US20120031671A1

US20120031671A1 - Drill Bits With Rolling Cone Reamer Sections

Info

Publication number: US20120031671A1
Application number: US12/849,246
Authority: US
Inventors: Christopher Propes
Original assignee: National Oilwell Varco LP
Current assignee: National Oilwell DHT LP
Priority date: 2010-08-03
Filing date: 2010-08-03
Publication date: 2012-02-09

Abstract

A drill bit for drilling a borehole in earthen formations comprises a bit body having a central bit axis, a first end adapted to be connected to a drillstring, and a second end opposite the first end. In addition, the bit comprises a pilot bit extending from the second end of the bit body. Further, the bit comprises a reamer section extending radially from the bit body and axially positioned between the first end of the bit body and the pilot bit. The reamer section comprises a rolling cone cutter rotatably mounted to a journal shaft extending from the bit body. Moreover, the rolling cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND

1. Field of the Invention
The invention relates generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas or minerals. More particularly, the invention relates to drill bits for enlarging the diameter of an earthen borehole. Still more particularly, the invention relates to rolling cone underreamers used to open a hole below a restriction so that the opened hole is larger than the restriction itself.
2. Background of the Technology
In the drilling of oil and gas wells, concentric casing strings are installed and cemented in the borehole as drilling progresses to increasing depths. Each new casing string is supported within the previously installed casing string, thereby limiting the annular area available for the cementing operation. Further, as successively smaller diameter casing strings are suspended, the flow area for the production of oil and gas is reduced. Therefore, to increase the annular space for the cementing operation, and to increase the production flow area, it is often desirable to enlarge the borehole below the terminal end of the previously cased borehole. By enlarging the borehole, a larger annular area is provided for subsequently installing and cementing a larger casing string than would have been possible otherwise. Accordingly, by enlarging the borehole below the previously cased borehole, the bottom of the formation can be reached with comparatively larger diameter casing, thereby providing more flow area for the production of oil and gas.
Drill bits which drill holes through earth formations where the hole has a larger diameter than the bit's pass-through diameter (the diameter of an opening through which the bit can freely pass) are known in the art. Early types of such bits included so-called “underreamers”, which were essentially a drill bit having an axially elongated body and extensible arms on the side of the body which reamed the wall of the hole after cutters on the end of the bit had drilled the earth formations. Mechanical difficulties with the extensible arms limited the usefulness of underreamers.
More recently, so-called “bi-centered” drill bits have been developed. A typical bi-centered drill bit includes a “pilot” section located at the end of the bit, and a “reaming” section which is typically located at some axial distance from the end of the bit (and consequently from the pilot section). Bi-centered bits drill a hole larger than their pass through diameters because the axis of rotation of the bit is displaced from the geometric center of the bit. This arrangement enables the reaming section to cut the wall of the hole at a greater radial distance from the rotational axis than is the radial distance of the reaming section from the geometric center of the bit. In many conventional bi-centered bits, the pilot section comprises a fixed cutter or PDC bit attached to the end of the bit. The reaming section is usually axially spaced away from the end of the bit, and is disposed to one side of the bit. The reaming section typically includes a number of PDC inserts on blades on the side of the bit body in the reaming section.
FIGS. 1 and 2 illustrate an example of a conventional PDC bi-center bit 10 that includes a bit body 11 with a threaded pin 12 at one end for connection to a drill string, and a pilot section 20 defining an operating end face 13 opposite pin 12. Pilot section 20 includes a plurality of pilot blades 21 having a plurality of cutter elements 22 mounted thereon, and includes gauge pads 23 at the ends of the pilot blades 21 distal the lower end of the bit 10. A reamer section 30 is integrally formed with the body 11 between the pin 12 and the pilot section 20. Reaming section 30 includes a plurality of reaming blades 31 that are eccentrically positioned above pilot section 20. Reamer blades 31 also have cutter elements 32 mounted thereon and gauge pads 33 similar to those on the pilot section 20.
Cutter elements 22, 32 are typically formed of extremely hard materials. In the typical PDC bi-center bits, each cutter element comprises an elongate and generally cylindrical tungsten carbide support member which is received and secured in a pocket formed in the surface of one of the several blades. The cutter element typically includes a hard cutting layer of polycrystalline diamond (PD) or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. For convenience, as used herein, reference to “PDC cutter element” refers to a cutter element employing a hard cutting layer of polycrystalline diamond or other superabrasive material.
Blades 31 radiate from the bit body 11 but are only positioned about a selected portion or quadrant of bit 10 when viewed in end cross section. Accordingly, bit 10 may be tripped into a hole marginally greater than a pass through diameter D_pt, yet be able to drill an enlarged borehole having a diameter D_bthat is substantially greater than the pass through diameter D_pt.
For most conventional PDC bi-center bits, the reamer section represents the portion of the bit most susceptible to pre-mature wear and damage. Specifically, to achieve a pass through diameter that is less than the diameter of the enlarged hole to be drilled, the reamer blades are only positioned about a selected portion or quadrant of the bit body. In other words, the reamer blades are not disposed about the entire circumference of the bit. Due to such space limitations, most conventional PDC bi-centered bits only include two to four reamer blades. Consequently, the total space available on all the reamer blades for mounting cutter elements is also limited, and hence, for a given sized cutter element, the number of cutter elements in the reamer section is also limited. Furthermore, the cutter elements on the reamer blades continuously engage the formation as the bit is rotated. Due to the limited number of cutter, the cutting loads experienced by reamer section is spread out among fewer total cutter elements, thereby tending to increase the cutting load experienced by each cutter element in the reamer section as well as the associated wear.
Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP.
Increasing ROP while simultaneously increasing the service life of the drill bit will decrease drilling time and allow valuable oil and gas to be recovered more economically. Accordingly, drill bits for enlarging a borehole diameter that enable increased ROP and longer bit life would be particularly desirable.

BRIEF SUMMARY

These and other needs in the art are addressed in one embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central bit axis, a first end adapted to be connected to a drillstring, and a second end opposite the first end. In addition, the bit comprises a pilot bit extending from the second end of the bit body. Further, the bit comprises a reamer section extending radially from the bit body and axially positioned between the first end of the bit body and the pilot bit. The reamer section comprises a rolling cone cutter rotatably mounted to a journal shaft extending from the bit body. Moreover, the rolling cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body.
These and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central bit axis, a first end adapted to be connected to a drillstring, and a second end opposite the first end. In addition, the bit comprises a pilot bit extending from the second end of the bit body. Further, the bit comprises a reamer section extending radially from the bit body and axially positioned between the first end of the bit body and the pilot bit. The reamer section comprises a plurality of outwardly facing rolling cone cutters, each rolling cone cutter rotatably mounted to a journal shaft extending from the bit body.
These and other needs in the art are addressed in another embodiment by a method for drilling a wellbore in an earthen formation. In an embodiment, the method comprises (a) rotating a drill bit coupled to a lower end of a drillstring, wherein the drill bit comprises a bit body having a bit axis. In addition, the method comprises (b) forming a pilot borehole having a diameter D₁with a pilot bit disposed at a lower end of the bit body. Further, the method comprises (c) forming an enlarged borehole having a diameter D₂with a reamer section extending from radially the bit body. The reamer section is positioned axially above the pilot bit. Operation (c) comprises rotating a plurality of reamer rolling cone cutters, each reamer cone cutter depending from a journal extending from the bit body. Moreover, each reamer rolling cone cutter comprises a central axis, a backface, and a nose positioned proximal the diameter D₂.
Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the preferred embodiment of the present invention, reference will now be made to the accompanying drawings, wherein:

FIG. 1 is a side view of a conventional bi-center bit;

FIG. 2 is an end view of the drill bit of FIG. 1;

FIG. 3 is a side view of an embodiment of a bi-center drill bit in accordance with the principles described herein;

FIG. 4 is a perspective view of the drill bit of FIG. 3;

FIG. 5 is a bottom end view of the drill bit of FIG. 3;

FIG. 6 is a cross-sectional view of the drill bit of FIG. 3;

