EP3775467A1

EP3775467A1 - Borehole cross-section steering

Info

Publication number: EP3775467A1
Application number: EP19777204.9A
Authority: EP
Inventors: Geoffrey Charles Downton; Jonathan Marshall; Scott Richard WOOLSTON
Original assignee: Novatek IP LLC
Current assignee: Novatek IP LLC
Priority date: 2018-03-26
Filing date: 2019-03-26
Publication date: 2021-02-17
Also published as: SA520420206B1; EP3775467A4; CN112020594A; RU2020133524A; RU2771307C2; WO2019191013A1; RU2020133524A3; CA3095123A1

Abstract

A drill bit forming a borehole in the earth may be urged sideways, creating a curve in the borehole, by a cross-sectional shape of the borehole. For example, a borehole with a cross-sectional shape comprising two circular arcs of distinct radii, one larger and one smaller than a gauge of the drill bit, may push the drill bit away from the smaller circular arc and into the larger circular arc. Forming a borehole with such circular arcs may be accomplished by extending a cutting element from a side of the drill bit for only a portion of a full rotation of the drill bit. The radii and angular ranges occupied by these circular arcs may be adjusted by altering the timing of extension and retraction of the extendable cutting element.

Description

BOREHOLE CROSS-SECTION STEERING

BACKGROUND

This application is related to U.S. Patent Application Nos. 15/935,316, filed on 26 March 2018; 15/944,605, filed 3 Apr 2018; 16/217,019, filed 11 Dec 2018; 16/216,966, filed 11 Dec 2018; 16/216,999, filed 11 Dec 2018; 16/279,168, filed 19 Feb 2019; and 16/284,275, filed 25

Feb 2019, which are herein incorporated by reference in its entirety.

When exploring for or extracting subterranean resources, such as oil, gas, or geothermal energy, and in similar endeavors, it is common to form boreholes in the earth. Such boreholes may be formed by engaging the earth with a rotating drill bit capable of degrading tough subterranean materials. As rotation continues the borehole may elongate and the drill bit may be fed into it on the end of a drill string.

At times it may be desirable to alter a direction of travel of a drill bit from a path it might naturally take through the earth as it is forming a borehole. This may be to steer it toward valuable resources or away from obstacles, or merely to keep the drill bit from veering off course. A variety of techniques have been developed to accomplish such steering. Many known drill bit steering techniques require pushing against an interior surface of a borehole. One such technique comprises pushing off an interior wall of a borehole with a radially extendable pad. This pushing may urge the drill bit laterally into the interior wall opposite from the pad.

Extension of the pad may be timed in coordination with rotation of the drill bit to effect consistent steering. This pushing often requires great amounts of energy to be expended downhole. Further, the amount of energy required may increase as a desired radius of curvature of the borehole decreases. Thus, a means for forming a curving borehole, and especially a curving borehole comprising a relatively small radius of curvature, while expending less energy downhole and prolonging a useful life of a tool may prove valuable.

Extension of the pad may be accomplished via hydraulic pressure within a piston. A typical piston may slide within a hollow cylinder to alter a contained volume therein. Such a piston-cylinder combination may form a type of transducer capable of converting energy between fluid pressure and mechanical motion. For example, in an engine, energy in the form of expanding gas enclosed within a cylinder may be transferred to a piston causing it to slide. In a pump, this function may be reversed with force from the piston compressing fluid within the cylinder.

In some instances, it may be desirable to define a maximum distance, known as a "stroke length," that a piston can travel within a cylinder. This may be done in a variety of ways. For example, U.S. Patent No. 9,085,941 to Hall, et al. describes a pin that may be inserted into a passageway in a piston. While the piston is translating, the passageway may come into contact with the pin to inhibit further translational movement of the piston. The pin may be configured to allow the piston to translate a specified distance.

Other devices may not only define a stroke length for a piston but also allow for adjustment of that stroke length. U.S. Patent No. 7,409,901 to Lucas, et al. describes how a piston stroke length may be adjusted manually via various mechanical means, such as, for example, by adjusting the throw of an eccentric lobe that rotates to drive the piston, or by adjusting swivels, cams, or linkages. While such means may achieve their intended functions, adjusting a piston's stroke length by simpler processes may prove valuable.

In Figure 1, an embodiment of a drill bit 110 is shown suspended from a derrick 112 by a drill string 114. While a land-based derrick is shown, water-based structures are also common. Such a drill string may be formed from a plurality of drill pipe sections fastened together end-to- end or, in other embodiments, a flexible tubing may be used. As the drill bit 110 is rotated, either from the derrick 112 or by a downhole motor, it may engage and degrade a subterranean formation 116 to form a borehole 118 therethrough. Drilling fluid may be passed along the drill string 114 and expelled at the drill bit 110 to cool and lubricate the drill bit 110 as well as carry loose debris to a surface of the borehole 118 through an annulus surrounding the drill string 114.

At times it may be desirable to take measurements or perform various functions within a borehole while drilling is in progress. It is believed that certain measurements and functions are most effective when taken or performed as close as possible to an end of a drill string, or on a drill bit itself. However, such drill bits often experience significant wear and damage while drilling, due to the harsh conditions experienced during drilling. Worn or damaged drill bits often require replacement which can be expensive and time consuming. Instrumenting drill bits to take measurements or perform functions may significantly add to replacement expense and complexity. One of the more complex aspects of instrumenting such a drill bit is providing a mechanism for communicating back and forth across the connection between the drill bit and the drill string. Such connections are typically made by threading a drill bit to a drill string amid an often dirty and hectic drilling operation. Given the disorder of such conditions it may be difficult to certify the final positions, either rotationally or axially, of the drill bit relative to the drill string. Any communication mechanism spanning such a connection must be robust and functional regardless of orientation.

Another feature adding complexity to drill bit instrumentation is the externally-threaded protrusions and the internally-threaded cavities that commonly form either side of the

connection. In particular, passing communications into a cavity may be difficult as access may be restricted by space constraints. Thus, a mechanism capable of passing communications across a drill-string-to-drill-bit connection independent of specific rotational orientation while providing access inside a threaded cavity may prove useful in instrumenting a drill bit.

BRIEF DESCRIPTION

One technique for controlling a direction of travel of a drill bit as it forms a borehole through the earth may be to give the borehole a cross-sectional shape that urges the drill bit laterally. Much energy may be saved in this manner as the borehole does the urging, rather than a drilling tool. A borehole capable of urging a drill bit laterally may have a cross-sectional shape comprising two circular arcs, one with a larger radius and one with a smaller radius than that of a drilling tool passing through the borehole. The drilling tool may be pushed away from the smaller circular arc and into the open space provided by the larger circular arc. This lateral pushing may add a curve to the borehole as it is formed having a center of curvature closer to the larger circular arc than the smaller circular arc.

These two circular arcs, while centered at a common axis of the borehole, may each occupy a distinct angular range about this axis. A sharpness of the curve imparted to the borehole as it is formed may depend on the relative radii and angular sizes of the two circular arcs. Thus, the drill bit may be precisely steered by changing these relative radii and angular sizes and the rotational orientations of the two circular arcs at different positions along the length of the borehole. Producing these two circular arcs may be accomplished by first rotating a drilling tool to bore a hole through the earth and then extending a cutting element from a side of the drilling tool during only a portion of its rotation. While extended, this cutting element may remove additional earthen material from an internal surface of the borehole to form a first of the circular arcs. While retracted, a second circular arc may be formed. Adjusting the relative radii, angular sizes and rotational orientations of these two circular arcs as the borehole is formed, to steer the drilling tool, may be achieved by altering the timing of the extension and retraction.

A steerable downhole tool may alter a direction of travel of a drill bit while drilling into the earth by extending a rod from openings disposed in a side of the tool. The rod may slide within a cavity, spanning a width of the tool, passing from one of the openings to another and extending from various openings at various times.

The rod may degrade material from an internal surface of a borehole in which the drill bit is traveling, by engaging the surface with cutter elements exposed on opposing tips of the rod. A stabilizer, protruding from the side of the tool, may then push off of the borehole wall opposite from the area of degradation to drive the drill bit into the degraded region.

For example, while the tool is rotating within the borehole, the rod may be extended from a first of the openings. With the rod extended, the tool may be rotated about an axis thereof to degrade a portion of the borehole. After a certain amount of rotation, roughly one-half of a full rotation in some embodiments, the rod may be retracted to a neutral position within the tool. The tool may continue to rotate until a second of the openings is adjacent to the area where the rod was initially extended. At this point, the rod may be extended from the second opening and the tool may be rotated another roughly one-half rotation to continue degradation of the same area.

In another embodiment, a drill bit may be rotated to form a borehole through the earth. Such a drill bit may comprise fixed cutting elements, capable of degrading subterranean materials, protruding from an exterior of a body. These fixed cutting elements may be spaced at a constant radius from a rotational axis of the body to form an initially cylindrical borehole.

The body may also comprise at least one rotatable cutting element protruding from its exterior. To remove earthen material from an internal wall of the borehole, the rotatable cutting element may be positioned in a first rotational orientation wherein it may extend radially beyond the constant radius of the fixed cutting elements. To stop removing material from the borehole wall, the rotatable cutting element may be positioned in a second rotational orientation wherein it may remain radially within the constant radius.

Rotation of the rotatable cutting element may be synchronized with rotation of the drill bit to provide consistent removal in certain angular sections of the borehole. By altering material removal in these angular sections various borehole cross-sectional shapes may be formed.

Specifically, a borehole may be provided with a smaller internal radius at some angular positions that may urge the drill bit laterally into other angular positions comprising a larger internal radius to steer the drill bit.

In another embodiment, an apparatus may comprise an axial body, such as that of a drill bit or stabilizer. One or more extendable cutting elements may be extendable in a single radial direction from an exterior of the body as the body rotates within a borehole. Extension of the cutting elements may allow them to engage and degrade an inner wall of the borehole. By timing these extensions various cross-sectional shapes may be created.

An abrasion-resistant gauge pad, protruding from the exterior of the body, may ride against the borehole wall without rapidly wearing the gauge pad or significantly damaging the borehole. Riding against the borehole wall provided with the cross-sectional shape described earlier may urge the body radially.

A piston's stroke length may be defined by a rod passing through a through hole in the piston, restricting the piston's motion, and altered by adjusting the rod. In some embodiments, this rod may comprise a noncylindrical external geometry that may interact with an interior of the piston's through hole. A radius of this noncylindrical external geometry may vary along an axial length of the rod or around a circumference thereof. Adjustment of the rod, via axial translation or rotation for example, may change a point of contact between the rod's external geometry and the through hole's interior and adjust possible stroke lengths. Alternately, the through hole may comprise a unique geometry in which the rod may radially translate to adjust the piston's stroke length.

A drill bit assembly may comprise a chassis, separate from a drill bit, housed within a cavity of the drill bit. A drill string may be secured to the drill bit and retain the chassis within the cavity. The chassis may comprise two pairs of interfacing exchange surfaces, a first pair disposed between the chassis and the drill string and a second pair disposed between the chassis and the drill bit. Both of the first pair of interfacing exchange surfaces are annular in shape and fixed together independent of rotational orientation. The second pair of interfacing exchange surfaces are fixed together in a specific rotational orientation. These pairs of interfacing exchange surfaces may allow for various types of signals, such as electrical, hydraulic, optical or electromagnetic for example, to be exchanged and passed through the chassis or to electronics disposed on the chassis. These electronics may be disposed on an exterior of the chassis and contained within at least one pressure chamber formed between the exterior of the chassis and an interior of the drill bit. In such a configuration, instrumentation may be removed from one drill bit and inserted into another, and thus reused, when one drill bit becomes worn or damaged.

