Boreholes are conventionally drilled to facilitate the recovery of hydrocarbons from underground wells and reservoirs, typically using a drill bit attached to a lower end of a drill string or the like. The structure and type of drill bits varies considerably, but they generally have a fixed drilling diameter (that is, they will only cut a certain diameter of hole). Furthermore, drill bits are prone to wear and thus the diameter of the hole that the drill bit cuts may reduce over time. This is disadvantageous, particularly when the bit is replaced by another bit, as the reduction in diameter may cause the replacement bit to become stuck. Also, as boreholes can be many kilometres in length, the diameter of the borehole can reduce as the length increases.

According to the present invention, there is provided a method of drilling a borehole, the method comprising the steps of providing a drill bit attachable to a drill string or coiled tubing string, where the drill bit has at least one cutting blade, and drilling the borehole, characterised in that the configuration of the said at least one cutting blade can be changed to adjust the cutting diameter of the drill bit.

The invention also provides a drill bit comprising a body and at least one blade pivotally mounted thereon and movable between a retracted position and an extended position, in the retracted position the blade lying substantially within the circumference defined by the body and a cutting face of the blade extending longitudinally of the body, and in the extended position the blade extending laterally of the body, and blade extending means for rotating the blade from the retracted position to the extended position, the blade being located at an end of the drill bit, characterised in that the drill bit includes a locking means to lock the blade in the retracted position.

The invention further provides a drill bit comprising a body and at least one blade pivotally mounted thereon and movable between a retracted position and an extended position, in the retracted position the blade lying substantially within the circumference

defined by the body and a cutting face of the blade extending longitudinally of the body, and in the extended position the blade extending laterally of the body, and blade extending means for rotating the blade from the retracted position to the extended position, the blade being located at an end of the drill bit, characterised in that the blade is at least partially coated with polycrystalline diamond.

The polycrystalline diamond coating typically comprises polycrystalline diamond cutters.

The method preferably includes the additional step of extending the blade to the desired cutting diameter.

The blade is typically extended by applying pressure thereto. The pressure may be applied by fluid such as drilling mud, or by the weight of the string or the like. The pressure applied is typically a minimum of 20 pounds per square inch (psi) to initiate extension of the blades.

In a simple embodiment, the blade is extended to the required cutting diameter and the blade to effect drilling of the borehole.

The method described in certain embodiments provides a drill bit that will pass through a restriction (such as small tubing or a safety valve) and allow a hole larger than the restriction to be drilled below the restriction by expanding the blades to a pre- determined size. On completion of drilling, the

fluid pressure is reduced to allow the cutting blades to collapse to their rest position so that the drill bit can be retrieved to surface back through the smaller diameter of the restriction.

The drill bit is typically rotated at 100 revolutions per minute (rpm) depending upon formation structure.

In certain embodiments, the downward forces experienced by the blade during a cutting operation, in response to weight applied to the blade from above or fluid pressure applied to the blade, tends to maintain the blade in an extended configuration.

This effect may be achieved by rotating the blade such that the resultant of the blade forces is directed outwardly of the blade pivot. With this arrangement, there is no requirement to continue to apply a blade extending force to the blade once the blade has been extended, other than the application of weight to the drill bit.

The method optionally comprises the additional steps of maintaining pressure to extend the blade, and retracting the drill string or coiled tubing string from the borehole. The drill bit is optionally bi- directional and can be used to drill or cut in the upward direction also.

Preferably, the blade is located at the end of the drill bit, and this allows fewer limitations on the

length and width of the blade and the cutting diameter of the drill bit.

The ability to rotate the blade through an angle of preferably greater than 45° permits the bit to define a relatively large cutting area as the extent of the cutting face of the blade is not limited by the diameter of the body of the drill bit. Preferably, the blade extending means rotates the blade through an angle of at least 60°, and more preferably an angle of at least 75°. In one preferred embodiment the blade extending means is capable of rotating the blade through approximately 90°, such that the blade extends substantially perpendicularly to the longitudinal axis of the body. With this range of movement available the cutting diameter provided by the blade is substantially independent of the body diameter; in the retracted position the only limitation is the length of blade that may be accommodated. As the blade is provided at an end of the bit, the restrictions on the length of blade that can be accommodated are considerably reduced.