FIG. 7 is an enlarged cross-sectional view of one rolling cone cutter of the drill bit of FIG. 3;

FIG. 8 is a schematic bottom end view of the drill bit of FIG. 3 illustrating the reamer cone cutters as they are positioned in the borehole;

FIG. 9 is a side view of an embodiment of a speed drill bit in accordance with the principles described herein;

FIG. 10 is a bottom end view of the drill bit of FIG. 9;

FIG. 11 is an enlarged cross-sectional view of one rolling cone cutter of the drill bit of FIG. 9;

FIG. 12 is a side view of an embodiment of a bi-center drill bit in accordance with the principles described herein;

FIG. 13 is a bottom end view of the drill bit of FIG. 12;

FIG. 14 is an enlarged cross-sectional view of one rolling cone cutter of the pilot bit of FIG. 12;

FIG. 15 is a side view of an embodiment of a speed drill bit in accordance with the principles described herein;

FIG. 16 is a bottom end view of the drill bit of FIG. 15;

FIG. 17 is a side view of an embodiment of a bi-center drill bit in accordance with the principles described herein;

FIG. 18 is a perspective view of the drill bit of FIG. 17;

FIG. 19 is a bottom end view of the drill bit of FIG. 17;

FIG. 20 is a side view of an embodiment of a speed drill bit in accordance with the principles described herein; and

