Drill Bits With a Fluid Cushion For Reduced Friction and Methods of Making and Using Same

Abstract

A drill bit is disclosed that in one configuration may include at least one cutter on a face section of the bit and at least one opening proximate the at least one cutter configured to discharge fluid under pressure onto the formation to create a fluid cushion between the drill bit and the formation during a drilling operation. An actuation device associated with the drill bit may be utilized to provide fluid under pressure to the at least one opening.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority from the U.S. Provisional Patent Application having the Ser. No. 61/142,049 filed Dec. 31, 2008.

BACKGROUND INFORMATION

1. Field of the Disclosure

This disclosure relates generally to drill bits and systems that utilize the same for drilling wellbores.

2. Background of the Art

Oil wells (also referred to as “wellbores” or “boreholes”) are drilled with a drill string that includes a tubular member having a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”). The BHA typically includes devices and sensors that provide information relating to a variety of parameters relating to the drilling operations (“drilling parameters”), behavior of the BHA (“BHA parameters”) and parameters relating to the formation surrounding the wellbore (“formation parameters”). A drill bit is attached to the bottom end of the BHA. The drill bit is rotated by rotating the drill string and/or by a drilling motor (also referred to as a “mud motor”) in the BHA to disintegrate the rock formation to drill the wellbore. A large number of wellbores are drilled along contoured trajectories. For example, a single wellbore may include one or more vertical sections, deviated sections and horizontal sections through differing types of rock formations. When a drilling condition changes, it is desirable to alter one or more drilling parameters, such as rate of penetration (ROP), depth of cut (DOC) of the drill bit cutters, weight-on-bit (WOB), rotational speed of the drill bit (RPM), etc., to alter a behavior of the drill bit, such as whirl. stick-slip, vibration, etc. The ROP is typically controlled by controlling the weight-on-bit (WOB) and RPM. WOB is controlled by varying the hook load at the surface and the RPM is controlled by altering the drill string rotation at the surface and/or by controlling the drilling motor speed in the BHA. Such methods require the drilling system or operator to take actions at the surface. Therefore, the impact of such surface actions on the drill bit behavior is not substantially immediate—it occurs a later time period, depending upon the wellbore depth.

Therefore, there is a need to provide an improved drill bit and a system for using the same for controlling drill bit behavior during drilling of wellbores.

SUMMARY

In one aspect, a drill bit is disclosed that, in one configuration, includes one or more cutters on a face section thereof and one or more fluid openings proximate to the cutters. The fluid openings are configured to discharge fluid under pressure onto the formation during drilling. The discharged fluid provides a cushion between the drill bit face and the formation, which reduces friction between the drill bit face and the formation.

In another aspect, a method of making a drill bit is disclosed that may include: providing one or more cutters on a face section of the drill bit and providing one or more fluid channels proximate to the cutters configured to discharge high pressure fluid onto the formation to reduce friction between the drill bit face and the formation during drilling of a wellbore.

In another aspect, a method of drilling a wellbore is provided that may include: conveying a drill bit attached to a bottomhole assembly into the wellbore, the drill bit having one or more cutters on a face section thereof and one or more fluid channels proximate to the cutters configured to discharge fluid under pressure on the formation to create a fluid cushion between the formation and the face section to reduce friction between the formation and the face section; and drilling the wellbore using the drill bit while discharging the fluid under pressure onto the formation.

