ROLLING CONE DRILL BIT HAVING NON-UNIFORM LEGS

Abstract

A drill bit for drilling through earthen formations. In an embodiment, the drill bit comprises a bit body having a bit axis. In addition, the drill bit comprises a first rolling cone cutter mounted on the bit body at a first journal angle and adapted for rotation about a first cone axis. Further, the drill bit comprises a second rolling cone cutter mounted on the bit body at a second journal angle and adapted for rotation about a second cone axis, wherein the second journal angle differs from the first journal angle.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional application Ser. No. 60/750,415 filed Dec. 14, 2005, and entitled “Rolling Cone Drill Bit Having Non-Uniform Legs,” which is hereby incorporated herein by reference in its entirety.

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 rolling cone rock bits. Still more particularly, the invention relates to leg, cone, and journal arrangements of such bits.

2. Background of the Invention

An earth-boring drill bit is typically mounted on the lower end of a drill string and is turned by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.

An earth-boring bit in common use today includes one or more rotatable cutters that perform their cutting function due to the rolling movement of the cutters acting against the formation material. The cutters roll and slide upon the bottom of the borehole as the bit is rotated, the rotatable cutters thereby engaging and disintegrating the formation material in their path. The rotatable cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones or rolling cone cutters. The borehole is formed as the action of the rotary cones remove chips of formation material which are carried upward and out of the borehole by drilling fluid which is pumped downwardly through the drill pipe and out of the bit.

The earth disintegrating action of the rolling cone cutters is enhanced by providing the cutters with a plurality of cutter elements. Cutter elements are generally of two types: inserts formed of a very hard material, such as tungsten carbide, that are press fit into undersized apertures in the cone surface; or teeth that are milled, cast or otherwise integrally formed from the material of the rolling cone. Bits having tungsten carbide inserts are typically referred to as “TCI” bits or “insert” bits, while those having teeth formed from the cone material are known as “steel tooth bits.” In each instance, the cutter elements on the rotating cutters break up the formation to form the new borehole by a combination of gouging and scraping or chipping and crushing.

In oil and gas drilling, the cost of drilling a borehole is 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 always 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 its rate of penetration (“ROP”), as well as its durability. The geometry, materials, and positioning of cutter elements upon the rotatable cone cutters significantly impact ROP and durability. Likewise, the geometry and positioning of the cone cutter cutters on the bit legs may affect ROP, footage drilled and total bit life. For example, characteristics including journal angle, cone offset, cone diameter, cone height, and other factors may impact bit life, drilling efficiency and footage drilled.

In designing rolling cone drill bits, a conventional practice is to employ bit legs and rotatable cone cutters that include uniform characteristics such as journal angle, cone offset, cone diameter, cone height, and others. For example, it is generally believed that a higher journal angle, for example about 36°, is more effective in drilling through relatively hard formations. As such, when a particular formation hardness is expected to be encountered, it is typical to employ a bit in which all three cones have identical, relatively high journal angles. Similarly, it is common to employ bits in which the rolling cone cutters are all offset the same amount relative to the bit axis. By designing bits with rolling cone cutters of uniform or identical characteristics, such as journal angle and cone offset, as examples, the bit may be thought to be optimized for particular formations and/or other drilling parameters; however, in many cases, the selected, uniform characteristics may actually cause the bit to suffer undesirable consequences, such as undue wear to certain rows of cutter elements, and/or breakage of particular cutting elements. Likewise, providing all the rolling cone cutters and bit legs with the same characteristics may not provide the desirable or optimum ROP for a given formation, as a further example.

Increasing ROP while maintaining good cutter and bit life to increase the footage drilled is an important goal in order to reduce drilling time and recover valuable oil and gas more economically. Optimizing bit leg and cone characteristics to provide enhancements in ROP and bit life would further that goal.

BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS

In accordance with at least one embodiment, a drill bit for drilling through earthen formations comprises a bit body having a bit axis. In addition, the drill bit comprises a first rolling cone cutter mounted on the bit body at a first journal angle and adapted for rotation about a first cone axis. Further, the drill bit comprises a second rolling cone cutter mounted on the bit body at a second journal angle and adapted for rotation about a second cone axis, wherein the second journal angle differs from the first journal angle.

In accordance with another embodiment, a drill bit for drilling through earthen formations comprises a bit body having a bit axis. In addition, the drill bit comprises at least three rolling cone cutters mounted on the bit body and adapted for rotation about a different cone axis, each of the cone cutters including a circumferential row of gage cutter elements and at least one circumferential row of inner row cutter elements spaced apart from the row of gage cutter elements. At least one of the inner row cutter elements of one rolling cone cutter intermesh with the inner row cutter elements of a different rolling cone cutter. Further, each of the rolling cone cutters defines a journal angle and a cone offset. Still further, the journal angle of a first of the cone cutters differs from the journal angle of a second of the cone cutters.

