Patent Application
20200362640
This invention is related in general to the field of drill bits. More particularly, the invention is related to rotary drag bits with blades supporting cutters.
In a typical drilling operation, a drill bit is rotated while being advanced into a rock formation. There are several types of drill bits, including roller cone bits, hammer bits and drag bits. There are many drag bit configurations of bit bodies, blades and cutters.
Drag bits typically include a body with a plurality of blades extending from the body. For example, U.S. Pat. No. 10,233,696, issued on Mar. 19, 2019, discloses a drill bit that can be used for drilling operations The bit can be made of steel alloy, a tungsten matrix or other material. Drag bits typically have no moving parts and are cast or milled as a single-piece body with cutting elements brazed into the blades of the body. Each blade supports a plurality of discrete cutters that contact, shear and/or crush the rock formation in the borehole as the bit rotates to advance the borehole. Cutters on the shoulder of drag bits effectively enlarge the borehole initiated by cutters on the nose and in the cone, or center, of the drill bit.
Cutters mounted on blades of the drag bit can be made from any durable material, but are conventionally formed from a tungsten carbide backing piece, or substrate, with a front facing table comprised of a diamond material. The tungsten carbide substrates are formed of cemented tungsten carbide comprised of tungsten carbide particles dispersed in a cobalt binder matrix. The diamond table, which engages the rock formation, typically comprises polycrystalline diamond (“PCD”) directly bonded to the tungsten carbide substrate, but could be any hard material. The PCD table provides improved wear resistance, as compared to the softer, tougher tungsten carbide substrate that supports the diamond during drilling.
Cutters shearing the rock in the borehole are typically received in recesses along the leading edges of the blades. The drill string and the bit rotate about a longitudinal axis and the cutters mounted on the blades sweep a radial path in the borehole, failing rock. The failed material passes into channels between the bit blades and is flushed to the surface by drilling fluid pumped down the drill string.
Some materials the bit passes through tend to clog the channels and reduce the efficiency of the bit in advancing the borehole. As the bit fails materials such as shale at the borewall, the material quickly absorbs fluid and can form clays that are sticky. Clays can form ribbons as it is cut from the bore that agglomerate and can cling to the surface of the bit in the channels. This narrows the channels and can inhibit flushing of new material to the surface. The material expands as it absorbs water and pressure increases in the channels of the bit. While this pressure in the channel can help flush less sticky material from the channel, the pressure can cause clay to stick to the channel walls. This causes the bit to bog down and limits the volume of new material that can be processed through the channel.
The need exists for improved drill bits.
In some embodiments a drill bit body having a central axis about which the drill bit body is intended to rotate comprises a distal end having a face region on which is defined a plurality of blades extending from the face region to a gauge region and separated by channels between the blades, each blade supporting on an outer edge region a plurality of polycrystalline diamond compact (PDC) cutters distal to the gauge region; and a proximal end opposite the distal end, wherein: at least a portion of the gauge region is offset at a first angle relative to the outer edge region, and the gauge region includes a plurality of outwardly protruding ribs oriented in a direction offset at a second angle relative to the outer edge region. In some embodiments, the first angle is substantially the same as the second angle; the plurality of outwardly protruding ribs are parallel with each other on a given blade; at least some of the ribs include diamond cutting features thereon; at least one blade includes one or more PDC cutters proximal to the ribs; a plurality of backup cutters rotationally following the plurality of PDC cutters on the outer edge region; each blade of the plurality of blades comprises: two PDC cutters of the plurality of PDC cutters on a surface substantially parallel to the central axis and/or two backup cutters behind the two PDC cutters on the surface substantially parallel to the central axis; and/or the two PDC cutters on the surface substantially parallel to the central axis and the two backup cutters aid in steering the drill bit body during directional drilling and/or or when increased side cutting is desired.
In some embodiments, a drill bit body having a central axis about which the drill bit body is intended to rotate comprises a distal end having a face region on which is defined a plurality of blades extending from the face region to a gauge region and separated by channels between the blades, each blade supporting on an outer edge region a plurality of polycrystalline diamond compact (PDC) cutters distal to the gauge region; a proximal end opposite the distal end; and/or at least one cutter disposed distally to the gauge region on an outer surface oriented substantially parallel to the central axis, wherein: the gauge region includes a plurality of outwardly protruding ribs oriented in a direction offset relative to the outer edge region. In some embodiments, at least a portion of the gauge region is offset at an angle relative to the outer edge region; each blade of the plurality of blades comprises: two PDC cutters of the plurality of PDC cutters on a surface substantially parallel to the central axis and two backup cutters behind the two PDC cutters on the surface substantially parallel to the central axis; and/or the two PDC cutters on the surface substantially parallel to the central axis and the two backup cutters aid in steering the drill bit body during directional drilling and/or when increased side cutting is desired.
