Patent Grant
11060357
The present disclosure, in various embodiments, relates generally to earth-boring tools, such as drill bits, having radially and axially extending blades. Outer surfaces of the blades in a gauge region of the drill bits are shaped and topographically configured to limit side cutting of the bit while drilling a substantially straight portion of a borehole without limiting side cutting of the bit while drilling a curved (e.g., deviated) portion of the 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 bit body 12 of the drill bit 10 is typically secured to a hardened steel shank 18 having an American Petroleum Institute (API) thread connection for attaching the drill bit 10 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 10 within the borehole. Alternatively, the shank 18 of the drill bit 10 may be coupled directly to the drive shaft of a down-hole motor, which then may be used to rotate the drill bit 10, alone or in conjunction with a rotary table or top drive.
The bit body 12 of the drill bit 10 may be formed from steel. Alternatively, the bit body 12 may be formed from a particle-matrix composite material. Such bit bodies typically are 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. Drill bits that have a bit body formed from such a particle-matrix composite material may exhibit increased erosion and wear resistance relative to drill bits having steel bit bodies.
The process of drilling an earth formation may be visualized as a three-dimensional process, as the drill bit 10 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 drill bit 10 is rotated only by the motor drive shaft, and linear drilling when the drill bit 10 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 invention. The bottom hole assembly of the AutoTrak™ drilling system employs a non-rotating sleeve through which a rotating drive shaft extends to drive the drill bit 10, 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 10 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 drill bit 10 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 10 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 10, it is known that if a lateral force (indicated by arrow 28) is applied to the drill bit 10, the drill bit 10 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 10 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 drill bit 10 is mounted, and various design factors of the drill bit including the cutting element size, radial placement, back (or forward) rake, side rake, etc.
When lateral force 28 is applied to the drill bit 10 to steer or direct the drill bit 10 away from the linear path of the substantially vertical portion of the borehole, a gauge pad 22 located in a gauge region 20 of the drill bit 10 may engage a borehole sidewall and remove formation material. The ability of the drill bit 10 to cut the borehole sidewall as opposed to the bottom of the borehole is referred to in the art as “side cutting.” The amount of walk or drift may depend on the rate at which the drill bit 10 side cuts the borehole sidewall relative to an intended side cutting rate. The gauge region 20 of the drill bit 10 may also include a recessed region 24 adjacent to the gauge pad 22. By providing the recessed region 24 at the top of the gauge region 20 (e.g., adjacent to the shank 18 and distal from the face region 11 of the drill bit 10), the amount of contact between the gauge region 20 and the formation may be reduced, which enables the drill bit 10 to deviate from the vertical portion toward a substantially horizontal portion of the borehole over a shorter distance. As illustrated in
In some embodiments, a drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis and a blade 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. A gauge feature is provided on the blade in the gauge region. A first recessed region extends axially above the gauge feature and a second recessed region extends axially below the gauge feature. The gauge feature comprises an outermost surface extending radially beyond outer surfaces of the blade in the first and second recessed regions.
In other embodiments, a drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis and a blade 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. A gauge feature is provided on the blade in the gauge region adjacent a crown chamfer of the bit body. The gauge feature comprises an outermost surface of the gauge region extending radially beyond remaining outer surfaces of the gauge region. The remaining outer surfaces of the gauge region extend between the gauge feature and a gauge trimmer provided in the gauge region adjacent to the face region of the bit body.
In further embodiments, a drill bit for removing subterranean formation material in a borehole comprises a bit body comprising a longitudinal axis and a blade 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. A gauge feature is provided on the blade in the gauge region and a recessed region extending axially below the gauge feature. The gauge feature comprises an outermost surface extending radially beyond an outer surface of the blade in the recessed region. At least one of the outermost surface of the gauge feature and the outer surface of the blade in the recessed region is radially recessed relative to an outer diameter of the bit.
In yet other embodiments, a method of drilling a borehole in a subterranean formation comprises rotating a bit about a longitudinal axis thereof, engaging a subterranean formation with a plurality of cutting elements mounted to a face of the bit, and increasing a lateral force applied on the bit in a direction substantially perpendicular to the longitudinal axis such that radially outer surfaces of a blade in a gauge region of the bit engage the subterranean formation and such that side cutting exhibited by the bit is initially minimal and substantially constant and subsequently increases in a substantially linear manner with increasing lateral force.