Examples of certain features of the apparatus and method disclosed herein are summarized rather broadly in order that the detailed description thereof that follows may be better understood. There are, of course, additional features of the apparatus and method disclosed hereinafter that will form the subject of the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which:

FIG. 1 is a schematic diagram of an exemplary drilling system that includes a drill string that includes a drill bit at its bottom end made according to one embodiment of the disclosure;

FIG. 2A is a perspective view of an exemplary drill bit showing placement of one or more fluid openings on a bottom section of the drill bit according to one embodiment of the disclosure;

FIG. 2B shows a perspective view of the bottom section of the drill bit of FIG. 2A showing an exemplary symmetric placement of fluid openings proximate to cutters on certain blades of the drill bit according to one embodiment of the disclosure;

FIG. 3A is a schematic illustration of a side portion of the drill bit of FIG. 2A that shows a fluid channel in communication with each fluid opening from the center waterway of the drill bit and a control unit for supplying fluid under pressure to each of the fluid channels according to one embodiment of the disclosure; and

FIG. 3B shows a common control valve for controlling fluid supply to a number of fluid channels in the drill bit according to one embodiment of the disclosure.

DETAILED DESCRIPTION OF THE EMBODIMENTS

FIG. 1 is a schematic diagram of an exemplary drilling system 100 that may utilize drill bits made according to the disclosure herein. FIG. 1 shows a wellbore 110 having an upper section 111 with a casing 112 installed therein and a lower section 114 being drilled with a drill string 118. The drill string 118 is shown to include a tubular member 116 with a BHA 130 attached at its bottom end. The tubular member 116 may be a coiled-tubing or made by joining drill pipe sections. A drill bit 150 is shown attached to the bottom end of the BHA 130 for cutting the rock formation 119 to drill the wellbore 110 of a selected diameter.

Drill string 118 is shown conveyed into the wellbore 110 from a rig 180 at the surface 167. The exemplary rig 180 shown is a land rig for ease of explanation. The apparatus and methods disclosed herein may also be utilized with offshore rigs (not shown) used for drilling wellbores under water. A rotary table 169 or a top drive 168 coupled to the drill string 118 may be utilized to rotate the drill string 118, BHA 130 and the drill bit 150 to drill the wellbore 110. A drilling motor 155 (also referred to as the “mud motor”) may be provided in the BHA 130 to rotate the drill bit 150. The drilling motor 155 may be used alone to rotate the drill bit 150 or to superimpose the rotation of the drill bit 150 by the drill string 118. A control unit (or controller) 190, which may be a computer-based unit, may be placed at the surface 167 to receive and process data transmitted by the sensors in the drill bit 150 and the sensors in the BHA 130, and to control selected operations of the various devices and sensors in the BHA 130. The surface controller 190, in one embodiment, may include a processor 192, a data storage device (or a computer-readable medium) 194 for storing data, algorithms and computer programs 196 accessible to the processor 192. The data storage device 194 may be any suitable device, including, but not limited to, a read-only memory (ROM), a random-access memory (RAM), a flash memory, a magnetic tape, a hard disk and an optical disk. During drilling, a drilling fluid 179 from a source thereof is pumped under pressure into the tubular member 116. The drilling fluid is discharged at the bottom of the drill bit 150 and returned to the surface via the annular space 120 (also referred as the “annulus”) between the drill string 118 and the inside wall 142 of the wellbore 110.

Still referring to FIG. 1, the drill bit 150 includes a face section (or bottom section) 152. The face section 152 or a portion thereof, faces the formation in front of the drill bit or the wellbore bottom during drilling. The drill bit 150, in one aspect, may include one or more cutters 154 and one or more fluid openings 160 at the face section 152. The fluid openings may be proximate the cutters and configured to discharge or inject the fluid under pressure from the face section 152 of the drill bit 150 onto the formation in front of the drill bit during drilling of the wellbore 110. The drill bit 150 also includes relatively large additional openings in the drill bit (as described in reference to FIG. 2B) that are configured to discharge the drilling fluid at the drill bit bottom to move the cuttings made by the drill bit to the surface 167 via the annulus 120. The fluid openings 160 are typically small diameter openings proximate the cutters on the face section 152 that are capable of discharging fluid under high pressure to create a fluid laminate or a fluid cushion between the face section 152 of the drill bit 150 and the formation 162 in front of the drill bit. The fluid cushion may reduce the depth of cut of one or more of the cutters 154 proximate to the fluid openings 160. The depth of the fluid cushion may depend upon the pressure of the fluid discharged from the fluid openings 160. The depth of cut of the cutters 154 may depend on the fluid cushion depth. A suitable actuation device (or actuation unit) 165 in the BHA 130 and/or in the drill bit 150 may be utilized to control the supply of the fluid to the fluid openings 160 during drilling of the wellbore 110. A suitable sensor 178 associated with the openings 160 or the actuation device 165 may provide signals corresponding to the pressure of the fluid discharged from the openings 160.

