Patent Application
20180291689
The present application relates to drill bits used for drilling well bore equipment, such as plugs, packers, and other similar items and, more generally, for drilling and earth boring, such as water wells; oil and gas wells; injection wells; geothermal wells; monitoring wells, mining; and, other operations in which a well-bore is drilled into the Earth.
Specialized drill bits are used to drill well-bores, boreholes, or wells in the earth for a variety of purposes, including water wells; oil and gas wells; injection wells; geothermal wells; monitoring wells, mining; and, other similar operations. These drill bits come in two common types, roller cone drill bits and fixed cutter drill bits.
Wells and other holes in the earth are drilled by attaching or connecting a drill bit to some structure or method of turning the drill bit. In some instances, such as in some mining applications, the drill bit is attached directly to a shaft that is turned by a motor, engine, drive, or other source of torque capable of rotating the drill bit.
In other applications, such as oil and gas drilling, the well may be several thousand feet or more in total depth. In these circumstances, the drill bit is connected to the surface of the earth by what is referred to as a drill string and a motor or drive that rotates the drill bit. The drill string typically comprises several elements that may include a special down-hole motor configured to provide additional or, if a surface motor or drive is not provided, the only means of turning the drill bit. Special logging and directional tools to measure various physical characteristics of the geological formation being drilled and to measure the location of the drill bit and drill string may be employed. Additional drill collars, heavy, thick-walled pipe, typically provide weight that is used to push the drill bit into the formation. Finally, drill pipe connects these elements, the drill bit, down-hole motor, logging tools, and drill collars, to the surface where a motor or drive mechanism turns the entire drill string and, consequently, the drill bit, to engage the drill bit with the geological formation to drill the well-bore deeper.
As a well is drilled, fluid, typically a water or oil based fluid referred to as drilling mud is pumped down the drill string through the drill pipe and any other elements present and through the drill bit. Other types of drilling fluids are sometimes used, including air, nitrogen, foams, mists, and other combinations of gases, but for purposes of this application drilling fluid and/or drilling mud refers to any type of drilling fluid, including gases. In other words, drill bits typically have a fluid channel within the drill bit to allow the drilling mud to pass through the bit and out one or more jets, ports, or nozzles. The purpose of the drilling fluid is to cool and lubricate the drill bit, stabilize the well-bore from collapsing or allowing fluids present in the geological formation from entering the well-bore, and to carry fragments or cuttings removed by the drill bit up the annulus and out of the well-bore. While the drilling fluid typically is pumped through the inner annulus of the drill string and out of the drill bit, drilling fluid can be reverse-circulated. That is, the drilling fluid can be pumped down the annulus (the space between the exterior of the drill pipe and the wall of the well-bore) of the well-bore, across the face of the drill bit, and into the inner fluid channels of the drill bit through the jets or nozzles and up into the drill string.
Roller cone drill bits were the most common type of bit used historically and featured two or more rotating cones with cutting elements, or teeth, on each cone. Roller cone drill bits typically have a relatively short period of use as the cutting elements and support bearings for the roller cones typically wear out and fail after only 50 hours of drilling use.
Because of the relatively short life of roller cone bits, fixed cutter drill bits that employ very durable polycrystalline diamond compact (PDC) cutters, tungsten carbide cutters, natural or synthetic diamond, other hard materials, or combinations thereof, have been developed. These bits are referred to as fixed cutter bits because they employ cutting elements positioned on one or more fixed blades in selected locations or randomly distributed. Unlike roller cone bits that have cutting elements on a cone that rotates, in addition to the rotation imparted by a motor or drive, fixed cutter bits do not rotate independently of the rotation imparted by the motor or drive mechanism. Through varying improvements, the durability of fixed cutter bits has improved sufficiently to make them cost effective in terms of time saved during the drilling process when compared to the higher, up-front cost to manufacture the fixed cutter bits.
Recent developments in drilling practices has led to wellbores that include long lateral or horizontal sections that extend thousands of feet away from the well pad and drilling rig. Various operations must be conducted along these lateral sections before any producing any fluids, such as oil or gas, from the wellbore. These operations may include perforation and hydraulic fracturing along any number of zones along the lateral section. Typically, each zone is hydraulically isolated from other zones and/or other parts of the well bore with the use of any variety of plugs or packers, including plugs used during hydraulic fracturing and commonly referred to as frac plugs. (Subsequent references to “plugs”, “packers”, “plugs/packers” and so forth encompass all known varieties of plugs and packers, including frac plugs.)
While some plugs and packers are retrievable, most are designed to be drilled through and destroyed with its constituent parts being circulated out of the wellbore by drilling fluid. Drilling through the packers and plugs is often more economical than retrieving them, particularly since there may be fifty or more plugs in a single lateral section.