In accordance with another embodiment, a drill bit for drilling through earthen formations comprises a bit body having a bit axis. In addition, the drill bit comprises at least three rolling cone cutters mounted on the bit body and adapted for rotation about a different cone axis. Further, each of the cone cutters includes a circumferential row of gage cutter elements and at least one circumferential row of inner row cutter elements spaced apart from the row of gage cutter elements, wherein at least one of the inner row cutter elements of one rolling cone cutter intermeshes with the inner row cutter elements of a different rolling cone cutter. Still further, a first of the cone cutters differs from a second of the cone cutters in at least one characteristic selected from the group consisting of cone offset, journal angle, seal type, journal length, and journal diameter.

In accordance with another embodiment, a drill bit for drilling through earthen formations comprises a bit body having a bit axis. In addition, the drill bit comprises a plurality of bit legs, each of the legs including a rolling cone cutter mounted thereon and adapted for rotation about a different cone axis. Further, each of the cone cutters includes at least one circumferential row of inner row cutter elements, wherein at least one of the inner row cutter elements of one cone cutter intermeshes with the inner row cutter elements of a different cone cutter. Moreover, at least a first of the cone cutters differs from a second of the cone cutters in at least one characteristic selected from the group consisting of journal angle, cone offset, seal type and bearing configuration.

In accordance with yet another embodiment, a drill bit for drilling through earthen formations comprises a bit body having a bit axis. In addition, the drill bit comprises at least three rolling cone cutters mounted on the bit body and adapted for rotation about a different cone axis, each of the cone cutters including a circumferential row of gage cutter elements and at least one circumferential row of inner row cutter elements spaced apart from the row of gage cutter elements. Further, at least one of the inner row cutter elements of one rolling cone cutter intermeshes with the inner row cutter elements of a different rolling cone cutter. Each of the cone cutters defines a journal angle and a cone offset, and the cone offset of at least one cone cutter is different from the cone offset of another of the cone cutters.

Thus, the embodiments described herein comprise a combination of features providing the potential to overcome certain shortcomings associated with prior devices. 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 of the preferred embodiments, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings , which are not drawn to scale:

FIG. 1 is a perspective view of an earth-boring bit made in accordance with certain of the principles of the present invention.

FIG. 2 is a partial section view of the bit shown in FIG. 1 taken through one bit leg and one cone cutter.

FIG. 3 is a schematic representation showing a cross-sectional view of the intermesh of the three rolling cones of the bit shown in FIG. 1.

FIG. 4 is a schematic representation showing the three cone cutters of the bit shown in FIG. 1 as they are positioned in the borehole.

FIG. 5 is a partial section view of the drill bit shown in FIG. 1 taken along the lines 4-4 shown in FIG. 4.

FIG. 6 is an elevation view of the bottom of an alternative three cone drill bit made in accordance with certain principles of the present invention.

FIG. 7 is an elevation view of the bottom of an alternative three cone drill bit made in accordance with certain principles of the present invention.

FIG. 8 is a partial section view of another alternative drill bit taken through two intersecting planes so as to show views of two cones simultaneously.

FIG. 9 is a schematic representation showing three cone cutters in another alternative embodiment drill bit made in accordance with certain principles of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

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 and connections.

Rolling cone drill bits typically have been designed and manufactured such that their rotatable cones have identical journal angles, seal types, and bearing assemblies. This has an advantage of making the assembly of the bit easier and faster. Also, this conventional design approach does not require a manufacturer to inventory what might be a substantially larger number of parts, and it lessens the likelihood of assembly errors. Likewise, many conventional bits are manufactured with each rolling cone having the same degree of offset relative to the bit axis. However, at the same time, employing identical bit legs, journal angles, cone offsets seals, and bearings eliminates potential enhancements that could otherwise be provided by varying one or more of these characteristics. By optimizing these exemplary characteristics, as well as other leg and cone characteristics, a bit designer can enhance bit performance in one or more aspects, such as, ROP, gage-holding ability, durability, bit life, or combinations thereof

Referring now to FIG. 1, an earth-boring bit 10 is shown to include a central axis 11 and a bit body 12 having a threaded pin section 13 at its upper end that is adapted for securing the bit to a drill string (not shown). Bit 10 has a predetermined gage diameter as defined by the outermost reaches of three rolling cone cutters 1, 2, 3 (cones 1 and 2 shown in FIG. 1), which are rotatably mounted on bearing shafts that depend from the bit body 12. Bit body 12 is composed of three sections or legs 19 (two shown in FIG. 1) that are welded together to form bit body 12. Bit 10 further includes a plurality of nozzles 18 that are provided for directing drilling fluid toward the bottom of the borehole and around cone cutters 1-3. Bit 10 includes lubricant reservoirs 17 that supply lubricant to the bearings that support each of cone cutters 1-3. Bit legs 19 include a shirttail portion 16 that serves to protect the cone bearings and cone seals from damage caused by cuttings and debris entering between leg 19 and its respective cone cutter.

