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Publication numberUS20010020551 A1
Publication typeApplication
Application numberUS 09/802,999
Publication dateSep 13, 2001
Filing dateMar 9, 2001
Priority dateDec 11, 1998
Publication number09802999, 802999, US 2001/0020551 A1, US 2001/020551 A1, US 20010020551 A1, US 20010020551A1, US 2001020551 A1, US 2001020551A1, US-A1-20010020551, US-A1-2001020551, US2001/0020551A1, US2001/020551A1, US20010020551 A1, US20010020551A1, US2001020551 A1, US2001020551A1
InventorsMalcolm Taylor, Andrew Murdock, David Jelley
Original AssigneeMalcolm Taylor, Andrew Murdock, David Jelley
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Rotary drag-type drill bits and methods of designing such bits
US 20010020551 A1
Abstract
The invention provides a rotary drag-type drill bit in which the relationship of torque to rotary bit speed is such that torque generally increases with bit speed. Such a bit has a reduced tendency to exhibit the phenomenon known as “stick-slip” while drilling, when compared with bits having a different torque /speed characteristic, as a result of the positive damping effect of the torque/speed relationship. One method of designing such a drill bit comprises ascertaining the torque/rotary bit speed relationship, or other correlated relationships, for a number of different drill bit designs and then selecting from those designs a design having the desired type of relationship. Examples of drill bit structures specifically designed to achieve the desired torque/speed relationship are also disclosed.
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Claims(18)
What is claimed is:
1. A rotary drag-type drill bit in which a relationship of torque to rotary bit speed is such that torque generally increases with bit speed.
2. method of designing a rotary drag-type drill bit by ascertaining the depth of cut/rotary bit speed relationship for a plurality of different drill bit designs and selecting from those designs a design where a depth of cut/rotary bit speed relationship is such that depth of cut generally increases with bit speed.
3. A rotary drag-type drill bit in which the relationship between the overall cutting efficiency of the bit and the rotary speed of the bit is such that the overall cutting efficiency falls with increasing rotary speed.
4. A rotary drag-type drill bit comprising a bit body having an axis of rotation, a plurality of blades upstanding from the bit body, a plurality of primary cutters and a plurality of secondary cutters, the primary and secondary cutters being mounted upon the blades, wherein the plurality of secondary cutters are mounted at a lower cutting height than the plurality of primary cutters.
5. A drill bit as claimed in
claim 4
, wherein the secondary cutters are mounted at a cutting height spaced from that of the primary cutters by a distance falling within the range of about 5% to about 10% of a radius of one of the primary cutters.
6. A drill bit as claimed in
claim 4
, wherein the secondary cutters are orientated to have a higher cutting efficiency than the primary cutters.
7. A drill bit as claimed in
claim 6
, wherein the secondary cutters have a back rake angle lower than the primary cutters.
8. A drill bit as claimed in
claim 6
, wherein the secondary cutters have a side rake angle lower than the primary cutters.
9. A drill bit as claimed in
claim 4
, wherein the secondary cutters are shaped to have a higher cutting efficiency than the primary cutters.
10. A drill bit as claimed in
claim 9
, wherein a radius of the secondary cutters is smaller than that of the primary cutters.
11. A rotary drag-type drill bit comprising a bit body having an axis of rotation, a plurality of blades upstanding from the bit body, and a plurality of cutters carried by the blades, wherein the drill bit has a cutting efficiency which varies with the depth of cutting.
12. A drill bit as claimed in
claim 11
, wherein the cutters consist of a plurality of primary cutters mounted at a first cutting height and a plurality of secondary cutters mounted at a second, lower cutting height, the secondary cutters having a higher cutting efficiency than the primary cutters.
13. A drill bit as claimed in
claim 12
, wherein the secondary cutters are mounted at a cutting height spaced from that of the primary cutters by a distance falling within the range of about 5% to about 10% of a radius of one of the primary cutters.
14. A drill bit as claimed in
claim 12
, wherein the secondary cutters are orientated to have a higher cutting efficiency than the primary cutters.
15. A drill bit as claimed in
claim 14
, wherein the secondary cutters have a back rake angle lower than the primary cutters.
16. A drill bit as claimed in
claim 14
, wherein the secondary cutters have a side rake angle lower than the primary cutters.
17. A drill bit as claimed in
claim 12
, wherein the secondary cutters are shaped to have a higher cutting efficiency than the primary cutters.
18. A drill bit as claimed in
claim 17
, wherein a radius of the secondary cutters is smaller than that of the primary cutters.
Description
CROSS REFERENCE TO RELATED APPLICATION