A challenge, however, is that the various plugs and packers typically are manufactured from a variety of materials, including various metals, composites, and rubber/resilient elements. This poses a significant challenge, because these metals, composites, and rubber/resilient elements have significant differences in strengths. For example, the elastic nature of the rubber/resilient makes it hard for cutting elements to crush or shear the material, which may lead to stalling of the bit (i.e., the bit momentarily stops rotating, risking damage to the bit and/or the drill string) and, when it does fail, the pieces of the rubber/resilient element may come off in large chunks. These large pieces or chunks risk clogging or damaging the drill bit, and/or they may not be circulated adequately out of the well bore, risking damage to the formation and/or potentially decreasing the eventual production from the well.
Neither roller cone drill bits nor fixed cutter PDC bits (and, more generally, fixed cutter bits with tungsten carbide or other cutting materials) have proven particularly suitable for drilling out plugs and packers. First, neither roller cone bits nor PDC bits are designed or suitable for drilling through the variety of materials that make up plugs and packers, particularly the rubber/resilient elements. For example, both roller cone and fixed cutter bits tend to create pieces of the plugs/packers that are too large. For another, the type and distribution of cutters about the drill bit are typically too monolithic to drill adequately the different materials.
Further, as the number of zones in a lateral section and, consequently, the number of plugs or packers, increases, neither roller cone bits nor fixed cutter bits have proven sufficiently durable to drill all of the plugs/packers in a timely manner. Regardless of the cause, wear or mechanical failure, it often becomes necessary to trip the drill string out of the well simply to replace the drill bit so that any remaining plugs/packers may be drilled out. Each round trip might take hours or even more than a day, depending on the length of the lateral, and cost tens to hundreds of thousands of dollars.
Thus, there exists a need for a cost-effective drill bit capable of drilling through plugs, packers, and other equipment in a wellbore, as well as earth formations, without sacrificing durability and rate-of-penetration.
Embodiments of the drill bit include a bit body having a first end and a second end spaced apart from the first end and a connection for coupling the bit body to a drill string. The drill bit includes a cone section proximate the second end that extends a first radial distance from a centerline of the drill bit; a blade flank section that extends from proximate the first radial distance to a second radial distance from the centerline that is greater than the first radial distance; and a blade shoulder section that extends from proximate the second radial distance to a third radial distance greater than the second radial distance, the third radial distance proximate a gauge radial distance that defines a maximum radius of the drill bit. A plurality of blades are connected to the bit body and extend away from the bit body. At least one cutting element is positioned on at least one of the plurality of blades. A plurality of thermally stable polycrystalline cutters are positioned on at least one of the plurality of blades in at least one of the cone section, the blade flank section, and the blade shoulder section of the at least one of the plurality of blades or any combination thereof.
Optionally, at least one of a) the at least one cutting element or b) the plurality of thermally stable polycrystalline cutters includes a sawtooth profile.
Optionally, the at least one cutting element and the plurality of thermally stable polycrystalline cutters are positioned on the same blade of the plurality of blades.
Optionally, the plurality of thermally stable polycrystalline cutters are at least one of a) embedded in a tungsten carbide segment or puck coupled to the at least one of the plurality of blades, b) embedded in a matrix that forms the plurality of blades, and c) brazed to the at least one of the plurality of blades.
Optionally, at least one of the cutting element and the plurality of thermally stable polycrystalline cutters is a segmented or shaped portion of a polycrystalline diamond compact. Also, at least a portion of at least one of the plurality of thermally stable polycrystalline cutters may be triangular-shaped in cross-section, sawtooth shaped, m-shaped, w-shaped, or star-shaped.
At least one of the plurality of thermally stable polycrystalline cutters may include a cutting edge that defines a line, wherein the line is substantially parallel to a tangential line of a radial line that extends from a center of the drill bit to the cutting edge.
At least one of the plurality of thermally stable polycrystalline cutters may include a cutting edge that defines a line, wherein the line intersects a tangential line of a radial line that extends from a center of the drill bit to the cutting edge at an angle less than or equal to 20 degrees.
At least one of the plurality of thermally stable polycrystalline cutters may include a planar face and a horizontal line parallel to the planar face, wherein the horizontal line intersects a radial line that extends from a center of the drill bit to the horizontal line at an angle between greater than or equal to 70 degrees and less than or equal to 110 degrees.
At least one of the plurality of thermally stable polycrystalline cutters may include a side-rake angle in one of the ranges of a) from 70 degrees to 110 degrees and b) from −70 to −110 degrees.
Another embodiment of the drill bit includes a bit body having a first end and a second end spaced apart from the first end and a connection for coupling the bit body to a drill string. The drill bit includes a cone section proximate the second end that extends a first radial distance from a centerline of the drill bit; a blade flank section that extends from proximate the first radial distance to a second radial distance from the centerline that is greater than the first radial distance; and a blade shoulder section that extends from proximate the second radial distance to a third radial distance greater than the second radial distance, the third radial distance proximate a gauge radial distance that defines a maximum radius of the drill bit. A plurality of blades are connected to the bit body and extend away from the bit body. At least one cutting element that includes a sawtooth profile is positioned on at least one of the plurality of blades.