Referring now to both FIGS. 1 and 2, each cone cutter 1-3 is mounted on a pin or journal 20 extending from bit body 12, and is adapted to rotate about a cone axis of rotation 22 oriented generally downwardly and inwardly toward the center of the bit (only exemplary cone cutter 2 illustrated in FIG. 2). Pin 20 may also be referred to as a journal arm or journal pin. Each cutter 1-3 is secured on pin 20 by locking balls 26, in a conventional manner. In the embodiment shown, radial and axial thrusts are absorbed by journal sleeve 28 and thrust washer 31. The bearing structure shown is generally referred to as a journal bearing or friction bearing; however, the invention is not limited to use in bits having such structure, but may equally be applied in a roller bearing bit where cone cutters 1-3 would be mounted on pin 20 with roller bearings disposed between the cone cutter and journal pin 20. In both roller bearing and friction bearing bits, lubricant may be supplied from reservoir 17 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 34 which may take many forms. Drilling fluid is pumped from the surface through fluid passage 24 where it is circulated through an internal passageway (not shown) to nozzles 18 (FIG. 1). The borehole created by bit 10 includes sidewall 5, corner portion 6, and bottom 7, best shown in FIG. 2.

Referring still to FIGS. 1 and 2, each cutter 1-3 includes a generally planar backface 40 and nose portion 42 opposite backface 40. Adjacent to backface 40, cutters 1-3 further include a frustoconical surface 44 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 44 will be referred to herein as the “heel” surface of cone cutters 1-3, it being 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 44 and nose 42 is a generally conical surface 46 adapted for supporting cutter elements that gouge or crush the borehole bottom 7 as cone cutters 1-3 rotate about the borehole. Frustoconical heel surface 44 and conical surface 46 converge in a circumferential edge or shoulder 50. Although referred to herein as an “edge” or “shoulder,” it should be understood that shoulder 50 may be contoured, such as by a radius, to various degrees such that shoulder 50 will define a contoured zone of convergence between frustoconical heel surface 44 and the conical surface 46. Conical surface 46 is divided into a plurality of generally frustoconical regions or bands 48a-c generally referred to as “lands” which are employed to support and secure the cutter elements as described in more detail below. Grooves 49a, b are formed in cone surface 46 between adjacent lands 48a-c.

In the bit shown in FIGS. 1 and 2, each cone cutter 1-3 includes a plurality of wear resistant inserts or cutter elements 60, 61, 62. Inserts 60, 61, 62 each generally include a cylindrical base portion with a central axis, and a cutting portion that extends from the base portion and includes a cutting surface for cutting formation material. The cutting surface may be symmetric or asymmetric relative to the insert central axis. All or a portion of the base portion is secured into a mating socket formed in the surface of the cone cutter. Each insert 60, 61, 62 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, 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.

Inserts 60 are referred to herein as “heel” or “heel row” inserts as they extend from the generally frustoconical heel surface 44. Heel inserts 60 generally function to scrape or ream the borehole sidewall 5 (FIG. 2) to maintain the borehole at full gage, to prevent erosion and abrasion of heel surface 44, and to protect the shirttail portion 16 of bit leg 19. In this embodiment, heel inserts 60 are arranged in a circumferential row about cone axis 22.

Inserts 61 are positioned adjacent shoulder 50 and radially inward (relative to bit axis 11) of the circumferential row of heel cutter elements 60. Inserts 61 are referred to as “gage” or “gage row” inserts and are oriented to cut the borehole corner 6 (FIG. 2) and to ensure that the borehole maintains full gage diameter. In this embodiment, gage inserts 61 are arranged in a circumferential row about cone axis 22 and axially spaced apart from heel row inserts 60 relative to cone axis 22. In this embodiment, gage cutter elements 61 include a cutting surface having a generally slanted crest, although alternative shapes and geometries may be employed. Although cutter elements 61 are referred to herein as gage or gage row cutter elements, others in the art may instead describe such cutter elements as heel cutters or heel row cutters.

