Patent Grant
11332980
The disclosure, in various embodiments, relates generally to earth-boring tools, such as drill bits, having radially and axially extending blades. More particularly, the disclosure relates to drill bits including at least one insert mounted in the gauge region thereof to decrease deviations of the drill bit while directionally drilling of a borehole.
Rotary drill bits are commonly used for drilling boreholes or wellbores in earth formations. One type of rotary drill bit is the fixed-cutter bit (often referred to as a “drag” bit). The process of drilling an earth formation may be visualized as a three-dimensional process, as the drill bit may not only penetrate the formation linearly along a vertical axis, but is either purposefully or unintentionally drilled along a curved path or at an angle relative to a theoretical vertical axis extending into the earth formation in a direction substantially parallel to the gravitational field of the earth, as well as in a specific lateral direction relative to the theoretical vertical axis. The term “directional drilling,” as used herein, means both the process of directing a drill bit along some desired trajectory through an earth formation to a predetermined target location to form a borehole, and the process of directing a drill bit along a predefined trajectory in a direction other than directly downwards into an earth formation in a direction substantially parallel to the gravitational field of the earth to either a known or unknown target.
Several approaches have been developed for directional drilling. For example, positive displacement (Moineau) type motors as well as turbines have been employed in combination with deflection devices such as bent housings, bent subs, eccentric stabilizers, and combinations thereof to effect oriented, nonlinear drilling when the bit is rotated only by the motor drive shaft, and linear drilling when the bit is rotated by the superimposed rotation of the motor shaft and the drill string.
Other steerable bottom hole assemblies are known, including those wherein deflection or orientation of the drill string may be altered by selective lateral extension and retraction of one or more contact pads or members against the borehole wall. One such system is the AutoTrak™ drilling system, developed by the INTEQ operating unit of Baker Hughes, a GE company, LLC, assignee of the present disclosure. The bottom hole assembly of the AutoTrak™ drilling system employs a non-rotating sleeve through which a rotating drive shaft extends to drive the bit 100, the sleeve thus being decoupled from drill string rotation. The sleeve carries individually controllable, expandable, circumferentially spaced steering ribs on its exterior, the lateral forces exerted by the ribs on the sleeve being controlled by pistons operated by hydraulic fluid contained within a reservoir located within the sleeve. Closed loop electronics measure the relative position of the sleeve and substantially continuously adjust the position of each steering rib so as to provide a steady lateral force at the bit in a desired direction. Further, steerable bottom hole assemblies include placing a bent adjustable kick off (AKO) sub between the drill bit 100 and the motor. In other cases, an AKO may be omitted and a side load (e.g., lateral force) applied to the drill string/bit to cause the bit 100 to travel laterally as it descends downward.
The processes of directional drilling and deviation control are complicated by the complex interaction of forces between the drill bit and the wall of the earth formation surrounding the borehole. In drilling with rotary drill bits and, particularly with fixed-cutter type rotary drill bits, it is known that if a lateral force is applied to the drill bit, the drill bit may “walk” or “drift” from the straight path that is parallel to the intended longitudinal axis of the borehole. Many factors or variables may at least partially contribute to the reactive forces and torques applied to the drill bit by the surrounding earth formation. Such factors and variables may include, for example, the “weight on bit” (WOB), the rotational speed of the bit, the physical properties and characteristics of the earth formation being drilled, the hydrodynamics of the drilling fluid, the length and configuration of the bottom hole assembly (BHA) to which the bit is mounted, and various design factors of the drill bit.
In some embodiments, a drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis, a plurality of blades extending radially outward from the longitudinal axis along a face region of the bit body and extending axially along a gauge region of the bit body, and an insert coupled to at least one blade of the plurality in the gauge region. The insert comprises an elongated body having an upper surface, a lower surface, and a longitudinal axis extending centrally through the elongated body and intersecting the upper surface and the lower surface. The upper surface comprises at least one planar surface and at least one curved surface at least partially surrounding the at least one planar surface. The insert is coupled to the at least one blade such that the upper surface thereof extends radially beyond an outer surface of the at least one blade in the gauge region and the lower surface thereof extends radially below the outer surface of the at least one blade in the gauge region.