Embodiments of a shaped or segmented polycrystalline diamond compact are also disclosed. The shaped or segmented polycrystalline diamond compact includes a substrate, a cutting element, and at least two tips or a plurality of tips. At least one recess or groove separates the at least two tips. The recess optionally extends into the cutting element and/or the substrate. The at least two tips and the at least one recess form a sawtooth, m-shaped, or w-shaped profile along at least a portion of a perimeter of the shaped portion when viewed from the top of the shaped portion. The shaped or segmented polycrystalline diamond compact may optionally be machined, including with electrical discharge machining, pressed, or formed.
Another embodiment is a drill bit that includes a polycrystalline diamond compacts that are shaped or formed via machining, including electrical discharge machining, pressed, or formed, to include a sawtooth a sawtooth, m-shaped, or w-shaped profile along at least a portion of a perimeter of the shaped portion of the polycrystalline diamond compact when viewed from the top of the shaped portion.
Other configurations of the blades, blade portions, and cutting elements, are disclosed herein and fall within the scope of the disclosure. In addition, methods of manufacturing various embodiments of the drill bit are disclosed herein.
As used herein, “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.
Various embodiments of the present inventions are set forth in the attached figures and in the Detailed Description as provided herein and as embodied by the claims. It should be understood, however, that this Summary does not contain all of the aspects and embodiments of the one or more present inventions, is not meant to be limiting or restrictive in any manner, and that the invention(s) as disclosed herein is/are and will be understood by those of ordinary skill in the art to encompass obvious improvements and modifications thereto.
Additional advantages of the present invention will become readily apparent from the following discussion, particularly when taken together with the accompanying drawings.
To further clarify the above and other advantages and features of the one or more present inventions, reference to specific embodiments thereof are illustrated in the appended drawings. The drawings depict only typical embodiments and are therefore not to be considered limiting. One or more embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:
The drawings are not necessarily to scale.
The drill bit 10 includes a first end 12 that includes a shank or connection 14 configured to couple or mate the drill bit 10 to a drill string or a drill shaft that is coupled to a source of rotary torque or force, such as a motor, downhole motor, top drive or kelly drive of a drilling rig at the surface, or other sources, as described above in the background. The connection 14 include a typical pin connection with threads 16. The connection 14 includes a chamfer 17 configured to reduce stress concentrations at the end of the threads 16 and to ease mating with a box connection in the drill string, a shank shoulder 18, and the sealing face 19 of the connection 14. Of course, rather than a pin connection the connection 14 can be a box connection, bolts, welded connection, joints, and other structures for connecting the drill bit 10 to a motor, drill string, drill, top drive, downhole turbine, or other sources of rotary torque or force.
The threads 16 typically are of a type described as an American Petroleum Institute (API) standard connection of various diameters as known in the art, although other standards and sizes fall within the scope of the disclosure. The threads 16 are configured to operably couple with the threads of a corresponding or analogue box connection in the drill string, collar, downhole motor, or other connection to the bit as known in the art. The sealing face 19 provides a mechanical seal between the drill bit 10 and the drill string and prevents any drilling fluid passing through the inner diameter of the drill string and the drill bit 10 from leaking out.
The embodiments of the drill bit 10 optionally include a breaker slot 20 configured to accept a bit breaker therein. The bit breaker is used to connect or mate the drill bit 10 to the drill string and provides a way to apply torque to the drill bit 10 (or to prevent the drill bit 10 from moving as torque is applied to the drill string) while the drill bit 10 and the drill string are being coupled together or taken apart.
The bit body 25 includes one or more drill bit blades 30 connected thereto that optionally extend past the bit body 25 in both a radial direction away from the center or centerline 21 and a vertical direction towards and proximate to a second end 13 of the drill bit 10. As illustrated in
The drill bit 10 includes one or more blades 30 that includes a cone section 29 within a first radius proximate the center or centerline 21 of the drill bit 10; a blade flank section 28 spaced laterally away at a greater radial distance from the centerline 21 than the cone section 29; a blade shoulder section 27 spaced further laterally away at a greater radial distance from the centerline 21 than the blade the flank section 28; and a gauge (or gage) pad 45 typically proximate the greatest radial distance, or one-half the bit diameter 46 of the drill bit 10, from the centerline 21 and proximate the bit body 25. In other embodiments, the gauge pad 45 is less than the greatest radial distance. The gauge pad 45 optionally includes a crown chamfer 47 adjacent to the bit body 25.
The relative positions of the cone section 29, blade flank section 28, blade shoulder section 27, and gauge pad section 45 with respect to the bit centerline are better illustrated in the diagram of various blade profiles 600 illustrated in
Various profiles of embodiments of blades 30 are illustrated as lines 640; 650; 660; 670; 680; 690; 695; and 698. The profiles 600 illustrate the aggregate profile of the blades 30. In other words, the blades 30, taken as a whole, would generally appear as the embodiment of the profiles 600 if all of the blades 30 were laid flat on a plane through the centerline 621.
