Exhaust Port in a Protruding Element of a Downhole Drill Bit

Abstract

In one aspect of the present invention, a drill bit comprises an axis of rotation and a drill bit body that comprises a central bore and a working face, the working face comprising a plurality of fixed element cutting elements, a jack element extending from the working face and being coaxial with the axis of rotation, the jack element comprising a proximal end in mechanical communication with an oscillating hammer mechanism, the jack element also comprising a channel in fluid communication with the central bore, the channel directing a fluid flow into a formation, wherein a fluid volume defined by the hammer mechanism and the central bore is evacuated through the channel.

Description

BACKGROUND OF THE INVENTION

The present invention relates to the field of downhole oil, gas and/or geothermal exploration and more particularly to the field of percussive tools used in drilling. More specifically, the invention relates to the field of downhole jack hammers and vibrators which may be actuated by drilling fluid or drilling mud.

Percussive jack hammers are known in the art and may be placed at the end of a bottom hole assembly (BHA). There they act to more effectively apply drilling power to the formation, thus aiding penetration into the formation.

U.S. Pat. No. 7,424,922 to Hall, et al., which is herein incorporated by reference for all that it contains, discloses a jack element which is housed within a bore of a tool string and has a distal end extending beyond a working face of the tool string. A rotary valve is disposed within the bore of the tool string. The rotary valve has a first disc attached to a driving mechanism and a second disc axially aligned with and contacting the first disc along a flat surface. As the discs rotate relative to one another at least one port formed in the first disc aligns with another port in the second disc. Fluid passed through the ports is adapted to displace an element in mechanical communication with the jack element.

Percussive vibrators are also known in the art and may be placed anywhere along the length of the drill string. Such vibrators act to shake the drill string loose when it becomes stuck against the earthen formation or to help the drill string move along when it is laying substantially on its side in a nonvertical formation. Vibrators may also be used to compact a gravel packing or cement lining by vibration, or to fish a stuck drill string or other tubulars, such as production liners or casing strings, gravel pack screens, etc., from a bore hole.

U.S. Pat. No. 4,890,682 to Worrall, et al., which is herein incorporated by reference for all that it contains, discloses a jarring apparatus provided for vibrating a pipe string in a borehole. The apparatus thereto generates at a downhole location longitudinal vibrations in the pipe string in response to flow of fluid through the interior of said string.

U.S. Pat. No. 7,419,018 to Hall, et al., which is herein incorporated by reference for all that it contains, discloses a downhole drill string component which has a shaft being axially fixed at a first location to an inner surface of an opening in a tubular body. A mechanism is axially fixed to the inner surface of the opening at a second location and is in mechanical communication with the shaft. The mechanism is adapted to elastically change a length of the shaft and is in communication with a power source. When the mechanism is energized, the length is elastically changed.

Notwithstanding the preceding patents regarding downhole jack hammers and vibrators, there remains a need in the art for more powerful mud actuated downhole tools. There is also a need in the art for means to easily adjust the force of the downhole tool. Thus, further advancements in the art are needed.

BRIEF SUMMARY OF THE INVENTION

In one aspect of the present invention, a drill bit comprises an axis of rotation and a drill bit body that comprises a central bore and a working face, the working face comprising a plurality of fixed element cutting elements, a jack element extending from the working face and being coaxial with the axis of rotation, the jack element comprising a proximal end in mechanical communication with an oscillating hammer mechanism, the jack element also comprising a channel in fluid communication with the central bore, the channel directing a fluid flow into a formation, wherein a fluid volume defined by the hammer mechanism and the central bore is evacuated through the channel.

In some embodiments, the channel terminates at one or more nozzles disposed proximate the distal end of the jack element. The one or more nozzles may comprise a cross sectional area less than the cross sectional area of the channel. The one or more nozzles may comprise a wear resistant material such as polycrystalline diamond, cubic boron nitride, or tungsten carbide. In some embodiments, the nozzles may be threaded, pressed, or brazed into the jack element, or fastened by other methods or combinations thereof. The nozzles may comprise an adjustable trajectory.

In some embodiments, the jack element may be connected to the hammer mechanism by a shaft. The jack element may be connected to the shaft by a key and keyway, a bolted flange, a press fit, or combinations thereof. The shaft may be rotated by a turbine driven by the flow of drilling fluid, or by an electric motor. Torque from the turbine or electric motor may be directed through a gear assembly to increase or decrease the angular velocity of the shaft and thus the jack element.

The drill bit may rotate at a first angular velocity about the axis of rotation while the jack element rotates at a second angular velocity about the same axis of rotation. The second angular velocity may be equal in magnitude and opposite the direction of the first angular velocity. The second angular velocity may be variable in time, and may comprise a regular variation that repeats with every revolution of the jack element. The average angular velocity of the drill bit may or may not be equal to the average angular velocity of the jack element.