[0001] This is a continuation-in-part of U.S. patent application Ser. No. 09/210,518, filed Dec. 11, 1998, by Malcolm Taylor, et al., entitled “Rotary Drag-Type Drill Bits and Methods of Designing Such Bits” now pending.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] The invention relates to the design of rotary drag-type drill bits for use in drilling holes in subsurface formations.

[0004] 2. Description of the Related Art

[0005] As is well known, drag-type drill bits for boring earth formations comprise a bit body having a shank for connection to a drill string and a plurality of fixed cutters mounted on the bit body. A passage in the bit body supplies drilling fluid to nozzles in the surface of the bit for cleaning and cooling the cutters. In one common form of bit, a bit body has a leading face which comprises a number of circumferentially spaced blades extending outwardly away from the central axis of rotation of the bit, cutters being mounted along each blade. In polycrystalline diamond compact (PDC) type drill bits some or all of the cutters are preform cutters formed, at least in part, from polycrystalline diamond or other superhard material. One common form of cutter comprises a tablet, usually circular or part-circular, made up of a superhard table of polycrystalline diamond, providing the front cutting face of the cutter, bonded to a substrate which is usually of cemented tungsten carbide.

[0006] The bit body may be machined from solid metal, usually steel, or may be molded using a powder metallurgy process in which tungsten carbide powder is infiltrated with a metal alloy binder in a furnace so as to form a hard matrix. The general design and methods of construction of such drill bits are well known and will not therefore be described in greater detail.

[0007] It is well known that rotary drag-type drill bits may under certain conditions, particularly at low rotary speeds, and high weight-on-bit, be subject to torsional vibration as a result of a phenomenon commonly referred to as “stick-slip”. In stick-slip the situation arises where the bottomhole assembly is rotating more slowly than the upper end of the drill string due, for example, to frictional torque acting on the bottomhole assembly, with the result that the drill string begins to wind up. Eventually, the torsional energy stored in the drill string is transferred to the bottomhole assembly and accelerates it to a rotary speed faster than the steady state rotary speed. This transfer of torsional energy from the drill string to the bottomhole assembly can occur periodically giving rise to torsional vibrations.

[0008] Such torsional vibration is undesirable since it can lead to rapid wear of PDC bits, particularly in harder formations, due to damage to the cutters as a result of impact loads caused by the torsional vibration. Torsional vibration can have the effect that cutters on the drill bit may momentarily stop or be rotating backwards, i.e. in the reverse rotational direction to the normal forward direction of rotation of the drill bit during drilling. The effect of such reverse rotation on a PDC cutter may be to impose unusual loads on the cutter which tend to cause spalling or delamination, i.e. separation of part or all of the polycrystalline diamond facing from the tungsten carbide substrate. It would therefore be desirable to be able to design rotary drag-type drill bits which will not be susceptible to stick-slip, or to be able to select from existing or proposed bit designs those which will be less susceptible to this phenomenon.

[0009] Hitherto, it has generally been considered to be desirable for rotary drag-type drill bits to be as dynamically stable as possible in order to minimize all types of vibration during drilling. It has also generally been considered desirable for drill bits to be dynamically balanced for the same reason, except in the case of so-called “anti-whirl” bit designs where a deliberately out-of-balance bit is designed so that the part of the periphery of the bit which is urged against the wall of the borehole by the net out of balance force is free of cutters so as to slide over the surface of the borehole.

[0010] The present invention is based on the surprising discovery that bits exhibiting lateral vibration which increases with rotary bit speed may be less susceptible to stick-slip than bits which do not exhibit this characteristic. It has been found that increase in lateral vibration with increasing rotary bit speed is correlated with increase in bit torque. When a bit having this characteristic is subject to the rapid increases in rotary speed which occur during stick-slip, the increase in torque which results from the increase in speed serves to provide positive damping of the torsional vibrations, with the result that the bit drills more efficiently and is less susceptible to damage. The reduction of torsional vibrations may also reduce the risk of fatigue in the drill string.