Referring still to FIGS. 1 and 2, inserts 62 are positioned between the circumferential row of gage cutter elements 61 and nose 42. Inserts 62 are referred to as “inner row” or “bottomhole” cutter elements and serve primarily to gouge, crush, and remove formation material from the borehole bottom 7 (FIG. 2). In this embodiment, inner row cutter elements 62 are arranged in circumferential rows about cone axis 22 that are axially spaced apart from each other, from heel row inserts 60, and from gage inserts 61 relative to cone axis 22. Further, although bottomhole cutter elements 62 are shown to include cutting surfaces having a generally rounded chisel shape, other shapes and geometries may also be employed. As will be described in more detail below, inner row inserts 62 are preferably arranged and spaced on each cone cutter 1-3 so as to intermesh, yet not interfere with the inner row inserts 62 of the other cone cutters 1-3.

Referring momentarily to FIG. 3, the intermeshed relationship between cones 1-3 of bit 10 is schematically shown. In this view, commonly termed a “cluster view,” cone 2 is schematically represented in two halves so that the intermesh between cones 2 and 3 and between cones 1 and 2 may be depicted simultaneously. Performance expectations of rolling cone bits typically require that the cone cutters be as large as possible within the borehole diameter so as to allow use of the maximum possible bearing size and to provide a retention depth adequate to secure the cutter element base within the cone steel. To achieve maximum cone cutter diameter and still have acceptable insert retention and protrusion, some of the rows of cutter elements are arranged to pass between the rows of cutter elements on adjacent cones as the bit rotates. In some cases, certain rows of cutter elements extend so far that clearance areas or grooves corresponding to cutting paths taken by cutter elements in these rows are provided on adjacent cones so as to allow the bottomhole cutter elements on adjacent cutters to intermesh farther. Thus, the term “intermesh” as used herein refers to the overlap of any part of at least one cutter element on one cone cutter with the envelope defined by the maximum extension of the cutter elements on an adjacent cutter.

Referring still to FIG. 3, each cone cutter 1-3 has an envelope 101 defined by the maximum extension height of the cutter elements on that particular cone. In this embodiment, envelope 101 of each cone cutter 1-3 is defined by the extension height of inner row inserts 62; inner row inserts 62 have the largest extension height in this embodiment. The cutter elements that “intersect” or “break” the envelope 101 of an adjacent cone may be said to “intermesh” with that adjacent cone. For example, inner row insert 62-1 of cone 1 breaks envelope 101 of cone 2, and breaks envelope 101 of cone 3, and therefore intermeshes with the inserts of cones 2 and 3. Likewise, inner row insert 62-2 of cone 2 breaks envelope 101 of cone 1, and envelope 101 of cone 3, and therefore intermeshes with the inserts of cones 1 and 3. Still further, inner row insert 62-3 of cone 3 breaks envelope 101 of cone 1, and envelope 101 of cone 2, and therefore intermeshes with the inserts of cones 1 and 2. As best seen in FIG. 3, grooves 49a and 49b on each cone 1-3 allow the cutting surfaces of certain bottomhole cutter elements 62 of adjacent cone cutters 1-3 to intermesh, without contacting the cone steel or surface of cones 1-3. It should be understood however, that in embodiments where the intermeshing cutter elements do not extend as far as those depicted in FIG. 3, clearance areas or grooves may not be necessary.

The drill bit 10 previously described with reference to FIGS. 1 and 2 employs bit legs 19 and cone cutters 1-3 that differ in various characteristics, including journal angle and cone offset. In this way, each leg 19 and each cutter 1-3 can be optimized for a particular cutting duty or to better withstand applied loads and forces in order to provide the potential for increased ROP and bit life.

Bit offset is best understood with reference to FIG. 4. In this Figure, cones 1-3 are shown schematically as they appear in the borehole. In this instance, cones 1 and 2 are each positioned to have the same offset, while cone 3 has a different offset. Thus, the cone cutters 1-3 have differing or non-uniform offsets.

“Offset” is a term used to describe the orientation of a cone cutter and its axis relative to the bit axis. More specifically, a cone is offset (and thus a bit may be described as having cone offset) when the cone axis does not intersect or pass through the bit axis, but instead passes a distance away from the bit axis. Referring to FIG. 4, cone offset may be defined as the distance “d” between the projection 22p of the rotational axis 22 of the cone cutter and a line “L” that is parallel to that projection and intersects the bit axis 11. Thus, the larger the distance “d”, the greater the offset.

In a bit having cone offset, 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 hole bottom in motions that may be described as skidding, scraping and sliding. These motions apply a shearing type cutting force to the hole bottom. 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 where the cone cutter predominantly cuts via compressive forces and a crushing action. 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. This wear and possibly breakage is particularly noticeable in the gage row where the cutter elements cut the corner 6 of the borehole to maintain the borehole at full gage diameter.

Cone offset may be positive or negative. Referring again to FIG. 4, cone cutters 1 and 2 are mounted with negative offset, with the offset being the distance d, for both cones 1 and 2 in this example. By contrast, cone 3 is shown to be mounted having positive offset represented by d₂. In other embodiments, all three cone cutters may have positive offset, or all may have negative offset, where at least one of the offsets differs in magnitude from the others.

