Jack element for a drill bit

This patent application is a continuation of U.S. patent application Ser. No. 11/535,036 filed Sep. 25, 2006 and that issued as U.S. Pat. No. 7,571,780 on Aug. 11, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 11/278,935 filed Apr. 6, 2006 and that issued as U.S. Pat. No. 7,426,968 on Sep. 23, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/277,394 filed Mar. 24, 2006 and that issued as U.S. Pat. No. 7,398,837 on Jul. 15, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/277,380 filed Mar. 24, 2006 and that issued as U.S. Pat. No. 7,337,858 on Mar. 4, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,976 filed Jan. 18, 2006 and that issued as U.S. Pat. No. 7,360,610 on Apr. 22, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,307 filed Dec. 22, 2005 and that issued as U.S. Pat. No. 7,225,886 on Jun. 5, 2007, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,022 filed Dec. 14, 2005 and that issued as U.S. Pat. No. 7,198,119 on Apr. 3, 2007, which is a continuation-in-part of U.S. patent application Ser. No. 11/164,391 filed Nov. 21, 2005 and that issued as U.S. Pat. No. 7,270,196 on Sep. 18, 2007. All of these applications are herein incorporated by reference in their entirety.

This invention relates to drill bits, specifically drill bit assemblies for use in oil, gas and geothermal drilling.

Often drill bits are subjected to harsh conditions when drilling below the earth's surface. Replacing damaged drill bits in the field is often costly and time consuming since the entire downhole tool string must typically be removed from the borehole before the drill bit can be reached. Bit whirl in hard formations may result in damage to the drill bit and reduce penetration rates. Further, loading too much weight on the drill bit when drilling through a hard formation may exceed the bit's capabilities and also result in damage. Too often, unexpected, hard formations are encountered suddenly and damage to the drill bit occurs before the weight on the drill bit may be adjusted.

The prior art has addressed bit whirl and weight on bit issues. Such issues have been addressed in the U.S. Pat. No. 6,443,249 to Beuershausen, which is herein incorporated by reference for all that it contains. The '249 patent discloses a PDC-equipped rotary drag bit especially suitable for directional drilling. Cutter chamfer size and back-rake angle, as well as cutter back-rake, may be varied along the bit profile between the center of the bit and the gauge to provide a less aggressive center and more aggressive outer region on the bit face, to enhance stability while maintaining side cutting capability, as well as providing a high rate of penetration under relatively high weight-on-bit.

U.S. Pat. No. 6,298,930 to Sinor, which is herein incorporated by reference for all that it contains, discloses a rotary drag bit including exterior features to control the depth of cut by cutters mounted thereon, so as to control the volume of formation material cut per bit rotation as well as the torque experienced by the bit and an associated bottomhole assembly. The exterior features preferably precede, taken in the direction of bit rotation, cutters with which they are associated, and provide sufficient bearing area so as to support the bit against the bottom of the borehole under weight-on-bit without exceeding the compressive strength of the formation rock.

U.S. Pat. No. 6,363,780 to Rey-Fabret, which is herein incorporated by reference for all that it contains, discloses a system and method for generating an alarm relative to effective longitudinal behavior of a drill bit fastened to the end of a tool string driven in rotation in a well by a driving device situated at the surface, using a physical model of the drilling process based on general mechanics equations. The following steps are carried out: the model is reduced so to retain only pertinent modes, at least two values Rf and Rwob are calculated, Rf being a function of the principal oscillation frequency of weight-on-hook WOH divided by the average instantaneous rotating speed at the surface, Rwob being a function of the standard deviation of the signal of the weight-on-bit WOB estimated by the reduced longitudinal model from measurement of the signal of the weight-on-hook WOH, divided by the average weight-on-bit defined from the weight of the string and the average weight-on-hook. Any danger from the longitudinal behavior of the drill bit is determined from the values of Rf and Rwob.

U.S. Pat. No. 5,806,611 to Van Den Steen, which is herein incorporated by reference for all that it contains, discloses a device for controlling weight-on-bit of a drilling assembly for drilling a borehole in an earth formation. The device includes a fluid passage for the drilling fluid flowing through the drilling assembly, and control means for controlling the flow resistance of drilling fluid in the passage in a manner that the flow resistance increases when the fluid pressure in the passage decreases and that the flow resistance decreases when the fluid pressure in the passage increases.