Still referring to FIG. 1, the BHA 130 may further include one or more downhole sensors (collectively designated by numeral 175). The sensors 175 may include any number and type of sensors, including, but not limited to, sensors generally known as the measurement-while-drilling (MWD) sensors or the logging-while-drilling (LWD) sensors, and sensors that provide information relating to the behavior of the BHA 130 and the drill bit 150, such as drill bit rotation speed (revolutions per minute or “RPM”), tool face, pressure, vibration, whirl, oscillation, bending, stick-slip and formation type. The BHA 130 may further include a control unit (or controller) 170 configured to control the operation of the actuation device 165 and for at least partially processing data received from the sensors 175. The controller 170 may include circuits configured to process the signals from the sensors (e.g., amplify and digitize the signals), a processor 172 (such as a microprocessor) to process the digitized signals, a data storage device 174 (such as a solid-state-memory), and computer programs 176 accessible to the processor 170. The processor 172 may process the digitized signals, control the operation of the actuation device 165, process data from sensors 175, control the operations of the sensors 175 and other downhole devices, and communicate data information with the controller 190 via a two-way telemetry unit 188. The controller 170, in one aspect, adjusts the actuation device 165 to control the fluid cushion between the drill bit 150 and the formation 162 in response to one or more parameters of interest based on the programmed instructions stored in the data storage device 174 and/or instructions received from the surface controller 190. Adjusting or altering the fluid cushion, in turn, alters the depth of cut of one or more cutters.

Still referring to FIG. 1, altering cutter depth or cutter exposure may result in altering torsional or lateral fluctuation, whirl, stick-slip, bending moment, vibration, and/or oscillation of the drill bit 150 and the BHA 130, which, in turn, may result in drilling a smoother wellbore and reduce stress on the drill bit 150 and BHA 130, thereby extending the BHA and drill bit lives. For the same WOB and RPM, the ROP is generally higher when drilling into a soft formation, such as sand, than when drilling into a hard formation, such as shale. Transitioning drilling from a soft formation to a hard formation may cause excessive lateral fluctuations because of the decrease in ROP, while transitioning from a hard formation to a soft formation may cause excessive torsional fluctuations in the drill bit because of increase in the ROP. Controlling the fluctuations of the drill bit, therefore, is desirable when transitioning from a soft formation to a hard formation and vice versa. The fluid cushion, as mentioned earlier, may be controlled based on one or more parameters, including, but not limited to: pressure, tool face, ROP, whirl, vibration, torque, bending moment, oscillations, stick-slip and rock type. Automatically and selectively adjusting fluid cushion may enable the system 100 to control the torsional and lateral drill bit fluctuations, ROP and other physical drill bit and BHA parameters without altering the weight-on-bit or the drill bit RPM. The placement of fluid openings and apparatus for controlling the fluid cushion is described in reference to FIGS. 2A, 2B, 3A and 3B.

