Patent Application
20100276200
The present invention, in several embodiments, relates generally to a rotary fixed cutter or “drag” drill bit employing superabrasive cutters for drilling subterranean formations and, more particularly, to use of bearing blocks in association with superabrasive cutters to provide improved accuracy for obtaining one or more target depths of cut for the cutters, a controlled bearing area on the face of the drill bit, or both. Methods of drilling are also encompassed by embodiments of the invention.
Rotary drag bits employing superabrasive cutting elements in the form of polycrystalline diamond compact (PDC) cutters have been employed for several decades. PDC cutters are typically comprised of a disc-shaped diamond “table” formed on and bonded under high-pressure and high-temperature conditions to a supporting substrate such as cemented tungsten carbide (WC), although other configurations are known. Bits carrying PDC cutters, which for example, may be brazed into pockets in the bit face, pockets in blades extending from the face, or mounted to studs inserted into the bit body, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. Recent improvements in the design of hydraulic flow regimes about the face of bits, cutter design, and drilling fluid formulation have reduced prior, notable tendencies of such bits to “ball” by increasing the volume of formation material which may be cut before exceeding the ability of the bit and its associated drilling fluid flow to clear the formation cuttings from the bit face.
Even in view of such improvements, however, PDC cutters still suffer from what might simply be termed “overloading” even at low weight-on-bit (WOB) applied to the drill string to which the bit carrying such cutters is mounted, especially if aggressive cutting structures are employed. The relationship of torque to WOB may be employed as an indicator of aggressivity for cutters, so the higher the torque to WOB ratio, the more aggressive the bit. The problem of excessive bit aggressiveness is particularly significant in low compressive strength formations where an unduly great depth of cut (DOC) may be achieved at extremely low WOB. The problem may also be aggravated by drill string bounce or torque and drag, wherein the elasticity of the drill string may cause erratic application of WOB to the drill bit or the drill pipe dragging on the wall of the borehole, with consequent overloading. Moreover, operating PDC cutters at an excessively high DOC may generate more formation cuttings than can be consistently cleared from the bit face and back up the bore hole via the junk slots on the face of the bit by even the aforementioned improved, state-of-the-art bit hydraulics, leading to the aforementioned bit balling phenomenon.
Another, separate problem involves drilling from a zone or stratum of higher formation compressive strength to a “softer” zone of lower compressive strength. As the bit drills into the softer formation without changing the applied WOB (or before the WOB can be reduced by the driller), the penetration of the PDC cutters, and thus the resulting torque on the bit (TOB), increase almost instantaneously and by a substantial magnitude. The abruptly higher torque, in turn, may cause damage to the cutters and/or the bit body itself In directional drilling, such a change causes the tool face orientation of the directional (measuring-while-drilling, or MWD, or a steering tool) assembly to fluctuate, making it more difficult for the directional driller to follow the planned directional path for the bit. Thus, it may be necessary for the directional driller to back off the bit from the bottom of the borehole to reset or reorient the tool face. In addition, a downhole motor, such as drilling fluid-driven Moineau-type motors commonly employed in directional drilling operations in combination with a steerable bottomhole assembly, may completely stall under a sudden torque increase. That is, the bit may stop rotating, thereby stopping the drilling operation and again necessitating backing off the bit from the borehole bottom to re-establish drilling fluid flow and motor output. Such interruptions in the drilling of a well can be time consuming and quite costly.
Numerous attempts using varying approaches have been made over the years to protect the integrity of diamond cutters and their mounting structures and to limit cutter penetration into a formation being drilled. For example, from a period even before the advent of commercial use of PDC cutters, U.S. Pat. No. 3,709,308 discloses the use of trailing, round natural diamonds on the bit body to limit the penetration of cubic diamonds employed to cut a formation. U.S. Pat. No. 4,351,401 discloses the use of surface set natural diamonds at or near the gage of the bit as penetration limiters to control the depth-of-cut of PDC cutters on the bit face. The following other patents disclose the use of a variety of structures immediately trailing PDC cutters (with respect to the intended direction of bit rotation) to protect the cutters or their mounting structures: U.S. Pat. Nos. 4,889,017; 4,991,670; 5,244,039 and 5,303,785. U.S. Pat. No. 5,314,033 discloses, inter alia, the use of cooperating positive and negative or neutral backrake cutters to limit penetration of the positive rake cutters into the formation. Another approach to limiting cutting element penetration is to employ structures or features on the bit body rotationally preceding (rather than trailing) PDC cutters, as disclosed in U.S. Pat. Nos. 3,153,458; 4,554,986; 5,199,511 and 5,595,252.