A downhole drilling assembly may comprise a sub secured between a drill string and a drill bit. This sub may comprise a cavity formed therein and a chassis may be housed within the cavity. The drill bit may also comprise a cavity formed therein and an extender may be housed within this cavity. This extender may contact the drill bit at a base of this cavity and extend to within two inches of a mouth of the cavity. This extender may provide access for various types of communication to reach into the drill bit's cavity.

Several pairs of interfacing exchange surfaces may allow for communication (e.g.

passing electrical, hydraulic, optical or electromagnetic signals) between these various elements. One pair of interfacing exchange surfaces, between the drill string and the chassis, may allow for communication regardless of relative rotational orientation. Two other pairs of interfacing exchange surfaces, one between the chassis and the extender and another between the extender and the drill bit, may require a specific rotational orientation for communication.

The first pair of interfacing exchange surfaces may allow for communication regardless of rotational orientation. Meanwhile, the extender may allow for access within the cavity of the drill bit. The combination may allow for measurements to be taken or functions to be performed on the drill bit.

DRAWINGS

Figure 1 is an orthogonal view of an embodiment of a subterranean drilling operation. Figure 2 is a perspective view of an embodiment of a drill bit attached to an end of a drill string.

Figures 3-1 through 3-4 are cross-sectional views of embodiments of drilling tools disposed within non-circular subterranean boreholes. Figures 4-1 through 4-4 are cross-sectional views of additional embodiments of drilling tools disposed within non-circular subterranean boreholes.

Figure 5 is an orthogonal view of an embodiment of a non-circular subterranean borehole.

Figures 6 and 7 are perspective and longitude-sectional views, respectively, of embodiments of steerable downhole drill bits.

Figure 8 is a longitude-sectional view of an embodiment of a steerable downhole drill pipe section comprising an interchangeable stabilizer.

Figure 9 is a cross-sectional view of an embodiment of a steerable downhole tool comprising a locking mechanism.

Figures 9-1 and 9-2 are orthogonal views of embodiments of slidable rods of various geometries.

Figures 10-1 through 10-4 are orthogonal views of embodiments of drill bits in boreholes, each representing one step of a method for steering a downhole tool.

Figure 11 is a sectional view of an embodiment of a piston slidably disposed within a hollow cylinder and a rod passing through a through hole in the piston, restricting a stroke thereof.

Figures 12-1 and 12-2 are sectional views of embodiments of pistons comprising adjustable rods passing therethrough capable of altering stroke restrictions of each piston.

Figure 12-3 is a perspective view of an embodiment of a rod of the type shown in Figures 12-1 and 12-2.

Figures 13-1 and 13-2 are sectional views of additional embodiments of pistons comprising adjustable rods passing therethrough. Figure 13-3 is a perspective view of an embodiment of a rod of the type shown in Figures 13-1 and 13-2.

Figure 14 is an orthogonal view of another embodiment of a piston and rod combination.

Figure 15 is a perspective view of an embodiment of a drill bit that may form part of a subterranean drilling operation.

Figures 16-1 and 16-2 are orthogonal views of embodiments of a drill bit comprising a rotatable cutting element, shown in magnified view, in different rotational orientations.

Figures 17-1 and 17-2 are orthogonal views of embodiments of rotatable cutting elements in different rotational orientations. Figures 18-1 and 18-2 are perspective views of embodiments of a drill bit comprising a rotatable cutting element rotatable by means of a torque-generating apparatus comprising a rack and pinion gear configuration.

Figures 19-1 and 19-2 are perspective views of embodiments of a rotatable cutting element rotatable by means of a torque-generating apparatus comprising a worm gear configuration.

Figures 20-1 and 20-2 are perspective views of embodiments of a rotatable cutting element rotatable by means of a torque-generating apparatus, capable of contacting an external formation, and limited by a braking apparatus.

Figure 21 is an orthogonal view of an embodiment of multiple rotatable cutting elements all rotatable by means of a single torque-generating apparatus.

Figure 22 is a perspective view of an embodiment of a drill bit that may form part of a subterranean drilling operation.

Figure 23 is a longitude-sectional view of another embodiment of a drill bit.

Figure 24-1 is a perspective view of an embodiment of a piston comprising a plate of superhard material. Figure 24-2 is a perspective view of an embodiment of a piston comprising a plurality of cutting elements.

Figure 25-1 and 25-3 are perspective views of embodiments of drill bits comprising cutting elements extendable via rotation of a hinged arm. Figure 25-2 is a perspective view of an embodiment of a hinged arm.

Figure 26-1 and 26-3 are perspective views of embodiments of drill bits comprising cutting elements extendable via rotation of a cylindrical drum. Figure 26-2 is a perspective view of an embodiment of a cylindrical drum.

Figure 27 is a longitude-sectional view of an embodiment of a drill bit comprising an extendable push pad positioned opposite from extendable cutting elements.

Figures 28-1 through 28-3 are perspective views of embodiments of gauge pads.

Figures 28-4 and 28-5 are perspective views of embodiments of abrasion-resistant devices.

Figure 29 is a perspective view of another embodiment of a drill bit.

Figure 30 is a perspective view of an embodiment of a stabilizer.

Figure 31 is a perspective view of an embodiment of drill bit assembly.

Figure 32 is a perspective view of an embodiment of a disassembled drill bit assembly. Figure 32-1 is a perspective view of an embodiment of an interchangeable plate.

Figure 33 is a longitude-sectional view of an embodiment of drill bit assembly.

Figures 34-1 and 34-2 are perspective views of embodiments of chassis.

Figure 35 is a longitude-sectional view of an embodiment of a downhole drilling assembly that may form part of a subterranean drilling operation.

Figures 36-1 and 36-2 are perspective views of additional embodiments of downhole drilling assemblies.

Figure 37 is a perspective view of an embodiment of a rotationally-independent pair of interfacing exchange surfaces.

Figure 38 is a perspective view of an embodiment of a rotationally-specific pair of interfacing exchange surfaces.

DETAILED DESCRIPTION

Referring now to the figures, Figure 2 shows an embodiment of a drill bit 210 secured to an end of a drill string 214 that may form part of a subterranean drilling operation of the type just described. A plurality of blades 220 may protrude from the drill bit 210, spaced around a rotational axis thereof. Each of the blades 220 may comprise a plurality of fixed cutters 221 secured thereto capable of degrading earthen materials. As the drill bit 210 rotates, these cutters 221 may form a long hollow borehole through the earth. Such a borehole may comprise an initial radius determined by spacing between the fixed cutters 221 and a rotational axis of the drill bit 210.

At least one cutting element 222, also capable of degrading the earth, may be extendable from a side of the drill bit 210 (or another downhole tool in alternate embodiments). This extendable cutting element 222 may scrape earthen material away from an internal wall of a borehole initially formed by the fixed cutters 221. When extended, the extendable cutting element 222 may enlarge the radius of the borehole, from its initial size, in certain areas.

Figure 3-1 shows an embodiment of a drill bit 310-1 disposed within an elongate hollow borehole 318-1 formed in the earth 316-1. The borehole 318-1 may comprise a central axis 335-1 passing therethrough and a cross-sectional shape formed within a plane perpendicular to the axis 335-1. A plurality of fixed cutters 321-1, capable of degrading the earth 316-1, may be disposed on the drill bit 310-1. These fixed cutters 321-1 may be spaced about the axis 335-1 to form an initially cylindrical borehole with a constant radius as the drill bit 310-1 is rotated.

An extendable cutting element 322-1 may be extended from a side of the drill bit 310-1 to expand this initial borehole radius by removing additional earthen material from an internal wall of the borehole 318-1. This extendable cutting element 322-1 may be extended for only a fraction of a full rotation of the drill bit 310-1, before being retracted, such that this larger borehole radius is only present in an angular range of the borehole 318-1. Through this technique the borehole 318-1 may acquire a cross-sectional shape comprising two different circular arcs, each with a uniquely sized radius. In particular, a first circular arc 330-1, centered at the axis 335-1, may comprise a first radius 331-1, while a second circular arc 332-1, centered at the same axis 335-1, may comprise a second radius 333-1, smaller than the first radius 331-1.

Figure 3-2 shows an embodiment of drilling tool 310-2 disposed within a non-circular borehole 318-2, similar to that shown in Figure 3-1. The drilling tool 310-2 may comprise a cross section with a radius 334-2 that is smaller than the first radius 331-1, shown in Figure 3-1, that was formed by extension of the extendable cutting element 322-1. This drilling tool 310-2 cross-sectional radius 334-2 may also be larger than the second radius 333-1 of Figure 3-1 that was formed by the fixed cutters 321-1 of the drill bit 310-1. The drilling tool 310-2, in fact, may not fit through a borehole formed exclusively by the fixed cutters 321-1 without the enlargement created by the extendable cutting element 322-1. This sizing mismatch may constantly, and with little energy exerted by the drilling tool 310-2, urge the drilling tool 310-2 laterally (as indicated by arrow 340-2) as the smaller second radius 333-1 pushes the drilling tool 310-2 into space created by the larger first radius 331-1.

Also due to this size discrepancy, the drilling tool 310-2 may contact an internal wall of the borehole 318-2 generally at two points 336-2 and 337-2 of the cross section shown. These two points 336-2, 337-2 may be located on the smaller second radius 333-1. Limiting contact generally to two points may reduce friction between the drilling tool 310-2 and the

borehole 318-2.

Figure 3-3 shows an embodiment of a drilling tool 310-3 disposed within a non-circular borehole 318-3. In this embodiment, a first angular range 338-3 occupied by a first circular arc 330-3, forming part of a cross-sectional shape of the borehole 318-3, is larger than a second angular range 339-3 occupied by a second circular arc 332-3. The relative dimensions of these first and second angular ranges 338-3, 339-3 may be determined and adjusted by altering the timing of extension and retraction of an extendable cutting element as described in relation to Figure 3-1.

Figure 3-4 shows another embodiment of a drilling tool 310-4 disposed within a non-circular borehole 318-4. In this embodiment, first and second angular ranges 338-4, 339-4, occupied by first and second circular arcs 330-4, 332-4, are even more divergent in relative size than those shown in previous embodiments. As the second angular range 339-4 decreases in size relative to the first angular range 338-4, a lateral urging (as indicated by arrow 340-4) of the borehole 318-4 against the drilling tool 310-4 may decrease as well. Thus, a rate of steering of a drill bit as it forms a borehole through the earth may be controlled by altering timing of extension and retraction of extendable cutting elements.