FIG. 2A shows an isometric view of the drill bit 150 made according to one embodiment of the disclosure. The drill bit 150 shown is a polycrystalline diamond compact (PDC) bit having a bit body 212 that includes a cutting section 212a and shank 212b that connects to a BHA 130. The cutting section 212a includes a face section 218a (also referred to herein as the “bottom section”). For the purpose of this disclosure, the face section 218a may comprise a nose, cone and shoulder as shown in FIG. 3A. The cutting section 212a is shown to include a number of blade profiles 214a, 214b, . . . 214n (also referred to as the “profiles”). Each blade profile terminates proximate to a drill bit center 215. The bit center 215 faces (or is in front of) the bottom of the wellbore 110 ahead of the drill bit 150 during drilling of the wellbore. A side portion 213, generally referred to as the gauge or gauge section, is typically substantially parallel to the longitudinal axis 222 of the drill bit 150. A number of spaced-apart cutters are placed along each blade profile. For example, blade profile 214n is shown to contain cutters 216a-216m. Each cutter has a cutting surface or cutting element, such as cutting element 216a′ for cutter 216a, that engages the rock formation when the drill bit 150 is rotated during drilling of the wellbore. Each cutter 216a-216m is configured with a back rake angle and a side rake angle that, in combination, define the depth of cut of the cutter into the rock formation. Each cutter also has a maximum depth of cut.

Still referring to FIG. 2A, a number of fluid openings, such as openings 270b on blade 214b, 270d on blade 214d and 270n on blade 214n, may be provided to discharge fluid under pressure therefrom to the formation in front of the openings during drilling of the wellbore. In one aspect, the fluid openings 270a-270n may be placed proximate to the cutter on the blade profiles 214a-214n. In other aspects, the fluid openings may be located at any other section of the drill bit, such as the nose section, gage section. In another aspect, the openings may be located on any combination of the drill bit sections. A fluid channel, such as channel 244 may be provided in the bit body to supply the fluid under pressure to the fluid openings as described in more detail in reference to FIGS. 3A and 3B. In one configuration, an actuation device element 350 (FIG. 3A) may supply the fluid under pressure to the pad in each fluid openings.

FIG. 2B shows an isometric view of a face section 252 of an exemplary PDC drill bit 150. The drill bit 150 is shown to include six blade profiles 260a-260f, each blade profile including a plurality of cutters, such as cutters 262a-262m for the blade profile 260a. Alternate blade profiles 260a, 260c and 260e are shown converging toward the center 215 of the drill bit 250 while the remaining blade profiles 260b, 260d and 260f are shown terminating respectively at the side of blade profiles 260c, 260e and 260a. One or more fluid openings may be formed on one or more blades for discharging fluid under pressure onto the formation to create a fluid cushion between the formation and the face section of the drill bit. As an example, FIG. 2B shows fluid openings 270a on blade 260a proximate cutters 262a-262m, fluid openings 270c on blade 260c and fluid openings 270e on blade 260e. Fluid openings may also be provided on other blades. In one aspect, the fluid openings may be placed symmetrically or substantially symmetrically on the blades as shown in FIG. 2B or in another suitable pattern. Fluid openings 217a may also be provided on the shoulder section and/or openings 217b on the gage section of the drill bit, as shown in FIG. 2A. In operation, fluid openings 270a, 270c and 270e discharges a fluid under pressure onto the formation in front of the drill bit 150. Fluid openings 217a and 217b (FIG. 2A) discharges fluid under pressure on the formation on the side of the drill bit 150. Although the drill bit shown is a PDC bit with six blade profiles (260a-260f) and the fluid openings 270a-270e on three such blades, the drill bit 150 may include any suitable number of blade profiles and fluid openings at any desired locations. Furthermore, the concepts shown and described herein are equally applicable to non-PDC drill bits.

