The present disclosure relates to a cartridge for a drill bit of a rotary directional drilling system. The cartridge may be used to control the direction of a well-bore in a subsurface formation. The well-bore may be used for the extraction of hydrocarbons, water or geothermal energy or for the installation of utilities, although this disclosure will focus mainly on drilling systems for the extraction of hydrocarbons. The present disclosure also relates to a kit comprising the cartridge and a drill bit and to a method for directional drilling of a well-bore in a formation.

A rotational or rotary drilling system typically comprises a rotary drill bit arranged at the end of a drill string. The drill bits are provided with mechanical cutters for cutting the well bore. Examples of rotary drill bits include polycrystalline diamond compact (PDC) drill bits and roller cone bits. The drilling string is formed of multiple tubular sections or pipes which are added to the drill string as the depth of the well-bore increases. During drilling, the drill bits are rotated by rotating the entire drill string using a drive system located at the surface. When rotated, the drill bits produce drilling cuttings as they cut through the formation. Drilling fluid or drilling mud is pumped down the inside of the drill string to the drill bit and passes into the well-bore through nozzles 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 well-bore. Another function of drilling fluid is to carry the drilling cuttings out of the well-bore.

Systems and methods for rotary directional drilling in a subsurface formation are known. As used herein, the term “directional drilling” refers to the practice of drilling a well bore in which at least a portion of the well is not vertical. The direction of the drill string can be steered or deviated from a straight vertical path to drill the well-bore in a desired direction. In the oil and gas industry this can be used to access more of the natural resources present in a mineral formation than would otherwise be achievable using conventional vertical drilling. For example, the drill bit can be steered into a horizontal direction to follow a horizontal seam in a formation to liberate natural resources along a length of the horizontal seam.

To determine the position and orientation of the drill bit, tools such as measure-while- drilling (MWD) tools may be used. Such tools provide the data require to drill a certain trajectory. MWD tools may use accelerometers to measure inclination and magnetometers to determine azimuth to provide a three-dimensional overview of drilling progress. Data from the measurement tools is sent to an operator at the surface via a telemetry system. Power for the tools may be provided via a connection to the surface or more commonly by means of a remote power source such as a battery or a turbine generator arranged in the flow of drilling fluid. Directional drilling can be achieved by a number of methods. The most common method is to use a “bent sub” and a positive displacement motor or mud motor. A bent sub is a short length of pipe with threaded connections at either end for connection to the drill string. The axis of the lower connection is slightly angularly offset (less than 3 degrees) from the axis of the upper connection. The bent sub is introduced into the drill string near its downstream end at a small distance from the drill bit, which tilts the angle of the drill string below it and also tilts the axis of the drill bit. It is therefore not possible to rotate the drill bit by rotating the drill string due to the angular offset. Instead, a positive displacement motor is arranged between the bent sub and the drill bit. In some arrangements the bent sub is integral to the positive displacement motor. The positive displacement motor has a drive shaft, which is connected to the drill bit, and generates torque by the passage of drilling fluid through the positive displacement motor. By pumping drilling fluid down the drill sting and through the positive displacement motor, the drill bit can be rotated and a deviated section of well-bore can be drilled. However, to continue drilling in a straight line once the direction of the well-bore has been changed it is necessary to remove the bent sub from the drill string which involves pulling the entire drill string out of the well-bore. This is both time consuming and costly.

Another method of direction drilling is to use a steerable drilling system. In one type of steerable drilling system, the bent sub is placed very close to the drill bit so that the tilt angle is much closer to the drill bit compared to the conventional bent sub assembly and therefore the offset of the drill bit is much lower. As a result, the drill bit can also be rotated by rotating the entire drill string from the surface. Therefore, the steerable drilling system can be steered in the direction of the bent sub by pumping drilling fluid to the drill bit and using a positive displacement motor to drive the drill bit. To drill in a straight line, the drill bit can be rotated by both rotating the drilling string and pumping drilling fluid to the drill bit. Whilst this will cause the drill bit to sweep around due to its relatively small offset tilt, any effect of the tilt angle on the drill bit will be eliminated or averaged out equally in all directions by the rotation of the entire assembly such that the overall drilling direction is in a straight line. However, sweeping the bit in this manner can result in increased wear of the drill bit.