With negative offset, the region of contact R₁ is behind the cone's axis of rotation with respect to the direction of rotation of the bit. On the other hand, with positive offset, the region of contact R₂ of the cone cutter with the sidewall is ahead of the axis of rotation of the cone cutter. Both positive and negative offset cause the cone cutters to deviate from a pure rolling motion and causes them to slide over and scrape the bottom of the borehole in a shearing action. Without being limited by this or any other theory, it is believed that, whether positive or negative, a larger total offset distance “d” (i.e., a larger absolute value offset) tends to increase formation removal and ROP, but may also result in accelerated gage row insert wear, and hence tends to decrease bore hole gage maintenance. Conversely, it is believed that a smaller total offset distance “d” (i.e., a smaller absolute value offset) tends to enhance borehole gage maintenance, but may reduce ROP.

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. For example, in comparison to a conventional bit having a +0.219 in. offset for each of the three cones, it would be expected that increasing that offset to +0.50 in. for each of the three cones would provide a bit having a higher ROP if other factors remained the same. However, compared to the same bit having +0.219 in. offset for all three cones, in the bit with all cones having +0.50 in. offset, it would also be expected that on one or more of the +0.50 in. offset cones, the gage cutter elements would wear significantly and round off, such that it might prove impossible to maintain a full gage diameter borehole for an acceptable period of time. Accordingly, it is desirable to vary the offset among the three cones to optimize the bit's all-around performance and, for example, to provide at least one cone whose primary function would be to enhance ROP, and another cone whose primary function would be to maintain gage.

One example is to provide a three cone bit with the following offsets:

Cone 1	Cone 2	Cone 3
+0.50 in.	−0.031 in.	+0.50 in.

As compared to a conventional three cone bit in which all three cones have the same +0.219 in. offset, providing the bit with a larger +0.50 in. offset for cones 1 and 3 would be expected to provide a higher bit ROP if other factors remained the same. Providing cone 2 with −0.031 in. offset would enhance the bit's ability to maintain gage, even at the higher ROP, as the gage and heel cutter elements of cone 2 would not be subjected to the higher impacts and shearing forces from sidewall and corner cutting as those of cone cutters 1 and 3. Thus, employing differing or non-uniform cone offsets provides a potential for a bit design having enhanced ROP with satisfactory gage-holding capabilities.

The example given above is exemplary only, and various other positive and negative offsets may be employed. For example, in the specific example above, cone 2 may instead have a zero offset or a +0.031 in. offset and still provide the desirable gage-holding function.

Like offset, varying the journal angle between the various legs on the bit offers potential advantages. Journal angle may be defined as the angle between the cone axis (the cone axis coinciding with the axis of the journal pin) and a plane perpendicular to the axis of rotation of the drill bit. Conventionally, for relatively hard formations, such as bits having the IADC classification 6-1-x and higher, the journal angle for all cones is about 36° or more. Softer formation bits, such as bits having an IADC classification lower than 6-1-x, typically have uniform journal angles of about 32° for all cones. In general, a smaller or lower journal angle tends to increase formation removal and ROP, but may also detrimentally impact borehole gage maintenance. Without being limited by any particular theory, it is believed that a lower journal angle increases bottomhole scraping and sliding, but also reduces engagement between the gage row inserts and heel row inserts engages and the borehole sidewall. Conversely, it is believed that relatively higher journal angles tend to decrease formation removal and ROP, but also tend to enhance borehole gage maintenance. Referring to FIG. 5, bit 10, cones 1 and 2, and the journal pins 20-1 and 20-2 to mounted, respectively, are shown in partial cross-section. As shown, cone 1 is rotatably mounted on bit 10 with a journal angle 70 measured between axis 22 of cone 1 and a plane perpendicular to bit axis 11. In this example, journal angle 70 of cone 1 is 30°. Cone 2 is mounted with the journal angle 71 measured between axis 22 of cone 2 and a plane perpendicular to bit axis 11. In this example, journal angle 71 of cone 2 is 36°. Although not shown in FIG. 5, cone 3 is also mounted with a journal angle of approximately 30° in this embodiment. Cones 1-3 have the offsets previously described in reference to FIG. 4.

Thus, the lower journal angle 70 of cone 1 provides greater ROP relative to cone 2. Compared to a conventional three cone bit having each cone cutter mounted at a 32.5° journal angle, bit 10, with cones 1 and 3 each at a relatively low 30° journal angle, and cone 2 at a 36° journal angle, would expected to provide greater ROP. Further, in this example, cone 2, with its relatively large journal angle of 36°, would be expected to undergo less scraping against the borehole sidewall and thereby provide a cone cutter capable of cutting to full gage diameter for a longer period of time than cone cutters 1 and 3 that are more aggressively positioned with the lower journal angle.