Figures 4-1 and 4-2 show an embodiment of a single subterranean borehole 418-1 at different positions along its length. At a first position along a length of the borehole 418-1, shown in Figure 4-1, a cross section of the borehole 418-1 may comprise a first circular arc 430-1 positioned at a first rotational orientation. In this orientation, a drilling tool 410-1 disposed within the borehole 418-1 may be urged (as indicated by arrow 435-1) toward the first circular arc 430-1. At a second position along the borehole 418-1 length, shown in Figure 4-2, a rotational orientation of a first circular arc 430-2 may be rotated relative to the first circular arc 430-1 shown in Figure 4-1 (as indicated by arrow 450-2). This reorientation of the first circular arc 430-2 may cause the borehole 418-1 to urge the drilling tool 410-1 in a different direction (as indicated by arrow 435-2). Thus, by adjusting the rotational orientation of a borehole's circular arcs, a drilling tool may be urged in various azimuthal directions.

Figures 4-3 and 4-4 show an embodiment of a single subterranean borehole 418-3 at different positions along its length. At a first position along a length of the borehole 418-3, shown in Figure 4-3, a cross section may comprise a first circular arc 430-3 comprising a first radius 440-3. A drilling tool 410-3 disposed within the borehole 418-3 may be urged (as indicated by arrow 435-3) toward the first circular arc 430-3. At a second position along the borehole 418-3 length, shown in Figure 4-4, a radius 440-4 of a first circular arc 430-4 may be enlarged relative to the radius 440-3 of the first circular arc 430-3 shown in Figure 4-3. This resizing of the radius 440-4 may steer the borehole 418-3 in a tighter radius of curvature.

Figure 5 shows an embodiment of a section of elongate hollow borehole 518 formed in an earthen formation. This borehole 518 may have an axis 544 passing therethrough and a cross- sectional shape comprising first and second circular arcs 530, 532 of distinct radii centered at the axis 544. These first and second circular arcs 530, 532 may be adjusted relative to each other in both radii, angular size and rotational orientation during drilling such that they differ at various points along a length of the borehole 518. By adjusting these first and second circular arcs 530, 532 as drilling progresses, the borehole 518 may be formed to comprise multiple curves along its axis 544. These various curves may comprise unique radii of curvature based on the relative dimensions of the first and second circular arcs 530, 532 and the lateral urging forces created thereby. For example, a first curve 540 of the borehole 518, curving toward the first circular arc 530, may comprise a first radius of curvature 541. The size of this first radius of

curvature 541 may depend on the relative radii and angular sizes of the first and second circular arcs 530, 532. If this first radius of curvature 541 is not changing a direction of the borehole 518 as rapidly as desirable, then the relative dimensions of the first and second circular arcs 530, 532 may be altered, thus resulting in an increased urging force. For instance, in a second curve 542 of the borehole 518, an angular size of the first circular arc 530 may be reduced while an angular size of the second circular arc 532 may be expanded. By so doing, a second radius of curvature 543 within the second curve 542 may be smaller than the first radius of curvature 541 leading to a more rapid change of direction.

Figure 6 shows one embodiment of a drill bit 612 capable of degrading the earth, when rotated, to form a borehole therethrough. The drill bit 612 may be joined at an attachment end 620 thereof to a drill string (not shown) running the length of such a borehole. Opposite from the attachment end 620 the drill bit 612 may comprise an engagement end 621 comprising a plurality of blades 622 protruding therefrom. These blades 622 may be generally spaced about a periphery of the engagement end 621 and wrap from the engagement end 621 over to a side 623 of the drill bit 612. A plurality of tough cutter elements 626 may be secured to each of the blades 622 to aid in degrading hard earthen materials.

The side 623 may span from the attachment end 620 to the opposing engagement end 621 and comprise an opening 624 therein. A tip 625, comprising additional cutter elements 627 secured thereto, may be extendable from within the opening 624 to degrade a specific section of an adjacent borehole wall (not shown) surrounding the drill bit 612. A stabilizer 628, axially spaced from the opening 624, may protrude from the side 623. This stabilizer 628 may comprise tough gauge elements 629 designed to push against and ride along the borehole wall without wearing away. As the cutter elements 627 of the tip 625 degrade the specific wall section, as described previously, the stabilizer 628 may push off of the borehole wall into the degraded section, as will be described below.

Figure 7 shows another embodiment of a drill bit 712. The drill bit 712 comprises a plurality of threads 737 disposed within an attachment end 720 thereof, providing a mechanism for attachment to a drill string (not shown). The drill bit 712 also comprises a conduit 738 passing therethrough, allowing for drilling fluid conducted along a drill string to exit from an engagement end 721 of the drill bit 712, through nozzles 739 disposed therein, to aid in drilling.

A first opening 724 on a side 723 of the drill bit 712 may be connected to a second opening 734, opposite the first opening 724, by an elongate cavity 730 passing through the drill bit 712. Cutter elements 725, 726, extendable from the first opening 724 and second

opening 734 respectively, may be attached to a common rod 731 slidable within the cavity 730. As the rod 731 slides within the cavity 730 the cutter elements 725, 726 may extend or retract from their respective openings. Because both cutter elements 725, 726 are secured to opposing tips of the same rod 731, as one extends the other may retract. In the embodiment shown, the rod 731 is positioned between the engagement end 721 of the drill bit 712 and a plenum 740 of the conduit 738 wherein the nozzles 739 separate therefrom.

Extension or retraction of the cutter elements 725, 726 may be caused by the introduction of pressurized fluid that may urge the rod 731 to slide within the cavity 730. In the embodiment shown, pressurized fluid within a first channel 732 may urge the rod 731 to extend from the first opening 724. Subsequently, pressurized fluid within a second channel 733 may urge the rod 731 to return to a neutral position within the cavity 730. In some embodiments, such as the one shown, at least one spring 735 may also urge the rod 731 toward the neutral position.

Pressurized fluid within the second channel 733 may then urge the rod 731 to extend from the second opening 734.

One motivation for securing the cutter elements 725, 726 to the single rod 731 may be to maintain a generally consistent borehole width while drilling. Further, it is believed that the specific positioning of the cutter elements 725, 726 relative to a remainder of the drill bit 712 may be important to maintaining a consistent borehole width. In the embodiment shown, cutter elements 725, 726 disposed on opposing tips of the rod 731 are positioned farther apart from each other than opposing stabilizers 728 protruding from the side 723 of the drill bit 712. The stabilizers 728 themselves may be positioned farther apart than a width of the engagement end 721 of the drill bit 712 such that the cutter elements 725, 726 are not required to degrade too much material. In such a configuration, the cutter elements 725, 726 may remain exposed at all times, to some degree, to an adjacent borehole wall (not shown) surrounding the drill bit 712.

Figure 8 shows an embodiment of another steerable downhole tool, a drill pipe section in this case. The drill pipe section comprises a main body 812 rotatable about an axis 841 and comprising a first end 820 opposite from a second end 821. Both the first and second ends 820, 821 may comprise threads for connection to other elements. A side 823 may span between the first and second ends 820, 821. This side 823 may comprise two openings 824, 834 therein both leading to a cavity 830 passing through the body 812. A rod 831 may be slidably disposed within the cavity 830. Both the rod 831 and cavity 830 may be positioned within a plane perpendicular to the rotational axis 841. In the embodiment shown, the rod 831 actually intersects the rotational axis 841 of the body 812, however this is not necessary.

The rod 831 may comprise a shaft 842 surrounded by a bearing sleeve 843. The rod 831 may also comprise replaceable caps 844, 845 secured on opposing tips of the shaft 842. In the embodiment shown the replaceable caps 844, 845 are held to the shaft 842 via a threaded bolt; however a variety of other connections are also possible. The caps 844, 845 may be replaceable to allow for quick exchange should they become worn out or damaged.

A stabilizer body 846 may be threadably secured to the first end 820 of the main body 812. This stabilizer body 846 may have a stabilizer 828 protruding radially therefrom. When the stabilizer body 846 is threaded to the main body 812 the stabilizer 828 may sit axially spaced from the opening 824 of the main body 812. In this position, the stabilizer 828 may push against a borehole wall (not shown) when the rod 831 is extended from the opposite

opening 834. In this thread-on configuration, the stabilizer body 846 may be interchangeable with other similar bodies to allow for quick modification of stabilizer size, or merely

replacement when worn or damaged.

Figure 9 shows another embodiment of a steerable downhole tool comprising a rod 931 and cavity 930 offset from a rotational axis 941 of a body 912 of the tool. In this embodiment, the tool also comprises a locking mechanism 950 housed within the body 912. While a variety of designs are possible, the locking mechanism 950 shown comprises a latch 951 that may translate relative to the rod 931. When translated toward the rod 931, a convergent point of the latch 951 may engage with a mating geometry of the rod 931 to first urge the rod 931 toward a neutral position within the cavity 930 and then eventually lock the rod 931 in place within the cavity 930. When translated away from the rod 931, the latch 951 may release the rod 931 such that it may again slide freely within the cavity 930. It has been found that forming the latch 951 and rod 931 of different materials, each comprising unique properties, may reduce galling during locking allowing for ease of release.

Translation of the latch 951 may be achieved by adjusting fluid pressures in various chambers surrounding the latch 951. These chambers may be filled by the same pressurized fluid used to urge the rod 931 to extend or retract. For example, in the embodiment shown, a first chamber 952 may be pressurized at a generally constant pressure. When no other forces are acting, this generally constant pressure may urge the latch 951 against the rod 931 to lock it in place. When either of a second chamber 953 or third chamber 954 are filled with pressurized fluid however, the generally constant pressure within the first chamber 952 may be overcome to urge the latch 951 away from the rod 931 and release it from lock. Pressurized fluid being channeled to urge the rod 931 to slide axially in one direction may also feed into the second chamber 953 while pressurized fluid being channeled to urge the rod 931 to slide axially in an opposite direction may feed into the third chamber 954. Thus, in such a configuration, the rod 931 may be axially locked until fluid is sent to urge it in either direction, and then it may be unlocked and free to slide.

Figures 9-1 and 9-2 show embodiments of rods 931-1, 931-2 comprising various cross- sectional geometries. The cross-sectional geometries of the rods 931-1, 931-2 may be non- cylindrical and may mate with matching cavities to restrain rotation of the rods 931-1, 931-2 relative to their respective cavities. This restraint may keep cutter elements 925-1, 925-2, attached to each of the rods 931-1, 931-2, aligned as their respective tools rotate.

Figures 10-1 through 10-4 show different steps to downhole steering made possible by aspects of the embodiments described previously. Specifically, Figure 10-1 shows an initial position of a steering tool 1012-1 comprising a slidable rod 1031-1 housed therein. In this figure, the rod 1031-1 is positioned in a neutral position within the tool 1012-1. As a tool 1012-2 rotates, as shown in Figure 10-2, about a central axis thereof, a rod 1031-2 may be slid in one direction along its length such that it extends from one side of the tool 1012-2. Extension of this rod 1031 2 may cause a first cutter element 1025-2 attached to the rod 1031-2 to engage and degrade a borehole wall 1011-2 surrounding the tool 1012-2. This extension may also push a stabilizer 1028-2, positioned opposite from the first cutter element 1025-2, against the borehole wall 1011-2, thus pushing the entire tool 1012-2 in the direction of the degradation.

After rotating about its axis generally 180 degrees (other amounts are also anticipated), as shown in Figure 10-3, a rod 1031-3 may retract to the neutral position within its respective tool 1012-3. From this position, a second cutter element 1026-4, as shown in Figure 10-4, attached to a rod 1031-4, opposite from a first cutter element 1025-4, may be extended from a side of a tool 1012-4 to degrade a borehole wall 1011-4 while the tool 1012-4 rotates another generally 180 degrees in a similar manner as shown previously; with a different stabilizer 1028-4 pushing toward the area of degradation. From here, the method may repeat from the beginning.