In some embodiments, the disclosure is directed to a method comprising providing a drill bit body as described herein and rotating the drill bit body into a subterranean feature.
Further areas of applicability of the present disclosure will become apparent from the detailed description provided hereinafter. It should be understood that the detailed description and specific examples, while indicating various embodiments, are intended for purposes of illustration only and are not intended to necessarily limit the scope of the disclosure.
The present disclosure is described in conjunction with the appended figures.
In the appended figures, similar components and/or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a dash and a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label.
The ensuing description provides preferred exemplary embodiment(s) only, and is not intended to limit the scope, applicability, or configuration of the disclosure. Rather, the ensuing description of the preferred exemplary embodiment(s) will provide those skilled in the art with an enabling description for implementing a preferred exemplary embodiment. It is understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope as set forth in the appended claims. For example, though a specific type of rotary drill bit might be described, aspects of the invention can apply to many different kinds of drill bits, including natural diamond bits, hole-openers, bi-center bits, core bits, impregnated bits, PDC (polycrystalline diamond compact) bits, TSP (thermally stable polycrystalline diamond) bits, casing plug drill bits, reamers, expandable reamers, etc.
Referring to
During drilling operation, the rotary drill bit 200 may be coupled to the drill string. As the rotary drill bit 200 is rotated within the wellbore via the drill string, drilling fluid may be pumped down the drill string, through the internal fluid plenum and fluid passageways within the bit body 204 of the rotary drill bit 200, and out from the rotary drill bit 200 through nozzles 217.
Formation cuttings generated by the cutting elements of the bit body 204 may be carried with the drilling fluid through the fluid courses (e.g., “junk slots”), around the rotary drill bit 200, and back up the wellbore through the annular space within the wellbore outside the drill string.
The bit body 204 may include a plurality of raised blades 210 that extend from the face of the bit body 204. In some embodiments, the plurality of blades 210 extend radially along the bit face and are circumferentially spaced structures extending along the leading end or formation engaging portion of the bit body 204. Each blade 210 may extend generally in a radial direction, outwardly to the periphery of the bit body 204. For example, the blades 210 may generally extend from the cone region proximate the longitudinal axis, or central axis 202, of the bit, upwardly to the gauge region, or maximum drill diameter of the bit. In some embodiments, the blades 210 are substantially equally spaced around the central axis 202 of the bit and each blade 210 sweeps or curves backwardly in the direction of rotation indicated by arrow 215.
The bit body 204 further includes a plurality of superabrasive cutting elements 212, e.g., polycrystalline diamond compact (“PDC”) cutting elements, disposed on radially outward facing surfaces of each of the blades 210. For example, a plurality of discrete cutting elements 212 may be mounted on each blade 210. Each discrete cutting element 212 may be disposed within a recess or pocket in each blade 210. The cutting elements 212 may be mounted to a rotary drill bit 200 either by press-fitting or otherwise locking the stud (e.g., substrate portion of cutting element) of the cutting elements 212 into a receptacle on a drag bit, or by brazing a portion of the cutting elements 212 directly into a preformed pocket, socket or other receptacle on the face of a bit body 204.
Cutting elements 212 used in rotary drill bits are often PDC cutting elements. It has been known in the art that PDC cutters perform well on drag bits. PDC cutting elements include a polycrystalline diamond (PCD) material, which may be characterized as a superabrasive or superhard material. Such polycrystalline diamond materials are formed by sintering and bonding together small diamond grains (e.g., diamond crystals), under conditions of high temperature and high pressure, in the presence of a catalyst material to form polycrystalline diamond.