Further, in a preferred embodiment the degree of rotation of the blade is such that the downward forces experienced by the blade during a cutting operation, in response to weight applied to the bit from above, tend to maintain the blade in the extended configuration. This effect may be achieved by rotating the blade such that the resultant of the

blade forces is directed outwardly of the blade pivot. With this arrangement, there is no requirement to continue to apply a blade extending force to the bit once the blade has been extended, other than the application of weight to the bit.

Preferably also, the end of the bit comprises a drilling member, such as a spade point. The drilling member may be exposed only once the blade has been extended. Alternatively, or in addition, in the extended position the blade defines an additional cutting face when the blade is extended.

Preferably also, the bit includes at least two blades. Preferably, the blades are mounted on a common pivot axis and in extended configurations extend from opposite sides of the body.

Preferably also, the body defines a fluid passage communicating with an outlet adjacent the blade, so that fluid may be passed through the body and exit the body as a jet to assist in the cutting operation.

Outlets may be provided both above and below the blades. The opening of the passage, and thus the positioning of the blade in the extended configurations, is detectable at the surface as a decrease in back pressure when pressurised fluid is applied to the tool through a supporting member, such as drill pipe or coil tubing.

The method optionally includes the additional steps of attaching the drill bit to a drill string or coiled tubing string, running the string into a borehole through a restriction, extending the blade, and rotating the blade to drill a borehole below the restriction.

The locking means on the drill bit provides the advantage that it prevents the blade from opening partially or fully until required.

The drill bit is optionally provided with two blades, but this is not essential.

The locking means typically comprises a first locking member provided on one of the body and the blade, and a second locking member provided on the other of the body and the blade.

Alternatively, where two blades are provided, the locking means typically comprises a first locking member provided on one of the blades, and a second locking member provided on the other blade.

The first locking member typically comprises a biasing member that is provided with a recess at one end thereof, and a locking device located in the recess. The second locking member comprises a recess.

The biasing means is typically provided with a first aperture in which a biasing member is located to bias the locking device into engagement with the recess provided on the blade or body. The blade or the body typically includes an aperture formed therein for receiving the biasing means.

The aperture in the blade or body is preferably provided with a screw thread to receive a screw thread provided on the biasing means.

The bias of the biasing member can typically be varied by adjusting the position of the biasing means within the aperture formed in the blade or body. In this way, the bias of the biasing member can be varied.

The locking means is typically actuated by fluid pressure. The fluid pressure is preferably sufficient to overcome the bias of the biasing member. Thus, the or each blade will not be extended unless and until the fluid pressure applied to the locking means exceeds the bias force of the biasing member. In this way, the or each blade is prevented from partially or fully opening until fluid pressure sufficient to overcome the bias of the biasing member is applied to the locking means.

In one specific embodiment of the locking means, the biasing member comprises a screw, the biasing means

comprises a spring, and the locking device comprises a ball bearing.

The or each blade is typically at least partially coated with polycrystalline diamond. The polycrystalline diamond preferably comprises polycrystalline diamond cutters (PDCs).

Embodiments of the present invention shall now be described, by way of example only, with reference to the accompanying drawings, in which: Fig. 1 is a side view of a drill bit for use with the method of the present invention, showing the blades of the drill bit in an extended position; Fig. 2 shows the blades of the drill bit of Fig.

1 in a retracted position; Fig. 3 is an end elevation showing the blades of the drill bit of Figs 1 and 2 in the extended position; Fig. 4 is a sectional view of the drill bit of Fig. 1; Fig. 5 is a sectional view of the body of the drill bit of Fig. 1; Fig. 6a is a sectional view of a second embodiment of a drill bit for use with the method according to the present invention; Fig. 6b is a sectional view of the drill bit of Fig. 6a, with the blades of the drill bit removed;

Figs 7a to c show the blades for use with either embodiment of the drill bit in varying degrees of extension from a retracted position to a fully extended position; Figs 8a and 8b show alternative blade configurations for use with a locking means; and Fig. 8c shows an example of a locking means used to control movement of the blades shown in Figs 8a and 8b.

Referring to the drawings, Figs 1 to 5 show a first embodiment of a drill bit 10 for location on the lower end of a string of drill pipe (not shown), more commonly referred to in the art as a drill string.

It will be generally appreciated that the bit 10 could equally be attached to a lower end of a coiled tubing string (not shown). Drill bit 10 comprises a tubular body 12 carrying a pair of cutting blades 14, 15 on the lower end thereof. The blades 14,15 are illustrated in a fully extended position in Figs 1 and 3, and in a fully retracted position in Fig. 2.