In another context, that of so-called “anti-whirl” drilling structures, it has been asserted in U.S. Pat. No. 5,402,856 that a bearing surface aligned with a resultant radial force generated by an anti-whirl underreamer should be sized so that force per area applied to the borehole sidewall will not exceed the compressive strength of the formation being underreamed. See also U.S. Pat. Nos. 4,982,802; 5,010,789; 5,042,596; 5,111,892 and 5,131,478.
While some of the foregoing patents recognize the desirability to limit cutter penetration, or DOC, or otherwise limit forces applied to a borehole surface, the disclosed approaches are somewhat generalized in nature and fail to accommodate or implement an engineered approach to achieving a target ROP in combination with more stable, predictable bit performance. Furthermore, the disclosed approaches do not provide a bit or method of drilling which is generally tolerant to being axially loaded with an amount of weight-on-bit over and in excess what would be optimum for the current rate-of-penetration for the particular formation being drilled and which would not generate high amounts of potentially bit-stopping (e.g., stick-slip) or bit-damaging torque-on-bit should the bit nonetheless be subjected to such excessive amounts of weight-on-bit.
Various successful solutions to the problem of excessive cutter penetration are presented in U.S. Pat. Nos. 6,298,930; 6,460,631; 6,779,613 and 6,935,441, the disclosure of each of which is incorporated by reference in its entirety herein. Specifically, U.S. Pat. No. 6,298,930 describes a rotary drag bit including exterior features to control the depth of cut by cutters mounted thereon, so as to control the volume of formation material cut per bit rotation as well as the torque experienced by the bit and an associated bottom-hole assembly. These features, also termed depth of cut control (DOCC) features, provide the bearing surface or sufficient surface area to withstand the axial or longitudinal WOB without exceeding the compressive strength of the formation being drilled and such that the depth of penetration of PDC cutters cutting into the formation is controlled. Because the DOCC features are subject to the applied WOB as well as to contact with the abrasive formation and abrasives-laden drilling fluids, the DOCC features may be layered onto the surface of a steel body bit as an appliqué or hard face weld having the material characteristics required for a high load and high abrasion/erosion environment, or include individual, discrete wear resistant elements or inserts set in bearing surfaces cast in the face of a matrix-type bit, as depicted in FIG. 1 of U.S. Pat. No. 6,298,930. The wear resistant inserts or elements may comprise tungsten carbide bricks or discs, diamond grit, diamond film, natural or synthetic diamond (PDC or TSP), or cubic boron nitride.
FIGS. 10A and 10B of U.S. Pat. No. 6,298,930, respectively, depict different DOCC feature and PDC cutter combinations. In each instance, a single PDC cutter is secured to a combined cutter carrier and DOC limiter, the carrier then being received within a cavity in the face (or on a blade) of a bit and secured therein. The DOC limiter includes a protrusion exhibiting a bearing surface.
The aforementioned and incorporated by reference, U.S. patent application Ser. No. 11/818,820 discloses another solution to the problem of excessive cutter penetration. As described therein, interchangeable bearing blocks may be disposed in receptacles in a bit body of a drill bit proximate to a plurality of PDC cutters. The interchangeable bearing blocks may act to limit the DOC of the PDC cutters proximate to the bearing blocks.
In some embodiments, the present invention includes a method of drilling a subterranean formation comprising coupling at least one bearing block having at least one rubbing surface and an initial thickness to a drill bit, engaging a formation with at least one cutter of the drill bit within an initial depth of cut range, drilling the formation with the drill bit, and reducing the initial thickness of the bearing block by contacting the formation with the at least one rubbing surface to cause the initial depth of cut range to be at least partially increased.
In additional embodiments, the present invention includes a method of drilling a subterranean formation. The method includes coupling at least one bearing block having at least one rubbing surface and an initial thickness to a drill bit, engaging a formation with at least one cutter of the drill bit within an initial depth of cut range, drilling the formation with the drill bit, and increasing the initial depth of cut range by contacting the formation with the at least one rubbing surface to cause the initial thickness of the bearing block to be at least partially reduced. The method may, optionally, also include selecting one or more materials for the bearing block to wear at a predictable rate when engaged with a particular formation material or materials.
