CA2818431A1 - Drill bit having differentially rotating cutting structures - Google Patents

Description

"DRILL BIT HAVING DIFFERENTIALLY ROTATING CUTTING STRUCTURES"
FIELD OF THE INVENTION
This invention relates to drill bits, specifically drill bit assemblies for use in oil, gas, geothermal, and horizontal drilling. More specifically, the invention relates to drill bits having cutting structures that rotate about the bit's central axis at differential speeds relative to each other.
BACKGROUND OF THE INVENTION
In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a "drill string." The drill string is rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. Such apparatus may be a top drive or a rotary table which provides a (typically clockwise) rotational force to the drill string to facilitate the process of drilling a borehole. This causes the drill bit to cut through the formation material by either scrapping, fracturing, or shearing action, or through a combination of all cutting methods.
While the bit rotates, drilling fluid is typically pumped through the drill string's hollow tubular interior and directed out of the drill bit through nozzles that are in fluid communication with the hollow interior and are positioned in the bit face. The drilling fluid cools the bit and flushes cuttings away from the cutting structure and face of the bit. In conventional drilling operations, the drilling fluid and cuttings are forced from the bottom of the borehole to the surface through the annulus that is formed between the drill string's exterior and the borehole.
Drill bits in general are well known in the art. Such bits include diamond impregnated bits, milled tooth bits, tungsten carbide insert ("TCI") bits, polycrystalline diamond compacts ("PDC") bits, and natural diamond bits. An example of a rock bit for earth formation drilling using PDC cutters is disclosed in U.S. Pat. No. 5,186,268. FIGS. 1 and 2 from that patent show a rotary drill bit having a bit body 10. The lower face of the bit body 10 is formed with a plurality of blades 17-25, which extend generally outwardly away from a central longitudinal axis of rotation 15 of the drill bit. A plurality of PDC cutters 26 are disposed side by side along the length of each blade. The number of PDC cutters 26 carried by each blade may vary. The PDC cutters 26 are brazed to a stud-like carrier, which may also be formed from tungsten carbide, and is received and secured within a socket in the respective blade.
Existing drill bits generally drill at a rate that the driller puts into the top-drive (or rotary table), as transferred to the bit via the drill string.
However, the cutting surface(s) of existing drill bits often experience variable resistance to the drilling action (e.g. due to localized variations in the formation material).
For example, the outer circumferential area of a bit may experience great resistance to drilling than the center portion. This variable resistance along the cutting surface of a bit may result in uneven wear of the bit and premature bit failure.

Therefore, what is needed is a bit that is can compensate for such variable resistance.
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments of the invention will now be described, by way of example only, with reference to the accompanying drawings, wherein:
FIG. la is a perspective view of an exemplary embodiment of the invention;
FIG. lb is a sectioned view of the embodiment of FIG. la;
FIG. 2a is a partially exploded perspective view of the embodiment of FIG. la;
FIG. 2b is a sectioned view of FIG. 2a;
FIG. 3a is an exploded perspective view of the embodiment of FIG.
la;
FIG. 3b is a sectioned view of FIG. 3a;
FIGS. 4a and 4b are perspective views of components of the embodiment of FIG. la, illustrating middle cutting structure being connected directly to the bit body for co-rotation therewith;
FIG. 4c is an exploded perspective view of FIG. 4b;
FIG. 4d is a sectioned perspective view of the embodiment of FIG.1a;

FIGS. 5a ¨ 5d are various perspective views of components of the embodiment of FIG. la, illustrating how, if the resistance to rotation at both the innermost and outermost cutting structures is equal, both cutting structures rotate at the same rate;
FIGS. 6a ¨ 6d are various perspective views of components of the embodiment of FIG. 1 a, illustrating how, if the resistance to rotation at both the innermost and outermost cutting structures is unequal, said cutting structures rotate at the different rates;
FIG. 7 is a schematic sectioned view of another embodiment of a differential for use within a bit; and FIG. 8 is a schematic sectioned view of yet another embodiment of a differential for use within a bit.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
The following description are of preferred embodiments by way of example only and without limitation to the combination of features necessary for carrying the invention into effect. Reference is to be had to the Figures in which identical reference numbers identify similar components. The drawing figures are not necessarily to scale and certain features are shown in schematic or diagrammatic form in the interest of clarity and conciseness.