In other embodiments, a drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis, a plurality of blades extending radially outward from the longitudinal axis along a face region of the bit body and extending axially along a gauge region of the bit body, and an insert coupled to at least one blade of the plurality in the gauge region proximate to an uphole edge of the at least one blade. The insert comprises an elongated body having an oblong shape such that the elongated body extends across a majority of a width of the at least one blade. The elongated body has an upper surface comprising a planar surface and a curved surface at least partially surrounding the planar surface. The insert is coupled to the at least one blade such that one of the planar surface and the curved surface comprises a radially outermost surface of the insert.
In yet other embodiments, a method of drilling a borehole in a subterranean formation comprises rotating a drill bit about a longitudinal axis thereof within the borehole. The method further includes increasing a tilt angle of the drill bit such that an insert mounted on at least one blade in the gauge region of the drill bit engages a sidewall of the borehole and such that a remainder of the gauge region does not engage the sidewall of the borehole. The insert comprises an elongated body having an upper surface including a planar surface and a curved surface at least partially surrounding the planar surface. Engaging the sidewall with the insert includes rubbing at least one of the planar surface and the curved surface against the sidewall of the borehole without exceeding a compressive strength of the subterranean formation.
While the specification concludes with claims particularly pointing out and distinctly claiming what are regarded as embodiments of the present disclosure, various features and advantages of embodiments of the disclosure may be more readily ascertained from the following description of example embodiments of the disclosure when read in conjunction with the accompanying drawings, in which:
The illustrations presented herein are not meant to be actual views of any particular cutting structure, insert, drill bit, or component thereof, but are merely idealized representations, which are employed to describe embodiments of the present disclosure. For clarity in description, various features and elements common among the embodiments may be referenced with the same or similar reference numerals.
As used herein, any relational term, such as “first,” “second,” “over,” “above,” “below,” “up,” “down,” “upward,” “downward,” “top,” “bottom,” “top-most,” “bottom-most,” and the like, is used for clarity and convenience in understanding the disclosure and accompanying drawings and does not connote or depend on any specific preference, orientation, or order, except where the context clearly indicates otherwise.
As used herein, the terms “longitudinal,” “longitudinally,” “axial,” or “axially” refers to a direction parallel to a longitudinal axis (e.g., rotational axis) of the drill bit described herein. For example, a “longitudinal dimension” or “axial dimension” is a dimension measured in a direction substantially parallel to the longitudinal axis of the drill bit described herein.
As used herein, the terms “radial” or “radially” refers to a direction transverse to a longitudinal axis of the drill bit described herein and, more particularly, refers to a direction as it relates to a radius of the drill bit described herein. For example, as described in further detail below, a “radial dimension” is a dimension measured in a direction substantially transverse (e.g., perpendicular) to the longitudinal axis of the drill bit as described herein.
As used herein, the term “substantially” in reference to a given parameter, property, or condition means and includes to a degree that one of ordinary skill in the art would understand that the given parameter, property, or condition is met with a degree of variance, such as within acceptable manufacturing tolerances. By way of example, depending on the particular parameter, property, or condition that is substantially met, the parameter, property, or condition may be at least 90.0% met, at least 95.0% met, at least 99.0% met, or even at least 99.9% met.
As used herein, the term “about” in reference to a given parameter is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the given parameter).
As used herein, the terms “comprising,” “including,” “containing,” “characterized by,” and grammatical equivalents thereof are inclusive or open-ended terms that do not exclude additional, unrecited elements or method steps, but also include the more restrictive terms “consisting of” and “consisting essentially of” and grammatical equivalents thereof.
As used herein, the term “may” with respect to a material, structure, feature, or method act indicates that such is contemplated for use in implementation of an embodiment of the disclosure, and such term is used in preference to the more restrictive term “is” so as to avoid any implication that other compatible materials, structures, features and methods usable in combination therewith should or must be excluded.
As used herein, the term “configured” refers to a size, shape, material composition, and arrangement of one or more of at least one structure and at least one apparatus facilitating operation of one or more of the structure and the apparatus in a predetermined way.
As used herein, the singular forms following “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.
As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.
As used herein, the term “earth-boring tool” means and includes any tool used to remove formation material and to form a bore (e.g., a borehole) through an earth formation by way of the removal of the formation material. Earth-boring tools include, for example, rotary drill bits (e.g., fixed-cutter or “drag” bits and roller cone or “rock” bits), hybrid bits including both fixed cutters and roller elements, coring bits, percussion bits, bi-center bits, reamers (including expandable reamers and fixed-wing reamers), and other so-called “hole-opening” tools.