[0011] The present invention makes use of this discovery in the design of drill bits, either by allowing to be selected for development and manufacture those proposed bit designs which are found to have the above characteristic, or by specifically designing drill bits, or associated downhole components, in a manner to ensure that the bit or component will exhibit such characteristic.

[0012] An arrangement is illustrated in U.S. Pat. No. 5,402,856 in which a drill bit is provided with a device operable to permit the bit torque to be varied, the arrangement including a brake device moveable outwardly to bear on the surrounding borehole wall to apply a braking force or torque to the bit.

SUMMARY OF THE INVENTION

[0013] According to one aspect of the invention, therefore, the invention provides a rotary drag-type drill bit in which the relationship of torque to rotary bit speed is such that torque generally increases with bit speed.

[0014] The invention also provides a method of designing a rotary drag-type drill bit comprising the step of ascertaining the torque/rotary bit speed relationship for a plurality of different drill bit designs and selecting from those designs a design where the torque/rotary bit speed relationship is such that torque generally increases with bit speed.

[0015] In such method the plurality of different drill bit designs may comprise a series of modifications of a basic bit design. Thus, the effect of a series of possible modifications to the basic design may be compared, so that the version of the design likely to have the least susceptibility to stick-slip may be selected.

[0016] The torque/rotary bit speed relationship for the plurality of drill bit designs may be ascertained by creating a computer model of each drill bit design, applying to the computer model of each bit design motion corresponding to increasing rotary bit speed, determining the forces generated by each bit design during such motion, and correlating with the rotary bit speed the bit torque consequent upon said forces. It is common practice to use computers to model and analyze bit designs and various methods of analysis have been proposed and are available. However, for the purposes of the present invention a particularly suitable form of analytical software is that of the kind which uses the methods described in U.S. patent application Ser. No. 09/160,282, the content of which is incorporated herein by reference. This software takes account of the movement of a PDC bit (such as rotary bit speed and rate of penetration) and then calculates the total forces acting on the bit by summing all forces generated by cutters and other bit features. Such software may thus be used to correlate bit torque to rotary bit speed, under various conditions, in any particular PDC bit design.

[0017] Alternatively, the torque/rotary bit speed relationship for a plurality of drill bit designs may be ascertained by acquiring data on torque and bit speed from actual drill bits while such bits are drilling earthen formations. The data may be acquired during laboratory testing or during field drilling.

[0018] Since it has been discovered that increase in torque with increasing rotary drill speed correlates with increasing lateral vibration, in drill bits which are less susceptible to stick-slip, the invention also provides a method of designing a rotary drag-type drill bit comprising the step of ascertaining the lateral vibration/rotary bit speed relationship for a plurality of different drill bit designs and selecting from those designs a design where the lateral vibration/rotary bit speed relationship is such that lateral vibration generally increases with bit speed.

[0019] As before, the lateral vibration/rotary bit-speed relationship may be ascertained by creating a computer model of each drill bit design, applying to the computer model of each bit motion corresponding to increasing rotary bit speed, determining the forces generated by each bit design during such motion, and correlating with the rotary bit speed the lateral vibration consequent upon said forces. Alternatively, again, the lateral vibration/rotary bit speed relationship for the plurality of drill bit designs may be ascertained by acquiring data on lateral vibration and rotary bit speed from actual drill bits while such bits are drilling earthen formations.

[0020] In using these methods, the design of a bit exhibiting a low tendency to stick-slip, in accordance with the invention, is passive in that a bit design having the required characteristics is selected from a plurality of alternative bit designs which have been designed using other parameters. However, the present invention also allows drill bits or associated downhole components to be actively designed specifically to achieve the desired characteristics which have been found to reduce the tendency to stick-slip.

[0021] Accordingly, the present invention also provides the combination with a rotary drag-type drill bit of a device responsive to rotary bit speed and adapted to increase the bit torque with increase in bit speed.