In the rotary drill bit 200, the cutting elements 212 may be placed along the forward (in the direction of intended rotation) side of the blades 210, with their working surfaces facing generally in the forward direction for shearing the earth formation when the rotary drill bit 200 is rotated about its central axis 202. In some embodiments, the blade 210 may comprise one or more rows of cutting elements 212 disposed on the blade 210. For example, the blade 210 may comprise a first row of primary cutters and a second row of backup cutters. A plurality of primary cutting elements may be mounted side-by-side along each blade. The secondary cutting elements may be mounted rearwardly from the primary cutters on the blade 210. The secondary cutting elements may rotationally follow the primary cutters at selected back rake and side rake angles. For example, the secondary cutting elements may be spaced rearwardly from the primary cutting elements to cut or abrade a kerf region formed between adjacent primary cutters. In some embodiments, at least one of the cutting elements, e.g., a secondary cutter, is clocked relative to a kerf region formed by a rotationally preceding cutter, e.g., a primary cutter. As used herein, clocked refers to aligning a spoke of the cutting element with a kerf region.
In some aspects, the secondary cutting elements may be mounted on another blade 210 from the primary cutters. Although the figures only show a few secondary cutting elements mounted on each blade 210, any number of the primary cutting elements may be provided with an associated secondary cutting element. As well known in the art, cutting elements 212 are radially spaced such that the groove or kerf formed by cutting elements 212 overlaps to a degree with kerfs formed by one or more cutting elements 212 in other rows.
In some aspects, the secondary cutting element may lie at the same radial distance from the axis of rotation of the bit as its associated primary cutting element. In the example shown in
In some embodiments, the cutting elements 212 may comprises PDC cutters. However, in other embodiments, not all of the cutters need to be PDC cutters. The PDC cutters in this example have a working surface made primarily of super hard, polycrystalline diamond, or the like, supported by a substrate that forms a mounting stud for placement in a pocket formed in the blade 210. In some embodiments, each of the PDC cutters is fabricated discretely and then mounted—by brazing, press fitting, or otherwise into pockets formed on the bit. This example of a drill bit includes gauge pads 214. In some applications, the gauge pads of drill bits such as rotary drill bit 200 can include an insert of thermally stable, sintered polycrystalline diamond (TSP).
Generally, each blade 210 includes a cone region, a nose region, a shoulder region, and a gauge region. Fluid ports are disposed about the face of the bit body 204 and are in fluid communication with at least one interior passage provided in the interior of bit body. In some aspects, fluid ports include nozzles 217 disposed therein to better control the expulsion of drilling fluid from bit body into fluid courses and junk slots in order to facilitate the cooling of cutters on the bit and the flushing of formation cuttings up the borehole toward the surface when the bit is in operation.
In some embodiments, the cutting elements 212 are embedded or mounted on the blades at a selected back rake and a selected side rake depending on their location on the blade 210. The cutting elements 212 may be strategically located on the respective blades 210 in a desired forward sweep, back rake, and side rake configurations to facilitate optimum cutting efficiency and channeling of drilling fluid pumped through the rotary drill bit 200 around the blades 210 and cutting elements 212 to clear the cutting elements 212 of formation cuttings in an optimal manner.
As mentioned, the back rake and side rake of each cutting element may be dependent on the location of the cutting element on the blade. In some aspects, the back rake of the cutting element(s) in the cone region ranges from 5° to 45°, e.g., from 10° to 40°, from 15° to 35°, or from 20° to 30°. In terms of upper limits, the back rake of the cutting element(s) in the cone region may be less than 45°, e.g., less than 40°, less than 30°, or less than 20°. In terms of lower limits, the back rake of the cutting element(s) in the cone region may be greater than 5°, e.g., greater than 10°, greater than 15°, or greater than 18°. In some aspects, the side rake of the cutting element(s) in the cone region ranges from 0° to 10°, e.g., from 1° to 9°, from 2° to 8°, or from 4° to 6°. In terms of upper limits, the side rake of the cutting element(s) in the cone region may be less than 10°, e.g., less than 8°, less than 6°, or less than 5°. In terms of lower limits, the side rake of the cutting element(s) in the cone region may be greater than 0°, e.g., greater than 1°, greater than 2°, or greater than 4°.
In some aspects, the back rake of the cutting element(s) in the nose region ranges from 10° to 30°, e.g., from 12° to 28°, from 15° to 25°, or from 18° to 22°. In terms of upper limits, the back rake of the cutting element(s) in the nose region may be less than 30°, e.g., less than 28°, less than 25°, or less than 22°. In terms of lower limits, the back rake of the cutting element(s) in the nose region may be greater than 10°, e.g., greater than 12°, greater than 15°, or greater than 18°. In some aspects, the side rake of the cutting element(s) in the nose region ranges from 5° to 20°, e.g., from 6° to 18°, from 7° to 16°, or from 8° to 14°. In terms of upper limits, the side rake of the cutting element(s) in the nose region may be less than 20°, e.g., less than 18°, less than 15°, or less than 12°. In terms of lower limits, the side rake of the cutting element(s) in the nose region may be greater than 5°, e.g., greater than 6°, greater than 7°, or greater than 8°.