U.S. Pat. No. 5,864,058 to Chen, which is herein incorporated by reference for all that is contains, discloses a downhole sensor sub in the lower end of a drillstring, such sub having three orthogonally positioned accelerometers for measuring vibration of a drilling component. The lateral acceleration is measured along either the X or Y-axis and then analyzed in the frequency domain as to peak frequency and magnitude at such peak frequency. Backward whirling of the drilling component is indicated when the magnitude at the peak frequency exceeds a predetermined value. A low whirling frequency accompanied by a high acceleration magnitude based on empirically established values is associated with destructive vibration of the drilling component. One or more drilling parameters (weight-on-bit, rotary speed, etc.) is then altered to reduce or eliminate such destructive vibration.

In one aspect of the present invention, a drill bit has an axis of rotation and a working face with a plurality of blades extending outwardly from a bit body. The blades form in part an inverted conical region and a plurality of cutters with a cutting surface is arrayed along the blades. A jack element is coaxial with the axis of rotation and extended within the conical region within a range defined by the cutting surface of at least one cutter.

The cutters and a distal end of the jack element may have hard surfaces, preferably over 63 HRc. Materials suitable for either the cutter or the jack element may be selected from the group consisting of diamond, polycrystalline diamond, natural diamond, synthetic diamond, vapor deposited diamond, silicon bonded diamond, cobalt bonded diamond, thermally stable diamond, polycrystalline diamond with a binder concentration of 1 to 40 weight percent, infiltrated diamond, layered diamond, polished diamond, course diamond, fine diamond cubic boron nitride, chromium, titanium, aluminum, matrix, diamond impregnated matrix, diamond impregnated carbide, a cemented metal carbide, tungsten carbide, niobium, or combinations thereof.

The jack element may have a distal end with a blunt geometry with a generally hemi-spherical shape, a generally flat shape, a generally conical shape, a generally round shape, a generally asymmetric shape, or combinations thereof. The blunt geometry may have a surface area greater than the surface area of the cutting surface. In some embodiments, the blunt geometry's surface is twice as great as the cutting surface.

Depending on the intended application of the bit, various embodiments of the bit may out perform in certain situations. The bit may comprise three to seven blades. Cutters attached to the blades may be disposed at a negative back-rake angle of 1 to 40 degrees. Some of the cutters may be positioned at different angles. For example, the cutters closer to the jack element may comprises a greater back-rake, or vice-versa. The diameter of the cutters may range for 5 millimeters to 50 millimeters. Cutters in the conical region may have larger diameters than the cutters attached to the gauge of the bit, or vice-versa. Cutting surfaces may comprise a generally flat shape, a generally beveled shape, a generally rounded shape, a generally scooped shape, a generally chisel shape, or combinations thereof. Depending on the abrasiveness of the formation back-up cutters may also be desired. The bit may comprise various cone and flange angles as well. Cone angles may range from 25 to 155 degrees and flank angles may range from 5 to 85 degrees. The gauge of the bit may be 0.25 to 15 inches. The gauge may also accommodate 3 to 21 cutters.

The jack element may extend to anywhere within the conical region, although preferably 0.100 to 3 inches. The jack element may be attached within a pocket formed in the working face of the bit. It may be attached to the bit with a braze, a compression fit, a threadform, a bond, a weld, or a combination thereof. In some embodiments, the jack element is formed in the working face. In other embodiments, the jack element may be tapered. In other embodiments, a channel may connect the pocket to a bore of the drill bit. Such a channel may allow air to enter or to exit the pocket when the jack element is inserted or removed and to prevent a suction effect. A portion of the working face may extend adjacent the jack element in such a manner as to support the jack element against radial loads. In some embodiments, the working face has a cross-sectional thickness of 4 to 12 times the cross-sectional thickness of the jack element. The working face may also have 4 to 12 times the cross-sectional area as the jack element.

FIG. 1 is a bottom orthogonal diagram of an embodiment of a drill bit.

FIG. 2 is a side perspective diagram of the embodiment of the drill bit illustrated in FIG. 1 .