Still referring to
The blade flank section 28 of the drill bit 10 falls within the blade flank section 628 illustrated adjacent to and at a further radial distance from the centerline 621 than the cone section 629 in
The blade shoulder section 27 of the drill bit 10 falls within the blade shoulder section 627 illustrated adjacent to and at a further radial distance from the centerline 621 than the cone section 629 and the blade flank section 628 in
Returning to
As an example,
Of course, it will be understood that different blades in a given drill bit might have different blade shapes, lines, arcs, and or splines, either more or less aggressive, than any other given blade on the drill bit. Further, a blade shape need not remain constant, either straight or have a constant radius of curvature as its radial distance from the center of the bit increases. For example, blade shape 560 indicates a blade whose radius of curvature changes significantly as the radial distance from the center increases, from a trailing radius of curvature to a leading radius of curvature, something that might be suitable for drilling horizontal wells along very thin geological formations of different hardness.
Similarly, and looking at
Turning back to
The cutting elements 40 illustrated in the figures are of a polycrystalline diamond compact (PDC) type, but cutters of other materials, such as tungsten carbide, cubic boron nitride (CBN), thermally stable polycrystalline, natural or synthetic diamond, hardened steel, and other hard materials can be used. The embodiment of the cutting elements 40 include the PDC cutting element 41 configured with a side that interlocks with the substrate 42 and positioned in a pocket 43 of the blade 33, as illustrated in
The cutting elements 40 are positioned on the various blades 30 at selected radial distances from the centerline 21 depending on various factors, including the desired rate-of-penetration, hardness and abrasiveness of the plug/packer or expected geological formation or formations to be drilled, and other factors. For example, two or more cutting elements 40 may be placed at the same radial distance from the centerline 21, typically on different blades 30, such as blade 32 and blade 34, and, therefore, would cut over the same path through plug/packer or formation. Another embodiment includes positioning two or more cutting elements 40 at only slightly different radii from the centerline 21 of the drill bit 10, again, typically on different blades 30, so that the path that each cutter makes through a plug/packer or geological formation overlaps slightly with the cutter at the next further radial distance from the centerline of the drill bit 10.
In addition, the distance a given cutting element 40 travels during a single revolution of the drill bit 10 increases as the radial distance of the cutter 40 from the centerline 21 of the drill bit 10 increases. Thus, a cutting element 40 positioned at a greater radial distance from the centerline 21 of the drill bit 10 travels a greater distance for each revolution of the drill bit 10 than another cutting element 40 positioned at a lesser radial distance from the centerline 21 of the drill bit 10. As such, the first cutting element 40 at the greater radial distance would wear faster than the second cutting element 40 at the lesser radial distance. In view of this, relatively more cutting elements 40 optionally are positioned relatively more closely, i.e., with relatively less radial distance separating those cutting element 40 at adjacent radial distances (even if on different blades) the greater the absolute radial distance from the centerline 21 of the drill bit 10 (such as those cutters in the blade shoulder section 28) as compared to those cutting elements 40 positioned at relatively shorter radial distance, i.e., closer to the centerline 21 of the drill bit 10, such as those cutters in the cone section 29. Further, as a radial distance of a given cutting element 40 increases, other factors related to the cutting element position are typically, although not necessarily, selected to be less aggressive, including the exposure, back-rake, and side-rake, as described below.
The backup cutter 464 optionally is positioned a distance 486 from the packer/plug or geological formation 480 initially, i.e., before drilling begins. Typically, the backup cutter 464 only begins to engage the plug, packer, or geological formation 480 when the cutter 440 wears sufficiently, closing the distance 486. When the backup cutter 464 engages the plug, packer, or geological formation 480, it bears a portion of the torque and weight on bit (the force on the bit in a direction parallel to the well-bore) that would otherwise have been borne solely by the cutter 440, thereby reducing the wear on the cutter 440 and increasing the life of the cutter 440. While the distance 486 is illustrated as allowing some distance between the plug, packer, or geological formation 480 and the backup cutter 464 when the cutter 440 is new (i.e., unworn), the backup cutter 464 can be positioned to engage the packer/plug or geological formation 480 concurrently with the cutter 440 is new, i.e., the distance 486 is effectively zero. In other embodiments, the backup cutter 464 can be designed to engage the packer/plug or geological formation 480 before the cutter 440 does so, i.e., the distance 486 is effectively negative. The distance 486 is selected in consideration of the characteristics of the plug, packer, or geological formation to be drilled and other factors known in the art and may vary among different backup cutters at different radial distances from the center of the drill bit.