Since steerable drilling systems allow direction to be changed whilst rotating the drill string, higher rates of penetration and smoother well-bores can be achieved. Other types of steerable drilling systems may use different methods of directing the drill bit in a desired direction, for example, by using actuatable thrust pads to push the bit in a lateral direction. However, such systems may also result in increased wear on the drill bit and other drilling components. Furthermore, the requirement for additional components such as a positive displacement motors increases the complexity and cost of such systems and increases the likelihood of component failure. Instead of transferring mechanical force to the formation from a remote steering unit, some other types of steerable drilling systems may use drill bit hydraulics to achieve a steering force by controlling the flow and direction of drilling fluid exiting the drill bit. Known systems and methods of doing this to date have used specially adapted nozzles on the drill bit to obtain a directional drilling effect. However, this has required substantial modifications to conventional drill bits and often necessitated the use of rotating seals or valves which increased the complexity of the system and made the system more vulnerable to the extreme operating conditions experienced during drilling operations. In particular, known systems were also very susceptible to the severe vibrations and axial loads experienced during drill and accurately controlling the direction of fluid flow proved challenging. Such systems often required additional sections of pipe to be added to the drilling string to accommodate the flow control components, which increased the length of the string. This made the system more susceptible to the bending loads encountered as the direction of the drilling string was being changed.

The present disclosure has taken the foregoing problems with known rotary directional drilling systems into account.

According to an example of the present disclosure, there is provided a cartridge for a drill bit of a rotary directional drilling system. The cartridge comprises a cartridge housing having an inlet end for receiving drilling fluid from a drill string and an outlet end at which drilling fluid can exit the cartridge housing. The cartridge further comprises a flow diverter configured to selectively control the flow direction of drilling fluid as the drilling fluid exits the cartridge housing.

An example of the present disclosure includes a cartridge for a drill bit of a rotary directional drilling system, the cartridge comprising: a cartridge housing having an inlet end for receiving drilling fluid from a drill string and an outlet end at which drilling fluid can exit the cartridge housing; and a flow diverter; wherein the flow diverter is moveable relative to the cartridge housing to selectively control the flow direction of drilling fluid as the drilling fluid exits the cartridge housing; wherein the cartridge is adapted to be received within an internal space of a drill bit.

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

The inlet end of the cartridge housing may comprise an inlet for receiving a drilling fluid from the drill string. 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 percent by volume of the drilling fluid which passes into the drill bit. The inlet may be configured to receive at least 80 percent by volume of the drilling fluid which passes into the drill bit. The inlet may be configured to receive all of the drilling fluid which passes into the drill bit.

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

The cartridge uses fluid flow to change the direction of the drill bit during a directional drilling operation. In particular, the cartridge uses differential fluid flow through the nozzles of a drill bit to change direction. By diverting at least a portion of the drilling fluid in a selected direction toward a particular segment of the well-bore, drilling fluid will exit the nozzle or nozzles of the drill bit in that segment of the well-bore at a faster velocity, resulting in a pressure drop at those nozzles and a differential pressure being established across the drill bit and around the sides of the drill bit in the return annulus aligned to the diverted flow, which helps to steer the drill bit in a desired direction.

The cartridge may be adapted to be received within an internal space of a drill bit. Advantageously, this allows an existing steerable rotary drill bit to be converted for use in a directional drilling system without the need to produce a specially designed drill bit or to modify the nozzles of the drill bit. Only relatively minor modifications are required to convert the drill bits, which include producing the internal space, or resizing the existing internal space, within the drill bit to receive the cartridge. This can be carried out quickly and easily in a machine shop. This may lead to time and cost savings for producing steerable drill bits.

A further advantage of the cartridge being adapted to be received within an internal space of a drill bit, is that the cartridge is protected from the drilling operation and does not suffer the same wear that other conventional components may exhibit as a result of being in physical contact with the well-bore during drilling. The cartridge of the present disclosure is smaller and lighter than known apparatus and is better supported by being located within the drill bit. Furthermore, locating the cartridge within the drill bit means that the cartridge moves around less than if it were outside the drill bit and part of the drill string, which puts less stress on the internal components of the cartridge.

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. This allows the flow diverter to be decoupled from the rotation of the drill string and the drill bit so that the flow diverter can be held geostationary to control the directing of drilling fluid into a particular segment of the well-bore. It also allows the rotational position of the flow diverter to be accurately controlled. As used herein, the term “geostationary” means stationary or not moving relative to the surrounding subsurface formation or well-bore. 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 well-bore.

