Cutting structures for casing component drillout and earth-boring drill bits including same

Cutting fittings for removing an oil well casing component and drill bits for ground drilling include the same fittings

Cutting Structures for Casing Component Drillout

and Earth‑Boring Drill Bits Included Same

Full description

Background of the invention

Embodiments of the present description relate generally to drilling a subterranean borehole. More specifically, some embodiments relate to drill bits and tools for drilling subterranean formations and have the ability to remove structures and materials, which may be located at, or near, the end of a casing or liner string, such as a bit or the heel of an oil well casing. bit or shoe, cementing equipment components and cement before drilling subterranean formation. Other embodiments relate to drill bits and tools for drilling through the sidewall casing or liner string and surrounding cement prior to drilling adjacent formation. Other embodiments also relate to drill bits and tools particularly suitable for removing casing components containing rubber or other elastomeric elements.

Drilling wells for oil and gas production conveniently uses longitudinal sections, or so-called "chains", for drilling pipes in which, at one end, a secured drill bit of larger diameter is attached. After drilling the chosen portion of the well, a series of tubular ends with a smaller diameter than the well, known as a casing, are placed in the well. After that, the rings between the well wall and the outside of the casing are filled with cement. Therefore, drilling and casing according to the conventional process typically requires drilling the well sequentially using a drill string with an attached drill bit, removing the drill string and drill bit from the well, and preparing and cementing the casing into the well. Also, many times after lining a section of a well with casing and cement, additional excavation may be required beyond the end of the casing or through the side wall of the casing. In some cases, a series of smaller pipe ends, known as a liner series, is run and cement is placed inside the previously worked cover. As used here, the term "lid" includes tubular members in the form of liners.

Because drilling and running the casing string can be time-consuming and expensive, some methods have been developed to increase efficiency, including the use of reamer stubs arranged on the end of the casing string and drilling the casing itself. Reamer stubs use cutting elements on the core end that can drill through minor obstructions and irregular areas within the previously drilled well, facilitating operation of the cap string and ensuring sufficient diameter for subsequent cementing. The reamer stubs also include an end section made of a material that can be easily drilled with drill bits. Accordingly, when the cement is in place, the reamer stubs usually do not present any difficulty in drilling the next drill bit through them. For example, US Patent No. 6,062,326 by Strong et al. A cap stub or reamer stub with which the inside can be shaped to drill through. However, using reamer stubs requires retrieving the drill bit and drill string used to drill the borehole before running the casing string with the reamer stub into the borehole.

Drilling is effected by casing using a specially designed drill bit, called a casing bit, attached to the end of the casing string. The casing bit serves not only for drilling earth formation, but also for guiding casing into the borehole. Therefore, the casing string operates in the well being drilled with the casing bit, eliminating the necessity of retrieving the drill string and drill bit after reaching the required depth where shoring is required. While this method generally increases the efficiency of drilling, further drilling to a greater depth must pass through or around the casing bit attached to the end of the casing string. In the case of a casing stub, the stub of the reamer or casing bit is drillable. Additional drilling can be accomplished with a smaller diameter drill bit and an attached casing string that passes through the inside of the first casing string to drill another section of the well beyond the specified depth. It has been achieved previously. Of course, cement placement can be repeated and additional drilling done as necessary. With correspondingly smaller and smaller tubular components, until the required depth of the well is achieved.

However, frequently drilling through conventional casing and casing-related components (e.g., casing shoes, reamer stubs, casing bits, casing wall, cementing equipment, cement, etc.) can cause damage. subsequent drill bit and bottom‑hole assembly deployed or reduced penetration at least for some time. For example, conventional drill bits often include highly resistant drilling, robust formulations that are usually made of materials that are difficult to drill through, such as tungsten carbide, polycrystalline diamond, or steel. . Furthermore, conventional float shoes, such as casing shoes or reamer shoes, may include components bonded to the casing that are difficult to remove, such as rubber or other flexible components. These elastomeric components, in some cases, cause the drill bit to rotate on top of the elastomeric component in the removed casing component instead of breaking and removing it, which prevents the cutting elements of the drill bit from interfering with the borehole surface and inhibits the drill bit. inhibiting drill bit of configuration progress. In other cases, conventional drill bits and cutting elements may break the flexible components into pieces of sufficient size to block the passages to clear the drill bit and result in what is known as “balling” of the drill bit. For example, larger elastomeric components may be cut into unwanted holes in conventional bits, making the conventional bit unable to efficiently clear cuttings from the bit surface, leading to the accumulation of cuts and debris that inhibit the drill bit from drilling. During the rest of the cover component and sufficient progress in the formation.