FIG. 21 is a perspective view of the drill bit of FIG. 20.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments of the present invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis.
Referring now to FIGS. 3-6, an embodiment of a bi-center bit 100 adapted for drilling through formations of rock to form a borehole is shown. Bit 100 has a central axis 111 about which bit 100 rotates in the cutting direction represented by arrow 118. In addition, bit 100 generally includes a bit body 112, a shank 113, and a threaded connection or pin 114 for connecting bit 100 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. Although bit body 112 is shown in FIG. 6 as comprising two components that are coupled together, in general, bit body 112 may be monolithic (i.e., a single, unitary piece) or formed of a plurality of components coupled together. At the lower end of bit 100 opposite pin 114, bit body 112 includes a pilot section or pilot bit 120 including an end face 121 that supports a pilot cutting structure 122. A reamer section 160 extends radially outward from body 112 and is axially disposed between pin 114 and pilot bit 120. Reamer section 160 includes a reamer cutting structure 162. As will be described in more detail below, in this embodiment, reamer section 160 includes a plurality of rolling cone cutters 171, 172.
Body 112 may be formed in a conventional manner using powdered metal tungsten carbide particles in a binder material to form a hard metal cast matrix. Alternatively, the body can be machined from a metal block, such as steel, rather than being formed from a matrix.
FIG. 6 shows a cross-sectional view of bit 100 taken in a vertical plane containing bit axis 111 and passing between cone cutters 171, 172 of reamer section 160. As best seen in FIG. 6, body 112 includes a central longitudinal bore 116 permitting drilling fluid to flow from the drill string into bit 100. A plurality of flow passages 117 extend through bit body 112 from bore 116. Passages 117 include outlet ports 119 disposed at their ends. Together, passages 117 and ports 119 serve to distribute drilling fluids around cutting structures 122 and 162 to flush away formation cuttings during drilling and to remove heat from bit 100.
Referring briefly to FIG. 5, bit 100 has a minimum pass through diameter D_pt, which represents the minimum diameter hole or bore through which bit 100 may be tripped. Further, pilot bit 120 defines a pilot gage diameter D_pbdetermined by the radially outermost reaches of pilot cutting structure 122. In general, the borehole formed by pilot bit 120, also referred to herein as the “pilot borehole,” has a diameter equal to pilot gage diameter D_pb. Reamer section 160 defines a reamer diameter D_rsdetermined by the radially outermost reaches of reamer cutting structure 162. In general, the borehole formed by reamer section 160, also referred to herein as the “enlarged borehole,” has a diameter equal to reamer diameter D_rs. Pilot diameter D_pbis less pass through diameter D_pt, however, reamer diameter D_rsis greater than pass through diameter D_pt. Thus, bit 100 may be tripped through a hole that is smaller than the diameter D_rsof the enlarged borehole formed by reamer section 160.
Referring again to FIGS. 3-5, in this embodiment, pilot bit 120 is coaxially aligned with bit body 112. In other words, pilot bit 120 and bit body 112 share the same central axis 111. In this embodiment, pilot bit 120 comprises a fixed cutter bit including a plurality of blades which extend from bit face 121. Specifically, cutting structure 122 includes a plurality of angularly spaced-apart primary blades 131, 132 and a plurality of angularly spaced apart secondary blades 133, 134. In this embodiment, the plurality of blades (e.g., primary blades 131, 132 and secondary blades 133, 134) are uniformly angularly spaced on bit face 121 about bit axis 111—the two primary blades 131, 132 are uniformly angularly spaced about 180° apart, and the two secondary blades 133, 134 are uniformly angularly spaced about 180° apart. In other embodiments (not specifically illustrated), one or more of the blades may be spaced non-uniformly about bit face 121. Still further, primary blades 131, 132, and secondary blades 133, 134 are circumferentially arranged in an alternating fashion. In other words, one secondary blade 133, 134 is disposed between each pair of circumferentially adjacent primary blades 131, 132. Although bit 100 is shown as having two primary blades 131, 132 and two secondary blades 133, 134, in general, bit 100 may comprise any suitable number of primary and secondary blades.
In this embodiment, primary blades 131, 132 and secondary blades 133, 134 are integrally formed as part of, and extend from, bit body 112 and bit face 121. Primary blades 131, 132 and secondary blades 133, 134 extend generally radially along bit face 121 and then axially along a portion of the periphery of pilot bit 120. In particular, primary blades 131, 132 extend radially from proximal central axis 111 toward the periphery of pilot bit 120. Thus, as used herein, the term “primary blade” may be used to refer to a blade that extends generally radially along the bit face from proximal the bit axis. However, secondary blades 133, 134 are not positioned proximal bit axis 111, but rather, extend radially along bit face 121 from a location that is distal bit axis 111 toward the periphery of pilot bit 120. Thus, as used herein, the term “secondary blade” may be used to refer to a blade that extends from a radial location distal the bit axis. Primary blades 131, 132 and secondary blades 133, 134 are separated by drilling fluid flow courses 119.
Referring still to FIGS. 3-5, each primary blade 131, 132 includes a cutter-supporting surface 142 for mounting a plurality of cutter elements, and each secondary blade 133, 134 includes a cutter-supporting surface 152 for mounting a plurality of cutter elements. Specifically, a plurality of cutter elements 140, each having a cutting face 144, are mounted to each primary blade 131, 132 and mounted to each secondary blade 133, 134.
Each cutter element 140 comprises an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the blade to which it is fixed. In general, each cutter element may have any suitable size and geometry. Cutting face 144 of each cutter element 140 comprises a disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed end of the support member. Further, each cutter element 140 is mounted such that each cutting face 144 is generally forward-facing. As used herein, “forward-facing” may be used to describe the orientation of a surface that is substantially perpendicular to, or at an acute angle relative to, the cutting direction of the bit (e.g., cutting direction 118 of bit 100). For instance, a forward-facing cutting face (e.g., cutting face 144) may be oriented perpendicular to the cutting direction of bit 100, may include a backrake angle, and/or may include a siderake angle. The cutting faces are preferably oriented perpendicular to the direction of rotation of bit 10 plus or minus a 45° backrake angle and plus or minus a 45° siderake angle. In addition, each cutting face 144 includes a cutting edge adapted to engage and remove formation material with a shearing action. Such cutting edge may be chamfered or beveled as desired. In this embodiment, cutting faces 144 are substantially planar, but may be convex or concave in other embodiments.
As one skilled in the art will appreciate, variations in the number, size, orientation, and locations of the blades (e.g., primary blades, secondary blades, etc.), and the cutter elements (e.g., cutter elements 140) are possible.
Pilot bit 120 further includes gage pads 151 disposed about the circumference of pilot bit 120 at angularly spaced locations. Specifically, a gage pad 151 intersects and extend from each blade 131, 132, 133, 134. Gage pads 151 are integrally formed as part of the bit body 112. Gage pads 151 can help maintain the size of the pilot borehole formed by pilot bit 120 by a rubbing action when primary cutter elements 140 wear slightly under gage. Thus, gage pads 151 define diameter D_pbof pilot bit 120. In addition, the gage pads also help stabilize the bit against vibration. In other embodiments, one or more of the gage pads (e.g., gage pads 151) may include other structural features. For instance, wear-resistant cutter elements or inserts may be embedded in gage pads and protrude from the gage-facing surface or forward-facing surface.
As previously described, cutter elements 140 and associated forward-facing cutting faces 144 are mounted to the cutter-supporting surface 142 of each blade. In general, cutter elements 140 may be mounted in any suitable arrangement on the blades. Examples of suitable arrangements may include, without limitation, radially extending rows, arrays or organized patterns, sinusoidal pattern, random, or combinations thereof. With weight-on-bit applied to bit 100 and rotation of bit 100 in the cutting direction represented by arrow 118, cutting faces 144 engage the formation and enable bit 100 to proceed to drill a pilot borehole.
As shown in FIGS. 3-5, in this embodiment, reamer section 160 comprises a plurality of rolling cone cutters 171, 172. In particular, each cone cutter 171, 172 is mounted on a pin or journal extending from bit body 112, and is adapted to rotate about a cone axis of rotation 175. In this embodiment, cone axis 175 of each cone 171, 172 is oriented generally downwardly and outwardly away from bit axis 111 and the center of bit 100.
Referring now to FIG. 7, an enlarged cross-section taken in a plane that contains axis 175 of exemplary cone 171 and is parallel to bit axis 111 is shown. Although only cone cutter 171 is shown in FIG. 7, cone 172 is similarly configured. Each cutter 171, 172 is secured on a journal 174 by locking balls 176. Radial thrusts and axial thrusts are absorbed by a journal sleeve and a thrust washer. Lubricant may be supplied from a reservoir (not shown) to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of one or more annular seals which may take many forms. As shown in FIG. 7, the enlarged borehole created by reamer section 160 generally includes sidewall 105, corner portion 106 and bottom 107.
Referring now to FIGS. 4 and 7, each cutter 171, 172 includes a generally planar backface 180 and nose 181 generally opposite backface 180. In this embodiment, backface 180 and nose 181 are both perpendicular to cone axis 175. Unlike most conventional rolling cone cutters, in this embodiment, each reamer cone cutter 171, 172 is oriented such that backface 180 is proximal bit body 112 and bit axis 111, and nose 181 is distal bit body 112 and bit axis 111. In general, a rolling cone cutter (e.g., cone cutter 171, 172) oriented with its backface (e.g., backface 180) proximal the bit central axis (e.g., bit axis 111) and its nose (e.g., nose) distal the bit axis may be referred to herein as an “outwardly facing” cone cutter, whereas a rolling cone cutter oriented with its backface distal the bit central axis and its nose proximal the bit axis may be referred to herein as an “inwardly facing” cone cutter. Thus, each cone cutter 171, 172 is an outwardly facing cone cutter, and most conventional cone cutters are inwardly facing cone cutters.