The flow diverter may be located at or proximal to the outlet end or downhole end of the cartridge housing. As used herein, the term “downhole” refers to a direction toward or facing the bottom of the well-bore. Furthermore, the term “uphole” refers to a direction toward or facing the top of the well-bore.

The cartridge may further comprise a bearing assembly for supporting the flow diverter. The bearing assembly may comprise at least one bearing located at the outlet end of the cartridge housing. Advantageously, by supporting the flow diverter using at least one bearing located at the outlet end of the cartridge housing, the flow diverter is supported at or close to the point where it is receiving force or pressure. The bearing reduces the likelihood of the flow diverter being damaged and helps it continue to turn freely.

The bearing assembly may comprise at least one bearing located within the cartridge housing. The at least one bearing located within the cartridge housing may be positioned between the inlet of the cartridge housing and the flow diverter. That is, the at least one bearing may be positioned upstream of the flow diverter. As such, the at least one bearing may be positioned upstream of the outlet end of the cartridge housing. Locating at least one bearing for the flow diverter within the cartridge housing and positioned upstream of the flow diverter helps to keep the apparatus for the directional drilling system compact and arranges the bearing support close to the flow diverter so that it is well supported at or close to the point it is receiving force or pressure. This makes the arrangement stiffer so there is less bending of the flow diverter or components it is mounted on. This arrangement also helps to protect the at least one bearing.

The bearing assembly may comprise a first thrust bearing located at the outlet end of the cartridge housing. This helps the flow diverter resist the axial loads it encounters from the column of drilling fluid above it, which flows down the drill string and strikes the flow diverter before being diverted.

The first thrust bearing may be a conical bearing. The conical thrust bearing may advantageously help the flow diverter to resist both lateral and axial loads it encounters during drilling. The first thrust bearing may be configured to rotate about a longitudinal axis of the cartridge. The longitudinal axis of the cartridge may be centrally located in the cartridge.

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

The bearing assembly may comprises a second thrust bearing located within the cartridge housing. The second thrust bearing further assists the flow diverter to resist the axial loads it encounters.

Optionally, the second thrust bearing may comprises a biasing member for biasing the position of the flow diverter in an axial direction. The biasing member may comprise a resilient element. The biasing member may comprises a spring or elastomeric element. The biasing member helps to hold the flow diverter in a fixed axial position. This may help to prevent the flow diverter from moving by any significant amount in the axial direction, such as shaking or vibrating, during use of the cartridge in a well-bore. This can help to reduce the likelihood of damage to the flow diverter and any related components, such as one or more associated axial bearing surface, during use of the cartridge in a well-bore. For example, the biasing member may help to hold the flow diverter, and any associated first thrust bearing located at the outlet end of the flow diverter, against a corresponding bearing surface of the drill bit.

The bearing assembly may comprise a radial bearing located within the cartridge housing. The radial bearing may help the flow diverter resist bending loads and/or inertial loads, which in turn helps to reduce rotational drag. The radial bearing may comprise a spacing member and two contact members arranged at each end of the spacing member. The contact members may contact the spindle of the cartridge. The contact members may comprise one or both of tungsten carbide and polycrystalline diamond. Preferably, the surface of the contact members 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 both of tungsten carbide and polycrystalline diamond.

The cartridge housing may be configured to rotate with the drill bit. The flow diverter may be rotatably mounted within the cartridge housing. This arrangement allows the flow diverter to be decoupled from the rotation of the drill bit and drill string so that it can be held geostationary for directing drilling fluid into a particular segment of the well-bore. The cartridge housing may therefore 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 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 the 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 cartridge may further comprise a support hanger. The support hanger may support the radial bearing. The support hanger allows the radial bearing to be mounted centrally and close to the spindle.

Optionally, the support hanger may be arranged proximal or adjacent to the flow diverter. This arrangement reduces the length of spindle between the support hanger and the flow diverter, which increases the stiffness of the arrangement and helps reduce bending and deflection of the spindle. This reduces rotational drag and helps the flow diverter to turn freely.

The support hanger may comprise a plurality of apertures to allow drilling fluid to pass through the support hanger. This allows the support hanger to span the internal chamber of the cartridge housing to centrally support the spindle of the flow diverter whilst still allowing drilling fluid to pass through.