It would be desirable to have a bit or drilling tool capable of drilling through casing or casing-related components, especially those involving plastics, while at the same time providing the core drilling capabilities of a conventional bit or drilling tool that uses superabrasive cutting elements.

General description of the invention

Various embodiments of the present description are directed toward earth-boring tools for drilling through elastomeric casing components and associated material. In one embodiment, the earth‑boring tool of the present description may include a body having a face at its leading end. A group of cutting elements can be arranged on a face. A plurality of abrasive cutting structures may be arranged on the subject object in association with at least some of the plurality of cutting elements. The abrasive cutting assembly assembly may include a composite material comprising an array of carbide particles in a matrix material. The plurality of abrasive cutting structures may include a relative exposure that is sufficiently greater than the relative exposure of at least some of the plurality of cutting elements to enable such abrasive cutting structures to engage and penetrate at least partially into the elastic component while being Effective inhibition of at least a group of cutting elements from engaging with the surface elastomeric component.

Other embodiments of the present description are directed toward methods of drilling with an earth‑boring tool. In one or more embodiments, these methods may include engaging and drilling the flexible component using at least one elongated abrasive cutting assembly and a plurality of wear nodes. The assembly of at least one elongated abrasive piece and wear node assembly may comprise a composite material comprising a plurality of hard particles that exhibit a virtually rough surface in the matrix material. Next, the adjacent subterranean formation can be engaged with the first material and drilled using a combination of cutting elements.

In additional embodiments, these methods may include connecting a flexible component in sufficiently small pieces to enable cutting to be pushed outward from the surface of the earth-boring tool using a plurality of abrasive cutting structures comprising a plurality of hard particles Which actually shows a rough surface in the matrix material.

Brief explanation of the drawings

Figure 1 shows a perspective view of an embodiment of the drill bit, current description;

Figure 2 shows an enlarged perspective view of part of the embodiment Figure 1;

Figure 3 shows an enlarged view of the surface of the drill bit from Figure 1;

Figure 4 shows a perspective view of part of another embodiment of the drill bit of the current description;

Figure 5 shows a magnified view of the surface of a different shape of the embodiment Figure 4;

Figure 6 shows a schematic side cross-section view of the design of placing a cutting element for a drill bit according to the embodiment. Figure 1 shows the relative exposures of the cutting elements and the cutting structures arranged on it;

Figure 7 shows a schematic side cross-sectional view of the design and placement of the cutting element for the drill bit according to the embodiment. Figure 4 shows the relative exposures of the cutting elements and the arrangement of the pieces arranged on them.

Figure 8 shows a perspective view of another embodiment of the drill bit from the current description.

Figure 9 shows a diagram showing the embodiment surface of the drill bit from Figure 8. And

Figure 10 shows an enlarged perspective view of part of the embodiment surface of the drill bit from Figure 8.

Detailed description

The illustrations provided herein, in some cases, are not actual representations of any particular cutting element, cutting fixture, or drill bit, but are merely ideal representations which are used to illustrate the present description. Additionally, elements shared between drawings may retain the same numerical designation.

