Abstract
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.
Claims
1. 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.
2. A cartridge for a drill bit of a rotary directional drilling system, the cartridge comprising: a cartridge housing having an inlet end comprising an inlet for receiving a drilling fluid from a drill string and an outlet end comprising an outlet at which the drilling fluid can exit the cartridge housing; a flow diverter configured to selectively control the flow direction of the 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 and positioned between the inlet of the cartridge housing and the flow diverter.
3. The cartridge according to claim 1, wherein the bearing assembly comprises a first thrust bearing located at the outlet end of the cartridge housing.
4. The cartridge according to claim 3, wherein the first thrust bearing is a conical bearing.
5. The cartridge according to claim 4, wherein the first thrust bearing is configured to rotate about a central longitudinal axis of the cartridge.
6. The cartridge according to claim 2, wherein the bearing assembly comprises a second thrust bearing located within the cartridge housing.
7. The cartridge according to claim 6, wherein the second thrust bearing comprises a biasing member for biasing the position of the flow diverter in an axial direction.
8. The cartridge according to claim 2, wherein the bearing assembly comprises a radial bearing located within the cartridge housing.
9. The cartridge according to claim 8, wherein the radial bearing comprises a spacing member and two contact members arranged at each end of the spacing member; and wherein the contact members contact a spindle of the cartridge.
10. The cartridge according to claim 9, wherein the contact members are made of tungsten carbide and/or polycrystalline diamond.
11. The cartridge according to claim 9, wherein the flow diverter is mounted on the spindle, wherein the spindle is fixedly attached to the flow diverter and rotates with the flow diverter.
12. The cartridge according to claim 9, wherein the spindle is rotatably mounted within the radial bearing.
13. The cartridge according to claim 12, further comprising a support hanger, wherein the support hanger supports the radial bearing.
14. The cartridge according to claim 13, wherein the support hanger is arranged proximal or adjacent to the flow diverter.
15. The cartridge according to claim 14, wherein the support hanger comprises a plurality of apertures to allow drilling fluid to pass through the support hanger.
16. The cartridge according to claim 2, wherein the flow diverter is rotatably mounted within the cartridge housing.
17. The cartridge according to claim 2, wherein the cartridge is adapted to be received within a shank bore of a drill bit.
18. A method for directional drilling of a well-bore in a formation, the method comprising: receiving a cartridge within an internal space of a drill bit, 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 exits the cartridge housing; and a flow diverter to selectively control the flow direction of drilling fluid as the drilling fluid exits the cartridge housing; and using the flow diverter to selectively direct at least a portion of the drilling fluid to one or more nozzles of a drill bit.
19. The method according to claim 18, further comprising: 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.
20. The method according to claim 18, wherein the cartridge is received in a drill bit at a drilling site or drilling rig.
Description
[0047] Embodiments of the present disclosure are described below in more detail, by way of example only, with reference to the accompanying drawings, in which:
[0048] FIG. 1 is a longitudinal cross-section of a rotary drill bit which is configured to receive the cartridge of the present disclosure.
[0049] FIG. 2 is a plan view of the drill bit of FIG. 1.
[0050] FIG. 3 is a longitudinal cross-section of an upper part of the drill bit of FIG. 1 showing a cartridge in accordance with an embodiment of the present disclosure received in the bit.
[0051] FIG. 4A is a longitudinal cross-section of a flow diverter and spindle of the cartridge of FIG. 3.
[0052] FIG. 4B is a rear or downhole view of a flow diverter and spindle of the cartridge of FIG. 3.
[0053] FIG. 5 is a perspective view of the support hanger of the cartridge of FIG. 3.
[0054] FIG. 6 is a longitudinal cross-section of an upper part of the drill bit of FIG. 1 showing a cartridge in accordance with another embodiment of the present disclosure received in the bit.
[0055] FIG. 7A is a longitudinal cross-section of a flow diverter and spindle of the cartridge of FIG. 6.
[0056] FIG. 7B is a rear or downhole view of a flow diverter and spindle of the cartridge of FIG. 6.
[0057] FIGS. 8A to 8D are plan views of the drill bit and cartridge assembly of FIGS. 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.
[0058] FIG. 9A is a schematic illustration of the drill bit and cartridge assembly of FIGS. 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.
[0059] FIG. 9B is an uphole view of the arrangement shown in FIG. 9A.
[0060] FIG. 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.
[0061] 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 FIG. 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 FIG. 2.
[0062] 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.
[0063] 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 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.
[0064] FIG. 3 shows a longitudinal cross-section of an upper part of the drill bit 1 of FIG. 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.
[0065] 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.
[0066] 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.
[0067] 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.