Referring now in detail to the accompanying drawings, there are illustrated exemplary embodiments of a drill bit according to the present invention, the drill bit generally referred to by the numeral 10.
Figures la ¨ 6d illustrate a drill bit 10 according to a preferred embodiment of the invention. Bit 10 is adapted for drilling through formations of rock to form a borehole. Bit 10 has a leading end 101 and a trailing end 10t.
Leading end 101 includes drill bit face 10f. Trailing end 10t includes a bit body 12 having shank 14 and a connection 15. Preferably, bit body 12 is of a tapered configuration, with its leading end 121 being of larger diameter as compared to its trailing end 12t. Connection 15 may comprise a pin-end connection having tapered threads for connecting bit 10 to a bottom hole assembly of a conventional rotating a drill string, or alternatively, for connection to a downhole motor assembly, either of which may be employed to impart rotational force or torque F to the bit 10 for drilling the borehole.
Bit 10 preferably provides a central passage 16 for supplying drilling fluid through one or more flow passages 17 and fluid ports 18 in the face region 10f of the bit 10. The central longitudinal axis of rotation of the drill bit 10 is indicated at C. External fluid courses or junk slots 20 are preferably provided on the face region 10f and the bit body 12 to allow well cuttings and circulating drilling fluid to flow up past the bit. Preferably, junk slots 20 are in accordance with appropriate API

(American Petroleum Institute) specification. More preferably, fluid ports 18 include nozzles (not shown) disposed therein to better control the expulsion of drilling fluid from bit body 12 into fluid courses and junk slots 20 in order to facilitate the cooling of bit 10 and the flushing of formation cuttings up the borehole toward the surface when bit 10 is in operation.
Leading end 101, or drill bit face 10f, includes a plurality of cutting structures 21 concentrically or coaxially arranged about the bit's central axis C.
Exemplary bit 10 comprises three, generally circular, cutting structures or blades 21a, 21b, 21c coaxially arranged about the bit 10. However, a greater or fewer number of cutting structures may be provided on a bit as determined to be optimum for a particular drill bit. Cutting structures 21 preferably have cutter extensions 22 which project into the interior of the bit body 12 to facilitate attachment, connection or linkage to the bit body 12 and which direct some or all of the rotational force or torque F from the bit body 12 to the cutting structures 21, as further described below.
Since exemplary bit 10 comprises three, generally circular, cutting structures 21a, 21b, 21c, exemplary bit 10 further comprises three cylindrical cutter extensions 22a, 22b, 22c placed in a substantially nested coaxial arrangement.
In the preferred embodiment, the most centric (innermost) cutting structure 21c further comprising a central passage 16' which is in fluid communication with, and an extension of, central passage 16 and functions to direct drilling fluid from central passage 16 out through fluid ports 18 via flow passages 17 (see, for example, FIG.
1b).