In the fully retracted position shown in Fig. 2, the blades 14,15 extend parallel to a longitudinal axis of the bit 10, and lie within the overall diameter of the body 12. Thus, the bit 10 can be run through a restriction (e. g. a safety valve or the like) in a predrilled borehole. Thereafter, the blades 14,15 can be extended (as will be described) which allows a hole larger than the restriction to be drilled below the restriction. In the fully extended position as shown in Figs 1 and 3, the blades 14,15 extend

outwardly of the body 12 in a direction that is substantially perpendicular to the longitudinal axis of the body 12. Once the borehole has been drilled below the restriction to the required depth, the blades 14,15 collapse to the retracted position to allow the string and bit 10 to be withdrawn from the borehole through the restriction. The blades 14,15 can be biased to the retracted position using, for example, a spring, or can be pushed inwards by the restriction as the bit 10 is withdrawn.

An upper cylindrical portion of the body 12 contains an annular blade actuating piston 16 (Fig. 4), normally biased to a blade retracted position by a spring 18. The piston 16 is movable in response to elevated fluid pressure within the body 12, although it may be configured to be movable in response to weight applied to the bit (e. g. by the weight of a drill string or coiled tubing string to which the bit 10 is attached). The lower face of the piston 16 is attached to or otherwise engages upper ends of two dowels 20,21 that extend through the body 12 and contact a cam member 22 that is axially movable on a rectangular body portion 24 extending below the cylindrical portion 12. The cam 22 includes two axially extending fingers 26,27 for engaging cam surfaces of the respective blades 14,15.

The blades 14,15 are held on the rectangular body portion by a common hinge pin 28. The blades 14,15 are substantially U-shaped and each blade has two

transversely spaced legs 30a and 30b on either side of the rectangular body portion 24. The pin 28 passes through apertures 31 in the legs 30a, 30b so that the blades 14,15 may pivot about the pin 28.

The blades 14,15 are biased towards the retracted position by respective torsion springs 32.

As best seen in Fig. 4, the width of each blade 14, 15, at least at the blade end, corresponds to the body diameter, representing around 48° of the circumference swept by the extended blades. The width of the blade 14,15 is defined as the width of the blade at its broadest point in a direction that is parallel to the axis of rotation of the blade about its pivot point (i. e. about pin 28), and this width is substantially equal to the diameter of the body 12. In other words, the width of the blades 14, 15 in a direction that is tangential to the direction of rotation of the blades in their extended position is equal to the diameter of the body 12 of the bit 10. For clarity, this is the equivalent of the overall diameter of the bit 10 when the blades are in the retracted position.

It should also be noted that the thickness of the blades 14,15 is relatively large, providing blades that are relatively robust. The thickness of the blades 14,15 at their greatest extent is in a direction that is parallel to the longitudinal axis of the bit 10 and is substantially equal to half the diameter of the body 12.

Referring now to Figs 7a to 7c, there is shown three- dimensional views of the blades 14,15. Fig. 7a shows the blades 14,15 in the fully retracted position, whereas Fig. 7c shows them fully extended.

It will be appreciated that the blades 14,15 may be used in any intermediate position, such as that shown in Fig. 7b. In use, the blades 14,15 are extended to the required cutting diameter of the borehole. To facilitate cutting diameters that are larger than the full extent of the blades 14,15, the lengths of the blades 14,15 may also be changed. It will be noted that by having the blades 14,15 at a lower end of the bit 10, there is no restriction on the lengths of the blades 14,15, and thus no restriction on the diameter of the borehole that can be drilled using bit 10.

Each blade 14,15 defines a primary cutting face 34, 35 that extends laterally of the body when the blades 14, 15 are in an extended position, as best shown in Fig. 7c. The faces 34,35 are provided with a hardened facing of, for example, polycrystalline diamond or tungsten carbide and it will be noted that each cutting face 34,35 extends over more than half of the diameter of the circumference swept by the extended blades. From Fig. 2 of the drawings it will be noted that the faces 34,35 lie longitudinally relative to the body 12 when the blades are in the retracted position. Each blade also defines a cutting face 36,37 on the blade end surface, which

surfaces are provided with a polycrystalline diamond or tungsten carbide facing.

The cutting faces 36,37 allow the drill bit 10 to be operated without the blades fully extended. The projection of the faces 36,37 allows the cutting faces to contact the formation and will abrade the surface of such as the blades 14,15 are rotated.