In some aspects, the back rake of the cutting element(s) in the shoulder region ranges from 10° to 30°, e.g., from 12° to 28°, from 15° to 25°, or from 18° to 22°. In terms of upper limits, the back rake of the cutting element(s) in the shoulder region may be less than 30°, e.g., less than 28°, less than 25°, or less than 22°. In terms of lower limits, the back rake of the cutting element(s) in the shoulder region may be greater than 10°, e.g., greater than 12°, greater than 15°, or greater than 18°. In some aspects, the side rake of the cutting element(s) in the shoulder region ranges from 5° to 20°, e.g., from 6° to 18°, from 7° to 16°, or from 8° to 14°. In terms of upper limits, the side rake of the cutting element(s) in the shoulder region may be less than 20°, e.g., less than 18°, less than 15°, or less than 12°. In terms of lower limits, the side rake of the cutting element(s) in the shoulder region may be greater than 5°, e.g., greater than 6°, greater than 7°, or greater than 8°.
In some aspects, the back rake of the cutting element(s) in the gauge region ranges from 15° to 50°, e.g., from 20° to 45°, from 25° to 40°, or from 30° to 35°. In terms of upper limits, the back rake of the cutting element(s) in the gauge region may be less than 50°, e.g., less than 45°, less than 40°, or less than 35°. In terms of lower limits, the back rake of the cutting element(s) in the gauge region may be greater than 15°, e.g., greater than 20°, greater than 25°, or greater than 30°. In some aspects, the side rake of the cutting element(s) in the gauge region ranges from 0° to 10°, e.g., from 1° to 9°, from 2° to 8°, or from 4° to 6°. In terms of upper limits, the side rake of the cutting element(s) in the gauge region may be less than 10°, e.g., less than 8°, less than 6°, or less than 5°. In terms of lower limits, the side rake of the cutting element(s) in the gauge region may be greater than 0°, e.g., greater than 1°, greater than 2°, or greater than 4°.
The cutting elements 212 may have cutting faces having the same general shape, or the cutting elements 212 may have various shapes. The cutting faces of the elements may also differ in size according to their position on the blade 210 of the rotary drill bit 200. Additionally, cutting elements 212 may have differing cutting profiles, e.g., exposure heights, such that those elements extending further from the bit face are more exposed (e.g., high profile) to the formation material than those which are mounted at a relatively lower height (e.g., low profile) from the bit face. In some embodiments, cutting elements have a limited amount of exposure generally perpendicular to the selected portion of the formation-facing surface in which the superabrasive cutter is secured to control the effective depth-of-cut of at least one superabrasive cutter into a formation when the bit is engaging a formation during drilling.
In some embodiments, the cutting elements 212 having the smallest cutting face, as measured by surface contact surface area, will generally be mounted so as to have the greatest exposure to the formation, while the cutting elements having the largest cutting face will have the least exposure to the formation. This arrangement increases the stability of the bit by creating relatively tall and sharply tapered ridges between the kerfs which provide the side forces helpful in resisting bit vibration. The most exposed cutters may either have more or less negative back rake relative to the other cutters as dependent upon the type of formation being cut.
As shown in
Referring to
A plurality of blades 310 extend from a face region of the bit body 304 to the gauge pad 314. Blades 310 are separated by channels between the blades 310. Each blade 310 supports, on an outer edge region 324, a plurality of polycrystalline diamond compact (PDC) cutters distal to the gauge pad 314. For example, the first cutting element 312-1, the second cutting element 312-2, and the fifth cutting element 312-5 are part of the first plurality of PDC cutters on the outer edge region 324 and distal to the gauge pad 314.
In some aspects, not shown, the ribs are oriented substantially parallel relative to the outer edge region 324 (e.g., where first angle θ is 0 degrees), which is also substantially parallel to the longitudinal axis. In other embodiments, as shown, gauge pad 314 is offset at a first angle θ relative to the outer edge region 324. In some aspects, not shown, the first angle θ is 0 degrees. In other embodiments, the first angle θ is greater than or equal to 5, 10, 15, or 20 degrees (e.g., to reduce impact on the gauge region 324). In some embodiments, the first angle θ is equal to or less than 65, 55, 45, or 40 degrees (e.g., to facilitate in casting the bit body 304).