As used herein, the term “cutting element” means and includes an element separately formed from and mounted to an earth-boring tool that is configured and positioned on the earth-boring tool to engage an earth (e.g., subterranean) formation to remove formation material therefrom during operation of the earth-boring tool to form or enlarge a borehole in the formation. By way of non-limiting example, the term “cutting element” includes tungsten carbide inserts and inserts comprising superabrasive materials as described herein.
As used herein, the term “superabrasive material” means and includes any material having a Knoop hardness value of about 3,000 Kgf/mm2 (29,420 MPa) or more such as, but not limited to, natural and synthetic diamond, cubic boron nitride and diamond-like carbon materials.
As used herein, the term “polycrystalline material” means and includes any material comprising a plurality of grains or crystals of the material that are bonded directly together by inter-granular bonds. The crystal structures of the individual grains of the material may be randomly oriented in space within the polycrystalline material.
As used herein, the term “polycrystalline compact” means and includes any structure comprising a polycrystalline material formed by a process that involves application of pressure (e.g., compaction) to the precursor material or materials used to form the polycrystalline material.
The bit body 102 of the drill bit 100 is typically secured to a hardened steel shank 111 having an American Petroleum Institute (API) thread connection for attaching the drill bit 100 to a drill string. The drill string includes tubular pipe and equipment segments coupled end to end between the drill bit and other drilling equipment at the surface. Equipment such as a rotary table or top drive may be used for rotating the drill string and the drill bit 100 within the borehole. Alternatively, the shank 111 of the drill bit 100 may be coupled directly to the drive shaft of a down-hole motor, which then may be used to rotate the drill bit 100, alone or in conjunction with a rotary table or top drive.
The bit body 102 of the drill bit 100 may be formed from steel. Alternatively, the bit body 102 may be formed from a particle-matrix composite material. Such bit bodies may be formed by embedding a steel blank in a carbide particulate material volume, such as particles of tungsten carbide (WC), and infiltrating the particulate carbide material with a liquefied metal material (often referred to as a “binder” material), such as a copper alloy, to provide a bit body substantially formed from a particle-matrix composite material.
A row of cutting elements 110 may be mounted to each blade 104 of the drill bit 100. For example, cutting element pockets may be formed in the blades 104, and the cutting elements 110 may be positioned in the cutting element pockets and bonded (e.g., brazed, bonded, etc.) to the blades 104. The cutting elements 110 may comprise, for example, a polycrystalline compact in the form of a layer of polycrystalline material, referred to in the art as a polycrystalline table, that is provided on (e.g., formed on or subsequently attached to) a supporting substrate with an interface therebetween. In some embodiments, the cutting elements 110 may comprise polycrystalline diamond compact (PDC) cutting elements each including a volume of superabrasive material, such as polycrystalline diamond material, provided on a ceramic-metal composite material substrate. Though the cutting elements 110 in the embodiment depicted in
The gauge region 106 of each blade 104 may be a longitudinally (e.g., axially) extending region of each blade 104. The gauge region 106 may be defined by a rotationally leading edge 112 opposite a rotationally trailing edge 114 of the blade 104 and an uphole edge 116 opposite a downhole edge 118. The uphole edge 116 is adjacent to a crown chamfer 107 of the bit 100 proximal to the shank 111 of the bit 100 and distal from the face 108 of the bit 100, and the downhole edge 118 is adjacent to the face 108 of the bit 100. As used herein, the terms “downhole” and “uphole” refer to locations within the gauge region 106 relative to portions of the drill bit 100 such as the face 108 of the bit 100 that engage the bottom of a wellbore to remove formation material. The uphole edge 116 is located closer to (e.g., proximate to, adjacent to) to the shank 111 of the bit 100 or to an associated drill string or bottom hole assembly as compared to the downhole edge 118 that is located closer to (e.g., proximate to, adjacent to) the face 108 of the bit 100.