Continued abrasion of the formation will allow the blades 14,15 to reach their fully extended position, or the required cutting diameter.

In addition to the cutting face as defined by the blades 14,15, the end of the rectangular body portion 24 also defines a spade point 38 provided with a polycrystalline diamond or a tungsten carbide facing.

The cutting action of the various faces can be assisted by the action of jets above and below the blades formed by fluid pumped from the surface through the body 12 and out of appropriate jetting ports 40,41 (Fig. 5) in the body 12, the fluid also serving to carry cuttings from the cutting face to the surface.

In use, the drill bit 10 is mounted on the end of a drill string, coiled tubing string or the like. The drill string is rotated (typically in an anti- clockwise direction as viewed in Fig. 3) to rotate the drill bit 10. Where coiled tubing is used a

motor (not shown) is typically used to rotate the bit 10, as is known in the art. Initially, the provision of the various springs 18,32 ensures that the blades 14,15 remain in the retracted position. However, even in this position, the cutting faces 36,37 may be used for drilling a relatively small diameter circular area. Drilling fluid or"mud"is then pumped through the drill string or coiled tubing string from the surface, and the pressure acting on the upper end of piston 16 pushes the piston 16 against the action of the spring 18. This movement pushes the dowels 20,21 out of the cylindrical portion of the body and moves the cam member 22 into contact with the cam faces of the blades 14,15. The blades 14,15 are thus pivoted outwardly, and if necessary the cutting faces 36,37 are employed to cut the formation to allow the blades 14,15 to move to the required cutting diameter. The provision of the cam fingers 26,27 extending beyond the body of the cam member 22 and engaging the blade cam surfaces permits the blades 14,15 to be rotated through 90°, until they are substantially perpendicular to the body axis, at which point the maximum cutting diameter is achieved. It will be appreciated that the maximum cutting diameter can be varied by changing the length of the blades 14,15. As described above, there is no limitation to the length of the blades 14,15 and thus the diameter of the hole that can be cut because the blades 14,15 are located at a lower end of the bit 10.

On reaching the fully extended positions the head of each blade 14,15 comes into contact with a side face of the rectangular body portion 24 and thus acts as a stop, and also reduces the cutting force load that must be borne by the hinge pin 28.

The illustrated blade configuration is primarily intended for drilling in a downward direction, though the provision of cutting faces 36,37 that extend onto the upper surfaces of the extended blades allows the drill bit 10 to be used to cut in an upward direction if necessary.

It will be evident that the cutting faces 34,35 define a relatively large area, thus increasing the cutting rate and decreasing blade wear. Also, the relatively wide blades 14,15 serve to stabilise the drill bit 10 in the bore, and of course provide blades 14,15 that are relatively robust and less likely to be damaged during drilling.

It will also be apparent that the extended blade configuration, that is the extended blades being over centre, leads to the forces experienced by the blades tending to maintain the blades at the required cutting diameter. Further, key seating of the blade cam surfaces and the cam fingers 26,27 is most unlikely as the forces experienced by the blades 14, 15 are transferred to the body 12 via the upper or rear surfaces of the blades, the arms of the U-shape and the hinge pin 28, and there are no significant

forces required between the cam fingers 26,27 and the blade surfaces to maintain the blades extended,.

The term"key seating"refers to the groove that may be formed by continued application of the cam surfaces to the cam fingers 26,27. In the present invention, once the cam fingers 26,27 have extended the blades 14,15, the force required to extend the blades can be removed. This is because the weight of the drill string or coiled tubing string above the drill bit 10,110, will keep the blades extended without any additional force due to the inherent design of the drill bit 10,110. In this way, the possibility of creating such a groove is substantially reduced.

It will be evident to those of skill in the art that the above-described embodiments offer numerous advantages over conventional drill bits. It will further be evident to those of skill in the art that the above-described embodiments are merely exemplary of the present invention, and that various modifications and improvements may be made thereto without departing form the scope of the present invention.

In a further embodiment of the invention a skirt may be provided on the cam member 22 to cover the gap that is otherwise formed between the lower end of the cylindrical body portion 15 and the upper end of the cam member 22 as the blades are extended. The skirt

prevents debris filling the gap that might prevent retraction of the cam member 22 and thus retraction of the blades. In the blade retracted position the skirt may cover the jetting points 40, these being exposed only when the blades are extended. The exposure of the ports 40, indicating that the blades are extended, will be detectable at the surface as a drop in fluid back pressure. It is possible to calibrate the fluid back pressure detected at the surface to give an indication of the cutting diameter (i. e. the extent of the blades 14,15), as different extensions of the blades will correspond to different back pressures.