[0022] The rotary bit speed responsive device may be provided on the drill bit itself, or may be provided on an additional downhole component which, in use, rotates with the drill bit. In either case, the rotary bit speed responsive device may include brake means adapted, in use, to bear on the formation being drilled with a force which increases with increase in rotary bit speed. The brake means may include elements, which are displaced outwardly, with respect to the axis of rotation, to bear on the surrounding wall of the borehole in the formation being drilled. For example, the brake means may comprise a number of formation-engaging elements which are displaceable outwardly under the action of power means selected from: hydraulic pressure of drilling fluid supplied to the drill bit during drilling; a source of electrical power; axial motion of the drill bit under weight-on-bit.

[0023] In an alternative arrangement the rotary bit speed responsive device may comprise means to modify the orientation of a number of cutters mounted on the drill bit. For example, the device may be adapted to reduce the back-rake of cutters mounted on the drill bit with increasing rotary bit speed, since such reduction in back-rake will increase the bit torque.

[0024] Alternatively, or additionally the device may be adapted to increase the depth of cut of cutters mounted on the drill bit with increasing rotary bit speed.

[0025] In an alternative arrangement, the rotary bit speed responsive device may comprise means to increase the effective cutting diameter of the drill bit with increasing rotary bit speed. Such increase in effective cutting diameter will also increase the bit torque.

[0026] In this case the nominal diameter of the drill bit is preferably the maximum effective cutting diameter permitted by the rotary bit speed responsive device. Thus, the drill bit will drill a full diameter hole when rotating at maximum speed, and will drill a slightly undersize hole when the bit speed drops below the maximum. Since the variation in effective cutting diameter will mean that some parts of the borehole will be undersize, it may be necessary subsequently to ream out these portions of the borehole to the full diameter.

[0027] In such an arrangement the drill bit may include a number of cutters or abrasion elements mounted on the bit body for movement inwardly and outwardly relative to the axis of rotation of the bit, the cutters or abrasion elements being moved outwardly in response to increasing rotary bit speed.

[0028] In another alternative arrangement according to the invention, the device responsive to rotary bit speed in order to increase the bit torque with increase in bit speed may comprise a mass rotatable with the bit and located outwardly of the axis of rotation of the bit. Such mass may be mounted in the bit body itself or in a further downhole component which is rotatable with the bit.

[0029] In accordance with another aspect of the invention there is provided a drill bit the overall efficiency of which is designed to decrease with increasing rotary speed. In a practical embodiment, this may be achieved by arranging two groups of cutters on the drill bit, a first one of the two groups having cutters of relatively low cutting efficiency, a second one of the two groups having cutters of relatively high cutting efficiency, wherein the cutters of the second group of cutters have -a smaller depth of cut than the cutters of the first group.

[0030] It is well known that the cutting efficiency of a drill bit cutter is dependent upon a number of factors including the back rake angle, the side rake angle and the radius of the cutter.

[0031] In use, as the rotary speed of the drill bit falls due to the stick-slip behavior of the bit, the depth of cut will tend to increase. The increase in cutting depth will result in the proportion of cutting undertaken by the relatively efficient cutters increasing, improving the overall efficiency of cutting. This change in the overall efficiency of the drill bit will tend to dampen slowing of the drill bit. If the bit speed increases, then the relatively efficient cutter will perform less cutting, reducing the overall efficiency and damping the increase in bit speed.

[0032] It will be appreciated that such damping will tend to reduce stick-slip behavior.

BRIEF DESCRIPTION OF THE DRAWINGS

[0033]FIG. 1 is a graph illustrating increase of lateral vibration with rpm in a rotary drag-type drill bit of low susceptibility to stick-slip;

[0034] FIGS. 2-5 are diagrammatic representations showing the increasing pattern of vibration with rpm in another drill bit of low susceptibility to stick-slip;

[0035]FIGS. 6 and 7 are graphical plots illustrating the correlation between torque and lateral vibration in a drill bit;

[0036]FIG. 8 is a graph showing a plot of lateral vibration in a drill bit over time compared with increase in rpm over time;

[0037]FIG. 9 is a corresponding plot of bit torque against time showing again the correlation between bit torque and lateral vibration;