Adjacent to backface 180, cone cutters 171, 172 further include a generally frustoconical surface 182 that may be referred to herein as the “heel” surface of cone cutters 171, 172. Extending between heel surface 182 and nose 181 is a generally frustoconical cone surface 183 adapted for supporting a plurality of cutting elements. Heel surface 182 and cone surface 183 converge in an annular shoulder 184.
As best shown in FIG. 7, moving axially relative to axis 175 from nose 181 to backface 180, cone surface 183 is divided into a plurality of annular frustoconical regions 185 a-e, generally referred to as “lands”, which are employed to support and secure the cutting elements as described in more detail below. Each frustoconical land 185 a-e is disposed at a cone surface angle β relative to cone axis 175. Thus, as used herein, the phrase “cone surface angle” refers to the angle of a surface of a cone cutter relative to the cone axis as viewed in a plane that contains the cone axis and is parallel with the bit axis. In this embodiment, moving along surface 183 from nose 181 to backface 180, each successive lands 185 a-e is oriented at a smaller angle β relative to cone axis 175. Thus, for example, land 185 e is oriented at a cone surface angle β_185erelative to cone axis 175, and land 185 a is oriented at an angle β_185athat is greater than angle β_185e. Consequently, cone surface 183 is slightly bowed outward or convex between backface 180 and nose 181.
Referring still to FIG. 7, for each reamer cone cutter (e.g., cone cutter 171, 172), each portion of the cone surface between the nose and backface (e.g., each portion of cone surface 182) is preferably oriented at a cone surface angle β between 45° and 90°, and more preferably between 45° and 75°. In this embodiment, each portion of surface 183 (e.g., each land 185 e-e) is oriented at an angle β between 45° and 75°. In addition, each reamer cone cutter 171, 172 has a maximum outer diameter D_cand a length L_cmeasured axially relative to axis 175 from backface 180 to nose 181. In embodiments described herein, each outwardly facing cone cutter (e.g., cone cutter 171, 172) is preferably sized such that the ratio of the maximum cone diameter D_cto the cone axial length L_cis between 2.0 and 4.0, and more preferably between 2.0 and 3.0. In this embodiment, the ratio of the cone diameter D_cto the cone axial length L_cof each cone cutter 171, 172 is 2.5. As compared to most conventional rolling cone cutters, embodiments of reamer cone cutters described herein (e.g., reamer cone cutters 171, 172) a flatter. In other words, the ratio of the cone diameter (e.g., diameter D_c) to the cone axial length (e.g., length L_c) of embodiments of reamer cone cutters described herein are greater than the ratio of the cone diameter to the cone axial length of most conventional rolling cone cutters. The purpose of the generally flatter reamer cones is to allow formation of an enlarged borehole having the desired profile. In particular, the flatter reamer cones cut a relatively smooth single curve profile similar to a fixed cutter reamer. If the if the cone diameter to cone axial length were smaller, the reamer cones would create more of a ledge in the borehole where it transitions from pilot diameter to reamer diameter as opposed to the smooth profile of the flatter cone mounted at a high journal angle.
In bit 100 illustrated in FIGS. 3-7, each cone cutter 171, 172 includes a plurality of wear resistant inserts or cutting elements 186. These cutting elements each include a generally cylindrical base portion having a central axis, and a cutting portion that extends from the base portion and includes a cutting surface for engaging and cutting formation material. The cutting surface may be symmetric or asymmetric relative to the central axis. All or a portion of the base portion is secured by interference fit into a mating socket formed in the surface of the cone cutter. Thus, as used herein, the term “cutting surface” is used to refer to the surface of the cutting element that extends beyond the surface of the cone cutter. The extension height of the insert or cutting element is the distance from the cone surface to the outermost point of the cutting surface of the cutting element as measured perpendicular to the cone surface.
Referring specifically to FIG. 7, exemplary cone 171 includes a plurality of cutting elements 186 extending from surface 183. Specifically, in this embodiment, cutting elements 186 are arranged in a plurality of axially spaced circumferential rows relative to cone axis 175, each row disposed along one land 185 a-e. In this embodiment, no cutter elements or inserts are provided on heel surface 182. However, in other embodiments, cutter elements may be provided on the heel surface.
Referring still to FIG. 7, cone axis 175 extends down and away from bit axis 111. As viewed in a plane that contains cone axis 175 and is parallel to bit axis 111 (e.g., FIG. 7), cone axis 175 is oriented at a “cone axis angle” angle α measured upwardly from bit axis 111 to cone axis 175. Thus, as used herein, the phrase “cone axis angle” refers to the angle measured upwardly from the bit axis to the cone axis in a plane that contains the cone axis and is parallel to the bit axis. In embodiments described herein, each outwardly facing cone cutter is preferably oriented with a cone axis angle α between 30° and 90°, more preferably between 45° and 90°, and even more preferably between 60° and 90°. In the embodiment shown in FIGS. 3-7, each outwardly facing cone cutter 171, 172 is oriented with a cone axis angle α of 75°.
Referring now to FIGS. 5 and 8, in this embodiment, reamer section 160 includes two outwardly facing cone cutters 171, 172. In particular, cone cutters 171, 172 are circumferentially adjacent each other and eccentrically positioned to one side of bit body 112. In other words, cone cutters 171, 172 are not uniformly angularly or circumferentially spaced about bit body 112. In general, a bit having a reamer section with a plurality of cone cutters or blades that are non-uniformly distributed about the circumference of the bit body (e.g., bit 100) may be referred to as a “eccentric” or bi-center bit. As best shown in FIG. 8, a maximum cone separation angle θ defines the angle between the rotational axes of the circumferentially outermost cone cutters of the reamer section of a bi-center bit (e.g., cone cutters 171, 172 of reamer section 160 of bit 100) in end view. In other words, maximum cone separation angle θ is the angle between the axes of the reamer section cone cutters of a bi-center bit that are circumferentially furthest from each other. For bi-center bits (e.g., bit 100), angle θ is preferably between 90° and 150°, and more preferably between 110° and 130°. In this embodiment, only two cone cutters 171, 172 are provided in reamer section 160, and thus, maximum cone separation angle θ is the angle measured between axes 175 of cone cutters 171, 172. Angle θ between cone cutters 171, 172 is 120°. Although reamer section 160 includes two cone cutters 171, 172 in this embodiment, in general, the reamer section (e.g., reamer section 160) may include one, two, or more cone cutters (e.g., cone cutters 171, 172).
Referring still to FIG. 8, “offset” is a term used to describe the orientation of a cone cutter (e.g., cone 171) and its axis (e.g., cone axis 175) relative to the bit axis (e.g., bit axis 111). More specifically, a cone is “offset,” and thus a bit may be described as having “cone offset,” when a projection of the cone axis does not intersect or pass through the bit axis, but instead passes a distance away from the bit axis. As shown in the end view along bit axis 111 of FIG. 8, cone offset may be defined as the distance “d” measured perpendicularly from the projection of the cone axis 175 and a line “L” that is parallel to the projection of the cone axis and intersects the bit axis 111. Thus, the larger the distance “d”, the greater the offset. Thus, as used herein, the phrase “cone offset distance” refers to the distance, in end view (i.e., as viewed from the borehole bottom along the bit axis), measured perpendicularly from a projection of a cone axis, and a line parallel to the projection of the cone axis and intersecting the bit axis.
Cone offset may be positive or negative. With negative offset, the region of contact of the cone cutter with the borehole sidewall (e.g., sidewall 105) is behind or trails the cone's axis of rotation (e.g., axis 175) with respect to the direction of rotation of the bit (e.g., direction of rotation 118). On the other hand, with positive offset, the region of contact of the cone cutter with the borehole sidewall is ahead or leads the cone's axis of rotation with respect to the direction of rotation of the bit.
In a bit having cone offset (positive or negative), a rolling cone cutter is prevented from rolling along the hole bottom in what would otherwise be its “free rolling” path, and instead is forced to rotate about the centerline of the bit along a non-free rolling path. This causes the rolling cone cutter and its cutter elements to engage the borehole bottom in motions that may be described as skidding, scraping, dragging, and sliding. These motions apply a plowing and shearing type cutting force to the borehole bottom (e.g., bottom 107). Without being limited by this or any other theory, it is believed that in certain formations, these motions can be a more efficient or faster means of removing formation material, and thus enhance ROP, as compared to bits having no cone offset (or relatively little cone offset) where the cone cutter predominantly cuts via compressive forces and a crushing action. In general, the greater the offset distance, whether positive or negative, the greater the formation removal and ROP. However, it should also be appreciated that such shearing cutting forces arising from cone offset accelerate the wear of cutter elements, especially in hard, more abrasive formations, and may cause cutter elements to fail or break at a faster rate than would be the case with cone cutters having no offset. Consequently, the magnitude of cone offset may be limited.
Referring still to FIG. 8, in this embodiment, cone 172 has a positive offset, and thus, the region of contact R₁₇₂of cone cutter 172 with the borehole sidewall 105 is ahead of its respective cone axis 175 relative to the direction of rotation 118 of bit 100. Further, in this embodiment, cone 171 has a negative offset, and thus, the region of contact R₁₇₁of cone cutter 171 with the borehole sidewall 105 is behind of its respective cone axis 175 relative to the direction of rotation 118 of bit 100. Moreover, in this embodiment, each cone cutter 171, 172 has substantially the same magnitude cone offset distance d. In other embodiments of eccentric or bi-center drill bits including a reamer section with rolling cone cutters, each rolling cone cutter of the reamer section (e.g., each cone 171, 172 of reamer section 160) may have negative offset or positive offset, select cones may have negative offsets and other(s) positive offset, two or more cones may have a different magnitude cone offsets, or combinations thereof.