[0068] The spindle 108 is supported along its length by a bearing hanger or support hanger 116. The support hanger 116 comprises an inner tubular member 118, through which the spindle passes, and an outer tubular member 120, which is received in recessed portions of the adjoining parts of the upper 102a and lower 102b cartridge sleeves. The support hanger 116 rotates with the cartridge sleeves 102a and 102b, which in turn rotate with the drill bit 1. Three support legs 122 (only two shown in FIG. 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.
[0069] 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.
[0070] 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.
[0071] The first thrust bearing 112, second thrust bearing 126 and radial bearing form a bearing assembly of the cartridge 100.
[0072] 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.
[0073] 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.
[0074] FIGS. 4A and 4B show the flow diverter 106 and spindle 108 of FIG. 3 in more detail. FIG. 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.
[0075] 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).
[0076] FIG. 4B is a downhole perspective view of the flow diverter 106 and spindle 108 of FIG. 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 FIG. 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.
[0077] FIG. 5 shows the support hanger 116 of the cartridge 100 of FIG. 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.
[0078] FIG. 6 shows a longitudinal cross-section of an upper part of the drill bit 1 of FIG. 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 FIG. 6 is similar to that of the cartridge 100 of FIG. 3 and like references numerals have been used in FIG. 6 to refer to the same parts. The main differences between the cartridge 100 of FIG. 6 and that of FIG. 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 FIGS. 7A and 7B.
[0079] Similar to FIG. 3, the second thrust bearing 126 of the cartridge 100 of FIG. 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 FIG. 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.
[0080] Similar to FIG. 3, the radial bearing 124 of the cartridge 100 of FIG. 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 FIG. 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.
[0081] FIGS. 7A and 7B show the flow diverter 106 and spindle 108 of FIG. 6 in more detail. FIG. 7A is an uphole perspective longitudinal cross-sectional view of the flow diverter 106 and spindle 108. The flow diverter 106 comprises substantially disc-shaped plate 109 arranged at a downhole end 106b of the flow diverter 106. A notch is formed in the outer circumference of the disc-shaped plate 109 to form a flow-diverting aperture 110, which is radially offset from the longitudinal axis of the flow diverter 106 and spindle 108 indicated by line A-A. The outer circumference of the disc-shaped plate 109 is arranged to closely conform to the internal circumference of the housing of the cartridge 100 (see FIG. 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).
[0082] FIG. 7B is a downhole perspective view of the flow diverter 106 and spindle 108 of FIG. 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).
[0083] FIGS. 8A to 8D are plan views of the drill bit 1 and cartridge 100 assembly of FIGS. 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 FIG. 2.
[0084] In FIG. 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.
[0085] In FIG. 8B, the flow diverter 106 has rotated a small angular distance counter-clockwise and now the flow-diverting aperture 110 in the flow diverter 106 is partially obscured by one of the bit webs 26 of the drill bit 1. The flow area of the fluid pathway through the flow-diverting aperture 110 and bit window 20 has decreased compared to that shown in FIG. 5A. Therefore, the flow velocity of the drilling fluid through the fluid pathway has increased and the pressure drop has increased.
[0086] In FIG. 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.
[0087] In FIG. 8D, the flow diverter 106 has rotated yet a further small angular distance counter-clockwise. As in FIG. 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.
[0088] FIGS. 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 FIG. 8A to 8C, or as a dual stream from two nozzles, as in FIG. 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.
[0089] FIG. 9A is a schematic side view of the drill bit 1 and cartridge (not shown) assembly of FIGS. 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. FIG. 9B is an uphole view of the arrangement of FIG. 9A showing the cutters 4 and drilling fluid nozzles 24a, 24b and 24c arranged on the bit face 6 of the drill bit 1.
[0090] In FIGS. 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 FIG. 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 FIG. 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.
[0091] Without being bound by theory, it is believed that four physical mechanisms are involved in steering the drill bit 1. The first physical mechanism is a hydraulic effect caused by a pressure differential around the circumference of the drill bit 1. Fluid flow at high velocity has a lower static head pressure when compared to fluid flowing at lower velocity. This phenomenon is well understood and governed by Bernoulli's fluid energy equation. As such, the diverted return flow around the face of one segment of the drill bit 1 produces a pressure differential around the rotating drill bit circumference which pulls the drill bit 1 in the direction of arrow B in FIG. 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.
[0092] The second physical mechanism is also a hydraulic effect and occurs in addition to the Bernoulli effect. This mechanism occurs as the diverted fluid flow jets out of the nozzle 24a and encounters the subsurface formation 300 prior to rapidly changing direction and flowing around the bit as described above. This causes rapid acceleration of the drilling fluid at the boundary of the formation 300, which in turn causes a high positive pressure which acts on a segment of the bit face 6 as denoted by arrow A in FIG. 9A. This creates a bending moment denoted by arrow C in FIG. 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.
[0093] 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.
[0094] 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’.
[0095] 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.
[0096] 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.