[0038]FIGS. 10 and 11 are graphs showing torque plotted against rotary drill speed (rpm) for another design of drill bit,

[0039] FIGS. 12-14 illustrate diagrammatically three possible arrangements for achieving increase in bit torque with increasing rpm;

[0040]FIG. 15 shows diagrammatically one possible method of powering the devices of FIGS. 12-14;

[0041]FIGS. 16 and 17 show diagrammatically arrangements for increasing the effective diameter of a drill bit with increasing rpm;

[0042]FIG. 18 is a view of a drill bit in accordance with another embodiment of the invention;

[0043]FIG. 19 is a view similar to FIG. 18 of a further alternative embodiment; and

[0044]FIGS. 20 and 21 are diagrammatic views, illustrating the positions of the cutters of FIG. 18.

DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED EMBODIMENT

[0045]FIG. 1 shows the lateral vibration of a particular drag-type rotary drill bit (Bit A) plotted against rpm, the vibration being plotted as lateral acceleration in meters/s/s, and the data being acquired in laboratory drilling tests. This shows that Bit A is not stable, experiencing lateral vibration that rises quickly with rotary speed to 60 m/s/s. However, contrary to the conventional teaching in the drill bit art, which considers that bit stability is required in order to reduce torsional vibrations, Bit A is found to exhibit a very low incidence of stick-slip while drilling.

[0046] This characteristic has been found in other PDC drill bits; and FIGS. 2-5 show the patterns of lateral vibration in an 8 inch unbalanced drill bit (Bit B) with increase of rotary bit speed from 210 rpm to 300 rpm.

[0047]FIGS. 6 and 7 show the correlation between lateral vibration and torque in Bit B. In FIG. 6 torque/weight-on-bit, in feet, is plotted against lateral acceleration, in m/s/s, and it will be seen that increasing torque is accompanied by increasing lateral vibration in Bit B over three different tests, whereas in a test of a similar fourth balanced bit (Bit C), circled in FIGS. 6 and 7, the correlation does not occur and there is no significant increase in lateral vibration with increase in torque.

[0048]FIG. 7 shows this characteristic even more clearly where a dimensionless factor=(torque/wob)/(mm/rev) is plotted against lateral acceleration.

[0049]FIGS. 8 and 9 further show the correlation between torque and lateral vibration in a further drill bit (Bit D). In the graph of FIG. 8 both rpm and lateral acceleration of the drill bit are plotted against time. Comparing FIG. 8 with FIG. 9, where torque is plotted against time, it will be seen that the pattern of variation in torque corresponds generally to the pattern of variation in lateral vibration, this being seen particularly in the correlation between the torque spike in FIG. 9 which matches the vibration spike in FIG. 8 in the 7-9 second time span.

[0050]FIGS. 10 and 11 show graphs of torque plotted against rpm for Bit A, which exhibited low tendency to stick-slip, and it will be seen that in each case there is an increase in torque with increasing rpm. This is shown particularly clearly in FIG. 10 which shows data acquired from laboratory test drilling. The characteristic is still present, though less strongly marked, in FIG. 11 where the data was acquired from field drilling.

[0051] It has been found that drill bits which are susceptible to stick-slip do not exhibit this rising torque/rotary bit speed characteristic.

[0052] Analysis has also shown that positive damping may be achieved when the depth of cut increases with increasing rotary speed. As will be appreciated, generally speaking increase in depth of cut will lead to an increase in bit torque so that a correlation between bit torque and depth of cut is to be expected.

[0053] It is proposed that Bit A, and other bits having the characteristics described, exhibit a low tendency to stick-slip because of a coupling of lateral vibration and torque which produces a positive damping characteristic which may be referred to as “Dynamic Damping” because dynamic effects are providing positive damping to prevent stick-slip.

[0054] To test this hypothesis, and to examine the contrary conventional view that force balanced, low vibration bits are less susceptible to stick-slip, two versions of Bit B were made: a balanced version with an out-of-balance force of only 2.2% of weight-on-bit, and another, unbalanced bit, with an out-of-balance force of 9.1% of weight-on-bit. In the testing of these bits, operating parameters were selected to induce stick-slip. These included drilling through hard formation, high weight-on-bit and low rotary speed. The balanced version of the bit demonstrated stick-slip while the unbalanced version did not. This test provided a result at odds with the conventional force-balancing hypothesis and hence support for the hypothesis on which the present invention is predicated.