Figure 11 shows an embodiment of piston 1110 slidably disposed within a hollow cylinder 1111 formed in a mass 1112. An arrow shows a direction 1113 of possible travel for this piston 1110 that may be aligned with a central axis 1117 of the piston 1110. The piston 1110 and cylinder 1111 may combine to form a volume 1114 capable of containing a fluid. A gasket 1115 may surround the piston 1110 and keep fluid contained within the volume 1114 from escaping between the piston 1110 and cylinder 1111. An increase in fluid pressure within the volume 1114 may urge the piston 1110 to slide out of the cylinder 1111. Conversely, a decrease in fluid pressure may pull the piston 1110 back into the cylinder 1111.

The piston 1110 may comprise a through hole 1116 passing therethrough. In the embodiment shown, the through hole 1116 passes radially across the piston 1110, perpendicular to and touching the central axis 1117 of the piston 1110; although other arrangements are also possible.

A rod 1118 may span the hollow cylinder 1111 from one side to another; secured to internal walls of the cylinder 1111 at opposing ends thereof. This rod 1118 may also be positioned perpendicular to the central axis 1117 of the piston 1110, similarly to the through hole 1116, and extend through the through hole 1116. By extending through the through hole 1116 and attaching to opposing sides of the cylinder 1111, the rod 1118 may restrict axial motion of the piston 1110.

Internal dimensions of the through hole 1116 may be larger than external dimensions of the rod 1118, allowing the piston 1110 to translate a certain distance before restriction by the rod 1118. A distance that the piston 1110 may travel before contacting the rod 1118 may define a stroke length 1119 for the piston 1110. Further, a cross section of the through hole 1116 may comprise a generally oblong shape that is elongated in the direction 1113 of travel of the piston 1110.

A solenoid 1120, or other type of control device in alternate embodiments, may adjust a position of this rod 1118 and this adjustment may alter the defined stroke length 1119. Such adjustments may provide additional benefits such as distributing impact wear between the rod 1118 and the through hole 1116. This solenoid 1120 may comprise at least one electrically conductive wire 1121 wound in a coil. If an electrical current is passed through such a wire 1121 a magnetic field may be produced that may act on certain materials forming the rod 1118.

Examples of other types of control devices capable of adjusting a position of a rod, that may replace the solenoid in other embodiments, include a hydraulic pump and ball screw. It is believed that such alternate control devices may provide additional accuracy at an expense of additional complexity.

Figures 12-1 and 12-2 show embodiments of adjustable rods 1218-1, 1218-2 that may alter respective stroke lengths 1219-1, 1219-2 of associated pistons 1210-1, 1210-2. These alterations may be enabled by unique geometries possessed by the rods 1218-1, 1218-2.

Specifically, such rods 1218-1, 1218-2 may each comprise a noncylindrical external geometry that may encounter an interior of a through hole 1216-1, 1216-2 of its associated

piston 1210-1, 1210-2 at different points based on the rods' 1218-1, 1218-2 positioning.

Figure 12-3 shows an embodiment of a rod 1218-3 comprising a noncylindrical external geometry characterized by a radius 1222-3, spaced from a central axis 1223-3 of the rod 1218-3, that varies in magnitude along an axial length of the rod 1218-3. While a wide variety of radial variations are anticipated, for simplicity's sake, this embodiment comprises two substantially constant radial sections; a first section 1224-3 comprising a relatively smaller radius and a second section 1225-3 comprising a relatively larger radius. The present embodiment also comprises a generally sloping transition between these two substantially constant radial sections.

In Figure 12-1, a linear solenoid 1220-1 retains the associated rod 1218-1 in a relatively retracted position such that only a first section 1224-1 thereof, comprising a relatively smaller radius, may extend into the through hole 1216-1 of the piston 1210-1. Because only the relatively smaller first section 1224-1 may contact the interior of the through hole 1216-1, the piston 1210-1 may have a relatively longer potential stroke length 1219-1 before being restricted by contact with the rod 1218-1.

In Figure 12-2, a linear solenoid 1220-2 ejects the associated rod 1218-2 axially to a relatively extended position such that a second section 1225-2 thereof, comprising a relatively larger radius, may also extend into the through hole 1216-1 of the piston 1210-1, in addition to a first, relatively smaller, section 1224-2. With this relatively larger second section 1225-2 also potentially contacting the interior of the through hole 1216-2, the piston 1210-2 may have a relatively shorter potential stroke length 1219-2 due to changed location of contact with the rod 1218-2.

Figures 13-1 and 13-2 show embodiments of other adjustable rods 1318-1, 1318-2 that may alter stroke lengths 1319-1, 1319-2 of associated pistons 1310-1, 1310-2 by a different mechanism. Such stroke length alterations may still be enabled by rods 1318-1, 1318-2 comprising noncylindrical external geometries. However, in these embodiments, external geometries of the rods 1318-1, 1318-2 may vary around a circumference thereof.

For example, Figure 13-3 shows an embodiment of a rod 1318-3 comprising a radius 1322-3, spaced from a central axis 1323-3 of the rod 1318-3, that varies in magnitude around a circumference of the rod 1318-3. While a wide variety or radial variations are possible, again for simplicity's sake, the embodiment comprises a flat surface 1330-3 running parallel to the central axis 1323-3 of the rod 1318-3 and perpendicular to a radius of the rod 1318-3.

In Figure 13-1, a rotary solenoid 1320-1 positions the associated rod 1318-1 rotationally such that a flat surface 1330-1 thereof faces a direction 1313-1 of travel of the piston 1310-1. As this flat surface 1330-1 creates a shorter distance from a central axis 1323-1 of the rod 1318-1 to an external geometry thereof, compared to other portions of the rod 1318-1, the piston 1310-1 may have a relatively longer potential stroke length 1319-1 with the rod 1318-1 in this rotational position.

In Figure 13-2, a rotary solenoid 1320-2 may rotate the associated rod 1318-2 such that a flat surface 1330-2 thereof faces at generally right angles to a direction 1313-2 of travel of the piston 1310-2. In this position, the stroke length 1319-2 may shorten in that the rod 1318-2 may restrain translation of the piston 1310-2 sooner. While only two positions are shown, generally at right angles from each other about a central axis of a rod, any of a variety of angular positions between these two extremes may provide a partially restricting effect allowing for variable control of a stroke length.

The through holes of the embodiments discussed thus far have comprised generally oblong cross-sectional shapes. Other shapes are also anticipated, however. For example,

Figure 14 shows an embodiment of a piston 1410 with a through hole 1416 passing therethrough. This through hole 1416 may comprise a cross-sectional shape featuring a generally triangular section 1440 and a notch 1441 section. A rod 1418 passing through the through hole 1416 may restrict translation of the piston 1410 when in contact with an interior of the through hole 1416.

In the embodiment shown, this rod 1418 is capable of radial translation, or translation

perpendicular to a central axis 1417 of the piston 1410. Adjustment of the rod 1418 in this manner may reposition it with respect to the through hole 1416. Specifically, radial translation of the rod 1418 within the generally triangular section 1440 of the through hole 1416 may change an internal width 1442, extending in a direction parallel with the central axis 1417 of the piston 1410, at the location of the rod 1418. Changing this through hole 1416 width 1442 may grant the piston 1410 a different stroke length.

Additionally, the notch 1441 section of the through hole 1416 may comprise an internal width 1443 substantially similar to an external dimension of the rod 1418 in the same direction. If the rod 1418 is translated into the notch 1441 section, the stroke length 1419 of the

piston 1410 may be restricted to naught effectively locking the position of the piston 1410 in place.

Figure 15 shows an embodiment of a drill bit 1510 of the type that may form part of a subterranean drilling operation. The drill bit 1510 may comprise a generally cylindrical body 1520 that may be rotated about a central axis 1521 thereof. On one end, the body 1520 may comprise an attachment mechanism 1522, shown here as a series of threads. This attachment mechanism may secure the drill bit 1510 to a mating attachment device disposed on a distal end of a drill string (not shown). Opposite from the attachment mechanism 1522, the body 1520 may comprise a plurality of blades 1523 extending both radially and longitudinally therefrom, spaced around the axis 1521 of the body 1520.

Each of these blades 1523 may comprise a leading edge with a plurality of fixed cutting elements 1524 protruding therefrom. Each of these fixed cutting elements 1524 may comprise a portion of superhard material (i.e. material comprising a Vickers hardness test number exceeding 40 gigapascals) secured to a substrate. The substrate may be formed of a material capable of firm attachment to the body 1520. As the drill bit 1510 is rotated, the superhard material of each fixed cutting element 1524 may engage and degrade tough earthen matter. Each of the fixed cutting elements 1524 may be spaced at a constant radius relative to the axis 1521 of the body 1520 to create an initially cylindrical borehole.

In addition to the fixed cutting elements 1524, a rotatable cutting element 1525 may also protrude from an exterior of the body 1520. This rotatable cutting element 1525 may also comprise a portion of superhard material secured to a substrate, similar in some respects to the fixed cutting elements 1524. An exposed surface of the rotatable cutting element 1525 may comprise a three-dimensional geometry incorporating some of this superhard material. Based on its rotational orientation, this exposed geometry may engage an internal wall of the borehole and remove earthen matter therefrom. Removing this material may change an internal radius of the borehole in some areas. The amount of earthen matter removed may be altered by rotation of the rotatable cutting element 1525 relative to the body 1520.

Figure 16-1 shows an embodiment of a drill bit 1610-1 rotatable about an axis 1621-1. The drill bit 1610-1 comprises a plurality of fixed cutting elements 1624-1 exposed on leading edges of a plurality of blades 1623-1. At least one of the fixed cutting elements 1624-1, positioned farthest from the axis 1621-1 of any of the plurality, may form a gauge cutting element 1634-1. A distance from the axis 1621-1 to this gauge cutting element 1634-1 may define an initial radius 1630-1 of a borehole as the drill bit 1610-1 is rotated.

A rotatable cutting element 1625-1 may also protrude from an exterior surface of the drill bit 1610-1 in relative proximity to the gauge cutting element 1634-1. In contrast to the fixed cutting elements 1624-1, this rotatable cutting element 1625-1 may be capable of rotation, relative to the drill bit 1610-1, about its own axis 1631-1. An exposed portion of this rotatable cutting element 1625-1 may comprise a three-dimensional geometry comprising an offset distal end 1632-1. This exposed geometry may also comprise a slanting surface 1633-1 that may stretch from the offset distal end 1632-1 toward a proximal base thereof.

The unique aspects of this three-dimensional exposed geometry may allow it to extend radially beyond the initial radius 1630-1 in a first rotational orientation as shown. In this first rotational orientation, the slanting surface 1633-1 may be positioned in a generally parallel alignment with a leading face of the gauge cutting element 1634-1. It is believed that such an alignment may, in some subterranean formations, lead to a smoother extension of the offset distal end 1632-1. Also, in this first rotational orientation, the slanting surface 1633-1 may be positioned in a generally normal alignment relative to the initial radius 1630-1.