Figures 1-5 and 8-10 show different shapes and embodiments of the drill bit 12 in the form of a fixed cutter or so-called “traction” bit, according to the current description. For the purpose of clarity, identical numbers have been used to identify the identical components in Figures 1-5 and 8-10. As shown in Figures 1-5 and 8-10, the drill bit 12 includes a body 14 with a face 26 and generally radially extending blades 22, between which fluid sources 24 extend into undesired openings 35 between circumferentially adjacent blades 22 . The body 14 may comprise a tungsten carbide matrix or a steel body, each as is well known in the art. The blades 22 may also include pockets 30 which may be configured to receive cutting elements of one type such as, for example, ultra-abrasive cutting elements in the form of polycrystalline diamond compact 32 cutting elements. In general, the cutting element of this POLYCRYSTALLINE DIAMOND COMPACT may comprise a highly abrasive diamond block which is bonded to a substrate. Rotary traction bits using cutting elements of POLYCRYSTALLINE DIAMOND COMPACT have been used for decades. The cutting elements of a POLYCRYSTALLINE DIAMOND COMPACT typically consist of a disc-shaped diamond “plate” formed on and bonded under an ultra-high-pressure and high-temperature (HPHT) process to reinforce a tungsten carbide substrate. Cemented tungsten carbide, although other configurations are known. Drill bits that carry the cutting elements of POLYCRYSTALLINE DIAMOND COMPACT, which, for example, can be brazed into pockets in the surface of the bit, pockets in blades extending from the surface, or secured with large screws inserted into the body of the bit. . Well known in the field. Therefore, the cutting elements of the polycrystalline diamond compound POLYCRYSTALLINE DIAMOND COMPACT 32 can be installed on the blades 22 of the drill bit 12 by tempering, welding, or otherwise as known in the art. If POLYCRYSTALLINE DIAMOND COMPACT 32 cutting elements are used, they may be reassembled at a common angle, or at different angles. As a non-limiting example, the cutting elements of polycrystalline diamond compound POLYCRYSTALLINE DIAMOND COMPACT 32 may be assembled again at 15 degrees within the cone of the bit face near the centerline of the bit, at 20 degrees on the front and sideways, and at 30 degrees when secured. It is expected that the cutting elements 32 may include exposed natural diamond grit-impregnated segments, thermally stabilized polycrystalline diamond compounds, cubic boron nitride compacts, or diamond sand-impregnated segments, as known in The field can be chosen considering the hardness and abrasiveness of the subterranean formation or formations to be drilled.

Also, each of the blades 22 may include an area of 25 which is problematic for determining the outer radius of the drill bit 12 and, thus, the radius of the wall surface of the well drilled by it. The amplitude zones 25 include longitudinal upward extensions (where the drill bit 12 is oriented during use) of the blades 22, extending from the leading portion 20 and may have wear-resistant inserts or covers, such as cutting elements in the form of tools for coordinating the amplitude from a natural diamond. Or synthetic, hard facing material, or both, on external surfaces radially thereof as known in the art.

The drill bit 12 may also be provided with abrasive cutting structures 36 of a type other than the cutting elements 32. The abrasive cutting structures 36 may include a composite material comprising an assembly of hard particles in a die. Combinations of hard particles may include carbide material such as tungsten, aluminium, zirconium, chromium, tantalum, hafnium, vanadium, niobium, molybdenum, titanium and carbide Si, or ceramic material. A group of particles may include coarse, medium or fine coarse particles that have serrated edges, which are actually coarse. By way of example and not limitation, the range of particles may include sizes selected from the size range including 1/2 inch particles to particles suitable through a screen having 30 openings per square inch (30 mesh). Particles with sizes in the range from 12.7 mm (1/2 in) to 4.76 mm (3/16 in) can be called "coarse" particles, while particles with sizes in the range from 4.76 mm (3/3 in) can be called "coarse" particles. 16 inch) to 1.59 mm (1/16 inch) are "medium" particles, and particles with sizes in the range from 10 mesh to 30 mesh may be called "fine coarse" particles. Rough, jagged edges of a particle cluster can be created as a result of the formation of an embodiments by crushing the material of which the particles are composed. In some embodiments of the present description the hard particles may comprise a plurality of crushed sintered tungsten carbide particles having hard, serrated edges. Tungsten carbide particles may include particles in the range from about 12.7 mm (1/2 inch) to about 4.76 mm (3/16 inch), particles within or near this size range are called "coarse finite" particles. The matrix material may include a high-strength, low-boiling alloy, such as copper alloy. The material may be such that during use, the matrix material may wear away to expose new pieces of constant grade and rough edges of hard particles, allowing the hard edges of the hard particles to engage more efficiently with the components of the cover and associated material. In some embodiments of the present description, the copper alloy may include a composition of copper, zinc and nickel. For example, but not limited to, a copper alloy may contain approximately 48% copper, 41% zinc, and 10% nickel by weight.

