Patent Application
20080251297
Embodiments of the present invention relate generally to earth-boring tools and, more particularly, to earth-boring tools comprising passive and active up-drill protective and cutting features.
Drilling wells for oil and gas production conventionally employs longitudinally extending sections, or so-called “strings,” of drill pipe to which, at one end, is secured a drill bit of a larger diameter. The drill bit conventionally forms a bore hole through the subterranean earth formation to a selected depth. Generally, after a selected portion of the bore hole has been drilled, the drill bit is removed from the bore hole so that a string of tubular members of lesser diameter than the bore hole, known as casing, can be placed in the bore hole and secured therein with cement. Therefore, drilling and casing according to the conventional process typically requires sequentially drilling the bore hole using drill string with the drill bit attached thereto, removing the drill string and drill bit from the bore hole, and disposing and cementing a casing into the bore hole.
Rotary drill bits are commonly used for drilling such bore holes or wells. One type of rotary drill bit is the fixed-cutter bit (often referred to as a “drag” bit), which typically includes a plurality of cutting elements secured to a face region of a bit body. Referring to
The drill bit includes an outer diameter 155 defining the radius of the wall surface of a bore hole. The outer diameter 155 may be defined by a plurality of gage regions 160, which may also be characterized as “gage pads” in the art. Gage regions 160 comprise longitudinally upward (as the drill bit 100 is oriented during use) extensions of blades 130. The gage regions 160 may have wear-resistant inserts and/or coatings, such as hardfacing material, tungsten carbide inserts natural or synthetic diamonds, or a combination thereof, on radially outer surfaces 165 thereof as known in the art to inhibit excessive wear thereto so that the design borehole diameter to be drilled by the drill bit is maintained over time.
A plurality of cutting elements 180 is conventionally positioned on each of the blades 130. Generally, the cutting elements 180 have either a disk shape or, in some instances, a more elongated, substantially cylindrical shape. The cutting elements 180 commonly comprise a “table” of super-abrasive material, such as mutually bound particles of polycrystalline diamond, formed on a supporting substrate of a hard material, conventionally cemented tungsten carbide. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutting elements or cutters. The plurality of PDC cutting elements 180 may be provided within cutting element pockets 190 formed in rotationally leading surfaces of each of the blades 130. Conventionally, a bonding material such as an adhesive or, more typically, a braze alloy may be used to secure the cutting elements 180 to the bit body 110.
The bit body 110 of a rotary drill bit 100 typically is secured to a steel shank 200 having an American Petroleum Institute (API) thread connection for attaching the drill bit 100 to a drill string (not shown). Top transition surfaces 210 are located at the upper ends of the gage regions 160 between the outer diameter defined by the radially outer surfaces 165 of gage regions 160 and a shank shoulder 220. Transition edges 230 are defined between the radially outer surfaces 165 of gage regions 160 and their respective, associated top transition surfaces 210.
During drilling operations, the drill bit 100 is positioned at the bottom of a well bore hole and rotated. Drilling fluid is pumped through the inside of the bit body 110, and out through nozzles (not shown). As the drill bit 100 is rotated, the PDC cutting elements 180 scrape across and shear away the underlying earth formation material. The formation cuttings mix with the drilling fluid and pass through the fluid courses 140 and then through the junk slots 150, up through an annular space between the wall of the bore hole and the outer surface of the drill string to the surface of the earth formation.
When drilling in unconsolidated, highly abrasive and/or hardened formations as well as in other formation materials, the radially outer surface of the gage regions 160 of the drill bits are subjected to wear caused by the abrasive cuttings being drilled, the high sand content in the mud, and the sand particles along the borehole wall. Improvements in the wear-resistant inserts and/or coatings have helped to limit the accelerated wear from occurring to the radially outer surfaces 165 of the gage regions 160 in the normal (i.e., downward) drilling mode. However, when the drill bit 100 is reversed in the bore hole, such as when back reaming or up drilling is performed, substantial wear to the top transition surfaces 210 including the transition edges 230 located near the shank 200 end of the bit may occur. Such wear causes rounding over the gage region 160 and eventually will significantly wear the gage region 160.
Various embodiments of the present invention are directed toward a fixed-cutter drilling tool configured for down drilling and up drilling through subterranean formation and for limiting the accelerated wear from occurring to the passive regions. In one embodiment, the present invention comprises a body comprising an outer diameter and secured to a shank. At least one transition surface may be associated with and positioned between the outer diameter of the body and the lower extent of the shank. At least one up-drill feature may be disposed on the at least one transition surface and may be positioned to be passive (not engage the formation being drilled) during down drilling and active during up drilling, back reaming, or other similar activities.