FIG. 3 is a cross-sectional diagram of the embodiment of the drill bit illustrated in FIG. 1 .

FIG. 4 is a cross-sectional diagram of the embodiment of the drill bit and jack element illustrated in FIG. 1 engaging a formation.

FIG. 5 is a cross-sectional diagram of another embodiment of a drill bit.

FIG. 6 is a cross-sectional diagram of another embodiment of a drill bit.

FIG. 7 is a cross-sectional diagram of another embodiment of a drill bit.

FIG. 8 is a side orthogonal diagram of an embodiment of a distal end of a jack element.

FIG. 9 is a side orthogonal diagram of another embodiment of a distal end of a jack element.

FIG. 10 is a cross-sectional diagram of another embodiment of a drill bit.

FIG. 11 is a cross-sectional diagram of another embodiment of a drill bit.

FIG. 12 is a bottom orthogonal diagram of another embodiment of a drill bit.

FIG. 13 is a side orthogonal diagram of another embodiment of a drill bit.

FIGS. 1 and 2 disclose a drill bit 100 a of the present invention. The drill bit 100 a comprises a shank 200 a , which is adapted for connection to a downhole tool string, such as drill string made of rigid drill pipe, drill collars, heavy weight pipe, reamers, jars, and/or subs. In some embodiments, coiled tubing or other types of drill strings may be used. The drill bit 100 a of the present invention is intended for deep oil and gas drilling, although any type of drilling is anticipated such as horizontal drilling, geothermal drilling, mining, exploration, on and off-shore drilling, directional drilling, and any combination thereof.

The drill bit 100 a includes a bit body 201 a attached to the shank 200 a and comprises an end which forms a working face 202 a . Several blades 101 a - 101 e extend outwardly from the bit body 201 a , each of which comprise a plurality of shear cutters 102 a . The drill bit 100 a may have at least three blades and, preferably, the drill bit 100 a will have between three and seven blades. The blades 101 a - 101 e collectively form an inverted conical region 103 a . Each blade 101 a - 101 e may have a cone portion 253 a , a nose 204 a , a flank portion 205 a , and a gauge portion 207 a . Shear cutters 102 a may be arrayed along any portion of the blades 101 a - 101 e , including the cone portion 253 a , the nose 204 a , the flank portion 205 a , and the gauge portion 207 a.

A jack element 104 a having a distal end 206 a is substantially coaxial with an axis 105 a of rotation of the drill bit 101 a and extends to a distance 318 from the working face 202 a to its distal end 206 a within the inverted conical region 103 a . The distance 218 that the jack element 104 a extends falls within a range defined by a diameter 211 a of a cutting surface 210 a of at least one of the cutters 102 a . The cutter 102 may be attached to the cone portion 253 and/or the nose 204 of one of the blades 101 .

A plurality of nozzles 106 a are fitted into recesses 107 a formed in the working face 202 a . Each nozzle 106 a may be oriented such that a jet of drilling mud ejected from the nozzle 106 a engages a formation before or after the cutters 102 a . The jets of drilling mud may also be used to clean cuttings away from drill bit 100 a . In some embodiments, the jets of drilling mud may be used to create a sucking effect to remove drill bit cuttings adjacent the cutters 102 a and/or the jack element 104 a by creating a low pressure region within their vicinities.

FIG. 3 discloses a cross-section of an embodiment of the drill bit 100 a . The jack element 104 a comprises a hard surface 300 a of a least 63 HRc. The hard surface 300 a may be attached to the distal end 206 a of the jack element 104 a , but it may also be attached to any portion of the jack element 104 a . In some embodiments, the jack element 104 a is made of a material of at least 63 HRc. In the preferred embodiment, the jack element 104 a comprises tungsten carbide with a hard surface 300 a of polycrystalline diamond bonded to its distal end 206 a.

Preferably, the shear cutters 102 a also comprise a hard surface made of polycrystalline diamond. In some embodiments, the cutters 102 a and/or distal end 206 a of the jack element 104 a comprise a diamond or cubic boron nitride surface. The diamond may be selected from group consisting of polycrystalline diamond, natural diamond, synthetic diamond, vapor deposited diamond, silicon bonded diamond, cobalt bonded diamond, thermally stable diamond, polycrystalline diamond with a cobalt concentration of 1 to 40 weight percent, infiltrated diamond, layered diamond, polished diamond, course diamond, fine diamond or combinations thereof. In some embodiments, the jack element 104 is made primarily from a cemented carbide with a binder concentration of 1 to 40 weight percent, preferably of cobalt.