The gauge region 106 may be divided (e.g., bisected) into a first and second region including an uphole region 120 and a downhole region 121, respectively. The uphole region 120 may be referred to herein as a “recessed region” as the uphole region 120 is radially recessed relative to the downhole region 121 of the gauge region 106, as is illustrated in
The gauge region 106 may further include an insert 122 mounted on the blade 104. The insert 122 may be mounted proximate to the uphole edge 116. In some embodiments, the insert 122 may be mounted within an uphole half of the gauge region 106. In other embodiments, the insert 122 may be mounted within an upper quartile of the gauge region 106. By way of non-limiting example, the insert 122 may be mounted within about 1.0 inch or within about 0.5 inch of the uphole edge 116 as measured from a center of the insert 122. Accordingly, the insert 122 may be mounted in the recessed uphole region 120. In some embodiments, as illustrated in
The insert 122 may be mounted in the gauge region 106 substantially intermediately between the rotationally leading edge 112 and the rotationally trailing edge 114 of the blade 104. In some embodiments, the insert 122 may have a width W122 (
The insert 122 is substantially received within and may be attached to a receptacle 105 within the blade 104. The insert 122 may be bonded or secured to the blade 104 by bonding or secured by brazing or other joining material. When the insert 122 is bonded to the blade 104 by bonding (including brazing), the bonding material may act as a filler to fill any interstitial gaps or voids between the receptacle 105 and the insert 122. In some embodiments, the receptacle 105 may substantially (e.g., entirely) enclose lateral side surfaces of the insert 122. In other embodiments, the receptacle 105 may extend only partially about (e.g., partially enclose) lateral side surfaces of the insert 122. In such embodiments, the receptacle 105 may extend from the rotationally leading edge 112 of the blade 104 at least partially across a width of the blade 104. As best illustrated in
The insert 122 may be mounted on the blade 104 in the gauge region 106 such that at least a portion of an upper surface of the insert 122 extends radially beyond an outer surface 109 of the blade 104.
As previously discussed and as illustrated in
In other embodiments, the downhole region 121 may extend to the outer diameter 103 of the bit 100, as illustrated in the cross-sectional view of
As explained in further detail with respect to
The bearing surfaces 124, 125 comprise substantially planar surfaces affording a surface area tailored to provide support for a bit 100 on which a selected formation being drilled may contact and rub against without exceeding the compressive strength of the selected formation (e.g., without substantially cutting the selected formation) when low lateral forces are applied to the bit as discussed in further detail below with regard to
Any of the foregoing inserts 122, 150, 170, 190, 200, and 220 illustrated in
In other embodiments, as illustrated in
As further illustrated in
As previously described with reference to
The inserts 170 and 190 may be mounted such that one of the semi-circular first and second ends forms a rotationally leading end and the other of the semi-circular first and second ends forms a rotationally trailing end. The inserts 170 and 190 may further be mounted such that the upper surfaces thereof extend radially beyond outer surfaces of the blade 104 adjacent which the inserts 170 and 190 are mounted and such that at least a portion of the outer surfaces, such as the bearing surfaces or curved surfaces, form radially outermost surfaces of the inserts 170 and 190. The radially outermost surfaces of the inserts 170 and 190 may contact formation material of a borehole sidewall prior to other surfaces of the upper surface of the inserts 170 and 190. Accordingly, the inserts 170 and 190 may be mounted at rake angles as previously described herein and to extend to or be recessed relative to the outer diameter 103 (
While the foregoing inserts 122, 150, 170, 190, 200, and 220 are described as being separately from the bit 100 and mounted thereto, the disclosure is not so limited. In other embodiments, the inserts 122, 150, 170, 190, 200, and 220 may be integrally formed with the bit body such that the inserts 122, 150, 170, 190, 200, and 220 form part of the blade 104 in the gauge region.
Any of the foregoing inserts 122, 150, 170, 190, 200, and 220 may comprise a volume of superabrasive material, such as polycrystalline diamond material, provided on a ceramic-metal composite material substrate and coupled thereto such that the upper surface of the foregoing inserts comprises the volume of superabrasive material. In other embodiments, the inserts 122, 150, 170, 190, 200, and 220 may comprise a matrix material having a plurality of abrasive particles including, but not limited to, diamond particles dispersed therein. In yet other embodiments, the inserts 122, 150, 170, 190, 200, and 220 may comprise diamond-like carbon, thermally stable polycrystalline diamond (TSP) and/or a tungsten carbide particle-matrix composite material.