When extended in this manner, the offset distal end 1632-1 may cut an extended radius 1635-1 into the borehole by removing additional earthen matter from an internal wall of the borehole. Removing material from this internal wall may change an internal radius of the borehole, at least in an angular section thereof. This extended radius 1635-1 may be restricted to certain angular sections positioned about a circumference of the borehole via deliberate rotational control of the rotatable cutting element 1625-1 to create purposefully non-cylindrical cross-sectional shapes.

Figure 16-2 shows another embodiment of a drill bit 1610-2, similar in many regards to that shown in Figure 16-1. In this embodiment, however, a rotatable cutting element 1625-2 protruding from an exterior surface of the drill bit 1610-2 may be rotated into a second rotational orientation. In this second rotational orientation, an exposed three-dimensional geometry of the rotatable cutting element 1625-2 may remain within an initial radius 1630-2 defined by an outermost fixed gauge cutting element 1634-2. Specifically, in this second rotational orientation, a slanting surface 1633-2 of the exposed geometry may be positioned in a generally tangent alignment relative to the initial radius 1630-2 such that it may smoothly avoid an internal wall of a borehole without removing material therefrom.

If extension and retraction of the rotatable cutting element 1625-2 is performed in unison with rotation of the drill bit 1610-2, such that a given rotational orientation of the drill bit 1610-2 correlates with a set rotational orientation of the rotatable cutting element 1625-2, then a consistent borehole cross-sectional shape may be created. Various embodiments of such unison rotation may comprise spinning the rotatable cutting element 1625-2 in consecutive full turns or oscillating it back and forth. In addition, or alternatively, extension and retraction of the rotatable cutting element 1625-2 may be performed at higher frequencies to reduce likelihood of the drill bit 1610-2 sticking to the borehole wall.

Figures 17-1 and 17-2 show embodiments of a rotatable cutting element 1725-1, 1725-2 protruding from an exterior surface of a drill bit 1710-1, 1710-2 in relative proximity to a fixed gauge cutting element 1734-1, 1734-2, also protruding from the exterior surface. In contrast to the gauge cutting element 1734-1, 1734-2, this rotatable cutting element 1725-1, 1725-2 may be capable of rotation, relative to the drill bit 1710-1, 1710-2, about its own axis 1731-1, 1731-2.

An exposed portion of this rotatable cutting element 1725-1, 1725-2 may comprise a generally flat distal surface 1733-1, 1733-2.

In a first rotational orientation of the rotatable cutting element 1725-1, as shown in Figure 17-1, the exposed portion may extend radially beyond an initial radius 1730-1 defined by a position of the gauge cutting element 1734-1. In a second rotational orientation, as shown in Figure 17-2, the rotatable cutting element 1725-2 may be rotated around its axis 1731-2 such that the exposed portion may remain within an initial radius 1730-2.

Figures 18-1 and 18-2 show embodiments of a drill bit 1810-1, 1810-2 comprising a rotatable cutting element 1825-1, 1825-2 protruding from an exterior surface thereof. The rotatable cutting element 1825-1, 1825-2 may be actively rotated by a torque-generating apparatus 1850-1, 1850-2. Such a torque-generating apparatus may be powered by any of a variety of known transducers capable of converting electrical, hydraulic or other types of energy into linear or rotary motion; such as a solenoid, piston, turbine or the like. Based on the type of transducer chosen, the torque-generating apparatus may be capable of external control, continuous full rotation, rotational oscillation, holding a set position, etc.

This torque-generating apparatus 1850-1, 1850-2 may be connected to the rotatable cutting element 1825-1, 1825-2 via a set of gears. In the embodiment shown, the torque generating apparatus 1850-1, 1850-2 comprises an axially-translatable rack gear 1851-1, 1851-2. Teeth of this rack gear 1851-1, 1851-2 may mesh with those of a pinion gear 1852-1, 1852-2 attached to the rotatable cutting element 1825-1, 1825-2. Thus, as the rack gear 1851-1, 1851-2 translates, the pinion gear 1852-1, 1852-2 may rotate the rotatable cutting element 1825-1, 1825-2. Specifically, as shown in Figure 18-1, as the torque-generating apparatus 1850-1 translates 1853-1 the rack gear 1851-1 outward along its axis, the pinion gear 1852-1

rotates 1854-1 the rotatable cutting element 1825-1 into an extended position, radially past a fixed gauge cutting element 1834-1. As shown in Figure 18-2, as the torque-generating apparatus 1850-2 translates 1853-2 the rack gear 1851-2 inward, the pinion gear 1852-2 rotates 1854-2 the rotatable cutting element 1825-2 into a retracted position, radially within a fixed gauge cutting element 1834-2. Such an arrangement could be reversed in alternate embodiments. Figures 19-1 and 19-2 show embodiments of a rotatable cutting element 1925-1, 1925-2 that may be rotated by a torque-generating apparatus 1940-1, 1940-2. In these embodiments, the torque-generating apparatus 1940-1, 1940-2 is connected to the rotatable cutting

element 1925-1, 1925-2 via a worm-wheel gear configuration. In particular, the torque generating apparatus 1940-1, 1940-2 may comprises a rotatable worm gear 1941-1, 1941-2.

Teeth of this worm gear 1941-1, 1941-2 may mesh with those of a worm wheel

gear 1942-1, 1942-2 attached to the rotatable cutting element 1925-1, 1925-2. Thus, as the worm gear 1941-1, 1941-2 rotates, the worm wheel gear 1942-1, 1942-2 may also rotate the rotatable cutting element 1925-1, 1925-2. Specifically, as shown in Figure 19-1, as the torque-generating apparatus 1940-1 rotates 1943-1 the worm gear 1941-1 in a first direction, the worm wheel gear 1942-1 rotates 1944-1 the rotatable cutting element 1925-1 into an extended position. As shown in Figure 19-2, as the torque-generating apparatus 1940-2 rotates 1943-2 the worm gear 1941-2 in a second direction, the worm wheel gear 1942-2 rotates 1944-2 the rotatable cutting element 1925-2 into a retracted position. Such an arrangement could be reversed in alternate embodiments.

Figures 20-1 and 20-2 show embodiments of a rotatable cutting element 2025-1, 2025-2 that may be rotated by a torque-generating apparatus 2040-1, 2040-2. In these embodiments, the torque-generating apparatus 2040-1, 2040-2 wraps around a circumference of the rotatable cutting element 2025-1, 2025-2 and comprises a geometry capable of protruding from a drill bit and engaging with an external formation through which the drill bit may be advancing. While thus engaged, rotation of the drill bit or its advancement through a formation may cause this torque-generating apparatus 2040-1, 2040-2 to rotate the rotatable cutting

element 2025-1, 2025-1.

The rotatable cutting element 2025-1, shown in Figure 20-1, may be freely

rotatable 2044-1 about an axis thereof. In Figure 20-2, however, a braking apparatus 2070-2 may engage a cam 2071-2 portion of the rotatable cutting element 2025-2. While engaged, this braking apparatus 2070-2 may rotationally secure the rotatable cutting element 2025-1 and restrain 2044-2 it from free rotation.

Figure 21 shows an embodiment of multiple rotatable cutting elements 2125-1, 2125-2 and 2125-3 that all may be rotated by a single torque-generating apparatus 2140. Similar in some respects to the torque-generating apparatus shown in Figures 19-1 and 19-2, this torque generating apparatus 2140 may comprise a worm gear 2141 with teeth wrapping therearound. In this embodiment however, each of the multiple rotatable cutting elements 2125-1, 2125-2 and 2125-3 may comprise a unique worm wheel gear 2142-1, 2142-2 and 2142-3, respectively, connected thereto. Teeth of each of these worm wheel gears 2142-1, 2142-2 and 2142-3 may mesh with those of the worm gear 2141 such that as the torque-generating apparatus 2140 rotates the worm gear 2141 each of the rotatable cutting elements 2125-1, 2125-2 and 2125-3 may rotate simultaneously. As can be seen, each of these rotatable cutting elements 2125-1, 2125-2 and 2125-3 may extend away from the torque-generating apparatus 2140, and protrude from an exterior of a drill bit 2110, in different radially-angular directions without interfering with one another. While a worm-wheel gear system is shown, alternate embodiments may comprise other arrangements comprising multiple rotatable cutting elements connected to a single torque generating apparatus.

Figure 22 shows an embodiment of a drill bit 2210 that may form part of a subterranean drilling operation. Although any of a variety of drill bit types may be functional with the novel elements described herein (e.g. roller cone bits, diamond impregnated bits and hybrids thereof), the embodiment of the drill bit 2210 shown comprises a plurality of blades 2220 protruding from one end thereof spaced around a rotational axis 2221 thereof. In the embodiment shown the plurality of blades 2220 are generally aligned with the rotational axis 2221, however in other embodiments blades may spiral around a circumference of a drill bit. A plurality of cutting elements 2222, capable of degrading tough earthen matter, may be disposed on each of the blades 2220. If this drill bit 2210 is rotated within an earthen formation, these cutting elements 2222 would normally create a generally cylindrically shaped borehole with a constant radius. The drill bit 2210 may also comprise a threadable attachment 2223, comprising a series of threads disposed within a cavity (hidden), disposed on an opposite end from the plurality of blades 2220.

Additional cutting elements 2224 may be extendable in a generally radial direction from an exterior of the drill bit 2210. Extension of these cutting elements 2224 may cause them to engage a wall of a borehole (not shown) through which the drill bit 2210 may be traveling and scrape earthen material away from the borehole wall at certain points around its circumference.

This scraping may cause the shape of the borehole to deviate away from the generally cylindrical shape initially created by the rigidly-secured cutting elements 2222 of the drill bit 2210. For example, if the cutting elements 2224 are extended during only a portion of a full rotation of the drill bit 2210, then the borehole may be given a new cross-sectional shape comprising two distinct radii, an initial radius formed by the secured cutting elements 2222 and an enlarged radius formed by the extendable cutting elements 2224.

While any of a variety of cutting element types may be used for extension, the present embodiment depicts a rotatable type of cutting element similar in some respects to those shown in U.S. Patent No. 7,703,559 to Shen et al.

In the embodiment shown, these extendable cutting elements 2224 are secured to an exposed end of a piston 2226 that may be extended or retracted by hydraulic pressure. While only a single piston is shown in the present embodiment, in various other embodiments a plurality of extendable cutting elements, each secured to its own unique piston, similar in some respects to those shown in Figure 2A of U.S. Patent No. 8,763,726 to Johnson et al., is also possible.

An abrasion-resistant gauge pad 2228 may protrude from the exterior of the drill bit 2210 and be positioned axially adjacent the extendable cutting elements 2224. In the embodiment shown only one abrasion-resistant gauge pad 2228 is shown aligned with the single radial direction, however in other embodiments a plurality of abrasion-resistant gauge pads may be positioned at a variety of locations about a circumference of a body. For example, in some embodiments each of a plurality of blades may comprise its own gauge pad. At this gauge pad 2228 the drill bit 2210 may comprise a cross-sectional radius sized between the two borehole radii discussed previously; larger than the smaller radius formed by the rigid cutting

elements 2222 but smaller than the larger radius formed by the extendable cutting

elements 2224. In fact, this gauge pad 2228 radius may not fit through a borehole formed exclusively by the rigid cutting elements 2222 without the enlargement created by the extendable cutting elements 2224. This sizing mismatch may constantly, and with little energy exerted by the drill bit 2210, urge the drill bit 2210 laterally as the smaller radius pushes the drill bit 2210 into space created by the larger radius.