The working face 202 a of the drill bit 100 a may be made of a steel, a matrix, or a carbide as well.

The cutters 102 a or the distal end 206 a of the jack element 104 a may also be made out of hardened steel or may comprise a coating of chromium, titanium, aluminum or combinations thereof.

The jack element 104 a may be disposed within a pocket 301 a formed in the bit body 201 a . The jack element 104 a is brazed, press fit, welded, threaded, nailed, or otherwise fastened within the pocket 301 a . In some embodiments, the tolerances are tight enough that a channel 302 a connected to a bore 330 of the drill bit 100 a is desirable to allow air to escape upon insertion of the jack element 104 a into the pocket 301 a and to allow air to fill in the pocket 301 a upon removal of the jack element 104 a . A plug 303 may be used to isolate the internal pressure of the drill bit 100 a from the pocket 301 a . In some embodiments, there is no pocket 301 a and the jack element 104 a is attached to a flat portion of the working face 202 a.

The drill bit 100 a may be made in two portions. The first portion 305 a may comprise at least the shank 200 a and a part of the bit body 201 a . The second portion 310 a may comprise the working face 202 a and at least another part of the bit body 201 a . The two portions 305 a , 310 a may be welded together or otherwise joined together at a joint 315 a.

A diameter 320 a of the jack element 104 a may affect its ability to lift the drill bit 100 a in hard formations. Preferably, the working face 202 a comprises a cross-sectional thickness, or diameter, 325 a of 4 to 12 times a cross-sectional thickness, or diameter, 320 a of the jack element 104 a . Preferably, the working face 202 a comprises a cross-sectional area of 4 to 12 times a cross-sectional area of the jack element 104 a.

FIG. 4 discloses the drill bit 100 a in which the jack element 104 a engages a formation 400 . Preferably the formation 400 is the bottom of a well bore. The effect of the jack element 104 a on the formation 400 may depend on the hardness of the formation 400 and also the weight loaded to the drill bit 100 a , which is typically referred to as weight-on-bit, or WOB. A feature of the present invention is the ability of the jack element 104 a to share at least a portion of the WOB with the blades 101 a - 101 e and/or cutters 102 a . One feature that allows the jack element 104 a to share at least a portion of the WOB is that the distal end 206 a has a blunt geometry 450 .

One long standing problem in the industry is that cutters, such as diamond cutters, chip or wear in hard formations when a drill bit is used too aggressively. To minimize cutter damage, a driller will reduce the rotational speed of the bit, but all too often a hard formation is encountered before it is detected and before the driller has time to react.

With the present invention, the jack element 104 a may limit the depth of cut that the drill bit 100 a may achieve per rotation in hard formations because the jack element 104 a actually jacks the drill bit 100 a thereby slowing its penetration in the unforeseen hard formations. If the formation is soft, the formation may not be able to resist the WOB loaded to the jack element 104 a and a minimal amount of jacking may take place. But in hard formations, the formation may be able to resist the jack element 104 a , thereby lifting the drill bit 100 a as the cutters 102 a remove a volume of the formation during each rotation. As the drill bit 100 a rotates and more volume is removed by the cutters 102 a and drilling mud, less WOB will be loaded to the cutters 102 a and more WOB will be loaded to the jack element 104 a . Depending on the hardness of the formation 400 , enough WOB will be focused immediately in front of the jack element 104 a such that the hard formation will compressively fail, weakening the hardness of the formation and allowing the cutters 102 a to remove an increased volume with a minimal amount of damage.

Typically, WOB is precisely controlled at the surface of the well bore to prevent over loading the drill bit. In experimental testing at the D.J. Basin in Colorado, crews have added about 5,000 more pounds of WOB to embodiments of the drill bit disclosed herein than typically applied to other drill bits. The crews use a downhole mud motor in addition to a top-hole motor to turn the drill string.

