The contact members 124a and 124b contact the spindle to provide bearing support. The spacing member 124c does not contact the spindle 108, but rather provides structural support to only the contact members 124a and 124 b. This arrangement reduces the contact area of the radial bearing 124 with the spindle 108, which helps 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 wear surface and extend the useful life of the collet 100.

Fig. 7A and 7B illustrate the diverter 106 and the spindle 108 of fig. 6 in more detail. Fig. 7A is an uphole perspective longitudinal cross-sectional view of the diverter 106 and the spindle 108. The diverter 106 includes a generally disk-shaped plate 109 disposed at the downhole end 106b of the diverter 106. A notch is formed in the outer circumference of the disk plate 109 to form a shunt aperture 110 radially offset from the longitudinal axis of the shunt 106 and spindle 108 indicated by line A-A. The outer circumference of the disc plate 109 is arranged to closely conform to the inner circumference of the housing of the collet 100 (see fig. 6) such that substantially all of the drilling fluid passes through the shunt aperture 110. A central bore 133 is provided in the downhole end 106b of the shunt 106 to receive a male pin component of a first thrust bearing (not shown).

Fig. 7B is a downhole perspective view of the diverter 106 and the spindle 108 of fig. 6. As can be seen in this figure, the shunt aperture 110 is formed as a circular sector and sweeps through an angular arc of about 85 degrees. However, it should be appreciated that the angular arc of the shunt aperture 110 may be varied or adjusted depending on the drill bit to which the collet 100 is to be fitted and the desired performance. The remainder of the downhole end 106b of the diverter 106 is closed and forms a flow blocking portion 111 that prevents drilling fluid from flowing through this portion of the diverter 106. A central collar or hub 136 is disposed at the uphole end 106a of the disk plate 109 and extends uphole. Spindle 108 is fixedly attached to 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).

Fig. 8A-8D are plan views of the assembly of the drill bit 1 and the collet 100 of fig. 3 and 6, each showing the diverter aperture 110 of the diverter 106 in a different position relative to the one or more bit windows 20 and bit web 26 of the drill bit 1 shown in fig. 2.

In fig. 8A, the diverter aperture 110 in the diverter 106 is fully aligned with one of the bit windows 20 of the drill bit 1. The flow area of the fluid path through aperture 110 and bit window 20 is greatest. Thus, the velocity of the drilling fluid through the fluid path is minimal, and this configuration minimizes pressure drop. The other two bit windows (not shown) of the drill bit 1 are blocked or obstructed by the flow-obstructing portion 111 of the flow divider 106 such that substantially no drilling fluid passes through these bit windows.

In fig. 8B, the diverter 106 has been rotated counter-clockwise a small angular distance and, at this point, the diverter aperture 110 in the diverter 106 is partially blocked by one of the drill bit flanks 26 of the drill bit 1. The flow area of the fluid path through the shunt aperture 110 and the bit window 20 is reduced compared to the situation shown in fig. 5A. Thus, the flow rate of drilling fluid through the fluid path increases, and the pressure drop increases.

In fig. 8C, the diverter 106 has been rotated further counter-clockwise a small angular distance and, at this point, the entire width of the drill bit web 26 falls into the diverter aperture 110 in the diverter 106, i.e. the drill bit window is maximally obstructed by the drill bit web 26. The flow area of the fluid path through the shunt aperture 110 and the bit window 20 is minimal. Thus, the flow rate of drilling fluid through the fluid path is greatest and this configuration maximizes the pressure drop.

In fig. 8D, the diverter 106 is rotated a small angular distance further counterclockwise. As shown in fig. 5C, the entire width of the drill bit web 26 falls into the aperture 110 in the diverter 106, i.e., the drill bit window is again maximally obstructed by the drill bit web 26. However, this time, the shunt aperture 110 spans two drill bit windows 20. The flow area of the fluid path through aperture 110 and bit window 20 is minimal. Thus, the flow rate of the drilling fluid through the fluid path is greatest and this configuration maximizes the pressure drop, but this time the fluid flow is distributed over the two bit windows and in turn communicates with the corresponding nozzles in the bit 1.

Fig. 8A to 8D show the rotation of the diverter 106 to show how it communicates with the bit window 20 of the 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. Rotation of the drill bit will cause the drill bit window 20 of the drill bit 1 to rotate successively into momentary alignment with the diversion aperture 110. Thus, with the bit windows 20 each communicating with the diversion apertures 110, drilling fluid will be expelled from the rotary drill bit 1, either from one nozzle as a single stream, as shown in fig. 8A-8C, or from both nozzles as a dual stream, as shown in fig. 8D. However, each of these streams can only be sequentially discharged into a particular sector of the wellbore corresponding to the angular position of the diverting orifice 110.