To achieve its abrasion resistance, preventing wear caused by rubbing against the borehole wall, the gauge pad 2228 may comprise one or more studs 2229 embedded therein.

These studs 2229 may be formed of superhard materials (i.e. materials comprising a Vickers hardness test number exceeding 40 gigapascals). Generally cylindrical studs are shown in the present embodiment, however studs of a variety of shapes and sizes, and arranged in a variety of patterns, are also contemplated.

Axially adjacent the extendable cutting elements 2224 and gauge pad 2228 a second cutting element 2225 and third cutting element 2227 may be rigidly secured to the exterior of the drill bit 2210. The second cutting element 2225 may sit axially adjacent the extendable cutting elements 2224 opposite from the gauge pad 2228 while the third cutting element 2227 may sit axially adjacent the gauge pad 2228 opposite from the extendable cutting elements 2224. In the embodiment shown, these second and third cutting elements 2225, 2227 are shown aligned with the single radial direction, however in other embodiments similar cutting elements may be positioned at a variety of locations about a circumference of a body. The third cutting element 2227 may effectively ream out the borehole deviation created by the extendable cutting elements 2224, or to a larger diameter, leaving the borehole generally cylindrical once again. While the present embodiment shows a solitary third cutting element 2227, in other

embodiments a plurality of cutting elements may perform such a reaming function.

Figure 23 shows another embodiment of a drill bit 2310 comprising extendable cutting elements 2324, an abrasion-resistant gauge pad 2328, and second and third cutting

elements 2325, 2327. The gauge pad 2328 is seen to slant away from a rotational axis 2321 of the drill bit 2310. It is believed that this slanting of the gauge pad 2328 may aid in allowing a borehole wall to urge the drill bit 2310 sideways while avoiding rapid wear due to rubbing. As is also visible from this angle, while a distance from the rotational axis 2321 to the extendable cutting elements 2324 is variable, similar distances to the gauge pad 2328 and second and third cutting elements 2325, 2327 may be fixed. In this fixed arrangement, the gauge pad 2328 may protrude farther from the rotational axis 2321 of the drill bit 2310 than the second cutting element 2325 and the third cutting element 2327 may protrude farther than the gauge pad 2328.

The extendable cutting elements 2324 may be extended or retracted based on hydraulic pressure acting on a base of a piston 2326 secured to the cutting elements 2324. Pressurized hydraulic fluid may be channeled against the base of the piston 2326 via a conduit 2330 passing through the drill bit 2310 built for this purpose. In various configurations, this hydraulic fluid may be regulated to control a physical position of the piston 2326 or a force applied to the piston 2326. In the embodiment shown, a pin 2331 may be secured to the drill bit 2310 and pass through a passageway intersecting the piston 2326 similar in some respects to those shown in U.S. Patent No. 9,085,941 to Hall et al. This pin 2331 may regulate the limits of extension and retraction of the cutting elements 2324.

A seal 2332 may surround a perimeter of the piston 2326 to block the pressurized hydraulic fluid from escaping out between the piston 2326 and drill bit 2310 and into the borehole. In the embodiment shown, this seal 2332 takes the form of two elastomeric rings disposed within grooves encircling the piston 2326 at around a midpoint of its axial length. In other embodiments, however, a similar seal may be positioned at any point axially along a piston from an exposed portion to a base thereof. Additionally, other seal embodiments may comprise a flexible material like a thin metallic bellows that may, in some circumstances, provide more wear resistance than an elastomer. In some embodiments a close fit may suffice to retain fluid without such a seal.

Figure 24-1 shows an embodiment of a piston 2426-1 that may be radially extendable from a drill bit (not shown) or other axial body. Rather than comprising separate cutting elements secured thereto, as shown in embodiments of pistons discussed previously, an entire exposed portion 2440-1 of the piston 2426-1 may be covered by a plate of superhard material to form a single extendable cutting element. The piston 2426-1 may be free to rotate about a central axis thereof to distribute wear about a circumference of the exposed portion 2440-1. In the embodiment shown, the exposed portion 2440-1 of the piston 2426-1 comprises a generally flat principal surface. Alternate embodiments, however, may have any of a variety of non-flat profiles.

Figure 24-2 shows another embodiment of a piston 2426-2 comprising two cutting elements secured to an exposed end thereof. A first cutting element 2424-2 secured to the piston 2426-2 may protrude from the exposed end a first distance and may dig into a borehole wall 2442-2 a certain amount. A second cutting element 2444-2 may protrude farther than the first cutting element 2424-2 but dig into the borehole wall 2442-2 substantially the same amount as the first cutting element 2424-2. This is possible if the second cutting element 2444-2 is spaced farther from a distal end of an axial body (not shown) than the first cutting

element 2424-2 and the first cutting element 2424-2 removes matter from the borehole wall 2442-2 as it digs. In this configuration, reaction forces experienced by the first and second cutting elements 2424-2, 2444-2 may balance rotational torque around an axis of the

piston 2441-2. Figure 25-1 shows an embodiment of a drill bit 2510-1 comprising one or more cutting elements 2524-1 radially extendable and retractable from an exterior thereof. In the embodiment shown, the cutting elements 2524-1 are in an extended configuration exposing them to external impact. These cutting elements 2524-1 may be secured to a hinged arm 2550-1. Figure 25-2 shows an embodiment of such a hinged arm 2550-2 comprising several cutting elements 2524-2 attached thereto and a pin 2551-2 extending from a body thereof. The pin 2551-2 may attach the hinged arm 2550-2 to a drill bit (not shown) such that the hinged arm 2550-2 is rotatable about a rotational axis 2552-2 passing through the pin 2551-2.

Figure 25-3 shows another embodiment of a drill bit 2510-3 comprising a hinged arm 2550-3 with cutting elements 2524-3 secured thereto. In this embodiment, the hinged arm 2550-3 is rotated to retract the cutting elements 2524-3 from an exterior of the drill bit 2510-3. In this retracted configuration the cutting elements 2524-3 may be shielded from impact. Thus, when extended, as shown in Figure 25-1, the cutting elements 2524-1 may engage a borehole wall (not shown) surrounding the drill bit 2510-1. Alternatively, while retracted, as shown in Figure 25-3, the cutting elements 2524-3 may be shielded from engaging the borehole wall.

In these embodiments, the rotational axis, about which a hinged arm may rotate, runs generally parallel to a rotational axis of a drill bit. However, other configurations similar in some respects to those shown in U.S. Patent No. 8,141,657 to Hutton are also possible.

Figures 26-1 and 26-3 show additional embodiments of drill bits 2610-1 and 2610-3 each comprising one or more cutting elements 2624-1 and 2624-3 radially extendable and retractable from exteriors thereof. These cutting elements 2624-1 and 2624-3 may be secured to rotatable cylindrical drums 2660-1 and 2660-3. Figure 26-2 shows an embodiment of such a cylindrical drum 2660-2 comprising cutting elements 2624-2 secured thereto and rotatable about a rotational axis 2662-2. When rotated to an extended configuration, as shown in Figure 26-1, the cutting elements 2624-1 may engage a borehole wall (not shown) surrounding the drill bit 2610-1.

While rotated to a retracted configuration, as shown in Figure 26-3, the cutting elements 2624-3 may be shielded from engaging the borehole wall. In these embodiments, the rotational axis, about which the cylindrical drum may rotate, runs generally parallel to a tangent of the drill bit to which the cylindrical drum is attached. Figure 27 shows another embodiment of a drill bit 2710. In addition to cutting elements 2724 extendable in a single radial direction (similar in many respects to embodiments previously described), the drill bit 2710 of the present embodiment further comprises a push pad 2770 extendable from the exterior opposite from the single radial direction. Such a push pad 2770 may push off a borehole wall (not shown) surrounding the drill bit 2710 to push the drill bit 2710 toward the cutting elements 2724. This pushing may stabilize the drill bit 2710 as the cutting elements 2724 engage the borehole wall. This pushing may also urge the drill bit 2710 into the now degraded borehole wall to aid in directing the drill bit 2710 as it progresses.

In the embodiment shown, both the push pad 2770 and the cutting elements 2724 are connected to sources of pressurized hydraulic fluid that may impel them outward. In some embodiments, this may even be the same source. In such cases, if a conduit 2737 channeling pressurized hydraulic fluid to the push pad 2770 is activated simultaneously with a conduit 2730 channeling pressurized hydraulic fluid to the extendable cutting elements 2724 then both may extend at the same time.

To avoid damaging a borehole wall, and disturbing its cross-sectional shape, various elements may be added to the gauge pads previously described. For example, the gauge pad 2228 shown in Figure 22 comprises a plurality of studs 2229 formed of superhard materials embedded therein. These studs 2229 may allow the gauge pad 2228 to smoothly push off a borehole wall. In other embodiments, such as one shown in Figure 28-1, a gauge pad 2828-1 may comprise a plate 2829-1 of superhard material secured thereto and covering an exposed section thereof. It is believed that such a plate may enhance the smooth borehole push off.

In an embodiment shown in Figure 28-2, an abrasion-resistant device 2829-2 may be attached to a gauge pad 2828-2 such that it may freely rotate about an axis 2882-2. When acted upon by an external force, such as from a borehole wall, this abrasion-resistant device 2829-2 may rotate out of the way rather than resist. It is believed that this lack of resistance may protect both the borehole wall and the gauge pad 2828-2. Figure 28-4 shows an embodiment of an abrasion-resistant device 2829-4, similar to that shown in Figure 28-2, comprising a plate 2880-4 of superhard material secured to a shaft 2881-4. This shaft 2881-4 may be attached to a gauge pad allowing the plate 2880-4 to rotate thereabout. Figure 28-3 shows another embodiment of an abrasion-resistant device 2829-3 rotatably attached to a gauge pad 2828-3 and Figure 28-5 shows an embodiment of a similar

abrasion-resistant device 2829-5. Rather than comprising a plate of superhard material, the abrasion-resistant device 2829-5 may comprise a plate 2880-5 formed of hard material with a plurality of studs 2889-5, formed of superhard material, embedded therein. While Figures 28-2 and 28-3 show embodiments of abrasion-resistant devices 2829-2, 2829-3 connected to gauge pads 2828-2, 2828-3 at only one end of a rotatable axis projecting generally outward from the gauge pad 2828-2, 2828-3, other embodiments of abrasion-resistant devices may comprise rotational axes in various alternate orientations and possibly connected to a gauge pad at multiple ends.

Figure 29 shows an embodiment of a drill bit 2910 comprising a unique gauge pad 2928. This gauge pad 2928 comprises an abrasion-resistant device 2929 formed generally in the shape of a ring 2990 with a plurality of studs 2929, formed of superhard materials, embedded in an exterior surface thereof. In the embodiment shown, this ring 2990 generally surrounds a circumference of the drill bit 2910. However, other sizes and configurations are also possible. When acted upon by an external force the ring 2990 may rotate around an axis thereof rather than resist.