Since more WOB increases the depth-of-cut of the cutters on a drill bit, the WOB added will also increase the traction at the drill bit, which will increase the torque required to turn the drill bit. Too much torque can be harmful to the motors rotating the drill string. Surprisingly, the crews in Colorado discovered that the additional 5,000 pounds of WOB did not significantly add much torque to their motors.

This finding from the DJ Basin is consistent with the findings of a test conducted at the Catoosa Test Facility in Rogers County, Okla., where the addition of 10,000 to 15,000 pounds of WOB did not add the expected torque to their motors either.

The minimal increase of torque on the motors is believed to be effected by the jack element 104 a . It is believed that as the WOB increases the jack element 104 a jacks the drill bit 100 a and then compressively fails the formation 400 in front of the drill bit 100 a by focusing the WOB to the small region in front of the jack element 104 a , thereby weakening the rest of the formation 400 in the proximity of the working face 202 a . By jacking the drill bit 100 a , the depth of cut of the cutters 102 a is limited until the compressive failure of the formation 400 takes place, leaving the formation 400 relatively weaker or softer. This, in turn, causes less torque to be required to drill. It is believed that the shearing failure and the compressive failure of the formation 400 happen simultaneously.

As the cutters 102 a along the inverted conical region 103 a of the drill bit 100 a remove portions of the formation 400 , a conical profile 401 in the formation 400 may be formed. As the jack element 104 a compressively fails the conical profile 401 , the formation 400 may be pushed towards the cutters 102 a of the inverted conical region 103 a of the blades 101 a - 101 e . Since cutting at the axis of rotation 105 a is typically the least effective (where the rotational velocity of the cutter 102 a is lowest), the present invention provides an effective structure and method for increasing the rate of penetration (ROP).

It is believed that it is easier to compressively fail and displace the conical profile 401 closer to its tip 401 ′ than at its base 401 ″, since there is a smaller cross-sectional area. If the jack element 104 a extends too far into the conical profile 401 , the cross-sectional area of the conical profile 401 becomes larger, which may cause it to become too hard to effectively compressively fail and/or displace it. If the jack element 104 a extends beyond a first distance 410 from the working face 202 a to the leading most, or most distant first point 416 of the leading most cutter 402 , i.e., the cutter 402 furthest from the working face 202 a , the cross-sectional area of the conical profile 401 may become indefinitely large and extremely hard to displace. In some embodiments, the jack element 104 a extends within a range of 0.100 to 3 inches from the working face 202 a . In some embodiments, the jack element 104 a extends a distance 414 from the working face 202 a that falls within a diameter 411 extending from a point 415 proximate to the working face 202 a of a cutting surface 413 of a cutter 403 proximate the axis 105 a of rotation to another point 415 ′.

As drilling advances, the jack element 104 a is believed to stabilize the drill bit 100 a as well. A long standing problem in the art is bit whirl, which is solved by the jack element 104 a provided that the jack element 104 a extends beyond the diameter 211 a of the cutting surface 210 a of at least one of the cutters 102 a within the inverted conical region 103 a , as illustrated in FIG. 2 .

Referring back to FIG. 4 , the leading most cutter 402 may be attached to the nose 204 a of at least one of the blades 101 a . Preferably, the distal end 206 a of the jack element 104 a does not extend from the working face 202 a beyond a distance 410 to the most distant first point 416 of a cutting surface of cutter 402 . The trailing most cutter 403 within the inverted conical region 103 a may be the closest cutter to the axis 105 of rotation. Preferably, the distal end 206 a of the jack element 104 a extends at least a second distance 412 from the working face 202 a to the point 415 of the cutting surface 413 of the cutter 403 that is proximate to the axis 105 a of rotation. This distance from the point 415 to the point 410 in which the distal end 206 a of jack element 104 a extends from the working face 202 a is illustrated in FIG. 3 as distance 312 . In some embodiments, the jack element 104 a extends into a region defined as the depth of cut 405 of at least one cutter, which may be the cutter 403 proximate the axis 105 a of rotation or other cutters 102 a.

Surprisingly, if the jack element 104 a does not extend beyond the distance 412 , it was found that the drill bit 100 a was only as stable as the typical commercially available shear bits. During testing it was found in some situations that if the jack element 104 a extended too far, it would be too weak to withstand radial forces produced from drilling or the jack element 104 a would reduce the depth-of-cut per rotation greater than desired.