The cutter 440 illustrated in
Returning to
Drill bit 10 optionally includes one or more gauge cutters 44 positioned in the blade shoulder section 27 to provide backup to the cutters at the greatest radial distance from the centerline 21 of the drill bit 10, similar to the backup cutter 464 described above in
Other features of the drill bit 10 include one or more nozzle bosses 50 (
Typically, the nozzle bosses 50 are configured to receive a jet or nozzle of various diameters or sizes and optionally includes threads or other means to secure the jets or nozzles in position as known in the art. The jets, ports, or nozzles are typically field replaceable to adjust the total flow area of the jets or nozzles and have a selected diameter chosen to balance the expected rate-of-penetration and, consequently, the rate at which drill cuttings are created by the bit and removed by the drilling fluid, the necessary hydraulic horsepower, and capabilities of the drilling rig facilities, particularly the pressure rating of the drilling rig's fluid management system and the pumping capacity of its mud pumps, among other factors. In some instances, a blank jet nozzle may be placed in a particular nozzle boss 50 preventing any fluid from flowing through that particular boss 50. Conversely, no jet nozzle can be used when desired, i.e., drilling fluid flows unrestricted through the nozzle boss 50.
The various nozzle bosses 50 and jets or nozzles have an orientation selected to enhance the removal of drill cuttings from the face of each blade 30 and from the cone section 29 of the bit and move them towards the annulus of the well-bore. Stated differently, the orientation of the nozzle boss 50 and jets or nozzles is such that the drilling fluid cleans the cutters 40 and the blades 31-36 of the drill bit 10. While six nozzle bosses 50, one for each blade 31-36, exist, either more or fewer nozzle bosses 50, jets, or nozzles can be used as selected for a given situation.
The drilling fluid flows through the fluid channels or junk slots 52, which are sized and positioned relative to the blades 31-36 based on the expected rate-of-penetration, characteristics of the plug/pack or the geological formation, particularly hardness and whether the formation swells or expands in the presence of the drilling fluid used, average size of the formation cuttings created, and other factors known in the art. For example, smaller (i.e., narrower) fluid channels 52 result in a higher fluid velocity with the result that cuttings are carried away more easily and quickly from the drill bit 10. However, smaller fluid channels or junk slots 52 raise the risk that one or more of the fluid channels 52 could become blocked by the formation cuttings, resulting in premature or uneven wear of the bit, reduced rate-of-penetration, and other negative effects. On the other hand, smaller junk slots 52 may restrict or slow down the rate at which cuttings are removed, notwithstanding the increased fluid velocity of the drilling fluid through the smaller junk slots 52, which, in turn, may permit more time for the drill bit to cut or grind the cuttings into smaller pieces, which in turn may help effectively drill out plugs or packers. The drilling fluid can flow through the drill string and out the jets or nozzles 51 as is typical, or it can be reverse circulated down the annulus, into the jets or nozzles, and up the drill string.
As mentioned above, previous drill bits with solely traditional cutters or cutting elements typically drill plugs or packers poorly. To remedy this, the drill bit 10 includes a plurality of cutters 60 positioned on at least one of the plurality of blades in at least one of the cone section 29, the blade flank section 28, and the blade shoulder section 27 of at least one of the plurality of blades 30, or any combination, including all of the sections of the drill bit, thereof. In other words, the plurality of cutters 60 optionally may be positioned in any of the following configurations: a) only in the cone section 29; b) only in the blade flank section 28; c) only in the blade shoulder section 27; d) in the cone section 29 and the blade flank section 28; e) in the cone section 29 and the blade shoulder section 27; f) in the blade flank section 28 and the blade shoulder section 27; g) in the cone section 29, the blade flank section 28, and the blade shoulder section 27. Alternatively, the cutters 60 may be position along a portion or an entire radial length of a blade from the cone section 29 towards the blade shoulder section 27. Optionally, at least one cutting element 40 and the cutters 60 are positioned on the same blade of the plurality of blades 30. Optionally, the cutters 60 are positioned one or more of a) behind the cutting element 40; b) in front of the cutting element 40 (either on the same blade or another blade); c) radially inward from the cutting element 40; d) radially outward from the cutting element 40; and e) any combinations thereof. Typically, the cutters 60 are smaller in size and cutting area (i.e., the area of the cutters 60 devoted to its cutting surface) than the cutting elements 40, although the cutters 60 could be larger, smaller, or any combination of sizes relative to the cutting elements 40.
The cutters 60 may be of any type of material as described above with respect to the cutting element 40. Optionally, at least one of the cutters 60 is preferably thermally stable polycrystalline and, optionally, a majority or all of the cutters 60 are thermally stable polycrystalline.
Alternatively, at least one of the cutting element 40 and/or at least one of the plurality thermally stable polycrystalline cutters 60 is a segmented portion 741 of a polycrystalline diamond compact as illustrated in
A difference between the shaped portion 1844 compared to the shaped portion 1744 is that the shaped portion 1844 includes at least two tips 1850 with tip chamfers 1845 rather than a single tip and tip chamfer 1745. At least one recess or groove 1848 separates the at least two tips 1850. The recess 1848 optionally extends into the cutting element 1841 and/or the substrate 1842. The recess 1848 optionally includes a recess chamfer 1849 so as to reduce the stresses those surfaces are subjected to during drilling operations. The at least two tips 1850 and the at least one recess 1848 form a sawtooth, m-shaped, or w-shaped profile 1852 along at least a portion of a perimeter 1854 of the shaped portion 1844 when viewed from the top of the shaped portion 1844. The at least two tips 1850 and the at least one recess 1848 provide multiple pointed surfaces to engage the rubber or resilient elements and/or other materials of a plug and/or a rock or earth formation, which in turn provides improved degradation of the material being drilled.