[0055] Laboratory testing with the same two bits showed the force-balanced bit, which exhibited stick-slip, to have low lateral vibrations and negative dependence of bit torque on rpm (negative damping). The less balanced bit showed stronger lateral vibrations at higher rpm and a positive bit torque/rpm relationship (positive damping). The torque/rpm relationship was also apparent from data acquired downhole. The appreciation of the above relationship between torque, lateral vibration and/or depth of cut and rotary bit speed in drill bits which are less susceptible to stick-slip has led to the concept, according to the present invention, of using these characteristics in the design of drill bits.

[0056] The simplest application of the concept in bit design is to ascertain the appropriate relationships for proposed or existing bit designs to select those designs which exhibit the rising torque/rotary bit speed characteristic, or correlated lateral vibration or depth of cut characteristics, which have been shown to indicate low susceptibility to stick-slip. The effect of modifications to a basic bit design on stick-slip susceptibility can be determined by ascertaining these relationships for the modifications and selecting that modification where the relationships indicate that the actual drill bit will exhibit low susceptibility to stick-slip.

[0057] Although the data necessary to determine the characteristics may be acquired from actual drill bits, for example by downhole data acquisition, it will be appreciated that the primary advantage of the invention is that it will allow proposed bit designs to be selected for lack of susceptibility to stick-slip before the bits are actually developed and manufactured. In this case, the characteristics of a proposed design may be determined by the use of analytical software by which a computer model of a proposed design of drill bit may be created, as previously mentioned. For the purposes of the present invention a particularly suitable form of analytical software is that of the kind which uses the methods described in U.S. patent application Ser. No. 09/160,282. This software takes account of the movement of a PDC bit (such as rpm and rate of penetration) and then calculates the total forces acting on the bit by summing all of the forces generated by cutters and other bit features. The software may therefore readily be used to produce torque/rpm data, or lateral vibrations/rpm or depth of cut/rpm data, in respect of any proposed design of drill bit.

[0058] A further application of the present invention is to the active design of drill bits, or associated downhole components, to produce the rising torque/rpm characteristic which is now indicated as being desirable to avoid stick-slip.

[0059] One simple method of providing for bit torque to increase with rotary bit speed is to provide the drill bit or an associated downhole component with a simple centrifugal governor. For example, a 100 kg mass rotating at 400 rpm at 8 inch radius would provide a torque of 1415 lb ft, and such an arrangement may provide sufficient positive damping to reduce the susceptibility to stick-slip to a useful extent. However more preferred arrangements are those which use other power sources to actuate a braking device. Such power sources may include drilling fluid pressure, stored energy (e.g. electrical energy stored during smooth drilling), or axial motion of the drill string under weight-on-bit.

[0060] The braking device may interact with the cylindrical borehole wall or with the cutting face of the borehole.

[0061] In the case where the braking device act on the borehole or, it may take the form of brake elements spaced apart around the periphery of the drill bit or associated downhole component and arrange to be displaced outwardly into engagement with the borehole wall with increasing rotary bit speed.

[0062] FIGS. 12-14 show diagrammatically typical forms which such brake elements might take.

[0063] In FIG. 12, the device is in the form of a curved pad 10 pivotally mounted at 11 adjacent the periphery 12 of the drill bit, the arrangement being such that the pad 10 trails the pivot 11 with respect to the direction of rotation indicated by the arrow 13.

[0064] In the arrangement of FIG. 13 the pad 14 leads the pivot 15 with respect to the direction of rotation of the bit or component. Such arrangement would provide a self-jamming effect and thereby increase the torque.

[0065]FIG. 14 shows an arrangement in which a roller 16 is so mounted that it may be forced outwardly by a piston 17 to jam against the borehole wall.

[0066] In each case power means of any of the kinds referred to above are provided to force the brake elements outwardly against the borehole wall in response to increase in rotary speed of the drill bit. FIG. 15 shows diagrammatically one type of arrangement which makes use of the hydraulic pressure of the drilling fluid which is normally supplied under pressure to the drill bit during drilling.