The jack element may comprise a hard material insert, and the insert may be disposed coaxial to the axis of rotation. In other embodiments, the insert may be disposed offset from the axis of rotation.

In some embodiments, the jack element may comprise an inclination instrumentation device in electrical communication with an electronic processing device disposed on the drill string.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a cross sectional view of an embodiment of a drilling operation.

FIG. 2 is a cross sectional view of an embodiment of a drill bit.

FIG. 3 is a cross sectional view of another embodiment of a drill bit.

FIG. 4 is a cross sectional view of another embodiment of a drill bit.

FIG. 5 is an orthogonal view of an embodiment of a fluid turbine.

FIG. 6 is a partial sectional view of an embodiment of a planetary gear assembly.

FIG. 7 is an orthogonal view of another embodiment of a drill bit.

FIG. 8 is an orthogonal view of another embodiment of a drill bit.

FIG. 9a is a cross sectional view of an embodiment of a jack element.

FIG. 9b is a cross sectional view of another embodiment of a jack element.

FIG. 9c is a cross sectional view of another embodiment of a jack element.

FIG. 10a is a perspective view of another embodiment of a jack element and shaft.

FIG. 10b is a perspective view of another embodiment of a jack element and shaft.

FIG. 10c is a perspective view of another embodiment of a jack element and shaft.

FIG. 11 is a cross sectional view of an embodiment of a jack element.

FIG. 12 is a cross sectional view of an embodiment of a drill bit.

DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED EMBODIMENT

Referring now to the figures, FIG. 1 discloses an embodiment of a drilling operation comprising a drilling derrick 101 supporting a drill string 100 inside a borehole 103. The drill string 100 comprises a drilling assembly 102 with a drill bit 104. Drilling assembly 102 may comprise electronic equipment able to send signals through a data communication system in the drill string 100 to a computer or data logging system located at the surface. As drilling assembly 100 rotates, it cuts deeper into a formation 105.

FIG. 2 is a cross-sectional view of an embodiment of a drilling assembly 100. Drilling assembly 100 comprises a drill bit body 200 and an oscillating hammer mechanism 201. A piston 202 is disposed within a bore 203 and divides the bore 203 into a lower chamber 204 and an upper chamber 205. The piston 202 is free to move along a central axis of the bore 203, thereby altering the respective volumes of the lower and upper chambers 204 and 205. Seals 206 disposed on the piston seal the piston to the walls of the bore 203 and may prevent fluid from flowing between the lower and upper chambers. The seals may comprise o-rings made from rubber or other polymers and may comprise a low friction coating such as PTFE. The seals may comprise a rigid structure or a spring element that forces the seals against the bore walls. In other embodiments, the seals may comprise a split metal ring.

A rotary valve assembly 207 may be disposed above the upper chamber 205. The rotary valve may comprise a stationary plate 208 and a rotating plate 209. Ports 210 in the rotating plate may alternately align and misalign with ports in the stationary plate, alternately allowing and blocking a fluid flow from entering the upper chamber 204.

The rotating plate 209 may be connected to a turbine 217 driven by the flow of drilling fluid or other fluid. Alternatively, the rotating plate may be driven by an electric motor, a positive displacement fluid device, or another method.

An anvil 211 may be in mechanical communication with a jack element 212. The jack element 212 may comprise a fluid channel 213 having an inlet 214 and an outlet 215. The jack element may slide freely in a bushing 216 or other bearing disposed in the drill bit body 200. The jack element translates between a fully extended position and a fully retracted position. The bushing may be made from brass, bronze, Babbitt metal, a polymer, other materials, or combinations of the above materials. Outlet 215 may comprise a nozzle fixed to the jack element. In some embodiments, the nozzle may comprise a cross-sectional area smaller than a cross-sectional area of the fluid channel 213, thus increasing the velocity of the fluid as it passes through the nozzle. The nozzle may be positioned to direct the fluid flow into the formation, or may be positioned to direct the fluid flow toward a working face to remove drilling chips, debris, and to cool the bit.

In the embodiment of FIG. 2, the piston 202 is in a fully refracted position, maximizing the volume of the lower chamber 204. Ports 210 in the rotary valve assembly 207 are closed, directing a fluid flow through nozzles 218 disposed in the bit body.