Varying the magnitude of the offsets among the cone cutters provides a bit designer the potential to improve ROP and other performance criteria of the bit. In the embodiments of bi-center bits described herein (e.g., bit 100), one cone cutter (e.g., cone cutter 172) preferably has a positive cone offset and one cone cutter (e.g., cone cutter 171) preferably has a negative cone offset. Such configuration offers the potential for the ROP and durability advantages below and provides a geometry best suited for allowing the bit to fit through the pass through.
For relatively large bits, a third reamer cone may be provided between the reamer cone with positive cone offset and the reamer cone with negative cone offset. Such a third cone may have positive, negative, or no cone offset. Further, for embodiments of bi-center drill bits including roller cones in the reamer section (e.g., bit 100), each reamer section cone cutter (e.g., each cone cutter 171, 172 of reamer section 160) preferably has a cone offset distance between 0.25 in. and 4.00 in., more preferably between 0.50 in. and 3.00 in., and even more preferably between 0.500 in. and 2.00 in.
As each cone cutter 171, 172 rotates about its axis 175 and bit 100 rotates about bit axis 111, cutter elements 186 mounted to cone cutters 172, 172 repeatedly move into and out of engagement with the formation. Due to the negative offset of cone cutter 171, during rotation of cone cutter 171 about axis 175, cutting elements 186 mounted thereto (a) engage the sidewall 105 as they move downward from their uppermost axial position relative to bit axis 111 (i.e., as they move downward from top dead center) toward their lowermost axial position relative to bit axis 111 (i.e., bottom dead center); (b) transition from engagement with sidewall 105 to engagement with bottom 107 as they approach their lowermost axial position relative to bit axis 111; (c) engage bottom 107 as they sweep through their lowermost axial position relative to bit axis 111; and (d) move out of engagement with the formation and bottom 107 as they move upward from their lowermost axial position relative to bit axis 111 and away from bottom 107. In other words, as cone cutter 171 rotates, cutters 186 mounted to cone cutter 171 repeat the following cycle—engagement with sidewall 105, followed by engagement with bottom 107, and then move out of engagement with the formation.
Due to the positive offset of cone cutter 172, as cone cutter 172 rotates about axis 175, cutting elements 186 mounted thereto (a) engage bottom 107 as they sweep through their lowermost axial position relative to bit axis 111 (i.e., as they sweep through bottom dead center); (b) transition from engagement with bottom 107 to engagement with sidewall 105 as they move upward from their lowermost axial position; (c) engage the sidewall 105 as move upward from their lowermost axial position relative to bit axis 111 to their uppermost axial position relative to bit axis 111; and (d) move out of engagement with the formation and sidewall 105 as sweep through their uppermost axial position relative to bit axis 111. In other words, as cone cutter 172 rotates, cutters 186 mounted to cone cutter 172 repeat the following cycle—engagement with bottom 107, followed by engagement with sidewall 105, and then move out of engagement with the formation.
As previously described, the cutter elements mounted to the reamer blades of conventional reamer sections continuously engage the formation as the drill bit is rotated. However, in embodiments described herein that include rolling cone cutters in the reamer section (e.g., cone cutters 171, 172 in reamer section 160), the reamer section cutting elements (e.g., cutting elements 186 mounted to cone cutters 171, 172) do not continuously engage the formation. Rather, the cutting elements mounted to the cone cutters in the reamer section cyclically move into and out of engagement with the formation. Moreover, the use of rolling cone cutters in the reamer section offers the potential to increase the available surface area for mounting cutting elements as compared to similarly sized conventional reamer blades. Accordingly, for a given sized cutting element, embodiments described herein offer the potential for an increased cutting element count in the reamer section as compared to similarly sized conventional reamer sections including reamer blades. The combination of increased cutting element count, and periodic engagement with the formation offers the potential to enhance load sharing among the cutting elements in the reamer section, reduce wear, and enhance overall bit durability.
Referring now to FIGS. 9-11, an embodiment of a drill bit 200 adapted for drilling through formations of rock to form a borehole is shown. Bit 200 is similar to bit 100 previously described. Namely, bit 200 has a central axis 211 about which bit 200 rotates in the cutting direction represented by arrow 218. In addition, bit 200 generally includes a bit body 212, a shank 213, and a threaded connection or pin 214 for connecting bit 200 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit 200 opposite pin 214, bit body 212 includes a pilot bit 120 as previously described. In addition, a reamer section 260 extends radially from bit body 212 and is axially positioned between pin 214 and pilot bit 120. Reamer section 260 includes a reamer cutting structure 262. However, unlike bit 100 previously described, in this embodiment, reamer section 260 includes three uniformly angularly and circumferentially spaced rolling cone cutters 271, 272, 273.
Referring still to FIGS. 9-11, each cone cutter 271, 272, 273 is configured substantially the same as cone cutters 171, 172 previously described. Namely, each cone cutter 271, 272, 273 is mounted on a pin or journal 274 extending from bit body 212, and is adapted to rotate about a cone axis of rotation 275. In addition, cone axis 275 of each cone 271, 272 is oriented generally downwardly and outwardly away from bit axis 211 and the center of bit 200. Further, each cutter 271, 272, 273 includes a generally planar backface 280 and nose 281 opposite backface 280. Backface 280 and nose 281 of each cone cutter 271, 272, 273 are perpendicular to cone axis 275. As with cones 171, 172 previously described, each reamer cone cutter 271, 272, 273 is an outwardly facing cone cutter (i.e., each cone cutter 271, 272, 273 is oriented with backface 280 is proximal bit axis 111 and nose 281 distal bit axis 211). Adjacent to backface 280, cutters 271, 272, 273 further include a generally frustoconical heel surface 282 and a generally frustoconical cone surface 283 that supports a plurality of cutting elements 186 as previously described.
As best shown in FIG. 11, each portion of cone surface 283 is preferably oriented at a cone surface angle β between 45° and 90°, and more preferably between 45° and 75°. In this embodiment, each portion of surface 283 is oriented at an angle β between 45° and 75°. In addition, each reamer cone cutter 271, 272, 273 is preferably sized such that the ratio of the cone diameter D_cto the cone axial length L_cis between 2.0 and 4.0, and more preferably between 2.0 and 3.0. In this embodiment, the ratio of the cone diameter D_cto the cone axial length L_cis 2.5. Still further, each cone 271, 272, 273 is preferably oriented with a cone axis angle α between 30° and 90°, more preferably between 45° and 90°, and even more preferably between 60° and 90°. In the embodiment shown in FIGS. 9-11, each outwardly facing cone cutter 271, 272, 273 is oriented with a cone axis angle α of 75°. Although only cone cutter 271 is shown in FIG. 10, cone cutters 272, 273 are similarly configured.
Referring now to FIGS. 9 and 10, in this embodiment, reamer section 260 includes three cone cutters 271, 272, 273. Further, unlike reamer section 160 previously described, in this embodiment, cone cutters 271, 272, 273 are uniformly angularly and circumferentially spaced about bit body 212. Thus, in this embodiment, the three cone cutters 271, 272, 273 are uniformly angularly spaced 120° apart about bit axis 211. In general, a bit having a reamer section with a plurality of cone cutters or blades uniformly distributed about the circumference of the bit body (e.g., bit 200) may be referred to as a “concentric” or “speed drill” bit. Thus, bit 200 may be described as a concentric or speed drill bit as opposed to an eccentric of bi-center bit.
As best shown in FIG. 10, pilot bit 120 defines pilot gage diameter D_pbdetermined by the radially outermost reaches of pilot cutting structure 122, and reamer section 260 defines a reamer diameter D_rsdetermined by the radially outermost reaches of cutting structure 262 and cone cutters 271, 272, 273. Thus, the enlarged borehole formed by reamer section 260 has the same diameter D_rs. Further, bit 200 has a minimum pass through diameter D_pt, which represents the minimum diameter of a hole or bore through which bit 200 may be tripped. Pilot diameter D_pbis less pass through diameter D_ptand reamer diameter D_rs, however, for concentric and speed drill bits such as bit 200, minimum pass through diameter D_ptis equal to reamer diameter D_rs. Thus, bit 200 cannot be tripped through a hole that is smaller than the diameter D_rsof the borehole formed by reamer section 260. However, embodiments of concentric and speed drill bits described herein including reamer rolling cone cutters offer the potential for enhanced ROP and durability. In particular, without being limited by this or any particular theory, the pilot bit (e.g., pilot bit 120) both drills the pilot borehole and creates stress fractures in the portion of the formation immediately surrounding the pilot borehole. Such stress fractures generally weaken the portion of the formation immediately surrounding the pilot borehole, thereby reducing the loads that the reamer section and associated cutting structure must apply to the formation surrounding the pilot borehole in order to form the enlarged borehole.
As best shown in FIG. 10, in this embodiment of speed drill bit 200, each cone cutter 271, 272, 273 has a negative cone offset. Thus, the region of contact of each cone cutter 271, 272, 273 with the enlarged borehole sidewall is behind or trails the cone's axis 175 with respect to the direction of rotation 218 of bit 200. Further, in this embodiment, each cone cutter 271, 272, 273 has the same magnitude cone offset distance. In other words, in end view along axis 211, the cone offset distance measured perpendicularly from a projection of axis 275 of each cone cutter 271, 272, 273 and a line parallel to the projection and passing through bit axis 211 is the same. For embodiments of concentric drill bits including roller cones in the reamer section (e.g., bit 200), each reamer section cone cutter (e.g., each cone cutter 271, 272, 273 of reamer section 260) preferably has a cone offset distance between 0.25 in. and 4.00 in., more preferably between 0.50 in. and 3.00 in., and even more preferably between 0.50 in. and 2.00 in. Although reamer cone cutters 271, 272, 273 each have negative cone offset and the same cone offset distance in this embodiment, in other embodiments of concentric or speed drill bits including a reamer section with rolling cone cutters, each rolling cone cutter of the reamer section (e.g., each cone 271, 272, 273 of reamer section 260) may have negative offset or positive offset, select cones may have negative offsets and other(s) positive offset, two or more cones may have a different magnitude cone offsets, or combinations thereof.