Referring to FIG. 11 , one indication that stability of the drill bit 10 f is achieved by the jack element 104 f is the reduction of wear on the gauge cutters 1401 a (illustrated in FIG. 11 on an embodiment of a drill bit 1000 . In the test conducted at the Catoosa Test Facility in Rogers County, Okla. the present invention was used to drill a well of 780 ft in 6.24 hours through several formations that included mostly sandstone and limestone. During this test, it was found that there was little to no wear on any of the polycrystalline diamond cutters 1401 a fixed to a gauge portion 207 f of the drill bit 100 f , which was not expected, especially since the gauge cutters 1401 a were not leached and the gauge cutters 1401 a had an aggressive diameter size of 13 millimeters, while the cutters 1400 a in the inverted conical region 103 f had 19 millimeter cutters. It is believed that this reduced wear indicates that there was significantly reduced bit whirl and that the drill bit 100 f drilled a substantially straight hole. The tests conducted in Colorado also found that the gauge cutters of that drill bit suffered little or no wear.

Referring back to FIG. 4 , an extension 404 of the working face 20 a of the drill bit 100 a forms a support around a portion of the jack element 104 a . Because the nature of drilling produces lateral loads, the jack element 104 a must be robust enough to withstand them. The support from the extension 404 may provide the additional strength needed to withstand the lateral loads.

Referring to FIG. 5 , another embodiment of a drill bit 100 b uses a ring 500 welded or otherwise bonded to a working face 202 b of the drill bit 100 b to give the extra support to resist lateral loads. The ring 500 may be made of tungsten carbide or another material with sufficient strength. In some embodiments, the ring 500 is made a material with a hardness of at least 58 HRc.

FIG. 6 discloses another embodiment of a drill bit 100 c that a jack element 104 c formed out of the same material as a bit body 201 c . The distal end 206 c of the jack element 104 c may be coated with a hard material 300 c to reduce wear. Preferably the jack element 104 c comprises a blunt distal end 206 c . The bit body 201 c and the jack element 104 c may be made of steel, hardened steel, matrix, tungsten carbide, other ceramics, or combinations thereof. The jack element 104 c may be formed out of the bit body 201 c through electric discharge machining (EDM) or on a lathe.

FIG. 7 discloses another embodiment of a drill bit 100 d that includes a tapered jack element 104 d . In the embodiment of FIG. 7 , the entire jack element 104 d is tapered, although in some embodiments only a portion or portions of the jack element 104 d may be tapered. A tapered jack element 104 d may provide additional support to the jack element 104 d by preventing buckling or helping resist lateral forces exerted on the jack element 104 d.

In such embodiments of drill bit 100 d , the jack element 104 d may be inserted from either the working face 202 d or the bore 600 of the drill bit 100 d . In either situation, a pocket 301 d is formed in a bit body 201 d and the tapered jack element 104 d is inserted. Additional material is then added into the exposed portion of the pocket 301 d after the tapered jack element 104 d is added. The additional material may comprise the geometry of the exposed portion of the pocket 301 d , such as a cylinder, a ring, or a tapered ring. In the embodiment of FIG. 7 , the tapered jack element 104 d is insertable from the working face 202 d . A proximal end 900 of the jack element 104 d is brazed to a closed end 301 d ′ of the pocket 301 d . A tapered ring 901 is then bonded into the remaining portion of the pocket 301 d . The tapered ring 901 may be welded, friction welded, brazed, glued, bolted, nailed, or otherwise fastened to the bit body 201 d.

FIGS. 8-9 disclose embodiments of a distal end, such as distal end 206 a illustrated in FIGS. 2-4 . The distal end has a blunt geometry that may comprise a generally hemispherical shape, a generally flat shape, a generally conical shape, a generally round shape, a generally asymmetric shape, or combinations thereof. FIG. 8 illustrates an embodiment of a distal end 206 e having hemispherical shape. FIG. 9 illustrates an embodiment of a distal end 206 f having a generally flat shape. The blunt geometry may be defined by the region of the distal end that engages the formation. In some embodiments, the blunt geometry comprises a surface area greater than an area of a cutting surface of one of the cutters 102 a attached to one of the blades 101 . The cutting surface of the cutter 102 a may be defined as a flat surface of the cutter 102 a , the area that resists WOB, or in embodiments that use a diamond surface, the diamond surface may define the cutting surface. In some embodiments, the surface area of the blunt geometry is greater than twice the cutter surface of one of the cutters 102 a.