Fig. 9A is a schematic side view of the assembly of the drill bit 1 and the chuck (not shown) of fig. 3 and 6 operating at a particular point in time. The drill bit 1 is connected to a portion of the drill pipe 200 and is disposed in a wellbore 301 of a subterranean formation 300. Fig. 9B is a uphole view of the arrangement of fig. 9A, showing cutters 4 and drilling fluid nozzles 24a, 24B and 24c arranged on bit face 6 of bit 1.

In fig. 9A and 9B, the drill bit 1 is rotated by the drill pipe 200 using a drive system (not shown) located at the surface, or a mud motor (not shown) downhole, or both. The flow divider of the collet 100 is connected to a rotation control unit (not shown) which is accommodated in the region of the drill rod 200. The rotational control unit counter-rotates the diverter (not shown) at substantially the same rotational speed as the drill bit 1, such that the diverter remains geostationary at a constant angular position relative to the wellbore 301. The diverter aperture (not shown) of the diverter is inclined in the azimuthal direction of arrow B in fig. 9A, which corresponds to the desired direction of travel. Thus, as the nozzles are sequentially aligned with the diverting apertures, drilling fluid will be discharged from the drill bit 1 into a particular sector of the wellbore 301 corresponding to the angular position of the diverting apertures of the diverter. At this particular point in time, the drilling fluid exits the drill bit 1 as a single high velocity stream via the nozzle 24a in fig. 9B. The drilling fluid flow impinges on the bottom of the wellbore 301 and then rapidly reverses direction back to the surface via the annular space formed between the drill pipe 200 and the wellbore 301. Diverting drilling fluid in this manner causes the drill bit 1 to steer in the direction of arrow B.

Without being limited by theory, it is believed that steering the drill bit 1 involves four physical mechanisms. The first physical mechanism is the hydraulic effect caused by the pressure difference around the circumference of the drill bit 1. The hydrostatic head pressure of a fluid flow having a high flow rate is lower when compared to a fluid flow having a lower flow rate. This phenomenon is well understood and governed by the Bernoulli fluid energy equation (Bernoulli's fluid energy equation). In this way, the split return flow on the surface around one section of the drill bit 1 creates a pressure differential around the circumference of the rotating drill bit that pulls the drill bit 1 in the direction of arrow B in fig. 9A towards the split (with a lower pressure relative to the rest of the drill bit circumference). In effect, the drill bit 1 is pulled toward the formation, thereby providing a lateral force that biases the drill bit.

The second physical mechanism is also a hydraulic effect, the appearance of which is complementary to the bernoulli effect. This mechanism occurs when the diverting flow is ejected out of nozzle 24a and hits the subterranean formation 300, as described above, and rapidly 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, thereby causing a high positive pressure to act on the section of the bit face 6, as indicated by arrow a in fig. 9A. This creates a bending moment, indicated by arrow C in fig. 9A, which deflects the drill rod 200 immediately above the drill bit 1, thereby creating an angle between the bit face 6 and the formation 300.

The two hydraulic effects described above (i.e., bernoulli and high bit face pressure) are complementary and serve to offset and tilt the bit toward the desired tool face.

The third physical mechanism is preferential erosion at the bit face 6 due to the fluid being biased in one bit section. The high fluid flow rates due to jetting at the bit face as described above may create an abrasive imbalance at the bit face 6. The rate of erosion is proportional to the fluid flow rate, and therefore the bit face region where the fluid velocity is high is subject to a higher rate of erosion than the region where the fluid velocity is low. In brief, the material in front of the bit is eroded or flushed away, resulting in a reduced "cutting" requirement and a more prevalent bias direction as the bit progresses in the "path of least resistance".

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. As the displaced drilling fluid is diverted in the low pressure zone and returned to the surface (see the first physical mechanism described above), an erosion imbalance will occur at the bit face due to the areas of high fluid acceleration. These abrasive and erosive effects will preferentially remove formation material at areas of high flow rates and accelerations of the bit face. This causes the drill bit 1 to be biased towards the region of preferential formation reduction.

Once the directional drilling operation is completed and the drill bit and drill pipe have been pointed in the desired direction, the drill bit may be restored to drilling in a straight line. For drilling along straight lines, the diverter is rotated at a controlled absolute rotational speed such that drilling fluid is delivered to the nozzles of the drill bit at substantially all angular positions such that there is no overall lateral resultant force on the drill bit.