An unlimited example of a material suitable for abrasive cutting compositions 36 includes a composite material manufactured under the trade name KUTRITE® by B & W Metals Co., Inc. of Houston, TX. The KUTRITE® composite material comprises crushed sintered tungsten carbide particles in a copper alloy with an ultimate tensile strength of 689 MPa (100,000 psi). KUTRITE® is also supplied as composite sticks and has a melting temperature of 1785°F, allowing abrasive cutting structures 36 to be formed using oxyacetylene welding equipment to weld the cutting structure material into the desired position on the drill bit 12 Abrasive cutting structures 36 can, therefore, be formed and machined while the material is welded to the blades 22. Another non-limiting example of a material suitable for abrasive cutting structures 36 includes a composite material manufactured under the trade name SUPERLOY® by Baker Oil Tools. In some embodiments, abrasive cutting structures 36 can be arranged directly on the outer surfaces of the blades 22. In other embodiments, pockets or floor depressions 34 can be formed in the blades 22, which can be configured to receive the abrasive cutting structures 36.

In some embodiments, as shown in Figures 1-3 and in at least parts of Figures 8-10, the abrasive cutting structures 36 may include a protruding block or wear knot structure, wherein a plurality of cutting structures is disposed The abrasive cutting structures 36 are adjacent to each other along the blades 22. Wear knot structures can be formed by welding the material, for example from a composite stick such as that described previously for KUTRITE®, with which the matrix material incorporating abrasive cutting structures is fused to the desired position. In other words, the matrix material can be heated to its melting point and thus, the matrix material, along with the hard particles, is allowed to push onto the desired surface of the blades 22. Fusing the material to the surface of the blade 22 may require the material to be specially positioned and/or to manually shape the material into the desired shape during the application process. In some embodiments, the wear nodes may include a preformed assembly and may be attached to the blade 22 by brazing. Regardless of whether the wear nodes are pre-formed or formed directly on the blades 22, the wear nodes can be formed to have any suitable shape which can be chosen according to the specific application. Without limitation, wear nodes may generally have a cylindrical shape, a column shape, or a hemispherical shape. Some embodiments may have a substantially flat top and other embodiments may have a pointed or chisel-shaped top as well as various other shapes. The size and shape of the hard particle assembly may have a surface that is rough and serrated, which may assist in cutting through the casing and components associated with the casing such as elastomeric components.

In other embodiments, as shown in Figures 4, 5 and in at least parts of Figures 8-10, the abrasive cutting assemblies 36 can be configured as elongated, single assemblies extending radially outward along the blades 22. Similarly for wear knots, the elongated assemblies can be configured By melting the matrix material and shaping the material onto the blades 22, or extended assemblies may include pre-formed assemblies, which can be attached to the blade 22 by brazing. Furthermore, similarly elongated structures may have surfaces that are rough and serrated to aid in the engagement and connection of elastomeric components.

It is desirable to select or tailor the thickness of the abrasive cutting structures 36 to provide sufficient material to cut through one or more components associated with the casing, such as a flexible component, a cap bit and a casing, as well as their unions between the interior of the casing and the surrounding formation to be drilled. In embodiments using a plurality of abrasive cutting structures 36 formed as wear nodes adjacent to each other, the plurality of abrasive cutting structures 36 can be positioned such that each abrasive cutting structure 36 is associated with and is positioned circularly behind one or more cutting elements. elements 32. The abrasive cutting assemblies 36 may be virtually uniform in size or the abrasive cutting assemblies 36 may differ in size. Without limitation, the abrasive cutting assemblies 36 may vary in size such that the cutting assemblies 36 are positioned at the most radially outward position (and, therefore, traverse a proportionately greater distance per rotation of the drill bit 12 than, for example, Which is located inside the cone of the drill bit 12) may be larger in size or at least in exposure in order to accommodate greater wear.