Referring now to Figs 6a and 6b, there is shown a second embodiment of a drill bit, generally designated 110, according to the present invention.

The drill bit 110 is substantially the same as the previous bit 10, except for the inclusion of an intensifier piston 152. Note that similar parts have been designated with the same reference numeral, prefixed by 1.

The purpose of the intensifier piston 152 is to increase the force applied to the piston 116 for a given fluid pressure. The intensifier piston 152 is positioned behind the piston 116, as shown in Fig. 6a. Although only one such intensifier piston 152 is shown, it will be generally appreciated that any number of such pistons 152 may be cascaded

in series to further increase the force applied to the piston 116.

Intensifier piston 152 has a plurality of apertures 154 therein at a front portion 156. The apertures 154 in the front portion 156 provide a fluid communication between the interior 158 of the intensifier piston 152 and thus the bore of the coiled tubing or drill string behind the drill bit 110, and an annular chamber 160 that is behind the piston 116.

In use, drilling fluid or mud is pumped down the central bore 162 of the drill bit 110 and the interior 158 of the secondary piston 152. The fluid pressure at the rear face of the intensifier piston 152 forces it from the position shown in Fig. 6a against the piston 116 with which it engages. The movement of the piston 116 pushes on the dowels 120, 121 which forces the skirt 122 against the blades 114,115 as shown in Fig. 6b and forces them outwards, as in the previous embodiment.

In addition to providing the movement of the intensifier piston 152 acting directly against the piston 116, the drilling fluid pumped down the central bore 162 and through the interior 158 of the intensifier piston 152 passes both to the end of the drill bit 110 and through apertures 154 into the annular chamber 160. The force of the fluid in the chamber 160 acts against the rear face 166 of the

piston 116 and thus increases the force on the piston 116. Hence, the intensifier piston 152 increases the surface area against which the force of the drilling fluid can act, thus increasing the force acting on piston 116 and thus the blades 114,115 for a given fluid pressure.

It will be appreciated that a number of such intensifier pistons 152 may be used in series, thereby increasing the surface area that is available proportionally and thus increasing the force exerted on the piston 116 to extend the blades 114,115 for a given fluid pressure.

This increase in force applied to the piston 116 results in an increase in the force, for the same pumping pressure, which is applied to the blades 114, 115 to extend them and/or to keep them extended.

This allows the drill bit 110 to drill in the opposite direction i. e. to cut while being retracted from a borehole. The increase in force applied to the blades 114,115 keeps them extended even when a retracting force, such as that applied by the retraction of the drill bit 110, is applied to them.

The movement of the skirt 122 provides a means for reducing the back pressure in the system when the blades are fully extended. In Fig. 6a, the skirt 122 is shown in the retracted position. However, in Fig.

6b the pressure applied by the drilling fluid has extended the dowels 120,121 as previously described,

that act against the skirt 122 forcing it into the position shown in Fig. 6b.

When the pressure of the fluid has extended the blades 114,115, they tend to remain extended due to the force provided by the weight of the drill string above it. In an extended position, the skirt 122 uncovers a plurality of apertures (not shown in Fig.

6) that extend through the rectangular body portion 124, to allow passage of the drilling fluid from the central bore of the drill bit 110. Thus, the fluid pressure that was required to extend the blades 114, 115 is reduced upon movement of the skirt 122 to expose the apertures, thereby allowing the drilling fluid to escape into the borehole.

In use, the drill bit 10,110 is attached to a lower end of a drill string, coiled tubing string or the like (not shown). The blades 14,15,114,115 of the drill bit 10,110 may be adjusted to the desired cutting diameter typically by the use of a specific fluid pressure acting on piston 16,116 to extend the blades. The fluid pressure can be calibrated so that at a given pressure, the blades extend to a given diameter (taking into account the length of the blades). The drill string is then rotated by any conventional means, or where coiled tubing is used, a motor is actuated, to rotate the drill bit 10,110 at a speed of around 100 revolutions per minute (rpm) or more, the maximum being dependent upon the type of material that is being cut, and a downward force

appropriate for the material being cut is exerted on the string.