The drill bit 100 including inserts 122, 150, 170, 190, 200, and 220 according to any of the foregoing embodiments may be coupled to a drill string including a steerable bottom hole assembly configured to directionally drill a borehole. In some embodiments, the steerable bottom hole assembly may comprise positive displacement (Moineau) type motors as well as turbines have been employed in combination with deflection devices such as bent housings, bent subs, eccentric stabilizers, and combinations thereof to effect oriented, nonlinear drilling when the bit is rotated only by the motor drive shaft, and linear drilling when the bit is rotated by the superimposed rotation of the motor shaft and the drill string. In other embodiments, the steerable bottom hole assemblies may comprise a bent adjustable kick off (AKO) sub. In operation, the drill bit 100 is rotated about the longitudinal axis 101 such that the cutting elements 110 on the face 108 of the bit 100 engage the formation to remove formation material and form a borehole. The gauge region 106 and the inserts 122, 150, 170, 190, 200, and 220 mounted thereon may also contact the formation and remove formation material along a sidewall of the borehole as described with reference to
While side cutting may be undesirable at low lateral forces when drilling the straight portion of the borehole as previously described, side cutting may be desirable at greater side loads when drilling curved portions of the borehole. Such side cutting enables the bit 100 to directionally drill so as to form deviated or curved portions of the borehole in an efficient manner. Accordingly, at moderate lateral forces, such as lateral forces greater than 500 pounds (226.7 kg) and up to about 1500 pounds (680.2 kg) depending at least upon the formation material and the compressive strength thereof and upon the size of the bit 100, the amount of side cutting exhibited by the gauge region 106 of the bit 100 begins to increase in a substantially constant, linear manner. This region 254 of the line 250 is referred to as the “linear region.” At moderate lateral forces, the amount of side cutting of the bit lacking inserts increases at a lower rate than in the sensitive region. This region of the line 251 is also referred to herein as the “linear region” as the amount of side cutting increases with increasing lateral force in a substantially constant, linear manner. At high lateral forces, such as lateral forces greater than about 1500 pounds (680.2 kg) depending at least upon the formation material and the compressive strength thereof and upon the size of the bit 100, the amount of side cutting exhibited by the bit 100 is maximized and plateaus, or caps. Accordingly, this region 256 of the line 250 is referred to as the “cap region.” At high lateral forces, the side cutting capabilities of the bit lacking inserts maximizes and the amount of side cutting for increasing lateral forces plateaus, or caps. Accordingly, this region of the line 251 may also be referred to herein as the “cap region.” In view of the foregoing, the gauge region 106 of the drill bit 100 may be shaped and topographically configured such as by recessing the gauge region 106 relative to the outer diameter 103 of the bit 100 to limit side cutting of the bit 100 while drilling a substantially straight portion of a borehole without limiting side cutting of the bit 100 while drilling a curved (e.g., deviated) portion of the borehole. Overall, as illustrated in
Without being bound by any particular theory and with exemplary reference to the embodiment illustrated in
In some embodiments in which the insert 122 mounted to the blade 104 is radially recessed relative to the outer diameter 103 of the bit 100, when the bit tilt angle is zero (e.g., when the longitudinal axis 101 is substantially coaxial with the borehole axis), the gauge region 106 and, more particularly, the insert 122 thereon may not be in contact with the formation. When the bit tilt angle is greater than zero, at least a portion of the gauge region 106 and, more particularly, the insert 122 may come into contact with the borehole sidewall and remove formation material when sufficient lateral force is applied prior to a remainder of the gauge region 106 contacting the borehole sidewall. The gauge region 106 of bit 100 may be designed such that the anticipated surface area and/or volume of the gauge region 106 contacting the formation at a given lateral force and/or given bit tilt angle is selectively controlled and/or tailored. In other embodiments in which at least a portion of the insert 122 extends to the outer diameter 103 of the bit 100, when the bit tilt angle is zero, the insert may be in contact with the formation. However, because the insert 122 is formed such that the insert 122 is substantially unaggressive at low lateral forces, the insert 122 may ride or bear against the formation material without substantially removing formation material therefrom while forming the straight portion of the borehole.
At low lateral forces, such as forces less than about 500 lbs (226.7 kg) depending at least upon the formation material and the compressive strength thereof and upon the size of the bit 100, the insert 122 may ride, rub on, or otherwise engage the borehole sidewall without substantially failing the formation material of the sidewall (e.g., without exceeding the compressive strength of the formation). In other words, at low lateral forces the insert 122 does not provide substantial side cutting action. At low lateral forces, the amount of side cutting by the bit lacking inserts increases rapidly with increasing lateral force. Accordingly, this region of the line 251 may be referred to herein as the “sensitive region” as the bit is highly responsive to (e.g., sensitive to) minimal applications of lateral force.