The support hanger may be arranged upstream of the flow diverter. The support hanger may be fixed relative to the cartridge housing. The support hanger may be fixed to the inside of the cartridge housing.

The cartridge may further comprise a connector to connect the flow diverter to a rotation control unit for controlling the rotational position of the flow diverter. The connector may be arranged at one end of the spindle. The connector may be arranged at an upstream or uphole end of the spindle. The connector may be arranged within the cartridge housing. This arrangement may help to protect the connector.

The flow diverter may be configured to divert drilling fluid with respect to a longitudinal axis of the cartridge. 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 cartridge so that fluid is diverted away from the longitudinal axis, which helps to divert drilling fluid to a segment of the well-bore via the nozzles in the drill bit.

The flow diverter may comprise a plate or plate member arranged to occlude or close the downhole or downstream open end or outlet end of the cartridge housing. 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 a nozzle of a drill bit. The cartridge may be configured to direct substantially all of the drilling fluid to the inlet of a single nozzle of a drill bit. In this arrangement, substantially all of the drilling fluid will exit the drill bit from a single nozzle within a relatively narrow segment of the well-bore.

The flow-diverting aperture may be configured to communicate with a plurality of inlets of a corresponding plurality of nozzles of a drill bit. For example, the dimensions of the flow- diverting aperture may be greater than the space between the inlets to the nozzles in the drill bit so that the flow-diverting aperture spans more than one inlet. The cartridge may be configured to direct substantially all of the drilling fluid to the inlets of multiple nozzles of a drill bit. In this arrangement, substantially all of the drilling fluid will exit the drill bit from more than one nozzle within a wider segment of the well-bore compared to an arrangement in which the fluid exits a single nozzle.

The cartridge may be adapted to be received within a shank bore of a drill bit. The cartridge may be adapted to be received entirely within a shank bore of a drill bit. This arrangement means that the cartridge and flow diverting components are contained within the drill bit. There is no requirement for additional drill string sections to house these components and therefore this arrangement provides for a compact and robust directional drilling system.

The cartridge housing may comprise a single part. The cartridge housing may comprise a plurality of parts. The cartridge housing may comprise a tubular sleeve. The cartridge housing may comprise a single sleeve. The cartridge housing may comprise multiple sleeves.

According to another example of the present disclosure, there is provided a kit comprising any of the cartridges described above and a drill bit of a rotary directional drilling system. The drill bit may be a PDC bit or a roller cone bit. According to another example of the present disclosure, there is provided a method for directional drilling of a well-bore in a formation. The method comprises receiving a cartridge within an internal space of a drill bit. The cartridge comprises a cartridge housing having an inlet end for receiving drilling fluid from a drill string and an outlet end at which drilling fluid exits the cartridge housing. The cartridge further comprises a flow diverter to selectively control the flow direction of drilling fluid as the drilling fluid exits the cartridge housing. The method further comprises using the flow diverter to selectively direct at least a portion of the drilling fluid to one or more nozzles of a drill bit.

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

The cartridge may be received in a drill bit at a drilling site or drilling rig.

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

Figure 1 is a longitudinal cross-section of a rotary drill bit which is configured to receive the cartridge of the present disclosure.

Figure 2 is a plan view of the drill bit of Figure 1.

Figure 3 is a longitudinal cross-section of an upper part of the drill bit of Figure 1 showing a cartridge in accordance with an embodiment of the present disclosure received in the bit.

Figure 4A is a longitudinal cross-section of a flow diverter and spindle of the cartridge of Figure 3.

Figure 4B is a rear or downhole view of a flow diverter and spindle of the cartridge of Figure 3.

Figure 5 is a perspective view of the support hanger of the cartridge of Figure 3.

Figure 6 is a longitudinal cross-section of an upper part of the drill bit of Figure 1 showing a cartridge in accordance with another embodiment of the present disclosure received in the bit.

Figure 7 A is a longitudinal cross-section of a flow diverter and spindle of the cartridge of Figure 6.

Figure 7B is a rear or downhole view of a flow diverter and spindle of the cartridge of Figure 6. Figures 8A to 8D are plan views of the drill bit and cartridge assembly of Figures 3 and 6 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.

Figure 9A is a schematic illustration of the drill bit and cartridge assembly of Figures 3 and 6 connected to part of a drill string and arranged in a well-bore of a subsurface formation. This figure also shows the forces acting on the drill bit as a result of using the cartridge of the present disclosure.