FIG. 3A shows a partial side view 300 of an exemplary blade profile 310 of the drill bit 150 (FIG. 2B). The blade profile 310 is shown to include exemplary cutters 316 and 318 on the face section 320 of a selected blade formed on a bit body 315. The cutters 316 and 318 extend a selected distance from the face section 320 of the blade profile 310. The face section 320 is further shown to include fluid openings 340a and 340b proximate the cutters 316 and 318 respectively. A fluid channel 345a extends from an inside chamber 348 of the drill bit to the fluid opening 340a while a fluid channel 345b extends from the inside chamber 348 to the fluid opening 340b. Similarly, each of the other fluid openings may be connected to their respective fluid channels. Typically, the inside chamber 348 center of the drill bit, is filled with the drilling fluid supplied (179) from the surface. In one embodiment, a fluid under pressure from a source thereof (such as the fluid in the chamber 348) may be supplied under pressure to each of the fluid openings, such as openings 340a and 340b via the fluid channels 345a and 345b, respectively. In one embodiment, an actuation device or a power source 350 placed at a suitable location in the drill bit 150 or in the BHA 130 may be utilized to supply the fluid under pressure to each of the fluid channels. In one aspect, the actuation device 350 may include a pump 351 driven by a prime mover 352, such as a motor. A controller 170 may be configured to control the operation of the prime mover 352. The controller 170 may utilize instructions stored in the downhole memory 174 and/or instructions transmitted by the surface controller 190 (FIG. 1) to control the operation of the actuation device 350. In one aspect, a sensor 360 may provide signals corresponding to the pressure of the fluid discharged by the actuation device 350, which signals may be utilized by the controller 170 to control the actuation device 350. In another aspect, the controller 170 may control the operation of actuation device 350 in response to any suitable parameter of interest, including but not limited to, vibration, oscillation, bending, stick-slip, WOB, RPM and formation type. In the system described above, the actuation device 350 supplies the fluid under the same pressure to each of the openings in the drill bit. In another aspect, a control valve 354 may be provided between the actuation device 350 and the fluid channels, such as channels 345a, 345b . . . 345p. The control valve 354 may be controlled by the controller 170 to control the pressure of the fluid supplied to the openings 340a, 340b, etc. The controller also may be configured to modulate the actuation device 350 and/or control valve 354. The control valve 354 may be coupled to the fluid channels by a distributor 370 (FIG. 3B) that receives the fluid from the actuation device and distributes the received fluid to the individual fluid channels 345a, 345b . . . 345p. In another aspect, a mechanical rotating device may be utilized to supply fluid to each of the channels. The actuation device 350 may be any suitable device, including, but not limited to, an electrical device, an electro-mechanical or hydraulic device, a pump driven by a motor, a hydraulic device, such as a pump driven by a fluid-driven turbine, and a mechanical device, such as a ring-type device that selectively allows a fluid to flow to the fluid channels 345a-345p.

Referring to FIGS. 1-3B, in operation, the fluid pressure may be controlled based on the desired impact on the rate of penetration of the drill bit into the earth formation and/or a property of the drill bit 150 or the BHA 130. The fluid pressure may be controlled based on any one or more desired parameters, including, but not limited to, vibration, drill bit lateral or torsional fluctuations, ROP, pressure, tool face, rock type, vibration, whirl, bending moment, stick-slip, torque and drilling direction. In general, however, the greater the fluid pressure, the greater the fluid cushion, an thus greater the reduction in the ROP of the drill bit into the formation. A drill bit made according to any of the embodiments described herein may be employed to reduces the depth of cut by the cutters at the face section of the drill bit, which in turn affects the drill bit fluctuations and ROP. Reduction in the drill bit fluctuations (torsional or lateral) may affect one or more of the drill bit and/or BHA physical parameters. The relationship between the applied fluid pressure and the ROP may be obtained in laboratory tests. The calculated or otherwise determined (such as through modeling) relationship among the fluid pressure, depth of cut, drill bit fluctuations, ROP and any other parameter obtained from tests or actual results may be stored in the downhole data storage device 174 and/or the surface data storage device 194. Such information may be stored in any suitable form, including, but not limited to, one or more algorithms, curves, matrices and tables. The fluid pressure may be controlled by the downhole controller 170 and/or by the surface controller 190. The system 100 provided herein may automatically and dynamically control the fluid pressure and thus the drill bit fluctuations, ROP and other parameters during drilling of the wellbore 110 without changing certain other parameters, such as the WOB and RPM. The fluid pressure to the openings 217a and 217b (FIG. 2A) on the side of the drill bit may be controlled in the same manner as the fluid pressure to the openings on the face section. The fluid openings on the face section and the side section may be activated concurrently.