In additional embodiments, the present invention includes a method of forming a drill bit for drilling a subterranean formation. The method includes forming at least one bearing block having at least one rubbing surface from at least one material exhibiting at least one of a wear rate and a reduced coefficient of friction as compared to another rubbing surface of the drill bit when the at least one rubbing surface is rotated by the drill bit in contact with the subterranean formation and coupling the at least one bearing block having the at least one rubbing surface to the drill bit.
In further embodiments, the present invention includes a method of drilling comprising drilling a first formation with a first average depth of cut and subsequently drilling a second formation with a second, substantially greater depth of cut.
In yet additional embodiments, the present invention includes a drill bit assembly for subterranean drilling comprising a drill bit including a plurality of blades, a plurality of cutting elements disposed on the plurality of blades, and at least one receptacle located in at least one blade of the plurality of blades. The drill bit assembly further comprises at least one bearing block disposed in the at least one receptacle. The at least one bearing block comprises a distal portion configured to provide at least one cutting element of the plurality of cutting elements with an initial depth of cut range and a base portion configured to provide the at least one cutting element of the plurality of cutting elements with an increased depth of cut range greater than the initial depth of cut range.
In yet additional embodiments, the present invention includes a bearing block for a rotary drill bit for subterranean drilling. The bearing block includes a body portion configured to secure to a complementary structure on a blade of a drill bit and a non-planar rubbing surface configured to contacting a formation during drilling with the drill bit under applied WOB. The bearing block material may be selected for specific wear or frictional characteristics, or both.
The illustrations presented herein are not actual views of any particular drilling system, assembly, or device, but are merely idealized representations which are employed to describe embodiments of the present invention.
An embodiment of the current invention is shown in
Fluid courses 20 lie between blades 18 and are provided with drilling fluid by nozzles 22 secured in nozzle orifices 24, nozzle orifices 24 being at the end of passages leading from a plenum extending into the bit body from a tubular shank at the upper, or trailing, end of the bit 10. Fluid courses 20 extend to junk slots 26 extending upwardly along the side of bit 10 between blades 18. Gage pads (not shown) comprise longitudinally upward extensions of blades 18 and may have wear-resistant inserts or coatings on radially outer surfaces 21 thereof as known in the art. Formation cuttings are swept away from PDC cutters 14 by drilling fluid emanating from nozzle orifices 24 which moves generally radially outwardly through fluid courses 20 and then upwardly through junk slots 26 to an annulus between the drill string from which the bit 10 is suspended and on to the surface.
Simultaneous reference may be made to
The bearing block 40, as shown in
It is noted that the word “block” as used to describe the bearing block 40 as given in the first embodiment of the invention, or any other embodiment, is not intended to create or import unintended structural limitations. Specifically, the word “block” is intended to mean piece, portion, part, insert, object, or body, without limitation, all of which have mass and shape, without further limitation to material and/or other physical attributes except as expressly presented herein.