Due to the negative offset of cone cutters 271, 272, 273, during rotation of each cone cutter 271, 272, 273 about its axis 175, cutting elements 186 mounted thereto (a) engage the enlarged borehole sidewall as they move downward from their uppermost axial position relative to bit axis 211 (i.e., as they move downward from top dead center) toward their lowermost axial position relative to bit axis 211 (i.e., bottom dead center); (b) transition from engagement with the enlarged borehole sidewall to engagement with the enlarged borehole bottom as they approach their lowermost axial position relative to bit axis 211; (c) engage the enlarged borehole bottom as they sweep through their lowermost axial position relative to bit axis 211; and (d) move out of engagement with the formation and the enlarged borehole bottom as they move upward from their lowermost axial position relative to bit axis 211. In other words, as each cone cutter 271, 272, 273 rotates, cutters 186 mounted thereto repeat the following cycle—engagement with the enlarged borehole sidewall, followed by engagement with the enlarged borehole bottom, and then move out of engagement with the formation. Thus, unlike the reamer blades of conventional reamer sections which continuously engage the formation as the drill bit is rotated, embodiments of concentric and speed drill bits described herein that include rolling cone cutters in the reamer section (e.g., cone cutters 271, 272, 273 in reamer section 260), the reamer section cutting elements (e.g., cutting elements 186) do not continuously engage the formation. Rather, the cutting elements mounted to the cone cutters in the reamer section cones (e.g., cutting elements 186) cyclically move into and out of engagement with the formation. Moreover, the use of rolling cone cutters (e.g., cone cutters 271, 272, 273) in the reamer section (e.g., reamer section 260), offers the potential to increase the available surface area for mounting cutting elements as compared to similarly sized conventional reamer sections that include reamer blades. Accordingly, for a given sized cutting element, embodiments described herein offer the potential for an increased cutting element count in the reamer section as compared to similarly sized conventional reamer sections including reamer blades. The combination of increased cutting element count, and periodic engagement with the formation offers the potential to enhance load sharing among the cutting elements in the reamer section, reduce wear, and enhance overall bit durability.
Referring now to FIGS. 12 and 13, an embodiment of an eccentric or bi-center drill bit 300 adapted for drilling through formations of rock to form a borehole is shown. Bit 300 is similar to bit 100 previously described. Namely, bit 300 has a central axis 311 about which bit 300 rotates in the cutting direction represented by arrow 318. In addition, bit 300 generally includes a bit body 312, a shank 313, and a threaded connection or pin 314 for connecting bit 300 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit 300 opposite pin 314, bit body 312 includes a pilot section or pilot bit 320 including an end face 321 that supports a pilot cutting structure 322. A reamer section 160 as previously described extends radially outward from body 312 and is axially disposed between pin 314 and pilot bit 320. Reamer section 160 includes cone cutters 171, 172 configured, sized, and oriented as previously described with respect to FIGS. 3-8. However, unlike bit 100 previously described, in this embodiment, pilot bit 320 is not a fixed cutter bit, rather, pilot bit 320 is a rolling cone drill bit.
Referring briefly to FIG. 13, bit 300 has a minimum pass through diameter D_pt, which represents the minimum diameter hole or bore through which bit 300 may be tripped. Further, pilot bit 320 defines a pilot gage diameter D_pbdetermined by the radially outermost reaches of pilot cutting structure 322. Reamer section 160 defines a reamer diameter D_rsdetermined by the radially outermost reaches of reamer cutting structure 162. Pilot diameter D_pbis less pass through diameter D_pt, however, reamer diameter D_rsis greater than pass through diameter D_pt. Thus, bit 300 may be tripped through a hole that is smaller than the diameter D_rsof the enlarged borehole formed by reamer section 160.
Referring again to FIGS. 12-14, pilot bit 320 is coaxially aligned with bit body 312, and thus, pilot bit 320 and bit body 312 share the same central axis 311. In this embodiment, pilot bit 320 comprises a rolling cone drill bit including a plurality of inwardly facing rolling cone cutters 371, 372, 373 which are rotatably mounted on bearing shafts that depend from the bit body 312. In this embodiment, rolling cone pilot bit 320 comprises three sections or legs 321 that are welded together to form the lower portion of bit body 312. Rolling cone pilot bit 320 further includes a plurality of ports or nozzles 319 that are provided for directing drilling fluid toward the bottom of the borehole and around cone cutters 371, 372, 373.
Referring still FIGS. 12-14, each cone cutter 371, 372, 373 is mounted on a pin or journal 374 extending from bit body 312, and is adapted to rotate about a cone axis of rotation 375 oriented generally downwardly and inwardly toward the center of the bit 300 and axis 311. In this embodiment, cones 371, 372, 373 are oriented such that a projection of each cone axis 375 intersects bit axis 311. However, in other embodiments, one or more of the pilot bit rolling cone cutters (e.g., rolling cone cutters 371, 372, 373) may have a positive or negative cone offset. As shown in FIG. 14, the pilot borehole created by pilot bit 300 includes sidewall 305, corner portion 306 and bottom 307.
In the embodiment shown, radial and axial thrust are absorbed by roller bearings 328, 330, thrust washer 331 and thrust plug 332. The bearing structure shown is generally referred to as a roller bearing; however, the invention is not limited to use in bits having such structure, but may equally be applied in a bit where cone cutters 371, 372, 373 are mounted on pin 374 with a journal bearing or friction bearing disposed between the cone cutter and the journal pin 374. In both roller bearing and friction bearing bits, lubricant may be supplied from a lubricant reservoir to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of an annular seal 334 which may take many forms.
Referring still to FIGS. 12-14, each cone cutter 371, 372, 373 includes a generally planar backface 340 and nose portion 342 opposite backface 340. Adjacent to backface 340, cutters 371, 372, 373 further include a generally frustoconical surface 344 that is adapted to retain cutter elements that scrape or ream the sidewalls of the borehole as the cone cutters rotate about the borehole bottom. Frustoconical surface 344 will be referred to herein as the “heel” surface of cone cutters 371, 372, 373. It is to be understood, however, that the same surface may be sometimes referred to by others in the art as the “gage” surface of a rolling cone cutter.
Extending between heel surface 344 and nose 342 is a generally conical surface 346 adapted for supporting cutter elements that gouge or crush the borehole bottom 307 as cone cutters 371, 372, 373 rotate about the borehole. Frustoconical heel surface 344 and conical surface 346 converge in a circumferential edge or shoulder 350. Although referred to herein as an “edge” or “shoulder,” it should be understood that shoulder 350 may be radiused to various degrees such that shoulder 350 will define a transition zone of convergence between frustoconical heel surface 344 and the conical surface 346. Conical surface 346 is divided into a plurality of generally frustoconical regions or bands 348 generally referred to as “lands” which are employed to support and secure the cutter elements as described in more detail below. Grooves 349 are formed in cone surface 346 between adjacent lands 348.
In the bit shown in FIGS. 12-14, each cone cutter 371, 372, 373 includes a plurality of wear resistant cutter elements in the form of inserts which are disposed about the cone and arranged in circumferential rows in the embodiment shown. More specifically, rolling cone cutter 371 shown in FIG. 14 includes a plurality of heel inserts 360 that are secured in a circumferential heel row 360 a in the frustoconical heel surface 344. Cone cutter 371 further includes a circumferential row 380 a of gage inserts 380 secured to cone cutter 371 in locations along or near the circumferential shoulder 350. Each insert 380 extends to pilot gage diameter D_pb. The cone cutter 371 further includes inner row inserts 381, 382, 383 secured to cone surface 346 and arranged in concentric, spaced-apart inner rows 381 a, 382 a, 383 a, respectively. Heel inserts 360 generally function to scrape or ream the borehole sidewall 305 to maintain the borehole at pilot gage diameter D_pband prevent erosion and abrasion of the heel surface 344. Gage inserts 380 function primarily to cut the corner 306 of the borehole Inner row cutter elements 381, 382, 383 of inner rows 381 a, 382 a, 383 a are employed to gouge and remove formation material from the remainder of the borehole bottom 307. Inner rows 381 a, 382 a, 383 a are arranged and spaced on rolling cone cutters 371 so as not to interfere with rows of inner row cutter elements on the other cone cutters 372, 373. Cone 371 is further provided with relatively small “ridge cutter” cutter elements 384 in nose region 342 which tend to prevent formation build-up between the cutting paths followed by adjacent rows of the more aggressive, primary inner row cutter elements from different cone cutters. Cone cutters 372 and 373 have heel, gage and inner row cutter elements and ridge cutters that are similarly, although not identically, arranged as compared to cone 371. The arrangement of cutter elements differs as between the three cones in order to maximize borehole bottom coverage, and also to provide clearance for the cutter elements on the adjacent cone cutters. For instance, in some embodiments, inner row inserts 381, 382, 383 are arranged and spaced on each cone cutter 371, 372, 373 so as to intermesh, yet not interfere with the inner row inserts 381, 382, 383 of the other cone cutters 371, 372, 373. In such embodiments, grooves 349 on each cone 371, 372, 373 allow the cutting surfaces of certain bottomhole cutter elements 381, 382, 383 of adjacent cone cutters 371, 372, 373 to intermesh, without contacting the cone steel or surface of cones 371, 372, 373.