In yet additional embodiments, a method of drilling a borehole in a subterranean formation comprises rotating a bit about a longitudinal axis thereof and engaging a subterranean formation with at least a portion of a gauge region of a blade of the bit. The gauge region comprises at least one recessed region comprising a radially outer surface of the blade and at least one gauge feature comprising a radially outermost surface extending radially beyond the radially outer surface of the blade in the at least one recessed region. The method further comprises increasing a tilt angle of the bit such that the radially outermost surface of the at least one gauge feature and the radially outer surface of the at least one recessed region are consecutively engaged with the subterranean formation with increasing tilt angle.
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, 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, directional terms, such as “above,” “below,” “up,” “down,” “upward,” “downward,” “top,” “bottom,” “upper,” “lower,” “top-most,” “bottom-most,” and the like, are to be interpreted relative to the earth-boring tool or a component thereof in the orientation of the figures.
As used herein, the terms “downhole” and “uphole” refer to locations on an earth-boring tool, such as a drill bit described herein, relative to a surface of the tool engaged with a bottom of a wellbore to remove formation material. Accordingly, an “uphole” portion of the tool is located closer to (e.g., proximate to, adjacent to) a shank of a bit or to an associated drilling string or bottom hole assembly as compared to a “downhole” portion that is located closer to a face of a bit in engagement with the bottom of the wellbore during a drilling operation.
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 “circumferential” or “circumferentially” refers to a direction with reference to a circumference (e.g., a periphery) of the drill bit described herein which may include, but is not limited to, an outer diameter of the drill bit.
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 a 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 used 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.
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. As previously described with reference to the conventional drill bit 10, the cutting elements 110 may comprise, for example, a polycrystalline compact in the form of a layer of hard polycrystalline material, also known 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 polycrystalline diamond material provided on a ceramic-metal composite material substrate, as is known in the art. Though the cutting elements 110 in the embodiment depicted in
At least one of the cutting elements 110 may be mounted within the gauge region 106 instead of on the face 108 of the bit 100. Such cutting elements are referred to in the art as gauge trimmers 114 as such a cutting element defines the outermost gauge dimension, or diameter, for the drill bit 100. The gauge trimmer 114 may be provided at a bottom 103 of the gauge region 106. The gauge trimmer 114 may comprise a cutting element having a linear cutting edge 115 aligned substantially parallel to the central axis 101 of drill bit 100. The linear cutting edges 115 of gauge trimmers 114 may be formed by grinding, milling, or otherwise removing at least a portion of a sharp cutting edge formed at the intersection of a planar cutting face and a peripheral side surface of the polycrystalline table. The gauge trimmers 114 may be mounted on the blades 104 and may be positioned at the furthermost radial distance from the central axis 101 of the bit 100 (e.g., the outer periphery of the drill bit 100) and the final diameter of the borehole being formed as a result of the drill bit 100 engaging, cutting, and removing formation material in the borehole. More particularly, the linear cutting edge 115 of the gauge trimmers 114 may be the radially outermost surface of the gauge trimmer 114, may define an outer diameter of the bit 100, and may define the final diameter of the borehole being formed as a result of the gauge trimmer 114 engaging, cutting, and removing formation material in the borehole. A dashed line is illustrated in
The gauge region 106 may be comprised of a gauge feature 112, a recessed region 116, and a transition region 120 therebetween. In some embodiments, the gauge feature 112 may comprise a radially outermost surface 118 positioned at the furthermost radial distance from the central axis of the bit 100 and, in conjunction with the gauge trimmers 114, may define the final diameter of the borehole being formed as a result of the gauge feature 112 engaging, cutting, and removing formation material in the borehole. Accordingly, the outermost surface 118 of the gauge feature 112 may be radially coextensive with (e.g., aligned with) the linear cutting edge 115 of the gauge trimmers 114. The outermost surface 118 may extend radially beyond any remaining outer surfaces of the blade 104, such as outer surfaces in recessed region 116 and transition region 120, extending between the gauge feature 112 and the gauge trimmer 114.
As illustrated in
The outermost surface 118 may have a sufficient amount of bearing surface area to contact a sidewall of the borehole so as to provide a bearing surface to generally distribute weight (e.g., force) applied by the formation against the bit 100, including lateral forces previously described herein. At low lateral forces, such as forces less than about 500 pounds (226.7 kg) depending at least upon the formation material and the compressive strength thereof and upon the size of the bit 100, the gauge feature 112 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 gauge feature 112 does not provide substantial side cutting action.