[0067] Referring to FIG. 15: in conventional manner drilling fluid is pumped under pressure down the drill string 18 and is delivered to nozzles 19 in the leading face of the drill bit which cause the drilling fluid to flow outwardly across the leading face of the bit to cool and clean the cutters and to carry the cuttings upwardly past the gauge section of the bit to the surface through the annulus between the drill string and the wall of the borehole, such annulus being indicated diagrammatically at 20 in FIG. 15.

[0068] For the purpose of powering the brake devices, for example of the kind shown in FIGS. 12-14, a passage 21 for drilling fluid leads to a control valve 22 which may selectively deliver drilling fluid through a passage 23 to the nozzles 19 or through a passage 24 to an hydraulic actuator 25, such as a piston and cylinder arrangement, for energizing the brake pads 10, 14, 16 of FIGS. 12-14.

[0069] The control valve 22 is arranged to divert a proportion of the drilling fluid from the nozzles 19 to the actuators 25 upon increase in the rotary speed of the drill bit or other component of the bottom assembly on which the brake devices may be mounted. The power for such a control valve could be generated from the flow of drilling fluid, using technologies well established, for example in mud pulse telemetry.

[0070] The control unit for the valve 22 is preferably “strapped down” (i.e. attached to the drill string) and is activated by rate of change of rotary speed. Slip-stick typically operates over a period of around 10-20 seconds, so a rate of change corresponding to doubling rpm in 2.5-5 seconds would indicate the occurrence of stick-slip.

[0071] Bit torque may also be varied by modifying the bits' “aggressivity”, defined as its torque/WOB. Torque can be increased by, for example, reducing the back rake of PDC cutters mounted on the drill bit and reduced by, for example, engaging a depth of cut limiter. Conversely, therefore, torque may be increased by allowing the depth of cut to be increased. The power to operate such mechanisms is again preferably hydraulic.

[0072] Another approach is to vary the bit torque by varying the effective cutting diameter of the drill bit. This may achieved by using an expanding bit which is enlarged above nominal size. Devices similar to the brake shoes described above could carry PDC or other cutters on an outwardly movable arm. Alternatively, cutters could be mounted on an hydraulically actuated piston member, such as indicated at 26 in FIGS. 16 and 27 in FIG. 17, which slides along an inclined ramp into engagement with the surrounding wall of the borehole. A similar arrangement might also be used for outward movement of brake shoes for the arrangement previously described.

[0073] The piston members 26 and 27 may be hydraulically actuated, for example by using a drilling fluid system of the kind shown in FIG. 15.

[0074] In the case of enlargement of the affecting cutting diameter of the drill bit, a short section of borehole would be oversize. Preferably, therefore, the maximum effective cutting diameter of the drill bit would be equivalent to the nominal diameter of the bit so that the moving pads would withdraw as the rotary speed drops, to reduce the borehole size, and expand to the nominal bit size as the rotary speed increases during slip. In this case a short undergauge portion of borehole would result. It is anticipated that a reaming device higher in the borehole (not necessarily integral with the drill bit) would correct this.

[0075] In another arrangement, a drill bit whose torque varies with rotary speed in such a manner as to reduce the likelihood of the onset of stick-slip behavior can be designed by arranging for the overall efficiency of the drill bit to vary with speed in such a manner that the overall cutting efficiency is higher at low rotary speeds than it is at higher speeds. As a result, if the drill bit starts to slow as would occur immediately prior to the onset of stick-slip behavior, the cutting efficiency will increase. The improvement in cutting efficiency that occurs with the reduction in rotary speed tends to damp the slowing of the bit. Conversely, if the bit speed rises, the efficiency falls tending to damp increases in rotary speed. The bit will tend to operate at, approximately, an equilibrium speed dependent upon the bit design and the parameters of the formation being drilled rather than to experience sudden accelerations and decelerations as occurs with stick-slip behavior.

[0076] One way in which the efficiency of a bit can be designed to change with rotary speed is to provide the bit with two groups of cutters at different cutting heights, and arrangements of this type are shown in FIGS. 18 and 19.