Initially, the blades 14,15,114,115 remain in the retracted position due to the biasing of springs 18, 32,118,132. Pressure is then applied to the drill bit 10,110 to extend the blades 14,15,114,115 as described above to the desired cutting diameter. The pressure may be applied using the weight of the drill string or coiled tubing string above the bit 10,110, or by using fluid pressure as described herein. The pressure required to extend the blades 14,15,114, 115 is typically in the order of 20 pounds per square inch (psi), depending upon the desired cutting diameter, and also on the type of material that is to be cut.

The drill string or coiled tubing string is then lowered until the drill bit 10,110 comes into contact with the surface or formation that is to be cut. The blades 14,15,114,115 begin to cut the borehole at the required cutting diameter. It should be noted that the cutting diameter may be changed at any time by either increasing the weight or pressure applied to the bit 10,110 to increase the cutting diameter, or by reducing the weight or pressure to reduce the cutting diameter. Cutting continues until the desired cutting depth is reached. The drill string or coiled tubing string is then removed from the borehole. It should be noted that the drill bit 10,110 may be used to cut whilst the drill string or

coiled tubing string is being removed from the borehole, although pressure of up to 5000 psi may be required to maintain the blades 14,15,114,115 at the desired cutting diameter during reverse operation.

Optionally, the cutting action of the various faces of the blades can be assisted by the action of fluid jets provided around (e. g. above and below) the blades that pump fluid through the body 12,112 and out of ports 40,41 (Fig. 5) in body 12,112. The fluid carries drill cuttings away from the blades.

The venting of drilling fluid through the apertures reduces the back pressure in the system which is a substantial advantage of the present invention. When the drill bit 110 is driven by a hydraulic motor located further up the drill string or coiled tubing string, for example, any reduction in the back pressure at the motor allows it to operate more efficiently. In addition, the circulation of the drilling fluid out of the apertures helps to remove debris and drill cuttings etc that collect in the borehole.

The inclusion of one or more intensifier pistons, as in the above described embodiment, offers a substantial advantage, in that the force required to extend and/or keep the blades extended is reduced.

The intensifier piston increases the downward force

applied to the blades by increasing the surface area against which the drilling fluid may act.

Furthermore, the provision of the skirt and apertures in the rectangular body allows the back pressure in the system to be substantially reduced when the blades are fully extended.

It should be noted that two drill bits 10,110 may be used in the string. The first drill bit could be used as a centraliser, and can be located in the middle of the string or at least spaced from the terminus of the string. The second drill bit can be used as a drill bit to cut. In certain cases, the two bits can be used in tandem adjacent to one another on the string and the spade point 38 of the upper drill bit could be replaced by an aperture provided with a screw thread. The upper and lower drill bits could then be coupled together.

Referring to Fig. 8, the blades 14,15,114,115 may be provided with a locking means 80 (Fig. 8c) to prevent the blades from opening partially or fully until required. As illustrated in Fig. 8c, the locking means 80 typically comprises a screw 82 or the like which is provided with a dimple or recess 84 on one end thereof, and a ball bearing 86. A spring 88 is located in an aperture 89 within the screw 82, the spring 88 acting on the ball bearing 86 to bias the ball bearing 86 into contact with an adjacent object.

In use, the locking means 80 is provided in an aperture 90 provided in one of the blades (blade 14 in Fig. 8a). Aperture 90 may be provided with a screw thread that matches that of the screw 82 to facilitate adjustment of the biasing of spring 88.

The ball bearing 86 is biased by the spring 88 into contact with a dimple 92 provided on the other of the blades (blade 15 in Fig. 8b).

The locking means 80 may be adjusted using a screw driver. The correct setting is typically achieved by fully screwing the screw 82 into aperture 90, and then backing-off a quarter of a turn. The setting of this may be adjusted if, during use, the blades do not open or they open too quickly.

In use, the locking means 80 is set to the appropriate setting. The drill bit 10,110 can then be run into the hole, the locking means 80 ensuring that the blades do not open whilst being run in.

This is particularly useful in horizontal boreholes for example. To open the blades, pressure is applied through body 12 to act on the pistons 16. The blades will remain closed until the pressure applied is sufficient to overcome the biasing force of the locking means 80, thus forcing the ball bearing 86 out of the dimple 92.

Modifications and improvements may be made to the foregoing without departing from the scope of the present invention.