Thus, in one aspect, a drill bit is disclosed that in one configuration may include a face section or bottom face that includes one or more cutters thereon configured to penetrate into a formation; at least one opening proximate a cutter configured to discharge fluid under pressure onto the formation; and an actuation device configured to supply the fluid under pressure to the at least one opening when the drill bit is engaged for cutting the formation. The at least one opening may comprise a plurality of openings and the actuation device may be configured to supply the fluid under pressure to each of the openings. In one aspect, the actuation device may be configured to supply a drilling fluid flowing through the drill bit to the openings when the drill bit is engaged in drilling the wellbore. In another aspect, the actuation device may comprise a control valve in a fluid line that supplies the fluid to the openings to control the amount of the fluid supplied to such openings. A suitable pump may be utilized to supply the fluid to the control valve. The control valve may be any suitable valve for use downhole, including, but not limited to, a one-way valve and an electrical valve. In another aspect, the actuation device may include a ring device configured to open and close a fluid passage to the openings. In another aspect, a controller associated with the drill bit may be configured to control the actuation device for providing fluid under pressure to the openings. The controller also may modulate the fluid supply to the openings.

In another aspect, a method for drilling a wellbore is provided, which method, in one aspect, may include: conveying a drill bit attached to a bottomhole assembly into the wellbore, the drill bit having at least one fluid channel proximate one or more cutters on a face section of the drill bit and one or more fluid channels proximate the one or more cutters configured to discharge fluid under pressure on to the formation to create a fluid cushion between the formation and the face section to reduce friction between the formation and the face section; and drilling the wellbore using the drill bit while supplying fluid under pressure to the one or more channels. In one aspect, when more than one fluid channel is provided, the method may further include providing the fluid to each channel at the same pressure. In another aspect, the method may further include controlling the pressure of the supplied fluid in response to a selected parameter. The selected parameter may include, but is not limited to, change of formation type (e.g. from hard to soft formation and vice versa), vibration, whirl, stick-slip, acceleration bending moment, oscillation, torque and rate of penetration. In another aspect, the fluid may be supplied using a suitable actuation device, including, but not limited to: a pump unit that supplies fluid under pressure to the one or more channels and a mechanical device that opens and closes a fluid supply line to the one or more fluid channels.

In yet another aspect, an apparatus for use in drilling a wellbore is provided, which, in one aspect may include: a drill bit attached to a bottom end of a bottomhole assembly, the drill bit having a face section that includes one or more cutters and at least one opening configured to discharge fluid from the drill bit and an actuation device configured to supply fluid under pressure to the at least one opening. The apparatus may further include a controller configured to control the actuation device to control the supply of the fluid to the at least one opening. In one aspect, the controller may be configured to control the actuation device in response to a parameter, including, but not limited to: vibration, stick-slip, weight-on-bit, rate of penetration of the drill bit; bending moment, tangential acceleration; axial acceleration; radial acceleration; a drill bit fluctuation, a dysfunction relating to the drill bit, and a dysfunction relating to the drill string or bottomhole assembly. In one aspect, the actuation device may be a pump that supplies fluid under pressure; and a mechanical motion device that opens and closes a fluid path to the at least one opening. The apparatus may further include a sensor that provides signals relating to the pressure of the fluid supplied to the at least one opening. In another aspect, the apparatus may include a plurality of openings proximate cutters and wherein the actuation device supplies the fluid under pressure to each such opening at the same pressure.