Ribs 320 are offset at a second angle relative to the outer edge region 324. In some embodiments, the second angle is substantially the same as the first angle θ. This aspect of the disclosure may be beneficial in that it facilitates casting of the bit body 304. Ribs 320 in the embodiment shown are parallel to each other (e.g., on a given blade). In other embodiments, not shown, the ribs 320 may be oriented at a second angle that is non-parallel (e.g., orthogonal or crisscross) relative to the first angle θ. In some embodiments, ribs 320 can be elongate, rounded (or peaked) structures protruding from a gauge pad 314. Ribs 320 can also be recessed into the gauge 314, such as v-grooves, rounded trenches, and/or rectangular trenches. Ribs 320 can have a length, a width, and a height. Length can be measured in a direction of the second angle and width can be measured orthogonal to length (e.g., width is measured in a direction of bit rotation when the second angle=first angle θ=0 degrees). Height can be measured radially outward (e.g., a distance beyond a surface of a gauge pad 314). Length of a rib 320 can be equal to or greater than 2, 3, 5, 10 or more times the width of the rib 320 and/or no more than 50 or 100 times the width of the rib 320. Ribs 320 can be spaced by a minimum 1, 1.5, 2, 4, or 5 times the width of the ribs 320 and/or by no more than 3, 5, or 10 times the width of each rib 320. In some embodiments, length of ribs 320 can be between 0.5 and 3 inches. Ribs 320 can cover between 5 and 90 percent or between 10 and 70 percent of a surface area of the gauge pad 314. Height of ribs 320 can be equal to or greater than 1/64, 1/32, 1/16, or ⅛ of an inch and equal to or less than ½, ¼, or ⅛ of an inch. Though a height of a rib 320 in
Ribs 320 have been found to beneficially increase side-cutting ability. Accordingly, in some embodiments, the bit body 304 is used for (e.g., configured for) side cutting. However, ribs 320 can cause the gauge pad 314 to be too aggressive and the rotary drill bit 200 can become unstable. It has now been found, however, that backup cutters, e.g., the third cutting element 312-3 and/or the fourth cutting element 312-4, can help stabilize a rotary drill bit 200 during drilling, wherein the bit body 304 has aggressive gauge pads 314 (e.g., gauge pads 314 with ribs 320). The backup cutters are not on the outer edge region; backup cutters are on the blade 310 and rotationally follow the plurality of PDC cutters on the outer edge region 324.
The sixth cutting element 312-6 is proximal to the gauge pad 314 (and the ribs 320). One or more PDC cutters can be placed proximal to the ribs 320 as up-drill cutters (e.g., to protect a proximal end of the gauge pad 314). The first cutting element 312-1 and the second cutting element 312-2 are on a surface that is substantially parallel to the central axis 202 (e.g., the first cutting element 312-1 and the second cutting element 312-2 are not at the face of the bit body 304, but on a side of the bit body 304). The third cutting element 312-3 and the fourth cutting element 312-4 are backup cutters behind the first cutting element 312-1 and the second cutting element 312-2, respectively. The first cutting element 312-1, the second cutting element 312-2, the third cutting element 312-3, and the fourth cutting element 312-4 aid in steering the bit body 304 during directional drilling and/or when increased side cutting is desired.
The bit body 304 can be used for drilling. The bit body 304 (sometimes referred to as a drill bit body) is provided. The bit body 304 has a central axis 202 about which the bit body 304 is intended to rotate. The bit body can comprise a distal end having a face region on which is defined a plurality of blades (e.g., blades 210, 310) extending from the face region to a gauge region (e.g., gauge pad 314) and separated by channels between the blades, each blade supporting on an outer edge region a plurality of polycrystalline diamond compact (PDC) cutters distal to the gauge region (e.g., cutters 212 and cutting elements 312-1, 312-2, and/or 312-5. A proximal end can be opposite the distal end. At least a portion of the gauge region is offset at a first angle (e.g., first angle θ) relative to the outer edge region. The gauge region includes a plurality of outwardly protruding ribs (e.g., ribs 220 or 320) oriented in a direction offset at a second angle relative to the outer edge region. The bit body 304 is rotated into a subterranean feature (e.g., rock) to form a hole in the subterranean feature.
A number of variations and modifications of the disclosed embodiments can also be used. While the principles of the disclosure have been described above in connection with specific apparatuses and methods, it is to be clearly understood that this description is made only by way of example and not as limitation on the scope of the disclosure.