As with the shaped portion 1844, the shaped portion 1944 includes at least two tips 1950 with tip chamfers 1945. In this instance, the shaped portion 1944 includes four tips 1950, with each tip 1950 optionally including a mirror or another tip 1950 opposite of itself. Of course, the tips 1950 may be positioned along at least a portion of a perimeter 1954 of the shaped portion 1944 when viewed from the top of the shaped portion 1944. At least one recess or groove 1948 separates the at least two tips 1950. The recess 1948 optionally extends into the cutting element 1941 and/or the substrate 1942. The recess 1948 optionally includes a recess chamfer 1949 so as to reduce the stresses those surfaces are subjected to during drilling operations. Thus, the at least two tips 1950 and at least one recess 1948 form a sawtooth, m-shaped, or w-shaped profile 1952 in part. With tips 1950 positioned about the perimeter 1954, the shaped portion 1944 optionally may be rotated relative to its original orientation in the drill bit when a first tip or tips 1950 become worn during use so as to reorient an unworn tip or tips 1950 relative to the drill bit. This process permits, in some instances, repair of a drill bit in the field or the shop and also extends the useful life and value of the shaped portion 1944.
The shaped portion 2044 includes at least two tips 2050, and in this example, at least four tips, with tip chamfers 2045. At least one recess or groove 2048 separates the at least two tips 2050. The recess 2048 optionally extends into the cutting element 2041 and/or the substrate 2042. The recess 2048 optionally includes a recess chamfer 2049 so as to reduce the stresses those surfaces are subjected to during drilling operations. The at least two tips 2050 and the at least one recess 2048 form a sawtooth profile 2052 along at least a portion of a perimeter 2054 of the shaped portion 2044 when viewed from the top of the shaped portion 2044.
As with the shaped portion 1844, the shaped portion 2144 includes at least two tips 2150 with tip chamfers 2145. In this instance, the shaped portion 1944 includes a plurality of tips 2150, with each tip 2150 optionally including a mirror or another tip 2150 opposite of itself. Of course, the tips 2150 may be positioned along at least a portion of a perimeter 2150 of the shaped portion 2144 when viewed from the top of the shaped portion 2144. At least one recess or groove 2148 separates the at least two tips 2150. The recess 2148 optionally extends into the cutting element 2141 and/or the substrate 2142. The recess 2148 optionally includes a recess chamfer 2149 so as to reduce the stresses those surfaces are subjected to during drilling operations. Thus, the at least two tips or plurality of tips 2150 and at least one recess 2148 form a sawtooth or star-shaped profile 2152 in part. The star-shaped profile 2152 may have at least two and in some embodiments a plurality of lobes or tips 2150. With tips 2150 positioned about the perimeter 2154, the shaped portion 2144 optionally may be rotated relative to its original orientation in the drill bit when a first tip or tips 2150 become worn during use so as to reorient an unworn tip or tips 2150 relative to the drill bit.
As with the shaped portion 1844, the shaped portion 2244 includes at least two tips 2250 with tip chamfers 2245. In this instance, the shaped portion 2244 includes a plurality of tips 2250, with each tip 2250 optionally including a mirror or another tip 2250 opposite of itself. Optionally, a ridge or raised portion 2256 of the cutting element 2241 extends between and couples each opposite pair of tips 2250. The ridge or raised portion 2256 may include a radius, fillet, or chamfer. Of course, the tips 2250 may be positioned along at least a portion of a perimeter 2254 of the shaped portion 2244 when viewed from the top of the shaped portion 2244. At least one recess or groove 2248 separates the at least two tips 2250 and, optionally, the recess 2248 extends between and couples an opposite recess 2248 such that the recess 2248 separates each ridge 2256. The recess 2248 optionally extends into the cutting element 2241 and/or the substrate 2242. The recess 2248 optionally includes a recess chamfer, fillet, or radius 2249 so as to reduce the stresses those surfaces are subjected to during drilling operations. Thus, the at least two tips or plurality of tips 2250 and at least one recess 2248 form a sawtooth profile 2252 in part. With tips 2250 positioned about the perimeter 2254, the shaped portion 2244 optionally may be rotated relative to its original orientation in the drill bit when a first tip or tips 2250 become worn during use so as to reorient an unworn tip or tips 2250 relative to the drill bit.
First, the traditional or typical rounded portion 1858 of the cutting element 1841 was brought into contact with the resilient material 2360, as indicated with arrow 2361. The wide and very shallow tracks 2362 illustrate that the rounded portion 1858 did not gain purchase and ineffectively sheared the resilient material 2360. This result is commensurate with traditional drilling experience that shows traditional polycrystalline diamond compacts do not drill resilient materials efficiently.