The recessed region 116 may occupy and define a majority of a surface area of the gauge region 106. Outer surfaces of the blade 104 within the recessed region 116 may be recessed (e.g., radially undersized) relative to the gauge feature 112 such that a surface 117 of the recessed region 116 does not extend to the outermost gauge dimension. The outermost surface 118 may extend radially beyond the surface 117 of the recessed region 116 by a distance d. In other words, the surface 117 of the recessed region 116 may be radially recessed relative to the outermost surface 118 by the distanced. In some embodiments, the distance d may be between about 0.02 inch (0.0508 cm) and 0.15 inch (0.381 cm).
As illustrated in
One or more of the outer surfaces of the blade 104 in the gauge region 106 may be provided with wear-resistant inserts 124 to inhibit excessive wear of the blades 104. The wear-resistant inserts 124 may comprise coatings, discs, bricks, or other inserts formed of wear-resistant material that may be coupled, bonded, at least partially embedded within, or otherwise attached to radially outer surfaces of the blades 104. The wear-resistant inserts 124 may comprise tungsten carbide, diamond grit-filled tungsten carbide, diamond-like carbon materials, polycrystalline diamond materials, thermally stable products such as thermally stable polycrystalline diamond, hardfacing materials, and other abrasion-resistant materials. As illustrated in
While side cutting may be undesirable at low lateral forces as previously described, side cutting may be desirable at greater side loads. 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 of the line 128 is referred to as the “linear region.” 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 of the line 128 is referred to as the “cap region.” In view of the foregoing, outer surfaces of the blades 104 in a gauge region 106 of the drill bit 100 may be shaped and topographically configured 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, the amount of side cutting performed by the gauge region 106 of the blade 104 may be at least partially a function of the surface area of the gauge region 106 in contact with the formation material at a given lateral force. Therefore, according to embodiments of the present disclosure, the drill bit 100 and, more particularly, the gauge region 106 and other gauge regions described herein are designed and topographically configured to selectively control the surface area of the gauge region 106 in contact with the sidewall of the borehole as a function of bit tilt angle of the bit 100 and/or lateral force applied to the bit 100. As used herein, the term “bit tilt angle” refers to an angle measured between the central axis 101 of the bit 100 and a borehole axis extending centrally through the borehole. As the drill bit 100 is operated to form the straight portion of the borehole, the drill bit 100 is generally oriented such that the central axis 101 of the bit 100 is substantially coaxial with the borehole axis. The bit tilt angle of the bit 100 may be at least partially a function of the lateral force applied to the bit 100 such that as the amount of lateral force applied to the bit 100 increases, the bit tilt angle of the bit 100 increases correspondingly. When the bit tilt angle is zero (e.g., when the central axis 101 is substantially coaxial with the borehole axis), the gauge region 106 and, more particularly, the gauge feature 112 may or 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 may come into contact with the borehole sidewall and remove formation material when sufficient lateral force is applied. The gauge region 106 of bit 100 may be designed such that the anticipated surface area 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.
Comparing line 127 to line 129, the surface area of the gauge region 20 in contact with the formation material increases rapidly as the bit tilt angle begins to increase while the surface area of the gauge region 106 in contact with the formation material remains minimal and substantially constant. While the surface area of the gauge region 106 subsequently increases at greater bit tilt angles, the surface area of the gauge region 106 in contact with the formation material may remain less than the surface area of the gauge region 20 in contact with the formation until the bit tilt angle is sufficiently high that substantially all of the surface area of the gauge region 106 is in contact with the formation.