Figure 30 shows an embodiment of a stabilizer 3010 that may form part of a subterranean drilling operation. The stabilizer 3010 may comprise a plurality of blades 3020 protruding therefrom spaced around a rotational axis 3021 thereof. A plurality of cutting elements 3022, capable of degrading tough earthen matter, may be disposed on each of the blades 3020. The stabilizer 3010 also comprises threadable attachments 3023, 3123 disposed on opposite ends thereof. Additional cutting elements 3024 may be extendable in a single radial direction from an exterior of the stabilizer 3010. Extension of these cutting elements 3024 may cause them to engage a wall of a borehole (not shown) through which the stabilizer 3010 is traveling. This engagement may degrade the borehole wall at certain points around its circumference causing a cross-sectional shape of the borehole to deviate away from circular. Additionally, an abrasion- resistant gauge pad 3028 may protrude from the exterior of the stabilizer 3010 and be positioned axially adjacent the extendable cutting elements 3024.

Figure 31 shows an embodiment of a downhole drill bit assembly comprising a drill bit 3112 secured to an end of a drill string 3114. The drill bit 3112 may comprise a plurality of blades 3122 protruding therefrom. These blades 3122 may be generally spaced about a periphery of one end of the drill bit 3112, opposite from the drill string 3114, and comprise a plurality of tough cutter elements 3126 attached to each of the blades 3122 to aid in degrading hard earthen materials. While a fixed-bladed type drill bit is shown, a variety of other drill bit types could alternately be used.

Figure 32 shows an embodiment of a downhole drill bit assembly that has been partially disassembled to highlight several features thereof. For example, a drill string 3214 may comprise a protrusion 3230 extending from one end thereof. This protrusion 3230 may be inserted into a cavity 3231 of a drill bit 3212. In the embodiment shown, the protrusion 3230 comprises a plurality of threads 3232 disposed thereabout that may engage with comparable threads 3233 formed on an internal surface of the cavity 3231 to secure the protrusion 3230 within the cavity 3231. These threads 3232 and 3233 may comprise complementary geometries such that they cease relative rotation once the protrusion 3230 arrives at a fixed position relative to the cavity 3231. Various markings 3240 and 3241 exposed on exterior surfaces of the drill string 3214 and drill bit 3212, respectively, may also indicate relative alignment.

The protrusion 3230 may comprise an interfacing exchange surface 3234 disposed on a distal tip thereof. Various embodiments of interfacing exchange surfaces may allow for the exchange of electrical, hydraulic, optical and/or electromagnetic signals. In the embodiment shown, the interfacing exchange surface 3234 is capable of exchanging power and data, via electricity and hydraulic fluid, with another interfacing exchange surface 3258 housed within the cavity 3231. Specifically, the interfacing exchange surface 3234 comprises an inductive ring 3235 that may sit adjacent another inductive ring 3236 of the other interfacing exchange surface 3258. While adjacent, electrical signals passing through the one inductive ring 3235 may be communicated to the other inductive ring 3236. These electrical signals may be passed regardless of rotational orientation of the drill string 3214 relative to the drill bit 3212.

As also shown in this embodiment, the interfacing exchange surface 3234 comprises two ducts 3237 exposed on the protrusion 3230 that may conduct fluid into the cavity 3231 and to two other ducts 3238 exposed on the other interfacing exchange surface 3258. These sets of two ducts 3237 and 3238 may allow for hydraulic power to be transmitted from the drill string 3214 to the drill bit 3212. Two nearly-semiannular grooves 3239 may also be positioned on the interfacing exchange surface 3234, one adjacent each of the two ducts 3237 exposed thereon. These nearly-semiannular grooves 3239 may allow fluid to flow therethrough from the two ducts 3237 of the protrusion 3230 to the two ducts 3238 of the cavity 3231 in a wide span of rotational orientations of the drill string 3214 relative to the drill bit 3212. Further, in the event that the span of possible rotational orientations is insufficient, a plate 3259, as shown removed from the interfacing exchange surface 3234 in Figure 32-1, forming the nearly-semiannular grooves 3239 could be exchanged with one comprising offset grooves to adjust the relative positions. As can be seen, only one of a pair of interfacing exchange surfaces needs such grooves for this type of rotationally independent fluid transfer.

Figure 33 shows another embodiment of a downhole drill bit assembly. As can be seen, a chassis 3342, comprising a body separate from a drill bit 3312, may be disposed within a cavity 3331 of the drill bit 3312. A drill string 3314 may be threaded into the cavity 3331 and retain the chassis 3342 therein. If the drill string 3314 were to be unthreaded, the chassis 3342 could be removed from the cavity 3331 and inserted into a different drill bit. This may be advantageous if the drill bit 3312 becomes worn or damaged. Both the drill string 3314 and the chassis 3342 may comprise a fluid channel 3349 passing therethrough allowing drilling fluid traveling through the drill string 3314 to exit through at least one nozzle 3348 of the drill bit 3312.

The drill string 3314 may connect to the chassis 3342 via a pair of interfacing exchange surfaces 3334, similar to those described previously. In this embodiment, the interfacing exchange surfaces 3334 allow for exchange of electricity and hydraulic fluids. For example, a pair of inductive rings 3335 may allow for exchanging electrical signals between the drill string 3314 and the chassis 3342. These electrical signals may be passed to electronics 3343 disposed on an exterior surface of the chassis 3342. These electronics 3343 may be housed within a pressure chamber 3344 formed between the chassis 3342, the cavity 3331 of the drill bit 3312, and pressure seals 3345 disposed on either side of the electronics 3343.

The electronics 3343 may receive additional electrical signals from a sensor 3346, capable of sensing characteristics of a surrounding borehole or parameters of an associated drilling operation, positioned on an exterior surface of the drill bit 3312. It is believed that positioning certain types of sensors as close as possible to an end of a drill bit may be advantageous. In another example, a fluid duct 3337 may allow fluid to flow from the drill string 3314 into another duct 3338 within the chassis 3342. This flow may be possible regardless of rotational positioning of the drill string 3314 relative to the chassis 3342. This other duct 3338 may pass completely through the chassis 3342 and conduct fluid to a cavity 3347 within the drill bit 3312. As the cavity 3347 is filled, a piston 3350 may be forced by fluid pressure within the cavity 3347 to extend from an exterior of the drill bit 3312.

In the embodiment shown, electrical and hydraulic interfacing exchange surfaces 3357 between the chassis 3342 and the drill bit 3312 may be fixed together in a specific rotational orientation such that they rotate together. As can be seen, one of these interfacing exchange surfaces 3357 may connect through the chassis 3342 to one of the other interfacing exchange surfaces 3334 described previously. Additionally, in the case of the electrical connection, the electronics 3343 may be connected to one or both of the interfacing exchange

surfaces 3334, 3357.

Figures 34-1 and 34-2 show embodiments of chassis 3442-1, 3442-2. These

chassis 3442-1, 3442-2 may be generally tubular shaped with a fluid channel 3449-1, 3449-2 passing therethrough. These chassis 3449-1, 3449-2 may also comprise various

electronics 3443-1, 3443-2 disposed circumferentially about an exterior surface thereof. An interfacing exchange surface may be disposed on either end of the chassis 3442-1, 3442-2.

Specifically, a first interfacing exchange surface 3451-1, 3451-2, providing for a connection independent of rotational orientation, may be disposed on one end of the respective

chassis 3442-1, 3442-2 and a second interfacing exchange surface 3450-1, 3450-2, providing for a connection of specific rotational orientation, may be disposed on an opposite end thereof. The first interfacing exchange surface 3451-1 may comprise ducts 3452-1 for hydraulic exchange and an inductive ring 3453-1 for electrical exchange. The second interfacing exchange

surface 3450-2 may comprise ducts 3452-2 for hydraulic exchange and a stab connection 3453-2 for electrical exchange.

Figure 35 shows an embodiment of a downhole drilling assembly 3511 comprising a drill string 3514 secured to a sub 3520, and the sub 3520 further secured to a drill bit 3510. A continuous fluid channel 3525 may pass axially through the drill string 3514 and sub 3520, and into the drill bit 3510. While any of a variety of types of drill bits may serve in this role and function with the novel elements described herein, the present embodiment drill bit 3510 comprises a plurality of blades 3521, spaced around a central axis, protruding from one end thereof. A plurality of cutting elements 3522 may be exposed on leading edges of each of the blades 3521. Such cutting elements 3522 may comprise a superhard material (i.e. a material comprising a Vickers hardness test number exceeding 40 gigapascals) capable of degrading tough subterranean materials. When the drill bit 3510 is rotated about this axis, the blades 3521 may engage an earthen formation allowing the cutting elements 3522 to bore a hole therein.

While it is common for drill bits used in downhole drilling to comprise a threaded protrusion extending therefrom for attachment, the drill bit 3510 of the embodiment shown comprises an internally-threaded cavity 3523 positioned axially opposite the blades 3521 and cutting elements 3522. An extender 3524 may be seated within this cavity 3523. This may allow for access deep into the drill bit 3510. When seated, this extender 3524 may comprise a proximal end that contacts a nadir of the drill bit 3510 cavity 3523. The cavity 3523 may be formed so deep into the drill bit 3510 that the cutting elements 3522 axially span this proximal end and nadir. The extender 3524 may also comprise and a distal end that extends to within two inches of a mouth of the cavity 3523. It is believed that this positioning relative to the cavity's 3523 mouth may allow for relatively easy access to this distal end. In the embodiment shown, the extender 3524 comprises a generally conical exterior shape. This conical shape may be widest toward the proximal end and narrow as it approaches the distal end. Additionally, the fluid channel 3525 may pass axially through the extender 3524.

The sub 3520 may be secured to the drill bit 3510 via an externally threaded

protrusion 3526 that may be inserted into the cavity 3523 of the drill bit 3510 and mate with the internal threads therein. These threads may be designed to cease rotation and lock into place at a fixed rotational and axial position. Threading of this protrusion 3526 into the cavity 3523 may act to retain the extender 3524 within the cavity 3523. Similarly, unthreading of the

protrusion 3526 and cavity 3523 may release the extender 3524 such that it may be

interchangeable with an alternate extender.

The sub 3520 may also comprise a cavity 3527 disposed therein comprising internal threads spread over at least a section thereof. A chassis 3528, comprising a generally tubular structure, may be housed within this cavity 3527. The drill string 3514 may comprise an externally threaded protrusion 3530 that may be inserted into the cavity 3527 of the sub 3520 and mate with the internal threads therein. These threads may be designed to cease rotation and lock into place at a fixed rotational and axial position. Threading of this protrusion 3530 into the cavity 3527 may act to both secure the drill string 3524 to the sub 3520 and retain the

chassis 3528 within the cavity 3527. While, unthreading the drill string 3524 from the sub 3520 may allow for both the sub 3520 and the chassis 3528 to be interchangeable with an alternate sub or chassis (or both) of different axial length. The fluid channel 3525 may pass axially through the chassis 3528.

Pairs of interfacing exchange surfaces, at each of the intersections between the drill bit 3510, the sub 3520 and the drill string 3514, may allow for various types of communications to occur between these elements. Mating of each of these pairs of interfacing exchange surfaces, in a manner allowing for communication, may naturally result from the physical attachment of the drill string 3514 to the sub 3520 and the sub 3520 to the drill bit 3510 without additional action. This may allow for such mating to be accomplished as part of the activities already commonly performed as part of a drilling operation.