In FIG. 3, the rotary valve has rotated to the open position, and fluid flow through the ports into the upper chamber 205 creates a pressure that acts on the top surface of the piston 202, forcing the piston downward toward the anvil 211 connected to the jack element 212. As the piston moves downward, the fluid contained in the lower chamber 204 is forced out through the channel 213 in the jack element 212. Fluid is exhausted through the fluid outlet 215 into a formation, and the piston impacts the anvil and forces the jack element further into the formation. It is believed that the impact of the piston on the anvil and the resulting impact of the jack element on the formation causes the formation to partially fail and allows the drill bit to penetrate the formation at a faster rate. The exhausted fluid through the jack may aid in cooling and lubricating the jack element during drilling. Also, the exhaust fluid may erode or weaken the formation and by positioning the exhaust port the exhaust fluid may help steer the tool string along a desired trajectory.

In the embodiment shown in FIG. 4, a shaft 401 connects the jack element 212 to a rotating device such as a fluid driven turbine or an electric motor. The jack element may rotate with the same angular velocity as the rotary valve, or may rotate with a different angular velocity. In this embodiment, the piston 202 comprises a bore 402 through which the shaft 401 passes. The piston is free to move along a central axis of the shaft. The shaft may comprise a connection to the rotating device that is able to transmit torque, but that isolates the rotating device from the axial motion and force that results from the impacts of the piston on the anvil and jack element. This connection may comprise a key and keyway, a splined interface, a pinned connection, combinations of the above, or a different method.

In FIG. 5, an embodiment of a fluid driven turbine is shown. A fluid flow 501 impinges turbine blades 502, causing a moment that rotates a shaft 503. In this embodiment, the fluid flow comprises drilling mud. The turbine may also produce power to turn an electrical generator for powering downhole instrumentation and data transfer devices. In some embodiments, the shaft drives a rotary valve assembly that controls the flow of fluid into an oscillating hammer assembly. In some embodiments, the shaft may also rotate a jack element.

FIG. 6 discloses an embodiment of a planetary gear assembly 601 disposed intermediate a driving shaft 602 in communication with a motor or turbine and a driven shaft 603 which may be in communication with a rotary valve assembly, a jack element, an electrical generator, or combinations thereof. Planetary gear assembly 601 may comprise a clutch 604 that creates a direct mechanical connection between the driving shaft 602 and the driven shaft 603 forces them to rotate at the same frequency. In some embodiments, multiple gear assemblies may be disposed between the driven and driving shafts 602 and 603 to provide multiple selectable gear ratios.

FIG. 7 discloses an orthogonal view of a working face 700 of a drill bit 104. In this embodiment, drill bit 104 comprises an angular velocity indicated by 701, imparted to the bit by rotation of the drill string. A jack element 212 disposed in the working face 800 of the drill bit 104 is rotationally isolated from the drill bit 104. In this embodiment, the jack element 212 comprises an angular velocity 802 having the same frequency and direction as the angular velocity of the drill bit such that the bit 104 and jack element 212 rotate together.

FIG. 8 discloses an embodiment wherein the drill bit 104 comprises an angular velocity indicated by 801. A jack element 212 comprises a superhard material cutting element 800 disposed offset from the axis of rotation. In this embodiment, the jack element comprises an angular velocity 802 having the same magnitude as the angular velocity 801 but rotating in the opposite direction.

In some embodiments, the angular velocity of the jack element may vary in time according to a repeating pattern. In one embodiment, the drill bit comprises a constant angular velocity 801. The jack element comprises an angular velocity that varies in time. In this embodiment, the jack element rotates quickly while the cutting element is in quadrants 804, 805 806, and slowly while the cutting element is in quadrant 807. Thus, in the time period of one revolution of the jack element, the offset cutting element is located within quadrant 807 for more than one quarter of the time period. It is believed that by varying the rotation of the jack element in this manner, the offset cutter will guide the drill bit in a direction corresponding to the quadrant through which the jack element rotates slowly through. Thus, directional drilling can be achieved by varying the angular velocity of the jack element.

The drill string may comprise inclination instrumentation devices that transmit information about the position, velocity, and direction of the drill bit, as well as instruments that provide information about the formation and drilling conditions. The data may be transmitted to the surface of the drilling operation for analysis and review through a communication system disposed in the drill string.

FIG. 9a discloses an embodiment of a jack element 900 comprising a channel 903. In this embodiment, nozzles 901 comprise a superhard material to resist wear and abrasion. Nozzles 901 comprise a threaded portion, and matching threads are disposed in an outlet portion 904 of the channel 903. The nozzles may be made from various suitable steel alloys and coated with polycrystalline diamond, cubic boron nitride, tungsten carbide, combinations thereof, or other superhard materials. In some embodiments, the nozzles may be made from tungsten carbide. The threaded nozzles are easily replaced when necessary, and can be replaced with nozzles having a different cross-sectional area.