One method for designing a bit that provides enhanced ROP relative to a conventional three cone bit, and that provides satisfactory gage-holding ability, is as follows. First, the arrangement of inserts and the cutting structure on the three cone cutters are selected and then analyzed to determine which cone cutter includes cutting inserts that will most impact ROP. That cone cutter (cone A in this example) will typically be the most aggressive cutter and include inserts in locations suggesting that they will dig into the formation the most and thereby provide the most benefit to ROP. Relative to a conventional three cone bit having the same offset and same journal angle for all three cone cutters, cone A in the new bit design would be provided with a larger offset and a lower journal angle than that of the conventional bit.

Next, the cone cutter that would appear to be the least aggressive based on the insert pattern and cutting structure would be identified. That cone cutter (cone B in this example) on the new design would be provided with the lowest offset and the highest journal angle of the three cone cutters in the new bit design. Given its less-aggressive cutting structure, cone B will have the least effect on ROP. However, the relatively low offset and high journal angle of cone B will enhance its ability to protect gage and maintain a full diameter borehole.

Next, the remaining cone cutter (cone C in this example) of the new bit design is selected to have a first benchmark journal angle and offset. For instance, cone cutter C may first be provided with the same journal angle and offset as a conventional bit where all three cones have the same characteristics. If in testing or modeling the ROP of the new design was not as great as desired, then the design could be modified to provide cone C with a lower journal angle and/or a larger offset compared to the initial offset and journal angle selected for cone C that did not provide the desired ROP performance. Conversely, if upon testing or modeling the bit was not able to maintain gage satisfactorily, then the design for cone C could be modified to have a smaller offset and/or higher journal angle relative to the initial offset and journal angle selected for cone C. Further iterations are possible to achieve an optimum offset and journal angles for each of the three cones A, B, and C.

As still further examples of particular embodiments of the invention, a three cone drill bit is shown in FIG. 6 to include two cones having low offsets and high journal angles relative to the third cone on the bit. For example, cones 1 and 2 include relatively small offsets of approximately +0.125 in. and relatively high journal angles of approximately 36°. By contrast, cone 3 includes a relatively larger offset of +0.313 in. and a relatively low journal angle of 32°. In this example, cones 1 and 2 are generally better suited for cutting harder formations.

As a further example, in another multi-coned bit shown in FIG. 7, cone 1 is provided with a relatively high cone offset relative to cones 2 and 3. In this example, cone 1 includes a positive offset of approximately +0.313 in. By contrast, cones 2 and 3 are provided with zero offset. In this arrangement, cone 1 with its relatively high offset may provide a relatively high penetration rate on the borehole bottom, while the cone cutters 2 and 3 maintain gage without experiencing severe wear or an inordinate amount of insert breakage in the gage row as might otherwise occur if 2 and 3 were likewise aggressively positioned with relatively high offsets. In this example, cone 1 may include a journal angle of about 32.5° while cones 2 and 3 employ journal angles of approximately 38° and 35.5°, respectively.

It should be understood that the examples presented above are merely specific examples of certain of the bits that may be manufactured to employ the concepts broadly disclosed herein. However, the concepts described herein are not limited only to those examples and may, for example, include multi-cone bits in which the journal angles and cone offsets differ in other respects and to different degrees. As a further specific example, a bit such as that shown in FIG. 5 may be employed having a first cone offset that is less than the cone offset of a second cone of the bit, and where the journal angle of the first cone is less than the journal angle of the second cone. In certain applications, as dictated by bit size, formation material, and other factors, substantial ROP gains from employing a relatively low journal angle in this bit may compensate or override the detrimental effects on ROP presented by a relatively low offset. Thus, such a situation could permit the relatively low offset to be employed in a particular cone cutter in order to enhance the durability of the gage region of the cutter and thus enhance the ability of the bit to maintain full gage diameter.

It is also contemplated that bearings will differ from leg to leg on a given bit, such differences including journal diameter, length and bearing type. Presently, it is conventional practice to employ the same type and sized bearings for each cone cutter and bit leg. For a conventional journal bearing bit, the diameter of the journal pin is typically the same for each cone cutter, the diameter being dependent on maintaining a minimum measure of cone steel between the bearing and the embedded base of adjacent inserts. For example, referring again to FIG. 5, an insert 62-1 is shown to have its base embedded in the steel of cone 2 at a location adjacent to journal pin 20-2. A minimum distance M must be maintained between the ball race 73 that is formed in the cone steel and the base of insert 62-1. Thus, in designing a conventional three cone bit, the journal pins on each of the three legs would have the same diameter, the diameter being that required to maintain a sufficient minimum distance M between the cone and insert base that most closely approaches the cone. This has been conventional practice even in cases where other cone cutters could have employed larger journal diameters because they were not constrained by adjacent inserts. By contrast, in FIG. 5, the diameter of journal pin 20-1 is greater than the diameter of journal 20-2 (figures not drawn to scale). In part, this is because there is no cutter element positioned in region 74 that would prevent pin 20-1 from having a relatively larger diameter. As such, the diameter of journal pin 20-1 is enlarged relative to the diameter of journal pin 20-2. Likewise, as discussed further herein, the diameter of cones 1 and 2 may differ. In general, a larger diameter cone offers the ability to employ journal pins that are longer or have a greater diameter, or both.