In another embodiment, the present invention contemplates a system for both down drilling and up drilling with a fixed-cutter drill bit. The system may comprise a bit body comprising a face that defines a distal end. At least one blade may be disposed over a portion of the face and may, at a proximal end thereof, define a gage region. At least one top transition surface may extend from a radially outer surface at a proximal end of the gage region toward a distal end of a shank secured to the bit body, and at least one up-drill feature may be disposed on the at least one top transition surface. The system may comprise a down drilling mode in which, while down drilling, the at least one top transition surface is configured as passive and portions of the bit body distal to the at least one top transition surface are configured as active. Furthermore, the system may comprise an up drilling mode in which, during up drilling or back reaming, the at least one top transition surface is configured as active.
In yet another embodiment, the present invention comprises a method of forming a bore hole. The method may comprise down drilling through a formation with an earth-boring tool. The earth-boring tool may comprise a body comprising a face at a distal end thereof and a gage region near a proximal end thereof, the gage region comprising longitudinally upward extensions of a plurality of blades. At least one top transition surface may extend from a proximal end of the gage region toward a distal end of the bit shank. Furthermore, at least one up-drill feature may be disposed on the at least one top transition surface, the at least one up-drill feature being passive during the down drilling. The method may further comprise up drilling in the bore hole with the earth-boring tool, wherein the at least one up-drill feature engages and cuts through some of the formation.
In another embodiment, the present invention contemplates a method of forming a fixed-cutter drilling tool. The method may comprise forming a body comprising an active region and a passive region in a down drilling mode. The active region may comprise portions of the body distal to a transition edge while the passive region may comprise portions of the body proximal to the transition edge. The body may be configured so that the passive region is active when the body is in an up drilling mode. The method further comprises disposing at least one up-drill feature on the passive region.
The illustrations presented herein are, in some instances, not actual views of any particular up-drill features or drill bit, but are merely idealized representations which are employed to describe the present invention. Additionally, elements common between figures may retain the same numerical designation.
Embodiments of the present invention provide an earth-boring tool comprising features capable of providing wear protection and/or cutting formation material during up drilling, back reaming, and other similar procedures. Referring to
The drill bit 100 may be operated in a conventional down-drilling mode wherein regions or portions of the bit body that are distal to (i.e., below, in vertical drilling) the top transition surfaces 210, and more particularly, to the transition edges 230, are defined as “active” and may engage as well as cut formation material during down drilling and wherein regions or portions of the bit body 110 that are proximal to (i.e., above) the gage region 160, and more particularly, the transition edges 230, and radially inboard of the outermost radius defined by the gage region 160 are defined as “passive” (i.e., does not intentionally engage the formation or cut formation material) during down drilling. The drill bit 100 also may be operated in an up drilling mode, wherein the regions or portions of the bit body 110 that are proximal to the gage region 160, and which are passive during down drilling, are active during up drilling or back reaming. Accordingly, the portions that are active during down drilling typically become passive during up drilling.
The drill bit 100 also comprises an up-drill feature 240 strategically located on the passive portions of the bit body 110. In some embodiments, the up-drill feature 240 may comprise metallurgically bonded hardfacing or a carbide material and may be similar to those features of U.S. application Ser. No. 11/685,898, referred to herein above and described therein as “hardfacing”, such as hardfacing 61, 71, 81, 91, 101, 111, and/or 121. The up-drill feature 240 is configured for cutting formation material and providing wear protection for the bit body 110 during up drilling or back reaming. Accordingly, the up-drill feature 240 is disposed on portions of the bit body 110 generally located axially above the transition edges 230, and radially inward of the maximum outer diameter of the drill bit 100 (e.g., at the gage region 160). As illustrated in
The up-drill feature 240 may comprise hardfacing material having a thickness of about 0.10 inches or more, as measured from the transition surface 210 itself. In another embodiment, the hardfacing material may comprise a thickness of 0.25 inches or more. The hardfacing material itself may comprise iron or nickel-based materials. By way of example and not limitation, the hardfacing material may include a matrix of Ni—Cr—B—Si with spherical cast WC pellets, and/or spherical sintered WC pellets. Another non-limiting example may include an iron matrix, again with spherical WC pellets, spherical cast WC pellets, crushed sintered WC, and/or crushed cast WC granules or any combination thereof. The hardfacing may be applied using a welding process. Such processes for application of the hardfacing to oil field tools are generally known to those of ordinary skill in the art and may include oxy-acetylene, MIG, TIG, SMA, SCA, PTA, etc. Furthermore, welding may include employing a pulsed arc as well as a constant arc. In some embodiments, the hardfacing may be mechanically shaped, such as by machining, after it is applied to form specific features and/or configurations in the hardfacing material.