FIG. 9b discloses another embodiment of a jack element 900. In this embodiment, nozzles 901 are pressed into outlet portions of the channel 903 disposed in the jack element.

FIG. 9c discloses another embodiment of a jack element 900. In this embodiment, nozzles 901 are brazed into the outlet portions of the channel 903 disposed in the jack element.

FIG. 10a discloses an embodiment of a jack element 1000 and a shaft 1001. Shaft 1001 comprises a key 1002 that corresponds to a keyway 1003 disposed in a bore 1004 in the jack element 1000. The jack element 1000 can translate along an axis of rotation, while the key and keyway transmit torque from the shaft to the jack element.

FIG. 10b discloses another embodiment of a jack element 1000 and a shaft 1001. In this embodiment, shaft 1001 comprises exterior splines 1005 disposed on the outer diameter of a distal end of the shaft 1001. Corresponding interior splines 1006 are disposed within a bore 1004 in the jack element. The splines allow translational movement of the jack element along a central axis of the shaft 1001, while transmitting torque from the shaft to the jack element.

FIG. 10c discloses another embodiment of a jack element 1000 and a shaft 1001. In this embodiment, threaded studs 1007 on the jack element 1000 pass through holes 1008 disposed in a flange 1009 on the shaft 1001. Threaded nuts 1010 may be used to fasten the jack element to the shaft 1001. In this embodiment, translational and rotational movements are transferred between the shaft and the jack element.

FIG. 11 discloses the channel 903 going through an insert 1103 secured to the jack element 1000. The insert may comprise a diamond working surface 1101 supported on a cemented metal carbide substrate 1102.

FIG. 12 discloses an anvil with a protruding member 1200 adapted to travel within the channel 903 of the jack element. A distal end 1201 of the protruding member may substantially form a seal with the inner surface 1203 of channel. Inlets 1204 may allow drilling fluid to enter the channel, and as the anvil travels towards the distal end of the jack element, the fluid volume within the channel may be expelled with a great force. This embodiment may intensify the force the fluid volume is ejected; thus, increasing the rate of erosion of the formation.

Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.

Claims

1. A drill bit, comprising:

an axis of rotation and a drill bit body comprising a central bore and a working face, the working face comprising a plurality of fixed cutting elements;

a jack element extending from the working face and being coaxial with the axis of rotation;

the jack element comprising a proximal end in mechanical communication with anaxially oscillating hammer mechanism;

the jack element also comprising a channel in fluid communication with the central bore, the channel directing a fluid flow into a formation; wherein

a fluid volume defined by the hammer mechanism and the central bore is evacuated through the channel.

2. The bit of claim 1, wherein the channel terminates at one or more nozzles disposed proximate the distal end of the jack element.

3. The bit of claim 2, wherein the one or more nozzles comprise a combined cross-sectional area less than the cross-sectional area of the channel.

4. The bit of claim 2, wherein the one or more nozzles comprise a wear resistant material such as polycrystalline diamond or cubic boron nitride.

5. The bit of claim 2, wherein the one or more nozzles are threaded into the jack element.

6. The bit of claim 2, wherein the one or more nozzles are pressed into the jack element.

7. The bit of claim 2, wherein the one or more nozzles are brazed into the jack element.

8. The bit of claim 2, wherein the one or more nozzles comprise an adjustable trajectory.

9. The bit of claim 1, wherein the jack element is connected to the hammer mechanism by a shaft.

10. The bit of claim 9, wherein the jack element is connected to the shaft by a key and keyway, a bolted flange, a press fit, threads, or combinations thereof.

11. The bit of claim 10, wherein the shaft is rotated by a fluid-driven turbine or an electric motor.

12. The bit of claim 11, wherein a gearbox is disposed intermediate the shaft and the turbine or electric motor.

13. The bit of claim 1, wherein the drill bit rotates at a first angular velocity about the axis of rotation and the jack element rotates at a second angular velocity about the axis of rotation.

14. The bit of claim 13, wherein the second angular velocity is equal in magnitude and opposite the direction of the first angular velocity.

15. The bit of claim 13, wherein the second angular velocity is variable in time.

16. The bit of claim 13, wherein the second angular velocity varies according to a pattern that repeats with every revolution of the jack element.

17. The bit of claim 1, wherein the jack element comprises a hard material insert.

18. The bit of claim 17, wherein the hard material insert is disposed coaxial to the axis of rotation.

19. The bit of claim 17, wherein the hard material insert is disposed offset from the axis of rotation.

20. The bit of claim 1, wherein the jack element comprises an inclination instrumentation device in electrical communication with an electronic processing device disposed on the drill string.