Second, the sawtooth profile 1852 with the at least two or a plurality of tips 1850 was brought into contact with the resilient material 2360, as indicated with arrow 2363. The narrow and relatively deeper tracks 2364 illustrate that the sawtooth portion 1852 did gain purchase and effectively sheared the resilient material 2360. This result suggests that a sawtooth profile 1852 more efficiently drills rubber or resilient materials. Consequently, Applicant believes that the m-shaped, w-shaped, or sawtooth profiles will have unexpected benefits and greater performance than would otherwise be expected from rounded cutters or those cutters with a single cutting surface as opposed to a m-shaped, w-shaped, or sawtooth profile.
Referring back to
The plurality of thermally stable polycrystalline cutters 60, including those formed of polycrystalline diamond compacts as disclosed in
The plurality of thermally stable polycrystalline cutters 60 may be oriented with any variety of exposure, back-rake, and side-rake as discussed above with respect to
Optionally, the at least one of the plurality of thermally stable polycrystalline cutters 60 includes a side-rake angle in one of the ranges of a) from 70 degrees to 110 degrees and b) from −70 to −110 degrees. In other words, in embodiments with the recited ranges the thermally stable polycrystalline cutters 60 are substantially parallel to the direction of rotation as defined and discussed above.
Optionally, at least one of the plurality of thermally stable polycrystalline cutters 60 includes a cutting edge 64 that defines a line 65, as illustrated in
Optionally, and also as illustrated in
Optionally, the thermally stable polycrystalline cutters 60 are placed with a density of between 20 and 400 per drill bit 10 and, more preferably, between 50 and 250 per drill bit, although other densities both above and below this range fall within the scope of the disclosure.
The orientation, size, and density of the thermally stable polycrystalline cutters 60 produce unexpected results, particularly when drilling through plugs, packers, and other equipment. First, it would not be expected that the thermally stable polycrystalline cutters 60 with the side-rake and the various orientations described above and illustrated in
Unexpectedly, test results show that rates of penetration increase for an embodiment of the disclosed drill bit as compared to traditional drill bits with only PDC cutters when drilling plugs or packers.
The data for each of the three drill bits are from a single run for each bit. The left most bar 804 represents the time it took for a standard PDC drill bit on a drill string coupled to only a top drive or surface drive system as its source of rotary torque to drill each plug. That standard PDC bit on the top drive, data 804, drilled 53 plugs, but it took an average of 33.7 minutes to drill each plug.
The middle bar 806 represents the time it took for a standard PDC drill bit on a drill string coupled to a downhole motor as its source of rotary torque to drill each plug. That standard PDC bit coupled to the downhole motor, data 806, drilled only 33 plugs before it was removed from the well. The PDC drill bit on the motor, data 806, averaged of 26.6 minutes to drill each plug, which likely is attributable to the fact that the downhole motors will rotate a drill bit at two to four times the revolutions per minute than a drill bit rotated from surface via a top drive.
The right most bar 810 represents the time it took for a drill bit 10 as disclosed with thermally stable polycrystalline cutters 60 in the blade shoulder section 28 coupled to a downhole motor as its source of rotary torque to drill each plug. As mentioned, one would typically expect that the use of a greater density of smaller cutters would result in a lower rate of penetration, i.e., a longer time to drill through each plug. On the contrary, the drill bit 10 as represented in data 810 drilled 53 plugs in an average of 19.0 minutes. This represents a 43% and a 28.6% improvement over the two runs with a standard PDC bit, which in turn represents a significant cost saving in reduced rig time.
It is believed that the orientation of the thermally stable polycrystalline cutters 60 as described above better cuts and grinds the softer rubber components of the plugs and packers than the PDC cutting elements 40 alone, which work better on the harder materials.
Methods of making the various embodiments of the drill bit 10 are also disclosed. The method includes forming a bit body 25 having a first end 12 and a second end 13 spaced apart from the first end 12. The method further includes forming a plurality of blades 30 connected to and extending away from the bit body 25 at least at the second end 13, the plurality of blades 30 including a cone section 29 at the second end 13 that extends a first radial distance from a centerline 21 of the drill bit, a blade flank section 28 that extends from proximate the first radial distance to a second radial distance from the centerline 21 that is greater than the first radial distance, and a blade shoulder section 27 that extends from proximate the second radial distance to a third radial distance greater than the second radial distance, the third radial distance proximate a gauge radial distance that defines a maximum radius of the drill bit 10. The bit body 25 can be formed integrally with the drill bit blades 30, such as being milled out of a single steel blank. Alternatively, the drill bit blades 30 can be welded to the bit body 25. Another embodiment of the bit body 25 and blades 30 is one formed of a matrix sintered in a mold of selected size and shape under temperature and pressure, typically a tungsten carbide matrix with a nickel binder, with drill bit blades 30 also integrally formed of the matrix with the bit body 25. A steel blank in the general shape of the bit body 25 and the drill blades 30 can be used to form a scaffold and/or support structure for the matrix. A selected number of blades 30 are milled or molded to have a selected shape in consideration of various factors, including the plugs, packers, or geophysical properties of the formation to be drilled as described above. The blades 30 may be symmetric or asymmetric relative to the drill bit body 25 and to each other, as illustrated in the figures.