Claims

1. A chuck for use with a drill bit of a rotary directional drilling system, the chuck comprising:

a collet housing having an inlet end for receiving drilling fluid from a drill pipe and an outlet end at which drilling fluid can exit the collet housing;

a diverter configured to selectively control a flow direction of the drilling fluid as the drilling fluid exits the collet housing; and

a bearing assembly for supporting the shunt;

wherein the bearing assembly comprises at least one bearing located at an outlet end of the cartridge housing.

2. A chuck for use with a drill bit of a rotary directional drilling system, the chuck comprising:

a collet housing having an inlet end and an outlet end, the inlet end including an inlet for receiving drilling fluid from a drill pipe, the outlet end including an outlet at which the drilling fluid can exit the collet housing;

a bearing assembly for supporting the shunt;

wherein the bearing assembly includes at least one bearing located within the cartridge housing and positioned between an inlet of the cartridge housing and the flow splitter.

3. A cartridge according to claim 1 or claim 2, wherein the bearing assembly comprises a first thrust bearing located at an outlet end of the cartridge housing.

4. A chuck according to claim 3, wherein the first thrust bearing is a tapered bearing.

5. The cartridge of claim 4, wherein the first thrust bearing is configured to rotate about a central longitudinal axis of the cartridge.

6. The cartridge of any of claims 2 to 5, wherein the bearing assembly comprises a second thrust bearing located within the cartridge housing.

7. The cartridge of claim 6, wherein the second thrust bearing includes a biasing member for biasing the position of the shunt in an axial direction.

8. The cartridge of any of claims 2 to 7, wherein the bearing assembly comprises a radial bearing located within the cartridge housing.

9. The cartridge of claim 8, wherein the radial bearing comprises a spacer member and two contact members disposed at both ends of the spacer member; and is also provided with

Wherein the contact member contacts the spindle of the chuck.

10. The chuck of claim 9, wherein the contact member is made of tungsten carbide and/or polycrystalline diamond.

11. A chuck according to any preceding claim, wherein the flow splitter is rotatably mounted within the chuck housing.

12. The chuck of any one of claims 9 to 11, wherein the flow splitter is mounted on the spindle, wherein the spindle is fixedly attached to and rotates with the flow splitter.

13. The chuck of any one of claims 9 to 12, wherein the main shaft is rotatably mounted within the radial bearing.

14. The cartridge of claim 13, further comprising a support cradle, wherein the support cradle supports the radial bearing.

15. The cartridge of claim 14, wherein the support hanger is disposed proximate or adjacent to the flow splitter.

16. A collet as defined in claim 14 or 15, wherein the support cradle comprises a plurality of apertures to allow drilling fluid to pass through the support cradle.

17. The cartridge of any preceding claim, further comprising a connector to connect the flow divider to a rotation control unit for controlling the rotational position of the flow divider.

18. A collet as defined in any one of the preceding claims, wherein the diverter comprises an eccentric diversion aperture for diverting the drilling fluid.

19. The chuck of claim 18, wherein the diverter orifice is configured to communicate with at least one inlet of a nozzle of a drill bit.

20. The chuck of claim 15 or 16, wherein the diversion apertures are configured to communicate with a plurality of inlets of a corresponding plurality of nozzles of a drill bit.

21. A chuck according to any preceding claim, wherein the chuck is adapted to be received within a shank bore of a drill bit.

22. A kit, comprising:

The cartridge of any one of claims 1 to 21; and

the drill bit of the directional drilling system is rotated.

23. The kit of claim 22, wherein the drill bit is a PDC bit or a roller cone bit.

24. A method for directionally drilling a wellbore in a subterranean formation, the method comprising:

receiving a collet within an interior space of a drill bit, the collet comprising: a collet housing having an inlet end for receiving drilling fluid from a drill pipe and an outlet end at which drilling fluid exits the collet housing; and a diverter to selectively control a flow direction of the drilling fluid as it exits the collet housing; and

the diverter is used to selectively direct at least a portion of the drilling fluid to one or more nozzles of a drill bit.

25. The method of claim 24, further comprising:

connecting the flow divider to a rotation control unit;

rotating the diverter in a rotational direction opposite the rotational direction of the drill pipe relative to the rotation of the drill pipe; and

the rotational position of the diverter is controlled to selectively direct at least a portion of the drilling fluid to one or more nozzles of a drill bit.

26. The method of claim 24 or claim 25, wherein the collet is received in a drill bit at a drilling site or rig.