Likewise, in embodiments using single, elongated structures on the blades 22, the abrasive cutting structures 36 may be of substantially uniform thickness, taken in the direction of intended bit rotation, as shown in, for example, Figure 4, or may The abrasive cutting compositions 36 are of different thicknesses, taken in the direction of rotation of the bit, as shown in, for example, Fig. 5. For example, but not limited to, abrasive cutting structures 36 at the most radially outward positions may be thicker. In other embodiments, the abrasive cutting compositions 36 may include a thickness to cover virtually the entire surface of the interface surface (e.g., the entire surface of the blades 22) behind the cutting elements 32.

In some embodiments, the abrasive cutting structures 36 may also include separate cutters 50 (Figure 5) arranged therein. The discrete cutters 50 may include cutters similar to those described in US Patent Publication No. 0079995/2007. Other suitable separate cutters 50 may include the abrasive cutting elements described in US Publication No. 0084608/2009. Another unlimited example of suitable discrete cutters 50 may include the star-shaped carbide cutter sold under the trade name OPTI-CUT by Baker Oil Tools. In some embodiments, the discrete cutters 50 can be arranged on blades 22 with cutting structures 36 such that the discrete cutters 50 have greater relative exposure than the relative exposure of the cutting structures 36, such that the discrete cutters 50 contact the cover components before the cutting structures. 36. In other embodiments, discrete cutters 50 and cutting structures 36 have approximately the same relative exposure. In still other embodiments, the discrete cutters 50 have a relative exposure that is less than the relative exposure of the cutting assemblies 36. In embodiments that have a lower relative exposure than the cutting assemblies 36, the discrete cutters 50 may be at least partially covered by the material comprising the cutting assemblies. cutting structures 36. In still other embodiments, the discrete cutters 50 may be circularly located behind or in front of the cutting structures 36.

Also, as shown in Figures 1-5, abrasive cutting structures 36 may extend along the area from the cone of the cone outward to the bypass (in the area from the center line L (Figures 6 and 7) to the locking areas 25) to provide maximum protection for elements Cutting elements 32, which are highly susceptible to damage when drilling cover mounting components. In other embodiments, such as those shown in Figures 8-10, the abrasive cutting assemblies 36 may be arranged along the area from the cone of the bit to the outside of the bypass, but may be flush with the securing areas 25. In this manner the abrasive cutting assemblies can be positioned cutting structures 36 to engage the flexible component, while the well volume as typically defined by gage regions 25 is protected.

The cutting elements 32 and abrasive cutting structures 36 can be dimensioned and shaped respectively, in combination with the special depths and locations of pockets 30 and, if present, troughs 34, to provide abrasive cutting structures 36 with greater relative exposure. Of superabrasive cutting elements 32. As used herein, the term "exposure" of a cutting element generally refers to the protruding distance above a portion of the drill bit, eg the blade surface or side, to which it is clamped. However, with specific reference to the present description, “relative exposure” is used to refer to the difference in exposure between the cutting element 32 and the cutting assembly 36 (plus a separate cutter 50). More specifically, the term “relative exposure” may be used to refer to the difference in exposure between a single cutting element 32 and a cutting assembly 36 (or a separate cutter 50) which, optionally, may be positioned approximately in the direction of rotation of the bit and along the same or similar rotation path. . In the embodiments shown in Figures 1-5, the abrasive cutting combinations 36 can generally be illustrated with superabrasive cutting elements 32 “following” alternating and close to close rotation on the same blade 22. However, the abrasive cutting structures 36 may also be positioned to alternate with superabrasive cutting elements 32 attached to the “drive,” filling the space between laterally adjacent superabrasive cutting elements 32, or both.