As the bit tilt angle increases so as to steer or direct the drill bit 100 away from the linear path of the substantially vertical portion of the borehole, the insert 122 in the gauge region 106 of the bit 100 may engage a borehole sidewall and penetrate the formation material thereof so as to remove formation material. As the bit tilt angle increases, outer surfaces of the blade 104 in the uphole region 120 and the downhole region 121 may increasingly engage the formation and increase the volume of the gauge region 106 in contact with the formation material until the bit tilt angle is sufficiently high that substantially all of the volume of the gauge region 106 is in contact with the formation. Further, as previously described, the gauge region 106 of the bit 100 includes a recessed uphole region 120. By providing the recessed region at the top of the gauge region 106, the amount of contact between the gauge region 106 and the formation may be reduced, which enables the bit 100 to deviate from the vertical portion toward a substantially horizontal portion of the borehole, referred to as the “build up rate,” over a shorter distance.
Accordingly, in operation, the drill bit 100 may exhibit the amount of side-cutting as a function of increasing lateral force and/or volume of the gauge region 106 engagement as a function of bit tilt angle as previously described with reference to
While the embodiments of the disclosure have been described with reference to mounting a single insert 122, 150, 170, 190, 200, and 220 to the gauge region 106 of each blade 104, the disclosure is not so limited. As illustrated in
As illustrated in
In other embodiments, the radial extension D312 of the rotationally leading edge 312 may be less than the radial extension D314 of the rotationally trailing edge 314. In such embodiments, the insert 150 may be said to exhibit a radial taper such that the radial extension of the insert 150 increases between the rotationally leading edge 312 and the rotationally trailing edge 314. In such embodiments, the rotationally trailing edge 314 may extend to or be radially recessed relative to the outer diameter of the bit 300 as previously discussed with reference to
As illustrated in
In other embodiments, the inserts 150 may be mounted on the blade such that a radial extension D1, D2, D3 measured from the longitudinal axis 301 of the bit 300 of the respective inserts 150 increases between the rotationally leading edge 312 and the rotationally trailing edge of the blade 304. In such embodiments, the plurality of inserts 150 collectively exhibits a radial taper such that the radial extension of the inserts 150 increases across a width of the blade 304. In such embodiments, outer surface 162 of the insert 150 located proximate to the rotationally trailing edge 314 may extend to or be radially recessed relative to the outer diameter of the bit 300 as previously discussed with reference to
As previously described with reference to
Additional non limiting example embodiments of the disclosure are described below:
A drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis, a plurality of blades extending radially outward from the longitudinal axis along a face region of the bit body and extending axially along a gauge region of the bit body, and an insert coupled to at least one blade of the plurality in the gauge region. The insert comprises an oblong body having an upper surface, a lower surface, and a longitudinal axis extending centrally through the elongated body and intersecting the upper surface and the lower surface. The upper surface comprises a bearing surface for supporting for the drill bit and providing a surface on which the subterranean formation being drilled rubs against the insert without exceeding the compressive strength of the selected formation. The insert is coupled to the at least one blade such that the upper surface thereof extends radially beyond an outer surface of the at least one blade in the gauge region and the lower surface thereof extends radially below the outer surface of the at least one blade in the gauge region.
The drill bit of Embodiment 1, wherein a remainder of the gauge region is free of cutting elements thereon.
The drill bit of either of Embodiments 1 or 2, wherein the insert is coupled to the at least one blade such that a radially outermost surface of the insert comprises the bearing surface.
The drill bit of any of Embodiments 1 through 3, wherein the bearing surface comprises at least one of a planar surface and a curved surface.
The drill bit of any of Embodiments 1 through 4, wherein the bearing surface comprises the curved surface and wherein the curved surface has a radius of curvature in a range extending from about 1.5 inch (38.1 mm) to about 12 inch (304.8 mm).
The drill bit of any of Embodiments 1 through 5, wherein the bearing surface comprises the planar surface and the planar surface is perpendicular to the longitudinal axis of the insert.
The drill bit of any of Embodiments 1 through 6, wherein the insert is mounted in an uphole quartile of the at least one blade proximate to an uphole edge in the gauge region.
The drill bit of any of Embodiments 1 through 7, wherein the insert is mounted on the at least one blade such that an entirety of the upper surface thereof is radially recessed to an outer diameter of the bit.
The drill bit of any of Embodiments 1 through 8, wherein a radially outermost surface of the insert is radially recessed relative to the outer diameter of the bit by a distance in a range from about 0.005 inch (0.127 mm) to about 0.050 inch (1.27 mm).