In the embodiment shown, inserts 360, 370, 380-383 each include a generally cylindrical base portion, a central axis, and a cutting portion that extends from the base portion, and further includes a cutting surface for cutting the formation material. The base portion is secured into a mating socket formed in the surface of the cone cutter. The base portion may be secured within the mating socket by any suitable means including, without limitation, an interference fit, brazing, or combinations thereof. The “cutting surface” of an insert is defined herein as being that surface of the insert that extends beyond the surface of the cone cutter. Further, it is to be understood that the extension height of an insert or cutter element is the distance from the cone surface to the outermost point of the cutting surface of the cutter element as measured substantially perpendicular to the cone surface.
Referring now to FIGS. 14 and 15, an embodiment of a concentric or speed drill bit 400 adapted for drilling through formations of rock to form a borehole is shown. Bit 400 includes aspects similar to both bits 200, 300 previously described. Namely, bit 400 has a central axis 411 about which bit 400 rotates in the cutting direction represented by arrow 418. In addition, bit 400 generally includes a bit body 412, a shank 413, and a threaded connection or pin 414 for connecting bit 400 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit 400 opposite pin 414, bit body 412 includes a pilot bit 320 as previously described with respect to FIGS. 12-14. In addition, bit 400 includes a reamer section 260 as previously described with respect to FIGS. 9-11. Reamer section 260 extends radially from bit body 412 and is axially positioned between pin 414 and pilot bit 320. Reamer section 260 includes cone cutters 271, 272, 273 configured, sized, and oriented as previously described with respect to FIGS. 9-11.
Referring now to FIGS. 17-19, an embodiment of an eccentric or bi-center bit 500 adapted for drilling through formations of rock to form a borehole is shown. Bit 500 is similar to bit 300 previously described. Namely, bit 500 has a central axis 511 about which bit 500 rotates in the cutting direction represented by arrow 518. In addition, bit 500 generally includes a bit body 512, a shank 513, and a threaded connection or pin 514 for connecting bit 500 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit 500 opposite pin 514, bit body 512 includes a pilot bit 520. In addition, bit 500 includes a reamer section 160 as previously described. Reamer section 160 extends radially from bit body 512 and is axially positioned between pin 514 and pilot bit 520. Reamer section 160 includes cone cutters 171, 172 configured, sized, and oriented as previously described with respect to FIGS. 3-8. However, unlike bit 300 previously described, which includes pilot bit 320 with inwardly facing rolling cone cutters 371, 372, 373, pilot bit 520 of bit 500 includes a plurality of outwardly facing rolling cone cutters 571, 572.
Referring still to FIGS. 17-19, pilot bit 520 is coaxially aligned with bit body 512, and thus, pilot bit 520 and bit body 512 share the same central axis 511. In this embodiment, pilot bit 520 comprises a rolling cone drill bit including a plurality of outwardly facing rolling cone cutters 571, 572. Each cone cutter 571, 572 is rotatably mounted on a pin or journal extending from bit body 512, and is adapted to rotate about a cone axis of rotation 575. In this embodiment, cone axis 575 of each cone 571, 572 is oriented generally downwardly and outwardly away from bit axis 511 and the center of bit 500. Rolling cone pilot bit 520 further includes a plurality of ports or nozzles 519 that are provided for directing drilling fluid toward the bottom of the borehole and around cone cutters 571, 572.
Each cone cutter 571, 572 is substantially the same as outwardly facing cone cutters 171, 172 previously described. Namely, each cutter 571, 572 is secured on its respective journal by locking balls. Radial thrusts and axial thrusts are absorbed by a journal sleeve and a thrust washer. Lubricant may be supplied from a reservoir (not shown) to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of one or more annular seals which may take many forms. Further, each cutter 571, 572 includes a generally planar backface 580 and nose 581 generally opposite backface 580. In this embodiment, backface 580 and nose 581 are both perpendicular to cone axis 575. Each reamer cone cutter 571, 572 is oriented such that backface 580 is proximal bit body 512 and bit axis 511, and nose 581 is distal bit body 512 and bit axis 511.
Adjacent to backface 580, cone cutters 571, 572 further include a generally frustoconical heel surface 582. Extending between heel surface 582 and nose 581 is a generally frustoconical cone surface 583 adapted for supporting a plurality of cutting elements. As best shown in FIG. 19, moving axially relative to axis 175 from nose 581 to backface 580, each cone surface 583 is divided into a plurality of annular frustoconical regions 585 a-e employed to support and secure the cutting elements as described in more detail below. In this embodiment, moving along surface 583 from nose 581 to backface 580, each successive lands 585 a-e is oriented at a smaller angle β relative to cone axis 575. For each cone cutter 571, 572, each portion of the cone surface 583 is preferably oriented at a cone surface angle β between 45° and 90°, and more preferably between 45° and 75°. In this embodiment, each portion of surface 583 (e.g., each land 585 e-e) is oriented at an angle β between 45° and 75°. In addition, each reamer cone cutter 571, 572 is preferably sized such that the ratio of the cone diameter D_cto the cone axial length L_cis between 2.0 and 4.0, and more preferably between 2.0 and 3.0. In this embodiment, the ratio of the cone diameter D_cto the cone axial length L_cof each cone cutter 571, 572 is 2.5.
In bit 500 illustrated in FIGS. 17-19, each outwardly facing pilot cone cutter 571, 572 includes a plurality of wear resistant inserts or cutting elements 186 as previously described extending from surface 583. Specifically, in this embodiment, cutting elements 186 are arranged in a plurality of axially spaced circumferential rows relative to cone axis 575, each row disposed along one land 585 a-e. In this embodiment, no cutter elements or inserts are provided on heel surface 582. However, in other embodiments, cutter elements may be provided on the heel surface.
As best shown in FIG. 17, each cone axis 575 extends down and away from bit axis 511. In particular, each outwardly facing pilot cone cutter 571, 572 is preferably oriented with a cone axis angle α between 30° and 90°, more preferably between 45° and 90°, and even more preferably between 60° and 90°. In the embodiment shown in FIGS. 17-19, each outwardly facing pilot cone cutter 571, 572 is oriented with a cone axis angle α of 75°.
Referring now to FIG. 19, in this embodiment, pilot section 560 includes two outwardly facing cone cutters 571, 572. Cone cutters 571, 572 are uniformly angularly and circumferentially spaced about bit body 512. Thus, in this embodiment, the two pilot cone cutters 571, 572 are uniformly angularly spaced 180° apart about bit axis 511. Further, in this embodiment, each pilot cone cutter 571, 572 has a positive cone offset, and thus, the region of contact of each cone cutter 571, 572 with the borehole sidewall is ahead or leads the cone's axis of rotation 575 with respect to the direction of rotation of bit 500. Moreover, in this embodiment, each cone cutter 571, 572 has substantially the same magnitude cone offset distance. In other embodiments of drill bits including a pilot section with outwardly facing rolling cone cutters, each outwardly facing cone cutter of the pilot section (e.g., each cone 571, 572 of pilot section 520) may have negative offset or positive offset, select cones may have negative offsets and other(s) positive offset, two or more cones may have a different magnitude cone offsets, or combinations thereof. For example, the cone offset of different cone cutters may be selected such that some of the cone cutters engage the formation with a more crushing action and other cone cutters engage the formation with a more shearing action. Such a combination may offer the potential to improve efficiency in tougher formations. For embodiments of drill bits including outwardly facing roller cones in the pilot section (e.g., bit 500), each pilot section cone cutter (e.g., each cone cutter 571, 572 of pilot section 520) preferably has a cone offset distance between 0.25 in. and 4.00 in., more preferably between 0.50 in. and 3.00 in., and even more preferably between 0.50 in. and 2.00 in. In this embodiment, each cone cutter 571, 572 has a cone offset of 1.1 in.
As each cone cutter 571, 572 rotates about its axis 575 and bit 500 rotates about bit axis 511, cutter elements 186 mounted to cone cutters 572, 572 repeatedly move into and out of engagement with the formation. Due to the positive offset of each cone cutter 571, 572, as cone cutter 571, 572 rotates about its axis 575, cutting elements 186 mounted thereto (a) engage the pilot borehole bottom as they sweep through their lowermost axial position relative to bit axis 511 (i.e., as they sweep through bottom dead center); (b) transition from engagement with pilot borehole bottom to engagement with pilot borehole sidewall as they move upward from their lowermost axial position; (c) engage the pilot borehole sidewall as move upward from their lowermost axial position relative to bit axis 511 to their uppermost axial position relative to bit axis 511; and (d) move out of engagement with the formation and pilot borehole sidewall as sweep through their uppermost axial position relative to bit axis 511. In other words, as cone cutter 571, 572 rotates, cutters 186 mounted to cone cutter 172 repeat the following cycle—engagement with pilot borehole bottom, followed by engagement with pilot borehole sidewall, and then move out of engagement with the formation.
Referring now to FIGS. 20 and 21, an embodiment of a concentric or speed drill bit 600 adapted for drilling through formations of rock to form a borehole is shown. Bit 600 includes aspects similar to both bits 200, 500 previously described. Namely, bit 600 has a central axis 611 about which bit 600 rotates in the cutting direction represented by arrow 618. In addition, bit 600 generally includes a bit body 612, a shank 613, and a threaded connection or pin 614 for connecting bit 600 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit 600 opposite pin 614, bit body 612 includes a pilot bit 520 as previously described. Pilot bit 520 includes outwardly facing cone cutters 571, 572 configured, sized, and oriented as previously described with respect to FIGS. 17-19. In addition, bit 600 includes a reamer section 260 as previously described with respect to FIGS. 9-11. Reamer section 260 extends radially from bit body 412 and is axially positioned between pin 414 and pilot bit 320. Reamer section 260 includes cone cutters 271, 272, 273 configured, sized, and oriented as previously described with respect to FIGS. 9-11.
While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.