To illustrate the above, Figure 6 shows a schematic side view of the design for placing a cutting element for drill bit 12. It shows cutting elements 32, 32? The cutting assemblies 36 as arranged on the drill bit (not shown) are such that an embodiment of the drill bit 12 is shown in, for example, Figures 1-3. Figure 7 shows a similar schematic side view showing cutting elements 32, 32? The assembly of bits 36 is as arranged on the drill bit (not shown) as the embodiment of drill bit 12 as shown in, for example, Figures 4 and 5. Figures 6 and 7 show cutting elements 32, 32? The cutting fixtures 36 are with respect to the longitudinal axis or center line L and its drilling shape P, as if all the cutting elements 32, 32?, and the cutting fixtures 36 are rotating on an oasis blade (not shown). Also, Figure 10 shows an enlarged perspective view of a portion of the blade 22 showing the cutting elements 32, 32 and cutting structures 36 as arranged on a portion of the drill bit 12 of Figures 8 and 9. As shown in Figures 6, 7, and 10, the cutting assemblies 36 can be sized, shaped, and positioned so as to engage and drill the first material or zone, such as the flexible component, as well as any other well component (e.g., casing, casing bit, bonded component Also with the casing, the cutting fixtures 36 may also be configured to drill through a cemented area surrounding the heel of the casing, if it is cemented inside the well. Also, a set of 32 cutting elements can be scaled, shaped, and placed to drill a subterranean formation behind the elastomeric component and other downhole components.

Cutting elements 32? A problem appears with surfaces oriented radially outwards and placed to cut the securing diameter of the drill bit 12. As shown in Figures 6 and 7, the gage region of the cutting element placement design for some embodiments of the drill bit 12 may include the cutting assemblies 36 associated with the cutting elements 32? Also, however, in other embodiments, as shown in Figures 8 and 10, the gage region of the cutting element placement design for some embodiments of the drill bit may include 12 cutting elements 32? But without associated cutting structures36. The cutting structures 36 may be replaced by a segment close to the gage region 25 to at least physically flow with the gage region 25.

The present invention foresees that the cutting structures 36 may be more exposed than the plurality of cutting elements 32 at least to the front and side aisle areas of the face 26. In this way, the cutting structures 36 may be approximated with respect to the plurality of cutting elements 32, To further illustrate, the cutting assemblies 36 can be configured to initially engage and etch materials and regions that are different from the subsequent materials and regions through which the assembly of cutting elements 32 is configured to engage and etch.

Accordingly, the cutting structures 36 may include an abrasive as previously described, while the cutting elements assembly 32 may include cutting elements of a polycrystalline diamond compound. This configuration may facilitate drilling through the flexible component, as well as the casing and other components associated with the casing (e.g., stub, cement cementing equipment components within the casing upon which the casing bit, cement, is arranged) with initially cut-out assemblies. cutting structures 36. However, when passing through the plutonic formation, the abrasive plutonic material that is drilled out of the material cutting structures 36 may wear out quickly to enable the cutting elements of the POLYCRYSTALLINE DIAMOND COMPACT 32 to be less likely to engage with the formation. . As shown in Figures 1-5 and 8-10, one or more of the plurality of cutting elements 32 may circularly precede the cutting combinations 36, without limitation. Alternatively, one or more elements of the set of cutting elements 32 may circularly follow cutting structures 36.

Significantly, after the material cutting structures 36 are worn away by scraping away the subterranean formation material being drilled, the cutting elements of the POLYCRYSTALLINE DIAMOND COMPACT 32 are released and drilling may occur more efficiently. Also, the materials chosen for the cutting structures 36 may allow the cutting structures 36 to wear away relatively quickly and precisely so that the cutting elements of the POLYCRYSTALLINE DIAMOND COMPACT 32 can engage with the subterranean formation material more efficiently and without interference from the cutting structures. 36.