[0077]FIG. 18 illustrates a fixed cutter drill bit 30 comprising a bit body 32 having an axis of rotation 33 and from which extends a plurality of blades 34. Each blade 34 carries a plurality of cutters 36 of polycrystalline diamond compact form. The bit 30 has six blades 34, the blades 34 being arranged in pairs. Each pair of blades 34 comprises a primary blade 38 carrying primary cutters 40 and a secondary blade 42 carrying secondary cutters 44. FIG. 20 illustrates one of the primary blades 38 and shows the relative location of the associated secondary blade 42. It is clear from FIG. 20 that the primary and secondary blades 38, 42 are arranged such that the primary cutters 40 are located at a greater cutting height 43 than the cutting height 45 of secondary cutters 44. As a result, the depth of cut achieved by the primary cutters 40 will be greater than that achieved by the secondary cutters 44.

[0078] As well as being arranged at a different cutting height, the secondary cutters 44 are arranged to have a higher cutting efficiency than the primary cutters 40. This is achieved by mounting the secondary cutters 44 at a lower back rake angle than the primary cutters 40, as shown in FIG. 21. Alternatively or additionally, the secondary cutters 44 may be mounted with a smaller side rake angle than the primary cutters 40 and may be of smaller radius than the primary cutters 40.

[0079] The difference in cutting height between the primary and secondary cutters is small and typically will be of the order of 5% to 10% of the radius of the primary cutters.

[0080] As described above, in use, with the drill bit 30 rotating at a given speed, all of the cutters 40, 44 are active, but the depth of cutting achieved by the primary cutters 40 is greater than that achieved by the secondary cutters 44. If the rotary speed increases, the overall depth of cut will tend to reduce resulting in the proportion of cutting undertaken by the primary cutters 40 increasing, and hence in the overall cutting efficiency reducing tending to damp the increase in speed. If the rotary speed falls, then the proportion of cutting undertaken by the secondary cutters 44 increases so the overall efficiency rises tending to damp the slowing of the bit.

[0081]FIG. 19 illustrates an arrangement which operates in substantially the same manner as that of FIGS. 18 but differs therefrom in that the primary and secondary cutters 40, 44 are not mounted upon separate blades. Rather, they are arranged in two rows upon each blade. If desired, the primary and secondary cutters could be interspersed with one another.

[0082] Whereas the present invention has been described in particular relation to the drawings attached hereto and with reference to several specific embodiments, 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.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US6536543 *Dec 6, 2000Mar 25, 2003Baker Hughes IncorporatedRotary drill bits exhibiting sequences of substantially continuously variable cutter backrake angles
US7234549May 26, 2004Jun 26, 2007Smith International Inc.Methods for evaluating cutting arrangements for drill bits and their application to roller cone drill bit designs
US7292967May 26, 2004Nov 6, 2007Smith International, Inc.Methods for evaluating cutting arrangements for drill bits and their application to roller cone drill bit designs
US7748474 *Jun 20, 2006Jul 6, 2010Baker Hughes IncorporatedActive vibration control for subterranean drilling operations
US8109346 *Feb 18, 2010Feb 7, 2012Varel International Ind., L.P.Drill bit supporting multiple cutting elements with multiple cutter geometries and method of assembly
US8185365Mar 25, 2004May 22, 2012Smith International, Inc.Radial force distributions in rock bits
US9004199 *Jun 22, 2010Apr 14, 2015Smith International, Inc.Drill bits and methods of manufacturing such drill bits
US20100320005 *Jun 22, 2010Dec 23, 2010Smith International, Inc.Drill bits and methods of manufacturing such drill bits
Classifications
U.S. Classification175/57, 175/426, 175/431
International ClassificationE21B10/42
Cooperative ClassificationE21B10/42
European ClassificationE21B10/42
Legal Events
DateCodeEventDescription
Apr 25, 2001ASAssignment
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Effective date: 20010315
Sep 24, 2001ASAssignment
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Effective date: 20010912
Jan 6, 2003ASAssignment
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Free format text: GRANT OF PATENT (SECURITY AGREEMENT);ASSIGNOR:REED-HYCALOG OPERATING, L.P.;REEL/FRAME:013336/0691
Effective date: 20021219