Claims

1. A drill bit for drilling a borehole in earthen formations, the bit comprising:

a bit body having a central bit axis, a first end adapted to be connected to a drillstring, and a second end opposite the first end;

a pilot bit extending from the second end of the bit body;

a reamer section extending radially from the bit body and axially positioned between the first end of the bit body and the pilot bit;

wherein the reamer section comprises a rolling cone cutter rotatably mounted to a journal shaft extending from the bit body;

wherein the rolling cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body.

2. The drill bit of claim 1, wherein the cone axis is oriented at a cone axis angle relative to the bit axis as viewed in a plane that contains the cone axis and is parallel to the bit axis, wherein the cone axis angle is between 45° and 90°.

3. The drill bit of claim 2, wherein the cone axis angle is between 60° and 90°.

4. The drill bit of claim 2, wherein the rolling cone cutter has a maximum outer diameter and a length measured axially between the backface and the nose, wherein the ratio of the maximum outer diameter to the axial length is between 2.0 and 4.0.

5. The drill bit of claim 4, wherein the ratio of the maximum outer diameter to the length is between 2.0 and 3.0.

6. The drill bit of claim 4, wherein the rolling cone cutter has a cone offset between 0.5 in. and 3.00 in.

7. The drill bit of claim 2, the rolling cone cutter includes a frustoconical heel surface adjacent the backface and a cone surface extending between the heel surface and the nose;

wherein a plurality of cutting elements extend from the cone surface; and

wherein the heel surface is substantially free of cutting elements.

8. The drill bit of claim 4, wherein the pilot bit is a fixed cutter bit or a rolling cone bit.

9. The drill bit of claim 8, wherein the pilot bit is a rolling cone bit including a plurality of outwardly facing pilot cone cutters, wherein each pilot cone cutter is rotatably mounted to a journal extending from the second end of the bit body.

10. The drill bit of claim 9, wherein each pilot cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body; and

wherein the cone axis of each pilot cone cutter is oriented at a cone axis angle relative to the bit axis as viewed in a plane that contains the cone axis and is parallel to the bit axis, wherein the cone axis angle of the cone axis of each pilot cone cutter is between 60° and 90°.

11. The drill bit of claim 10, wherein each pilot cone cutter has a maximum outer diameter and a length measured axially between the backface and the nose of the pilot cone cutter, wherein the ratio of the maximum outer diameter of each pilot cone cutter to the axial length of each pilot cone cutter is between 2.0 and 4.0.

12. The drill bit of claim 1, wherein the reamer section includes a plurality of rolling cone cutters, each rolling cone cutter being rotatably mounted to a journal shaft extending from the bit body; and

wherein each rolling cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body.

13. The drill bit of claim 12, wherein each cone axis is oriented at a cone axis angle relative to the bit axis as viewed in a plane that contains the cone axis and is parallel to the bit axis, wherein the cone axis angle of each cone axis is between 45° and 90°;

wherein each rolling cone cutter has a maximum outer diameter and a length measured axially between the backface and the nose, wherein the ratio of the maximum outer diameter to the axial length of each rolling cone cutter is between 2.0 and 4.0.

14. A drill bit for drilling a borehole in earthen formations, the bit comprising:

a pilot bit extending from the second end of the bit body;

wherein the reamer section comprises a plurality of outwardly facing rolling cone cutters, each rolling cone cutter rotatably mounted to a journal shaft extending from the bit body.

15. The drill bit of claim 14, wherein each rolling cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body; and

wherein the cone axis of each rolling cone is oriented at a cone axis angle relative to the bit axis as viewed in a plane that contains the cone axis and is parallel to the bit axis, wherein the cone axis angle of each rolling cone cutter is between 60° and 90°.

16. The drill bit of claim 15, wherein each rolling cone cutter has a maximum outer diameter and a length measured axially between the backface and the nose, wherein the ratio of the maximum outer diameter to the axial length of each rolling cone cutter is between 2.0 and 3.0.

17. The drill bit of claim 15, wherein each rolling cone cutter has a cone offset between 0.5 in. and 3.00 in.

18. The drill bit of claim 17, wherein a first of the rolling cone cutters has a positive cone offset and a second of the rolling cone cutters has a negative cone offset.

19. The drill bit of claim 15, wherein the plurality of rolling cone cutters are uniformly circumferentially spaced about the bit body.

20. The drill bit of claim 15, wherein the pilot bit comprises a fixed cutter bit or a rolling cone bit.

21. A method for drilling a wellbore in an earthen formation, comprising:

(a) rotating a drill bit coupled to a lower end of a drillstring, wherein the drill bit comprises a bit body having a bit axis;

(b) forming a pilot borehole having a diameter D₁with a pilot bit disposed at a lower end of the bit body;

(c) forming an enlarged borehole having a diameter D₂with a reamer section extending from radially the bit body, wherein the reamer section is positioned axially above the pilot bit;

wherein (c) comprises rotating a plurality of reamer rolling cone cutters, each reamer cone cutter depending from a journal extending from the bit body;

wherein each reamer rolling cone cutter comprises a central axis, a backface, and a nose positioned proximal the diameter D₂.

22. The method of claim 21, further comprising passing the drill bit through a bore having a diameter less than diameter D₂.

23. The method of claim 21, wherein each reamer cone cutter has a positive or negative cone offset.

24. The method of claim 23, wherein the cone offset of each reamer cone cutter is between 0.5 in. and 3.00 in.

25. The method of claim 21, wherein (b) comprises rotating a plurality of pilot rolling cone cutters, each pilot cone cutter depending from a journal extending from the lower end of the bit body;

wherein each pilot rolling cone cutter comprises a central axis, a backface, and a nose positioned proximal the diameter D₁.