Providing a bit with legs and cones having non-uniform journal angles and offsets also offers potential for optimization of bearing size(s), although it should be appreciated that insert size and placement affects the bearing size to a greater degree than journal angle and bit offset. Nevertheless, for bit legs and cone cutters having higher journal angles or smaller offsets, or both, there may exist greater space to accommodate a larger diameter journal pin and larger bearing surfaces. For example, an increase in journal angle while maintaining cone distance from the bottomhole allows for a longer cone cutter and hence a larger bearing surface area between the cone and the journal pin.

Bit 10 shown in FIG. 5 employs journal bearings on all three cone cutters. In other embodiments, certain cone cutters will be mounted via journal bearings while other cone cutters are mounted via roller bearings. For example, referring to FIG. 8, a roller cone bit 80 includes a first cone cutter 81 mounted on a journal pin 20-1 by means of roller bearings 84. Second cone cutter 82 is mounted with journal bearings. In part, the choice of bearing type may depend on the cone diameter, as well as cone speed. Without necessarily considering all other design factors, it may be preferable to use the roller bearings in larger diameter cone cutters and, in other cases, in cone cutters that turn faster than other cutters on the bit.

In a similar manner, the seal types and configurations may vary from leg to leg or cone to cone on a multi-coned bit. Referring again to FIG. 5, cone 2 is shown to be sealed against journal pin 20-2 via a conventional elastomeric O-ring seal 75. By contrast, cone 1 is sealed to journal pin 20-1 via seal member 76 having an elongate profile which may be, for example, what is sometimes characterized as a “bullet” seal. Certain such bullet seals and other seals applicable in the embodiments described herein are described in U.S. Pat. Nos. 6,170,830, 6,196,339, and 6,123,337, the disclosure of each of which is hereby incorporated herein by reference in its entirety. In the example shown in FIG. 5, where cone 1 is primarily intended to enhance ROP, such as in relatively soft formations, it may be that the RPMs of cone 1 are substantially higher per bit revolution than cone 2, and thus, a bullet seal may be more appropriate for cone 1. However, in cone 2, where bottomhole formation removal and ROP are not its primary function, the RPM may not be as high, and thus, an O-ring seal may be more appropriate. Preferably, although not a requirement, a cone that experiences greater RPMs employs a bullet seal, whereas a cone that experiences slower RPMs employ a more conventional O-ring, seal.

Thus, rather than standardizing on a particular bearing and seal for every leg of a multi-coned bit, the bearings and seals may be varied and optimized to provide maximum durability and bit life. Most conventional bits use identical bearings and seals for each cone in a multi-coned bit in order to simplify manufacturing and inventory management. However, the embodiments disclosed herein provide design flexibility such that the bearing capacity may be maximized for each individual cone cutter and optimized relative to the cutting structure of each cone in order to best absorb and withstand the cone's proportional share of load, as well as the direction in which it is loaded. Likewise, various seal types and seal arrangements may be employed and may be varied from cone to cone to optimize bit life and/or performance. For instance, referring to FIG. 8, cone 82 employs an O-ring seal 75. By contrast, cone 81 employs dual seals 86, 87 that are disposed in spaced apart seal glands 88, 89, respectively.

Conventionally, the bit legs, journal pins, and cone cutters are separated by a uniform angular distance or “separation angle” of 120°. However, according to some embodiments illustrated and described herein, the separation angle between the legs of the drill bit and the cone cutters attached thereto may be varied. As shown schematically in FIG. 9, a bit 90 in accordance with this application may include cones 2 and 3 spaced apart by 110°, with each of cones 2 and 3 each separated from cone 1 by 125°. This greater degree of separation between cones 1 and 2 and between cones 1 and 3 may provide clearance for cone 1 to be larger in diameter than cones 2 and 3. For example, cone 1 may have a 9⅞ in. diameter while cones 2 and 3 have a 7⅞ in. diameter which, in this arrangement, effectively form an 8¾ in. diameter bit 90. In general, a relatively larger cone (e.g., cone 1) provides the bit designer with the ability to employ larger diameter inserts in a given row, or a greater number of inserts, or both, than could be employed in the smaller sized cone. Likewise, the journal pin and bearing surfaces for cone 1 may be larger for the larger cone cutter. For example, the journal pin may be larger in diameter and may have a greater length, decreasing the unit loading on the bearing. Further, the larger cone 1 may provide the ability to employ a different type or longer-lasting seal assembly, or one structured in a way that could not be employed with the relatively smaller clearances in the smaller cone cutters 2 and 3. For example, in cone cutters 2 and 3, a single elastomeric O-ring seal may be employed, where, by contrast, in cone cutter 1 a dual seal arrangement may be employed, such as dual seals 86, 87 shown in FIG. 8. It should also be appreciated that mounting a cone cutter with a larger journal angle also allows for a larger diameter cone.