The foregoing disclosure is directed to certain specific embodiments for ease of explanation. Various changes and modifications to such embodiments, however, will be apparent to those skilled in the art. It is intended that all such changes and modifications within the scope and spirit of the appended claims be embraced by the disclosure herein.

Claims

1. A drill bit, comprising:

a face section that includes one or more cutters thereon configured to penetrate into a formation;

at least one opening in the drill bit configured to discharge fluid under pressure onto the formation; and

an actuation unit configured to supply the fluid under pressure to the at least one opening when the drill bit is engaged for cutting the formation.

2. The drill bit of claim 1, wherein the at least one opening comprises a plurality of openings and wherein the actuation unit is configured to supply the fluid under pressure to each of the openings.

3. The drill bit of claim 1, wherein the at least one opening is located at one or: a face section; gage section; and cone section.

4. The drill bit of claim 1, wherein the actuation unit comprises a control valve in a fluid line that supplies the fluid to the at least one opening to control the amount of the fluid to the at least one opening.

5. The drill bit of claim 4, further comprising a pump configured to supply the fluid to the valve.

6. The drill bit of claim 4, wherein the control valve is one of: a one-way valve; and

an electrical valve.

7. The drill bit of claim 1, wherein the actuation unit includes a ring device configured to open and close a fluid passage to the at least one opening.

8. The drill bit of claim 1, further comprising a controller configured to control the actuation device for providing fluid under pressure to the at least one opening.

9. The drill bit of claim 1, further comprising a sensor that provides signals relating to the pressure of the fluid supplied to the at least one opening.

10. A method of drilling a wellbore, comprising:

conveying a drill bit attached to a bottomhole assembly into the wellbore, the drill bit having at least one cutter on a face section of the drill bit and at least one opening proximate to at least one cutter, the at least one opening configured to discharge a fluid under pressure onto a formation when the drill bit is engaged in cutting the formation;

drilling the wellbore by rotating the drill bit; and

supplying the fluid under pressure to the at least one opening to create a fluid cushion between the face section of the drill bit and the formation.

11. The method of claim 10, wherein the at least one opening includes a plurality of openings and wherein the method further comprises providing fluid under substantially the same pressure to each of the openings.

12. The method of claim 10, further comprising controlling the supply of the fluid to the at least one opening in response to a selected parameter.

13. The method of claim 12, wherein the selected parameter relates to one or more of: a dysfunction relating to the drill bit; a dysfunction relating to the bottomhole assembly; a change of formation; vibration; whirl; stick-slip; bending moment;

oscillation; torque; rate of penetration; weight-on-bit; tangential acceleration; axial acceleration; radial acceleration; and drill bit fluctuation.

14. The method of claim 10, wherein supplying the fluid under pressure comprises using an actuation device that is one of: a pump configured to supply the fluid under pressure to the at least one opening; and a mechanical device that opens and closes a fluid supply line to the at least one opening.

15. A method of manufacturing a drill bit, comprising:

providing a drill bit having at least one cutter on a face section of the drill bit; and

forming at least one opening proximate the at least one cutter configured to discharge a fluid under pressure onto a formation when the drill bit is engaged in cutting the formation.

16. The method of claim 15, further comprising providing a fluid supply unit configured to supply the fluid under pressure to the at least one opening via a fluid channel.

17. The method of claim 16, further comprising providing a control unit configured to control the fluid supply unit in response to a parameter of interest.

18. The method of claim 17, further comprising providing a sensor configured to provide a measurement relating to the parameter of interest.

19. The method of claim 17, wherein the parameter of interest is one or more of: a dysfunction relating to the drill bit; a dysfunction relating to the bottomhole assembly; a change of formation; vibration; whirl; stick-slip; bending moment; oscillation; torque; rate of penetration; weight-on-bit; tangential acceleration; axial acceleration; radial acceleration; and drill bit fluctuation.

20. The method of claim 15, further comprising controlling the supply of the fluid to the at least one opening in response to a selected parameter.