The method also includes coupling at least one cutting element 40 to at least one of the plurality of blades 30 and coupling a plurality of thermally stable polycrystalline cutters 60 to at least one of the plurality of blades in at least one of the cone section, the blade flank section, and the blade shoulder section of the at least one of the plurality of blades and combinations thereof.
The method also includes forming a connection 14 for coupling the bit body 25 to a drill string on the bit body 25. The bit body 25 also can be formed integrally with the connection 14 from a steel blank or a steel connection 14 can be welded to the bit body 25.
The inner annulus of the drill bit 10 can be milled out of the connection. The nozzles 50, jets, ports, fluid channels and junk slots 52 within the drill bit body 25, and one or more pockets in each of the drill bit blades 30 configured to receive a cutting element 40 and/or cutter 60 also can be milled out of the drill bit body. Alternatively, if the drill bit 10 is formed from a matrix, special blanks may be placed within the mold at the location of the various features, such as the jets, nozzles, fluid channels, junk slots, and through holes with the matrix sintered about the blanks. Once the drill bit body 25 is removed from its mold after the sintering process the blanks can be removed from the drill bit body 25, thereby revealing the desired hole or feature in the drill bit body 25. Any imperfections in the molding process can be removed through finish milling or other similar tool work.
Optionally, the method includes positioning the at least one cutting element 40 and the plurality of thermally stable polycrystalline cutters 60 on the same blade of the plurality of blades 30.
The method may further include at least one of a) embedding the plurality of thermally stable polycrystalline cutters 60 in a tungsten carbide segment or puck 62 and coupling the tungsten carbide segment or puck 62 to at least one of the plurality of blades 30 or the bit body 25; b) forming the plurality of blades 30 from a matrix and embedding the plurality of thermally stable polycrystalline cutters 60 in the matrix; and c) brazing the plurality of thermally stable polycrystalline cutters 60 to at least one of the plurality of blades 30.
The method may include segmenting a portion of a polycrystalline diamond compact 740 to form at least one of the cutting element 40 and the plurality thermally stable polycrystalline cutters 60.
The method may include positioning the line 54 substantially parallel to a tangential line 66 of a radial line 69 that extends from a center 21 of the drill bit 10 to the cutting edge 64.
The method may include positioning the line 65 so as to intersect a tangential line 66 of a radial line 67 that extends from a center 21 of the drill bit 10 to the cutting edge 64 at an angle less than or equal to 20 degrees.
The method optionally includes positioning the horizontal line 68 so as to intersect a radial line 69 that extends from a center 21 of the drill bit 10 to the horizontal line 68 at an angle between greater than or equal to 70 degrees and less than or equal to 110 degrees.
The method optionally includes positioning at least one of the thermally stable polycrystalline cutters 60 to have a side-rake angle in one of the ranges of a) from 70 degrees to 110 degrees and b) from −70 to −110 degrees.
The one or more present inventions, in various embodiments, includes components, methods, processes, systems and/or apparatus substantially as depicted and described herein, including various embodiments, subcombinations, and subsets thereof. Those of skill in the art will understand how to make and use the present invention after understanding the present disclosure.
The present invention, in various embodiments, includes providing devices and processes in the absence of items not depicted and/or described herein or in various embodiments hereof, including in the absence of such items as may have been used in previous devices or processes, e.g., for improving performance, achieving ease and/or reducing cost of implementation.
The foregoing discussion of the invention has been presented for purposes of illustration and description. The foregoing is not intended to limit the invention to the form or forms disclosed herein. In the foregoing Detailed Description for example, various features of the invention are grouped together in one or more embodiments for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed invention requires more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive aspects lie in less than all features of a single foregoing disclosed embodiment. Thus, the following claims are hereby incorporated into this Detailed Description, with each claim standing on its own as a separate preferred embodiment of the invention.
Moreover, though the description of the invention has included description of one or more embodiments and certain variations and modifications, other variations and modifications are within the scope of the invention, e.g., as may be within the skill and knowledge of those in the art, after understanding the present disclosure. It is intended to obtain rights which include alternative embodiments to the extent permitted, including alternate, interchangeable and/or equivalent structures, functions, ranges or steps to those claimed, whether or not such alternate, interchangeable and/or equivalent structures, functions, ranges or steps are disclosed herein, and without intending to publicly dedicate any patentable subject matter.
This application claims the benefit of and priority from U.S. Provisional Patent Application No. 62/583,228 entitled Hybrid Plug Drill-Out Bit filed on Nov. 8, 2017 and U.S. Provisional Patent Application No. 62/483,359 entitled Hybrid Plug Drill-Out Bit filed on Apr. 8, 2017, both of which are incorporated in their entirety for all purposes by this reference.
| Number | Date | Country | |
|---|---|---|---|
| 62583228 | Nov 2017 | US | |
| 62483359 | Apr 2017 | US |