Cutting structures 21 of exemplary bit 10 are further depicted as having a plurality of pockets 24 which may receive polycrystalline diamond compact (PDC) cutter inserts, tungsten carbide inserts ("TCI") or other types of superabrasive cutters or wear elements such as thermally stable polycrystalline diamond compacts, (TSPs) hard facing, weldings, weldments or other wear-resistant members to reduce the abrasive wear thereof by contact with the formation under weight-on-bit as the bit 10 rotates under applied torque F. In lieu of pockets to receive inserts, the load bearing surfaces of the cutting structures 21 may be comprised of, or completely covered with, a wear-resistant material. It will be recognized by those skilled-in-the art that cutting structures 21 need not be specifically configured in the manner as shown in the Figures, but may be configured to include profiles, pockets, sizes, superabrisive cutter inserts, wear-resistant members and combinations other than those shown.
The bit 10 further comprises a differential 30 to direct some or all of the rotational force F from the bit body 12 to one or more of the plurality of cutting structures 21. In the embodiment of the exemplary bit 10, differential mechanism 30 is set inside the bit body 12 and drives both the innermost (most centric) and outermost cutting structures 21c, 21a. In contrast, the middle cutting structure 21b of the exemplary bit 10 is connected directly to the bit body 12, for co-rotation therewith. Preferably middle cutting structure 21b is connected to body 12 via one or more pin members 40 that are inserted through one or more ports 12p in the bit body 12 so as to mate with corresponding ports 22bp in the cutter extension 22b of said middle cutting structure 21b (see FIGS. 4b-4d). Pin members 40 may be threaded or welded in place once inserted. As such, any rotational force F
imparted on the bit body 12 is also transmitted to the middle cutting structure 21b (via pin members 40) to substantially the same extent and in substantially the same direction as applied to the bit body 12. In other embodiments, there may be a different number of cutting structures, some or all of which are driven by the differential 30.
Differential 30 of the exemplary embodiment comprises one or more pinion drive gears 32, which receive input torque IT from the bit body 12, a first ring gear 34a to drive the outermost cutting structure 21a, and a second ring gear 34c to drive the innermost cutting structure 21c (see FIGS 3a, 3b, 5a and 5b, for example).
The pinion drive gears 32 may have shaft portions 32s and be fit into the interior of bit body 12 by insertion of shaft portions 32s into suitable ports or recesses 12r provided in said bit body 12 (see FIG. 4d). Suitable bearings or bushing (not shown) may also be provide, to facilitate relative free rotation of pinion drive gears 32 within said recesses 12r.
The first ring gear 34a may be machined or formed out of the trailing end 21at of cutting structure 21a (see FIG. 3a), or it may be welded or otherwise attached to cutting structure 21a, such as by welding or threaded connection at trailing end 21at. The second ring gear 34c is preferably press-fit inside bit body 12 (near shank 14) using a tapered roller bearing 36 which is maintained within bit body 12 by being press-fit into an appropriately shouldered channel or groove 37 in a conventional manner (se FIG. 3b). Second ring gear 24c may be connected to innermost cutting structure 21c, for co-rotation therewith, such as by welding or threaded connection. Advantageously, tapered roller bearing 36 provides a backing to any compressive forces that may be placed on the bit 10.
Preferably, sealing members 50 are provided at appropriate locations within the bit 10, in a conventional manner (such as bushings placed in a stepped-path around cutter extensions), so as to direct drilling fluid along passages 16, 16' and out through fluid ports 18 and so as to keep annular fluid and drill cuttings out of the bit's interior during operations; see FIG. 2b. In the embodiment of FIGS.
la-6d, sealing members 50 comprise bushings such as wear sleeves 50a, brass ring members 50b, as well as o-rings (not shown) positioned within o-ring grooves 50g.
Tapered roller bearing 36 may also provide a sealing functionality. Some of sealing members 50 also provide wear and bearing functionality, and promote rotation of the cutting structures 21 and their cutting extensions 22 around axis C.
Operation During drilling operations, rotational force or torque F is received by bit 10 from a drill string, or alternatively, from a downhole motor assembly or some other source. As described above, rotational force F imparted on the bit body 12 is transmitted to the middle cutting structure 21b via pin members 40 ¨ resulting in rotation of the middle cutting structure 21b to substantially the same extent and in substantially the same direction the bit body 12, as indicated by arrows F
(see FIGS. 4a-4d). Rotational force F is also transmitted to the pinion drive gears 32 of the differential 30 as input torque IT, i.e. the bit body 12 functioning like a carrier or cage of a conventional differential. The pinion drive gears 32 revolve around the axis of the first and second ring gears 34a, 34c, which are co-axial with the bit's longitudinal axis C, thereby driving said first and second ring gears 34a, 34c and the respective cutting structures 21a, 21c (via cutter extensions 22a, 22c); i.e.
the pinion drive gears 32 functioning like planet gears of a conventional differential and the first and second ring gears 34a, 34c functioning like sun gears of a conventional differential.
If the resistance to rotation at both cutting structures 21a, 21c is equal, the pinion drive gears 32 revolve around axis C without spinning about their own axis 32a, thereby causing both ring gears 34a, 34c and, hence, both cutting structures 21a, 21c rotate at the same rate, as shown in FIGS 5a-5d and as indicated by arrows G. If, however, the resistance to rotation at both cutting structures 21a, 21c is unequal, the pinion drive gears 32 will spinning about their axis 32a (as indicated by arrow S in FIGS. 6c-6d, for example) as they revolve around axis C, thereby causing both ring gears 34a, 34c and, hence, both cutting structures 21a, 21c rotate at different rates. In such a case, the cutting structure 21 encountering the greater resistance will slow down with a proportionally equal speeding up of the cutting structure 21 that is facing the lower resistance;
see, for example, FIGS 6a-6d and as indicated by arrows H and I, with arrow I being shown going in the opposite direction to arrows F and H because ring gear 34c (and associated cutting structure 21c) has slowed down relative to ring gear 34a (and its associated cutting structure 21a).
During operations of the exemplary bit 10, a driller operating the bit 10 simply provides a desired input rotational drill rate (e.g. F) to the top-drive (or rotary table) and the drill string, said input rate then also determines the rate of rotation (e.g. F) of the middle cutting structure 21b of bit 10 as described above.
Differential 30 will adjust the rotational rate of innermost and outermost cutting structures 21a, 21c based on the bit's contact with the formation and the resulting (variable) resistance or torque load encountered by said innermost and outermost cutting structures 21a, 21c (e.g. H and I in FIGS. 6a-6d). Advantageously, innermost and outermost cutting structures 21a, 21c are optimized for drilling the formation material based on the actual resistance "felt" or experienced by said innermost and outermost cutting structures 21a, 21c. More advantageously, by providing a bit with differentially rotating cutting structures 21, bit 10 will last longer and drill faster than conventional bits which do not have such differentially rotating cutting structures.
Additional Embodiments Additional embodiments of a differential 30 are schematically illustrated in FIGS. 7 and 8, wherein ring gears are generally indicated by 34. In the embodiment of FIG. 7, the differential comprises four ring gears 34, driven by at least 4 pinion drive gears 32, and the differential 30 drives three cutting structures 21. In the embodiment of FIG. 8, the differential comprises three ring gears 34, driven by at least 4 pinion drive gears 32, and the differential 30 drives four cutting structures 21. In both of the FIG. 7 and FIG. 8 embodiments, the differential operates in a similar fashion as the differential 30 of the embodiment of FIGS. 1a ¨
6d as described above.
In the claims, the word "comprising" is used in its inclusive sense and does not exclude other elements being present. The indefinite article "a"
before a claim feature does not exclude more than one of the features being present.
Those of ordinary skill in the art will appreciate that various modifications to the invention as described herein will be possible without falling outside the scope of the invention.