Further, the surface area of outer surfaces of the blade 104 in the transition region 120 and the recessed region 116 may be selectively controlled such that as the bit tilt angle increases with applications of moderate lateral forces and/or high lateral forces as previously described with regard to the linear region and cap region of the line 128 of
With regard to the surface area and/or shape of the transition region 120, in some embodiments, the transition region 120 may be tapered relative to the central axis 101 of bit 100 as illustrated in
With regard to the cutting edge geometry of gauge region 106, the size and/or shape of the gauge features may be selected to adjust the aggressiveness with which the gauge region 106 side cuts the borehole sidewall. As used herein, the aggressiveness of the gauge region 106 refers to the relative volume of earth formation material being removed by the engagement of the gauge region 106 of the blade 104 with formation material on each rotation of the bit 100 as a function of force applied on the bit 100. Further, the size and/or shape of the gauge features may be selected to adjust the size of the insensitive region of the line 128 as previously explained with reference to
In each of the foregoing embodiments described with reference to
In some embodiments, the gauge feature 148 may comprise a radially outermost surface 152 defining the full diameter of the bit. The gauge feature 148 may further comprise a raised surface 154 extending radially outward beyond a recessed surface 156 of the recessed region 150. As illustrated in the profile view of
At the top of the gauge region 144, the gauge feature 148 may have a width coextensive with the width of the blade 104. The gauge feature 148 may taper in width as the gauge feature 148 extends along the length of the gauge region 144. Accordingly, the recessed region 150 may increase in width as the gauge feature 148 extends along the length of the gauge region 144. A boundary 158 between the gauge feature 148 and the recessed region 150 as the gauge feature 148 and the recessed region 150 extend side-by-side along the length of the gauge region 144 may be linear and/or curved.
In each of the foregoing embodiments described with reference to
With continued reference to
The recessed regions 165, 166 may be substantial similar to the recessed region 116 previously described with reference to
As further illustrated in
In some embodiments, the cutting element 196 may comprise a radially outermost surface that may be substantially radially coextensive with the radially outermost surface 198 of the gauge feature 192 such that the cutting element 196 does not extend radially beyond the radially outermost surface 198 of the gauge feature 192. In other embodiments, the radially outermost surface 198 of the cutting element 196 may be radially recessed relative to the radially outermost surface 198 of the gauge feature 192 or may extend radially beyond the radially outermost surface 198 of the gauge feature 192. The radially outermost surface of the cutting element 196 may be defined by the linear cutting edge 197 or one chamfer of a multi-chamfer cutting element.
While transition regions of gauge regions previously described here may have been described or illustrated as having a constant taper, the taper of the transition regions is not so limited. As illustrated in
While radially outer surfaces of gauge features previously described herein may have been described as defining or as extending to the outer diameter of the bit 100, the radial extension of the radially outermost surfaces of the gauge features previously described herein is not so limited. In some embodiments, the radially outer surfaces of gauge features as described herein may be radially recessed relative to the outer diameter of the bit 100. As illustrated in
While gauge features of gauge regions previously described herein may have been previously described such that the gauge regions comprise a single gauge feature, the gauge regions as previously described herein are not so limited. As illustrated in
The gauge feature 302 may taper in length as the gauge feature 302 extends circumferentially between the rotationally leading edge 306 and the rotationally trailing edge 308 of the blade 104. As illustrated in
At least one cutting element 314 may be mounted on the gauge feature 302. In some embodiments, the gauge feature 302 may include two cutting elements 314. One of the cutting elements 314 may be located proximate to the rotationally leading edge 306 while the other cutting element 314 may be located proximate to the rotationally trailing edge 308.
The cutting elements 314 may be mounted in pockets formed in the blade 104. The cutting elements 314 may be mounted at a high back rake angle such as a back rake angle in a range from about 85 degrees to about 90 degrees or from about 87 degrees to about 90 degrees. In some embodiments, the cutting elements 314 may be mounted in the pockets such that a radially outermost surface 316 thereof is substantially radially coextensive with the radially outermost surface 304 of the gauge feature 302. Put differently, the cutting elements 314 may be mounted in pockets such that the radially outermost surface 316 thereof (e.g., a cutting face) does not extend radially beyond the radially outermost surface 316 of the gauge feature 302. The cutting elements 314 may comprise polycrystalline diamond compact (PDC) cutting elements each including a volume of polycrystalline diamond material provided on a ceramic-metal composite material substrate.
In some embodiments, the cutting face of the cutting elements 314 may be substantially planar. In other embodiments, the cutting face of the cutting element 314 may include an arcuate (e.g., curved surface). In such embodiments, the cutting face may be ground such that the cutting face of the cutting element 312 has a curvature substantially the same as the curvature of the blade 104 in the gauge region 300.