The drill bit of any of Embodiments 1 through 9, wherein the insert is mounted on the at least one blade at a rake angle in a range from about −15 degree to about 15 degrees.
A directional drilling system comprising a steerable bottom hole assembly operably coupled to the drill bit of any of Embodiments 1 through 10.
A method of drilling a borehole in a subterranean formation comprises rotating a drill bit about a longitudinal axis thereof within the borehole and increasing a tilt angle of the drill bit such that an insert mounted on at least one blade in the gauge region of the drill bit engages a sidewall of the borehole and such that a remainder of the gauge region does not engage the sidewall of the borehole. The insert comprises an oblong body having an upper surface including a bearing surface such that engaging the sidewall comprises rubbing the bearing surface against the sidewall of the borehole without exceeding a compressive strength of the subterranean formation.
The method of Embodiment 12, further comprising increasing the tilt angle of the drill bit such that the insert mounted on the at least one blade penetrates the sidewall of the borehole and exceeds the compressive strength of the subterranean formation to side cut the sidewall of the borehole.
The method of either of Embodiments 12 or 13, further comprising increasing the tilt angle of the drill bit such that the remainder of the gauge region engages the sidewall of the borehole.
The method of any of Embodiments 12 through 14, wherein rotating the drill bit about the longitudinal axis thereof comprises rotating the drill bit about the longitudinal axis such that the longitudinal axis is coaxial with a central axis of the borehole and engaging a face of the drill bit with the subterranean formation without engaging the gauge region of the drill bit with the sidewall of the borehole.
A drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis, a plurality of blades extending radially outward from the longitudinal axis along a face region of the bit body and extending axially along a gauge region of the bit body, and an insert coupled to at least one blade of the plurality in the gauge region proximate to an uphole edge of the at least one blade. The insert comprises an elongated body having an oblong shape such that the elongated body extends across a majority of a width of the at least one blade. The elongated body has an upper surface comprising a bearing surface for supporting for the drill bit and providing a surface on which the subterranean formation being drilled rubs against the insert without exceeding the compressive strength of the subterranean formation. The insert is coupled to the at least one blade such that the bearing surface comprises a radially outermost surface of the insert.
The drill bit of Embodiment 16, wherein the insert is mounted in an uphole quartile of the at least one blade proximate to an uphole edge in the gauge region.
The drill bit of either of Embodiments 16 or 17, wherein the insert is mounted on the at least one blade such that an entirety of the upper surface thereof is radially recessed to an outer diameter of the bit.
The drill bit of any of Embodiments 16 through 18, wherein the insert is mounted on the at least one blade at a rake angle in a range from about −15 degree to about 15 degrees.
The drill bit of any of Embodiments 16 through 19, wherein the bearing surface comprises at least one of a first bearing surface extending perpendicular to a longitudinal axis of the insert and a second bearing surface extending at an incline relative to the longitudinal axis of the insert, the longitudinal axis extending centrally through the elongated body and intersecting the upper surface and a lower surface of the insert.
While the disclosed structures and methods are susceptible to various modifications and alternative forms in implementation thereof, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the present disclosure is not limited to the particular forms disclosed. Rather, the present invention encompasses all modifications, combinations, equivalents, variations, and alternatives falling within the scope of the present disclosure as defined by the following appended claims and their legal equivalents.
This application is a national phase entry under 35 U.S.C. § 371 of International Patent Application PCT/US2018/053577, filed Sep. 28, 2018, designating the United States of America and published as International Patent Publication WO2019/068005 A1 on Apr. 4, 2019, which claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application Ser. No. 62/565,375, filed Sep. 29, 2017, the disclosure of which is hereby incorporated herein in its entirety by this reference. The subject matter of this application is also related to the subject matter of U.S. application Ser. No. 16/147,041, entitled “Earth-Boring Tools Having a Selectively Tailored Gauge Region for Reduced Bit Walk and Method of Drilling with Same” filed Sep. 28, 2018, now U.S. Pat. No. 11,060,357, issued Jul. 13, 2021. The subject matter of this application is also related to the subject matter of U.S. application Ser. No. 16/651,962, filed Mar. 27, 2020, entitled “Earth-boring Tools Having a Gauge Region Configured for Reduced Bit Walk and Method of Drilling with Same.”
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2018/053577 | 9/28/2018 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2019/068005 | 4/4/2019 | WO | A |
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|---|---|---|---|
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