In other embodiments, the up-drill features 240 may be preformed from another suitable material, such as, for example carbides or borides of one or more of W, Ti, Mo, Nb, V, Hf, Ta, Cr, Zr, Al, or Si, diamond (natural or synthetic), and diamond impregnated material. In such embodiments, the preformed up-drill feature 240 may comprise similar thicknesses as the hardfacing material. The up-drill feature 240 comprising one or more of these other suitable materials may be attached to the passive portion of the bit body 110. For example, the up-drill feature 240 may be brazed, welded or otherwise secured to the bit body. In some embodiments, the up-drill feature 240 may further be at least substantially covered in a hardfacing material. Such a configuration may be beneficial to form specific features into the up-drill features 240, such as those described in more detail below. For example, a specific feature may be formed by molding or otherwise performing the up-drill feature 240 and then hardfacing material may be disposed over the preformed up-drill feature 240 in such a manner so as to at least substantially retain those external features formed in the preformed up-drill feature 240.
In some embodiments, the drill bit 100 may comprise a plurality of up-drill features 240 on portions of the bit body 110.
In other embodiments, the plurality of up-drill features 240 may comprise differing thicknesses and/or differing shapes. As shown in
In some embodiments, the one or more up-drill features 240 may be disposed over the top transition surfaces 210 extending diagonally from the transition edge 230 toward the shank shoulder 220.
The one or more up-drill features 240 may include one or more specific features configured according to the specific application of the drill bit 100. In some embodiments, the one or more specific features may be formed by applying the hardfacing in such a manner as to form a desired shape and/or contour. In other embodiments, the one or more specific features may be formed by machining the desired shape and/or contour into the hardfacing comprising the one or more up-drill features 240. In still other embodiments, when the up-drill features 240 comprise a carbide material, the one or more specific features may be formed by machining or molding the carbide. By way of example and not limitation, in one embodiment shown in
Still other designs for the up-drill feature 240 include additionally strategic up-drill feature placement and configurations, graded composite hardfacing materials, various carbide materials, recesses or cavities at edges of the outer diameter, and various methods of applying the material also may be employed. Moreover, material may be removed from portions of the bit body to form cavities. In one embodiment, the cavities may be backfilled with hardfacing and comprise additional hardfacing extending out of the cavities above an original surface of the bit body to form up-drill features. In other embodiments, a carbide up-drill feature 240 may be attached, e.g., brazed, to the bit body within the cavities.
Earth-boring tools according to embodiments of the present invention may be employed to form a bore hole in a subterranean formation. An earth-boring tool may be connected to a drill string and may down drill through subterranean formation to form a bore hole therein. The earth-boring tool may be configured according to any of the embodiments described herein above, and includes at least one up-drill feature 240 positioned on a portion of the earth-boring tool. The earth-boring tool may further be used to up drill in the bore hole. As the earth-boring tool up drills in the bore hole, the at least one up-drill feature 240 is configured and positioned as active and directly engages and cuts through some of the formation. As used herein, the term “earth boring tool” includes and encompasses conventional fixed cutter bits including core bits, bicenter bits, eccentric bits, fixed cutter reamers such as, for example, so-called “reamer wings,” and other drilling tools having a suitable surface or surfaces for disposition of an up-drill feature of an embodiment of the invention thereon.
The present invention has utility in relation to fixed-cutter drill bits and other drilling tools having bodies at least substantially comprised of a metal or metal alloy such as steel, but also has utility in bits and tools having bodies at least substantially comprised of particle-matrix composite materials, including conventional infiltrated composite bodies as well as non-infiltrated composite bodies. Conventional infiltrated composite bodies include those in which hard particles (e.g., tungsten carbide) are infiltrated by a molten liquid metal matrix material (e.g., a copper-based alloy) within a mold. Non-infiltrated composite bodies may include, for example, “sintered” particle matrix bits in which a powder metal (e.g., nickel or cobalt powder) is mixed with a powder comprising hard particles (e.g., tungsten carbide) and, thereafter, pressed and sintered to a final density. An example of sintered particle matrix bodies include those disclosed in pending U.S. patent application Ser. No. 11/271,153, filed Nov. 10, 2005 and pending U.S. patent application Ser. No. 11/272,439, also filed Nov. 10, 2005, the disclosure of each of which application is incorporated herein in its entirety by this reference.
While certain embodiments have been described and shown in the accompanying drawings, such embodiments are merely illustrative and not restrictive of the scope of the invention, and this invention is not limited to the specific constructions and arrangements shown and described, since various other additions and modifications to, and deletions from, the described embodiments will be apparent to one of ordinary skill in the art. Thus, the scope of the invention is only limited by the literal language, and legal equivalents, of the claims which follow.
The present application is a continuation-in-part of U.S. patent application Ser. No. 11/685,898, filed Mar. 14, 2007, the disclosure of which application is incorporated herein by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 11685898 | Mar 2007 | US |
| Child | 12133988 | US |