In some embodiments, a layer of layer sacrificial material 38 (Figure 7) may be arranged initially on the surface blade 22 or in an optional cavity or trough 34 and tungsten carbide is arranged to mount one or more cutting structures 36 thereon. The sacrificial material 38 may include a material with little or no carbide that can be shaped to position in a certain way quickly when engaged with the subterranean formation material in order to more easily expose the cutting elements 32. The sacrificial material 38 may have a lower relative exposure than the set of cutting elements 32, but the installation of one or more parts 36 arranged on top of it will achieve an overall relative exposure greater than that of the set of cutting elements 32. In other words, the proximate material 38 can be arranged on the blades 22, and optionally in a cavity or trough 34, having an exposure less than the exposure of the group of cutting elements 32. Then one or more cuts 36 can be arranged to be mounted on the proximate material 38, mounting the pieces 36 one at a time. or more having an exposure greater than the plurality of cutting elements 32. Without limitation, a suitable exposure of the proximate material 38 may be two-thirds or three-quarters of the exposure of the plurality of cutting elements 32.

Referring specifically to Figures 8-10 show different views of a drill bit embodiment 12 problem particularly for drilling casing-related components involving flexible materials. Various embodiments of the conventional cover and cover-related components utilize one or more flexible components, as commonly known in the art. For example, various conventional float shoes (e.g., casing shoes) may utilize one or more rubber seals in supporting operations to separate cement slurry from other fluids in the drill pipe network. As previously described, and as described, the drill bit 12 includes abrasive bit assemblies 36 formed as wear knots or elongated assemblies, or combinations thereof. In at least some embodiments of drill bit 12 formed particularly for flexible drilling components, the particle assembly may include at least rough particles having rough, effectively serrated edges, as described previously. Without limitation, the plurality of particles may include sizes selected from at least a size range including particles of about 12.7 mm (1/2 inch) to particles embodiments of about 4.76 mm (3/16 inch).

As stated above generally, the relative exposure of the cutting structures 36 is chosen to be sufficiently greater than the relative exposure of the cutting elements 32 so that the cutting structures 36 engage the cover or a cover-related component while at least the cutting elements 32 are effectively inhibited from Engaging with the cover or a component attached to the cover. In embodiments formed for use to drill one or more flexible components, the cutting assemblies 36 may be machined with sufficiently greater relative exposure than the relative exposure of the cutting elements 32 to not only prevent the cutting elements 32 from engaging with the flexible component, but to allow solid particles Rough and serrated to efficiently engage and penetrate the elastic component while keeping the cutting elements 32 out of contact with the surface elastomeric component. By way of example and not as a limitation, in at least some embodiments, cutting structures 36 can be configured to exhibit a relative exposure that is between about 4.76 mm (3/16 inch) and about 9.53 mm (3/8 inch) greater than the relative exposure of some of the The set of cutting elements is at least 32.

During use, the rough and jagged hard particles in the cutting structures 36 penetrate the elastic component and under the rotation of the bit and the weight on the bit, the elastic component mixes by grinding, shearing and cutting relatively smaller pieces than are removed by the cutting elements 32 out. As a result, the flexible component can be drilled more efficiently and relatively more quickly than with conventional methods. By moving relatively smaller portions of the flexible component, the rough, jagged solid particles of the cutting structures 36 are able to drill efficiently through the flexible component without actually rapidly rotating the flexible component and preventing drilling out. Furthermore, relatively smaller portions of the flexible component may flow more easily outward from the bit interface, reducing and even eliminating drill bit 12 formation.

In at least some embodiments, while drilling through one or more flexible components, a bit or drilling tool may be used at a relatively large circular speed and with a relatively low weight applied to the bit or drilling tool (i.e., the weight on the bit compared to the circular speeds and WOB that They are used for drilling subterranean formation. For example, but not limited to, the drill bit 12 can rotate at approximately 90 revolutions per minute or greater with a WOB between approximately 2,268 kg (5,000 lb) and approximately 4,536 kg (10,000 lb).

While certain embodiments are described and illustrated in the accompanying drawings, such embodiments are illustrative only and are not a limitation of the scope of the invention, and this invention is not limited to the special combinations and arrangements shown and described, as various other additions to, modifications to, and deletions from, the illustrated embodiments would be obvious to the average person who is an expert in the field. Therefore, the scope of the invention is not limited to the literal language and acceptable equivalents of the following elements of protection.