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

Figure 1 shows a rotary drill bit 1 for directional drilling of a well-bore in an earth or subsurface formation. The drill bit 1 is a polycrystalline diamond compact (PDC) bit. However, it will be appreciated that the cartridge of the present disclosure may be applied to 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 a well-bore (not shown). 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 a drill string (not shown). The drill bit 1 has an inlet port 14 for receiving drilling fluid from the drill string. 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 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 Figure 1 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 Figure 2.

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 well-bore (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 well-bore and back to the surface.

Figure 2 shows a plan view of the drill bit 1 of Figure 1. 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. Figure 3 shows a longitudinal cross-section of an upper part of the drill bit 1 of Figure 1 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). 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 valve or 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 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 Figure 3) 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 a drive connection 128 for connecting the spindle 108 and flow diverter 106 to a rotation control unit (not shown). The rotation control unit is used to control the rotational position of the flow diverter 106 and to decouple the flow diverter 106 from the rotation of the drill bit 1. The rotation control unit can be used to hold the flow diverter geostationary whilst the drill bit 1 rotates about it. Consequently, the rotation control unit 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.

Figures 4A and 4B show the flow diverter 106 and spindle 108 of Figure 3 in more detail. Figure 4A 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).

Figure 4B is a downhole perspective view of the flow diverter 106 and spindle 108 of Figure 3. 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 Figure 4A). 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 uphold 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. Figure 5 shows the support hanger 116 of the cartridge 100 of Figure 3 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.

Figure 6 shows a longitudinal cross-section of an upper part of the drill bit 1 of Figure 1 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 Figure 6 is similar to that of the cartridge 100 of Figure 3 and like references numerals have been used in Figure 6 to refer to the same parts. The main differences between the cartridge 100 of Figure 6 and that of Figure 3 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 Figures 7 A and 7B.

Similar to Figure 3, the second thrust bearing 126 of the cartridge 100 of Figure 6 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 Figure 6, 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 Figure 3, the radial bearing 124 of the cartridge 100 of Figure 6 is arranged inside the hanger support 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 Figure 6, 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.

Figures 7 A and 7B show the flow diverter 106 and spindle 108 of Figure 6 in more detail. Figure 7 A 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 Figure 6) 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).

Figure 7B is a downhole perspective view of the flow diverter 106 and spindle 108 of Figure 6. 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).

Figures 8A to 8D are plan views of the drill bit 1 and cartridge 100 assembly of Figures 3 and 6 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 Figure 2.

In Figure 8A, 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 Figure 8B, the flow diverter 106 has rotated a small angular distance counter clockwise and now the flow-diverting aperture 110 in the flow diverter106 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 Figure 5A. Therefore, the flow velocity of the drilling fluid through the fluid pathway has increased and the pressure drop has increased.

In Figure 8C, 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 Figure 8D, the flow diverter 106 has rotated yet a further small angular distance counter-clockwise. As in Figure 5C, 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.

Figures 8A to 8D 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 well-bore 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 Figures 8A to 8C, or as a dual stream from two nozzles, as in Figure 8D. However, each of these streams is sequentially discharged only into the particular sector of the well-bore corresponding to the angular position of the flow- diverting aperture 110.

Figure 9A is a schematic side view of the drill bit 1 and cartridge (not shown) assembly of Figures 3 and 6 in operation at a particular point in time. The drill bit 1 is connected to part of a drill string 200 and arranged in a well-bore 301 of a subsurface formation 300. Figure 9B is an uphole view of the arrangement of Figure 9A showing the cutters 4 and drilling fluid nozzles 24a, 24b and 24c arranged on the bit face 6 of the drill bit 1.

In Figures 9A and 9B, 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 of the cartridge 100 is connected to a rotation control unit (not shown) which is housed in a section of the drill string 200. The rotation control unit 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 well-bore 301. The flow-diverting aperture (not shown) of the flow diverter is angled in the azimuthal direction of arrow B in Figure 9A 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 well-bore 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 Figure 9B. The stream of drilling fluid strikes the bottom of the well-bore 301 and rapidly reverses direction to return to the surface via the annular space formed between the drill string 200 and the well-bore 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 Figure 9A 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 Figure 9A. This creates a bending moment denoted by arrow C in Figure 9A which deflects the drill string 200 immediately 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 drill bit 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.