The gauge region 300 may further comprise a recessed region 318 located axially below the gauge feature 302. An outer surface 320 of the blade 104 in the recessed region 318 may be recessed relative to the radially outermost surface 304 of the gauge feature 302 and to the outer diameter of the bit 100. The outer surface 320 may be recessed relative to the outer diameter of the bit 100 by a radial distance in a range extending from about 0.005 inch (0.127 mm) to about 0.360 inch (9.144 mm), from about 0.010 inch (0.254 mm) to about 0.180 inch (4.572 mm), or from about 0.030 inch (0.762 mm) to about 0.090 inch (4.572 mm) and, more particularly, by about 0.090 inch (2.286 mm).
A transition region 322 may extend axially and radially between the gauge feature 302 and the recessed region 318. In some embodiments, the transition region 322 may extend helically as the gauge feature 302 tapers in length as the gauge feature 302 extends circumferentially between the rotationally leading edge 306 and the rotationally trailing edge 308.
As best illustrated in the side cross-sectional view of the blade 104 in
The gauge feature 332 may taper in length as the gauge feature 332 extends circumferentially between the rotationally leading edge 340 and the rotationally trailing edge 342 of the blade 104. As illustrated in
The gauge feature 332 may have cutting elements 314 mounted therein as described with reference to
A first transition region 348 may extend axially and radially between the gauge feature 332 and the first recessed region 334, and a second transition region 349 may extend axially and radially the gauge feature 332 and the second recessed region 336. In some embodiments, the second transition region 349 may extend helically and the first transition region 348 may extend substantially straight as the gauge feature 332 tapers in length as the gauge feature 332 extends circumferentially between the rotationally leading edge 340 and the rotationally trailing edge 342.
As best illustrated in the side cross-sectional view of the blade 104 in
In the foregoing embodiments, the gauge features may be fixed to the blade 104 such that the gauge features are stationary. In such embodiments, the gauge features, the recessed regions, and/or the transition regions may be integrally formed with the bit body such that the gauge features, the recessed regions, and/or the transition regions form part of the blade 104 in the gauge region. In other embodiments, one or more elements of the gauge features may be separately formed and coupled to the blade 104. In yet further embodiments, one or more elements of the gauge features may be moveable.
The lower retaining member 354 may comprise a cavity 364 in which a damping element 366 may be disposed. The damping element 366 may comprise one or more springs, a fluid, and/or an elastically deformable material such as rubber. The damping element 366 may be provided between a base of the cavity 364 and a support plate 368. The support plate 368 may comprise a recess 367 sized and shaped to abut against an outer surface of the rolling element 358 without hindering rotation thereof. The rolling element 358 may be rotatable about any of the three rotational axes such that the rolling element 358 exhibits three rotational degrees of freedom.
In some embodiments, a lubricant chamber 374 may be provided within the bit body 102 and may be filled with a lubricating. The lubricant chamber 374 may be provided with a plug 376 shown in an uninstalled position in
In addition, the rolling element 358 may be translatable along an axis extending centrally through the aperture 360 of the upper retaining member such that the rolling element 358 may exhibit one translational degree of freedom. Accordingly, the rolling element 358, which may define a radially outermost surface along the gauge region 350, may be adjustable between an extended position and a retracted position. As illustrated in
A drill bit having a gauge region configuration 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 having gauge region configurations according to any of the foregoing embodiments may exhibit the amount of side-cutting as a function of increasing lateral force and/or the surface area engagement as a function of bit tilt angle 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 comprising a bit body comprising a longitudinal axis, a blade 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, a gauge feature provided in the gauge region of the blade, and a recessed region extending axially below the gauge feature in the gauge region of the blade. The gauge feature comprises an outermost surface extending radially beyond an outer surface of the blade in the recessed region. At least one of the outermost surface of the gauge feature and the outer surface of the blade in the recessed region is radially recessed relative to an outer diameter of the bit.
The drill bit of Embodiment 1, wherein each of the outermost surface of the gauge feature and the outer surface of the blade in the recessed region is radially recessed relative to the outer diameter of the bit.
The drill bit of either of Embodiments 1 or 2, wherein a radial distance by which at least one of the outermost surface of the gauge feature and the outer surface of the blade in the recessed region is in a range extending from about 0.005 inch (0.127 mm) to about 0.020 inch (0.508 mm).
The drill bit of either of any Embodiments 1 through 3, further comprising a cutting element mounted on the gauge feature.
The drill bit of either of Embodiments 1 through 4, wherein the cutting element is mounted at a back rake angle in a range extending from about 87 degrees to about 90 degrees.