The bearing block 40, trailing a plurality of cutters 14, provides a designed bearing or rubbing area 42 affording a surface area specifically tailored to provide support for bit 10 under axial or longitudinal WOB on a selected formation being drilled without exceeding the compressive strength thereof. Further, the bearing block 40 is manufactured, in association with receptacle 28, to provide a precision TDOC relating to the distance (thickness) 44 between the bottom 37 and the rubbing surface 32 of the bearing block 40. Resultantly, the bearing block 40, as inserted into the receptacle 28, defines the TDOC for the plurality of associated cutters 14, the TDOC being indicated in
Tailoring the configuration of the bearing block advantageously provides specifiable TDOC, limiting manufacturing uncertainty as well as reducing complexity of bit production by bringing to the manufacturing process a high precision and easily alterable component, i.e., the bearing block, without altering the base product, i.e., the bit body or frame. Also, the bearing block may be configured to provide for a selectable rubbing surface area not necessitating alteration to the bit body or frame. Moreover, the bearing block enables a variety of TDOCs and rubbing surface areas to be selectably chosen for a given bit body or frame, reducing inventory loads for bit frames by enhancing design rationalization and further facilitating refurbishment of a given bit in order to acquire a different TDOC and bearing or rubbing surface area by exchanging out and replacing the bearing block. Further, the use of a discrete, separately manufactured bearing block eliminates imprecision associated with hardfacing a steel bit body to provide a DOC limiting feature or complex machining of a bit mold to provide a DOC feature on a matrix bit body face, increasing precision of cutter exposure and desired bearing or rubbing area. Furthermore, the bearing block may be made from or optionally include a facing of an abrasion resistant materials to further enhance the life of the bit
Optionally, as can be seen in
Additional embodiments of the invention are shown in
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In some embodiments, the bearing block may comprise a “harder” material exhibiting high hardness and wear-resistant properties such as abrasion- and erosion-resistant characteristics. So-called “harder” materials may comprise materials such as tungsten carbide, natural or synthetic diamond (polycrystalline diamond compact (PDC) or thermally stable polycrystalline (TSP)), ceramic materials, or impregnated materials composed of diamond material, such as natural or synthetic diamond grit, dispersed within a matrix of wear resistant material. Use of harder materials in the bearing block may allow for a relatively consistent DOC during a drilling operation through one or more formations. That is, the harder, wear-resistant bearing block will substantially maintain its thickness throughout the drilling operation. Thus, an initially TDOC specified will be substantially maintained during a drilling operation. Other materials may also be utilized, alone or in combination, for the bearing block including homogenous or heterogeneous block materials. For example, materials exhibiting high hardness and abrasion- and erosion-resistant characteristics may be carried on supporting substrates exhibiting superior toughness and ductility such as thermally stable polycrystalline (TSP) diamond material disposed on a supporting substrate and other carbide materials.
In some embodiments, low friction materials (i.e., materials exhibiting a lower frictional force when the bearing block is rotated in contact with the formation) such as, for example, diamond, ceramic, hardened steel, or other alloy materials, or materials having a polished or other low-friction surface or coating may be selected. Low friction materials may exhibit a relatively lower coefficient of friction between the rubbing surface of the bearing block and the formation as the rubbing surface travels across the formation, resulting in a decrease in the amount of frictional force. For example, referring to
Further, in some embodiments it may be desirable to form a bearing block from a “softer” material, for example, a material selected for wear and exhibiting diminished properties such as wear-resistance, hardness, and abrasion- and erosion-resistant characteristics as compared to those detailed above. So-called “softer” materials may comprise materials such as a relatively soft carbide material, steel, other alloy, or particle-matrix composite materials. For example, a relatively soft carbide material may comprise hard particles (e.g., tungsten carbide) in a metal matrix material such as, for example, a cobalt or cobalt-based alloy. Such a relatively soft carbide may include a higher percentage by weight of the metal matrix material causing the resultant carbide to exhibit a relatively lower amount of wear-resistance than a carbide having a lower percentage by weight of the metal matrix material. For example, a relatively soft carbide may include a cobalt or cobalt-based alloy content of 4% to 30% by weight. In some embodiments, the relatively soft carbide may include a cobalt or cobalt-based alloy content of 16% by weight.
As above, the softer material may be used to form the entire bearing block or to form the rubbing surface while another material is used to form the base portion. The softer material may enable the thickness of the bearing block to be varied during a drilling process without having to modify the drill bit. For example, a drilling process may begin with a bearing block of an initial thickness providing for a lower TDOC. As the drilling process progresses the softer material of the bearing block will be subject to abrasion and erosion exhibited in the drilling process. The abrasion and erosion may tend to reduce the thickness of the bearing block with diminished wear-resistance. As the thickness of the bearing block is reduced, the DOC will increase. Thus, the bearing block formed from a softer material may enable drilling operations to select a variable TDOC based on wellbore variables such as the type and depth of the formations being drilled with the bit, and the material properties of the softer material.