FIG. 10 discloses a drill bit 100 e of the present invention with inner cutters 1400 b aligned on a cone portion 253 e of the blades 101 f . The cutters 1400 b are smaller than the cutters 1401 b on a flank portion 205 e or a gauge portion 207 e of the drill bit 100 e . In the testing performed in both Colorado and Oklahoma locations, the inner cutters 1400 b in an inverted conical region 103 e received more wear than a flank cutter 1405 b or the gauge cutters 1401 b , which is unusual since the rotational velocity of the cutters 1400 b is less than the rotational velocity of the gauge cutters 1401 b placed more peripheral to the inner cutters 1400 b.

Since the inner cutters 1400 b are now subjected to a more aggressive environment, the cutters 1400 b may be reduced in size to make the cutters 1400 b less aggressive. The inner cutters 1400 b may also be chamfered around their edges to make them less aggressive.

The cutters may have a diameter of 5 millimeters to 50 millimeters. Cutters having a diameter of 13 millimeters to 19 millimeters are more common in the deep oil and gas drilling.

In other embodiments, such as the embodiment of a drill bit 100 f illustrated in FIG. 11 , the inner cutters 1400 a may be positioned at a greater negative rake-angle 1500 than a flank cutter 1405 a or a gauge cutter 1401 a to make them less aggressive. Any of the cutters may comprises a negative rake-angle 1500 of 1 degree to 40 degrees. In some embodiments of the present invention, only the inner most cutter on each blade has a reduced diameter relative to the other cutters or only the inner most cutter on each blade may be set at a relatively more negative rake-angle than the other cutters.

FIG. 11 also discloses a sleeve 1550 which may be brazed into a pocket 301 f formed in a working face 202 f . When the braze material cools the sleeve 1550 may misalign from the axis 105 f of rotation. A bore 1551 having an inner diameter 1552 of the sleeve 1550 may be machined after the sleeve 1550 has cooled, so that the bore 1551 is coaxial with the axis 105 f of rotation. Then, the jack element 104 f may be press fit into the bore 1551 of the sleeve 1550 and be coaxial with the axis 105 f of rotation. A jack element 104 f may then be press fit into the sleeve 1550 . Instead of brazing the jack element 104 f directly into the working face 202 f , in some embodiments it may be advantageous to braze the jack element 104 f to the sleeve 1550 .

FIG. 12 discloses another embodiment of a drill bit 100 g where more cutters 1400 c in an inverted conical region 103 g have been added. This may reduce the volume that each cutter 1400 c in the inverted conical region 103 g removes per rotation, which may reduce the forces felt by the inner cutters 1400 c . Back-up cutters 1600 may be positioned between the inner cutters 1400 c to prevent blade washout.

FIG. 13 discloses an embodiment of a drill bit 100 h with a long gauge length 1700 . A long gauge length 1700 is believed to help stabilize the drill bit 100 h . A long gauge length 1700 in combination with a jack element, such as jack element 104 a illustrated in FIGS. 1-4 , may help stabilize the drill bit 100 h . The gauge length 1700 may be 0.25 to 15 inches long. In some embodiments, the gauge portion 207 h may comprise 3 to 21 cutters 102 h . The cutters 102 h may have several geometries to help make them more or less aggressive depending on their position on the drill bit 100 h . Some of these geometries may include a generally flat shape, a generally beveled shape, a generally rounded shape, a generally scooped shape, a generally chisel shape or combinations thereof. In some embodiments, the gauge cutters 1401 d may comprise a small diameter than the cutters 1400 d attached within the inverted conical region 103 h.

FIG. 13 also discloses a cone angle 1701 and a flank angle 1702 of the drill bit 100 h . The cone angle 1701 and the flank angle 1702 may be adjusted for different formations and different applications. Preferably, the cone angle 1701 may be anywhere from 25 degrees to 155 degrees and the flank angle 1702 may be anywhere from 5 degrees to 85 degrees.

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