A first pair of interfacing exchange surfaces 3531 may connect the drill string 3514 to the chassis 3528 within the sub 3520; specifically, one of the first pair of interfacing exchange surfaces 3531 may be disposed on a tip of the protrusion 3530 formed on one end of the drill string 3514. This first pair of interfacing exchange surfaces 3531 may allow for communication between the drill string 3514 and the chassis 3528 regardless of where they land in rotational orientation relative to each other. This independence from reliance on relative rotational orientation for communication may provide an allowance for play in the physical attachment of the drill string 3514 to the sub 3520; which often occurs under dirty and hurried conditions at a drilling location.

A second pair of interfacing exchange surfaces 3532 may connect the chassis 3528 to the extender 3524 within the drill bit 3510. And a third pair of interfacing exchange surfaces 3533 may connect the extender 3524 to the drill bit 3510, in which it is housed. These third interfacing exchange surfaces 3533 may be positioned inside of internal threads within the cavity 3523 of the drill bit 3510. The extender 3524 may be long enough axially that the cutting elements 3522, exposed on an exterior of the drill bit 3510, axially span this connection between the extender 3524 and the drill bit 3510. As opposed to the first pair, the second and third pairs of interfacing exchange surfaces 3532, 3533 may be fixed together in specific relative rotational orientations. In some embodiments, rotational orientation may be maintained by forming stab style connections. Further unlike the first pair, these orientation-specific interfacing exchange surfaces 3532, 3533 may be connected under cleaner and calmer conditions, removed from the drilling location, that may generally lead to more accurate positioning. Additionally, the extender 3524 may aid in bringing such connections out of the cavity 3523 of the drill bit 3510 that could restrict access. Speaking of the extender 3524, one side of each of the second and third pairs of interfacing exchange surfaces 3532, 3533 may be connected to one another via at least one communication conduit 3535 passing through the extender 3524.

One side of each of the first and second pairs of interfacing exchange surfaces 3531, 3532 may be connected to one another via at least one communication conduit 3534 passing through the chassis 3528. The chassis 3528 may further comprise various electronics 3529 disposed circumferentially about an exterior surface thereof. These electronics 3529 may be housed within a pressure chamber formed between the chassis 3528 and the sub 3520. These electronics 3529 may also be connected to at least one side of the first and second pairs of interfacing exchange surfaces 3531, 3532 via the communication conduit 3534 described previously. As the sub 3520 may be longer than the drill bit 3510, as shown in this embodiment, the size of these electronics 3529 need not be limited by the length of the drill bit 3510.

A pad 3536 may be radially extendable or retractable from a side of the drill bit 3510 via hydraulic pressure applied through the various communication conduits 3534, 3535 described previously. Extension of this pad 3536 may be to perform any of a variety of downhole functions, such as steering or stabilization. Specifically, as the pad 3536 extends it may push against an interior of a borehole (not shown) through which the drill bit 3510 is traveling to change its direction of travel or hold it in place. Activation of such a downhole function may be controlled by the electronics 3529 disposed downhole around the chassis 3528.

Figures 36-1 and 36-2 show additional embodiments of downhole drilling

assemblies 3611-1 and 3611-2 respectively. Each of the downhole drilling

assemblies 3611-1, 3611-2 may comprise a drill string 3614-1, 3614-2 secured to a

sub 3620-1, 3620-2, which is further secured to a drill bit 3610-1, 3610-2. Further, each embodiment comprises a mechanism, in addition to threads (hidden) described previously, for securing the attachment of the sub 3620-1, 3620-2 to its respective drill bit 3610-1, 3610-2. This additional security may be to prevent accidental or unintentional removal of the drill bit 3610-1, 3610-2 from the sub 3620-1, 3620-2 while attempting to remove the

sub 3620-1, 3620-2 from its respective drill string 3614-1, 3614-2.

Specifically, Figure 36-1 shows an embodiment of a downhole drilling assembly 3611-1 comprising a weld or adhesive 3640-1 securing the drill bit 3610-1 to the sub 3620-1.

Figure 36-2 shows an embodiment of a downhole drilling assembly 3611-2 comprising a plurality of mechanical fasteners 3641-2 that may each be threaded radially into the sub 3620-2 to further secure the drill bit 3610-2 to the sub 3620-2. One of these mechanical

fasteners 3641-2 is shown partly removed to reveal the threads. Additionally, each of these mechanical fasteners 3641-2 may comprise an exposed head comprising a unique geometry requiring a specialized tool for removal.

Each of the first, second and third pairs of interfacing exchange surfaces may allow for various types of communication. For example, any of the pairs of interfacing exchange surfaces may allow for the exchanging of electrical, hydraulic, optical and/or electromagnetic signals; although, they may do this in different ways. Specifically, the first pair of interfacing exchange surfaces, between the drill string and the chassis, may allow for this communication independent of any specific rotational orientation. Figure 37 shows one possible embodiment of a rotationally-independent pair of interfacing exchange surfaces. Particularly, a threaded protrusion 3740 may be received and secured within a threaded cavity 3741. This

protrusion 3740 comprises one interfacing exchange surface 3742 disposed on a distal tip thereof. In the embodiment shown, this interfacing exchange surface 3742 is capable of exchanging power and data, via electricity and hydraulic fluid, with another interfacing exchange surface 3743 housed within the cavity 3741. While this embodiment shows electrical and hydraulic based communication, other media such as optical or electromagnetic signals are also possible.

With respect to electricity, the interfacing exchange surface 3742 comprises an inductive ring 3744 that may sit adjacent another inductive ring 3745 of the other interfacing exchange surface 3743. While adjacent, electrical signals passing through the one inductive ring 3744 may be communicated to the other inductive ring 3745 via inductive coupling. These electrical signals may be passed regardless of relative rotational orientation of the pair of interfacing exchange surfaces 3742, 3743. With respect to hydraulic fluid, the interfacing exchange surface 3742 comprises two ducts 3746 exposed thereon that may conduct fluid to two other ducts 3747 exposed on the other interfacing exchange surface 3743. These sets of two ducts 3746, 3747 may allow for hydraulic power and/or pulsing data to be transmitted between the pair of interfacing exchange

surfaces 3742, 3743. Two nearly-semiannular grooves 3748 may also be positioned on the interfacing exchange surface 3748 inside the inductive ring 3744 discussed previously, one adjacent each of the two ducts 3746 exposed thereon. These nearly-semiannular grooves 3748 may allow fluid to flow therethrough from the two ducts 3746 of the protrusion 3740 to the two ducts 3747 of the cavity 3741 in a wide span of relative rotational orientations. As can be seen, only one of a pair of interfacing exchange surfaces needs such grooves for this type of rotationally independent fluid transfer.

In the embodiment shown, the ducts 3747 are positioned directly opposite each other, or 180 degrees apart, however, this spacing is not necessary. Specifically, similar ducts may be spaced at different angular positions in different embodiments. Further, threads of the protrusion 3740 may be roughly timed to threads of the cavity 3741 such that, even under imprecise conditions, the ducts 3747 are not blinded by blanks between the nearly-semiannular grooves 3748.

Other pairs of interfacing exchange surfaces, such as the second pair between the chassis and the extender and the third pair between the extender and the drill bit, may require a specific rotational orientation for communication. Figure 38 shows one possible embodiment of a rotationally-fixed pair of interfacing exchange surfaces. One interfacing exchange surface 3842 may comprise a plurality of pins 3850 protruding therefrom. Another interfacing exchange surface 3843 may comprise a plurality of sockets 3851 into which the pins 3850 may insert when the two interfacing exchange surfaces 3842, 3843 are paired with one another. Insertion of the pins 3850 into the sockets 3851 may align a plurality of ducts 3846 exposed on the one interfacing exchange surface 3842 with a matching plurality of ducts 3847 exposed on the other interfacing exchange surface 3843. In such a configuration, fluid may flow between the two sets of ducts 3846, 3847 to transmit hydraulic power and/or pulsing data between the interfacing exchange surfaces 3842, 3843 when rotationally aligned in a specific orientation. Further, the pins 3850 and sockets 3851 may be wired to transmit electrical power and/or data. Whereas this discussion has referred to the figures 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 disclosure.

Claims

1. A subterranean borehole, comprising:

an internal wall formed within an earthen formation defining an elongate hollow;

the wall delineating a cross-sectional shape within a plane perpendicular to an axis

passing through the hollow; and

the cross-sectional shape comprising first and second circular arcs, both centered at the axis but comprising distinct radii.

2. The subterranean borehole of claim 1, further comprising a drilling tool disposed within the hollow; wherein a radius of the first circular arc is larger than, and a radius of the second circular arc is smaller than, a cross-sectional radius of the drilling tool.

3. The subterranean borehole of claim 2, wherein the internal wall contacts the drilling tool at two points of the cross-sectional shape.

4. The subterranean borehole of claim 3, wherein the two points are located on the second circular arc.

5. The subterranean borehole of claim 1, wherein the axis is curved; a radius of the first circular arc is larger than one of the second circular arc; and the first circular arc is closer to a center of curvature of the axis than the second circular arc.

6. The subterranean borehole of claim 1, wherein the first and second circular arcs occupy distinct angular ranges about the axis.

7. The subterranean borehole of claim 6, wherein the axis is curved and a radius of curvature of the axis is dependent on the relative dimensions of the radii or angular ranges of the first and second circular arcs.

8. The subterranean borehole of claim 6, wherein the radii or angular ranges of the first and second circular arcs vary in dimension at different positions along the axis.

9. The subterranean borehole of claim 6, wherein the angular ranges of the first and second circular arcs vary in rotational orientation about the axis at different positions along the axis.

10. A method for forming a subterranean borehole, comprising:

boring an elongate hollow, comprising an axis passing therethrough and a cross-sectional shape within a plane perpendicular to the axis, within an earthen formation; and removing earthen material from an internal wall of the hollow to create first and second circular arcs on the cross-sectional shape, both centered at the axis but comprising distinct radii.

11. The method of claim 10, further comprising disposing a drilling tool, comprising a cross-sectional radius smaller than the first circular arc but larger than the second circular arc, within the hollow and forcing the drilling tool into the first circular arc with the second circular arc.

12. The method of claim 11, wherein the forcing of the drilling tool forms a curve in the axis as the hollow is bored.

13. The method of claim 11, further comprising adjusting the forcing of the drilling tool by altering distinct radii or angular ranges occupied by the first and second circular arcs.

14. The method of claim 13, wherein adjusting the forcing comprises altering a magnitude of force by altering respective dimensions of the radii or angular ranges of the first and second circular arcs.

15. The method of claim 13, wherein adjusting the forcing comprises altering a direction of force by altering respective rotational orientations about the axis of the angular ranges of the first and second circular arcs.

16. The method of claim 13, wherein adjusting the forcing of the drilling tool alters a curve in the axis as the hollow is bored.

17. The method of claim 10, wherein:

boring the elongate hollow comprises rotating a drilling tool;

removing earthen material from the internal wall to create the first circular arc comprises extending a cutting element from a side of the drilling tool during a first portion of rotation; and

creating the second circular arc comprises retracting the cutting element during a second portion of rotation.

18. The method of claim 17, further comprising altering timing of the cutting element extension and retraction to adjust angular ranges occupied by the first and second circular arcs.

19. The method of claim 18, further comprising decreasing a dimension of the angular range occupied by the first circular arc to decrease a radius of curvature of the axis.

20. The method of claim 17, further comprising altering depth of the cutting element extension and retraction to adjust radii occupied by the first and second circular arcs.