The drill bit of either of Embodiments 1 through 5, wherein a radially outermost surface of the cutting element is coextensive with the radially outermost surface of the gauge feature.
The drill bit of either of Embodiments 1 through 6, wherein the gauge feature extends from a rotationally leading edge to a rotationally trailing edge of the blade such that a width of the gauge feature is coextensive with a width of the blade.
The drill bit of either of Embodiments 1 through 7, wherein a radial extension of the radially outermost surface of the gauge feature relative to the longitudinal axis is substantially constant as the gauge feature extends between a rotationally leading edge and a rotationally trailing edge of the blade.
The drill bit of either of Embodiments 1 through 8, wherein a length of the gauge feature measured in a directional parallel to the longitudinal axis of the bit tapers between the rotationally leading edge and the rotationally trailing edge of the blade.
The drill bit of either of Embodiments 1 through 9, wherein the outer surface of the gauge feature is recessed relative to the outer diameter of the bit by a radial distance in a range of from about 0.010 inch (0.254 mm) to about 0.180 inch (4.572 mm).
A directional drilling system comprising a steerable bottom hole assembly operably coupled to the drill bit of any of Embodiments 1 through 10.
A drill bit for removing subterranean formation material in a borehole comprising a bit body comprising a longitudinal axis, a blade extending radially outward from the longitudinal axis along a face region of the tool body and extending axially along a gauge region of the bit body, a gauge feature in the gauge region of the blade, a first recessed region extending axially above the gauge feature, and a second recessed region extending axially below the gauge feature. The gauge feature comprises a radially outermost surface extending radially beyond outer surfaces of the blade in the first and second recessed regions.
The drill bit of Embodiment 12, wherein at least one of the outermost surface of the gauge feature, the outer surface of the blade in the first recessed region, and the outer surface of the blade in the second recessed region is radially recessed relative to an outer diameter of the drill bit.
The drill bit of Embodiments 12 or 13, wherein each of the outermost surface of the gauge feature, the outer surface of the blade in the first recessed region, and the outer surface of the blade in the second recessed region is radially recessed relative to the outer diameter of the drill bit.
The drill bit of either of Embodiments 12 through 14, further comprising a cutting element or a wear-resistant insert mounted thereon.
A method of drilling a borehole in a subterranean formation comprising rotating a bit about a longitudinal axis thereof, engaging a subterranean formation with at least a portion of a gauge region of a blade of the bit. The gauge region comprises a recessed region comprising a radially outer surface of the blade and a gauge feature comprising a radially outermost surface extending radially beyond the radially outer surface of the blade in the at least one recessed region. The method further includes increasing a tilt angle of the bit such that the radially outermost surface of the gauge feature and the radially outer surface of the recessed region are consecutively engaged with the subterranean formation with increasing tilt angle.
The method of Embodiment 16, wherein increasing the tilt angle of the bit comprises increasing a lateral force applied on the bit in a direction substantially perpendicular to the longitudinal axis such that the gauge feature engages the subterranean formation and such that side cutting exhibited by the bit is initially minimal and substantially constant and subsequently increases in a substantially linear manner with increasing lateral force.
The method of Embodiment 17, wherein increasing the lateral force applied on the bit such that side cutting exhibited by the bit is initially minimal and substantially constant comprises maintaining a substantially constant surface area of the gauge feature in contact with the subterranean formation with increasing applied lateral force.
The method of any of Embodiments 17 or 18, wherein increasing the lateral force applied on the bit such that side cutting exhibited by the bit is substantially linear manner with increasing lateral force comprises increasing a surface area of the gauge region in contact with the subterranean formation with increasing applied lateral force.
The method of any of Embodiments 16 through 19, further comprising increasing a lateral force applied on the bit in a direction substantially perpendicular to the longitudinal axis such that side cutting exhibited by the bit is subsequently maximized and substantially constant after increasing side cutting exhibited by the bit in the substantially linear manner.
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 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 PCT Application Serial No. PCT/US2018/053571, entitled “Earth-boring Tools Having a Gauge Region Configured for Reduced Bit Walk and Method of Drilling with Same,” filed Sep. 28, 2018. The subject matter of this application is also related to the subject matter of PCT Application Serial No. PCT/US2018/053577, filed Sep. 28, 2018 and titled “Earth-Boring Tools Having a Gauge Insert Configured for Reduced Bit Walk and Method of Drilling with Same.”
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