For example, the bearing block may be fabricated to provide a variable DOCC and TDOC during a directional drilling operation. In a directional drilling operation, the bottomhole assembly of a drill string including a downhole motor such as a Positive Displacement Motor (PDM) or hydraulic Moineau-type may be directed to follow a desired path. Systems utilizing ribs or a bent sub to steer a drill string are disclosed, for example, in U.S. Pat. No. 7,413,032, issued Aug. 19, 2008, entitled “Self-controlled Directional Drilling Systems and Methods” and U.S. Pat. No. 5,738,178, issued Apr. 14, 1998, entitled “Method and Apparatus for Navigational Drilling with a Downhole Motor Employing Independent Drill String and Bottomhole Assembly Rotary Orientation and Rotation” both of which are assigned to the assignee of the present invention and the entire disclosure of each of which patents is incorporated herein by this reference. In a directional drilling process, the initial bearing block thickness may be selected to exhibit an initial, relatively low TDOC allowing for better tool face control as a curve to drill directionally is initiated. As the curve is “kicked off” and the drill string is directed at an angle to the original substantially vertical drilling direction, the bearing block comprising a softer material will exhibit a reduced thickness and provide an increased DOC for drilling the curve and the subsequent lateral (tangent) section of the wellbore in a more aggressive manner. As the drill string is directed in a substantially horizontal direction, the thickness of the bearing block may be even further reduced allowing for an ever greater DOC.
In another scenario, it is contemplated that a first formation requiring a lesser TDOC for an optimum rate of penetration (ROP) may be drilled through initially, followed by drilling through a second formation requiring a greater TDOC for an optimum rate of penetration. Based upon the material characteristics of a portion of the bearing block to be worn during drilling, the formation abrasivity, erosiveness of the drilling fluid employed, and the thickness of the first formation to be drilled through before reaching the second formation, the bearing block wear material and thickness of such material may be selected to substantially optimize drilling performance in both formations. Thus, an embodiment of a method of drilling according to the present invention comprises drilling a first formation with a first average depth of cut and subsequently drilling a second formation with a second, substantially greater depth of cut.
Referring again to
In summary, a bearing block according to embodiments of the invention may be configured for use with one or more blades of a bit body or frame. The inventive bearing block is designed so that it may be replaced or repaired, typically, without necessitating alteration to a standardized bit frame. The interchangeable, customizable bearing block may include one or more of a specifically selected thickness, a rubbing surface orientation and an area suitable for improving drilling performance of a bit. Bearing blocks with varying thicknesses and rubbing surface orientations, topographies and areas may be implemented. Use of different surface orientations and, particular, shapes may be used to create more or less rubbing at certain speeds (DOC) or at different wear states. This variability may be enhanced by utilizing a bearing block that exhibits a rubbing surface area contacting the formation that changes with wear.
The bearing block may be located substantially in the cone region on a blade of the bit frame, in the cone/nose region, in the nose region, etc. The interchangeable, modifiable bearing block according to embodiments of the invention brings manufacturing selectability by providing a customizable product suitable for use with a common bit frame, thus, not requiring a complex assortment of stocked bit frames. Each bearing block is selectably insertable into a bit frame, enabling a bit to be customized or adapted for different drilling applications, including difficult formations, or for different drilling systems. Also, by providing a block that is selectively connectable to a bit frame, different cutting characteristics may be advantageously obtained without affecting or requiring alteration of the bit frame. Moreover, the bearing block may be designed for specific associated cutters or sets of cutters to obtain customized cutter profiles and TDOCs, due to the ability of the bearing block with a customized profile and wear properties to be connected to a common bit frame without alteration thereto.
Additionally, bearing blocks fabricated from a variety of materials may provide greater flexibility in drilling operations utilizing bearing blocks for varied drilling applications. Materials such as harder materials may be selected to provide a substantially consistent DOC through a drilling process. Alternatively, softer materials may be selected to provide a varied depth of cut during a drilling process. Bearing blocks comprising different combinations of materials may enable for even greater flexibility in varying the DOC and DOCC throughout a drilling process. Further, lower friction materials may also be selected to increase efficiency during the drilling process.
While particular embodiments of the invention have been shown and described, numerous variations and alternate embodiments will occur to those skilled in the art. Accordingly, it is intended that the invention only be limited in terms of the appended claims and their legal equivalents.
This application claims the benefit of U.S. Provisional Patent Application Ser. No. 61/174,412, filed Apr. 30, 2009, the disclosure of which is hereby incorporated herein by this reference in its entirety. The application is also related to, but does not claim priority to, copending U.S. patent application Ser. No. 11/818,820, filed Jun. 14, 2007, the disclosure of which is hereby incorporated herein by this reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 61174412 | Apr 2009 | US |