The choice of seal types and seal arrangements may follow from cone size. For example, referring again to FIG. 9, there is schematically shown a bit 90 having cone 1 with a relatively large diameter and cones 2 and 3 with relatively smaller and equal diameters. In this example, the smaller cones 2 and 3 will rotate faster, making it desirable to use a seal such as the bullet seal 76 shown in FIG. 5. By contrast, the relatively large and slower turning cone 1 may be sealed with a conventional O-ring seal, or a pair of seals as mentioned above.

It should be appreciated that having both positive and negative offset cone cutters on the same bit may also dictate or suggest employing differing separation angles. For example, referring again to FIG. 4, the separation angle between cones 2 and 3 is greater than the separation angle between cones 1 and 2 and between cones 1 and 3.

It may also be desirable in certain designs to include differing cone heights from leg to leg. Cone height may be measured from various points, but generally is defined as the distance between a fixed point on the bit and the point in which the projection of the cone axis 22 intersects bit axis 11. For example, referring back to FIGS. 1 and 5, and using the upper surface 9 of pin section 13 as the fixed reference point, cone cutter 1 is higher in the bit than cone cutter 2 and thus may be described as having a greater cone height (the cone having the greater height being the one closer to a reference point and further from the borehole bottom than the other cone). In a drill bit where, for example, one cone was intended primarily to maintain gage, and another (or others) intended to enhance ROP, the cone cutter designed to maintain gage preferably has a greater cone height (be positioned further from the hole bottom). Such cone cutter would also desirably include a low offset, and a high journal angle (for example, in the range of about 36°-39°). On the other hand, the cone cutter designed to enhance ROP preferably has a smaller cone height (be positioned closer to the hole bottom). Such cone cutter would also desirably include a larger offset, and a lower journal angle (for example, in the range of about 30°-32.5°).

In designing a multi-cone bit, one exemplary method of design would be for the bit designer to first select an offset for the first cone cutter and an offset for the second cone cutter. As explained above, the first offset may be intended to enhance ROP while the second is intended to enhance gage-holding ability. Thereafter, journal angles of the first and second cones may be selected, with such angles also selected to enhance ROP, gage-holding ability, or other desired performance characteristics. Alternatively, the journal angle(s) and offset(s) for the differing cone cutter(s) and leg(s) may first be selected.

A next step in the design may be to choose the journal angle and offset for a third cone cutter in a bit employing more than two cones. The method would also include the step of determining the appropriate size, shape, and materials for the cutting inserts, as well as their layout on the cone cutters. It is desirable that the bearing structure then be determined after the insert geometry is designed so as to be able to maintain the necessary separation between the inserts and the journal. Thereafter, depending upon such factors as cone size and speed, appropriate seal type and size may then be selected. The method also includes selecting the appropriate cone height, cone diameter, and cone separation angles. Typically, these three characteristics would be selected after determination of the offset and journal angle for each cone cutter.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the above-described structures are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims which follow, the scope of which shall include all equivalents of the subject matter of the claims.

Claims

1. A drill bit for drilling through earthen formations comprising:

a bit body having a bit axis;

a first rolling cone cutter mounted on the bit body at a first journal angle and adapted for rotation about a first cone axis;

a first plurality of cutter elements mounted to the first rolling cone cutter;

a second rolling cone cutter mounted on the bit body at a second journal angle and adapted for rotation about a second cone axis, wherein the second journal angle differs from the first journal angle;

a second plurality of cutter elements mounted to the second rolling cone cutter, wherein at least one of the second plurality of cutter elements intermeshes with the first plurality of cutter elements.

2. The drill bit of claim 1 wherein the first rolling cone cutter is mounted on the bit body at a first cone offset and the second rolling cone cutter is mounted on the bit body at a second cone offset that is different than the first cone offset.

3. The drill bit of claim 2 wherein the first cone offset is greater than the second cone offset, and wherein the first journal angle is less than the second journal angle.

4. The drill bit of claim 2 wherein the first cone offset is positive and the second cone offset is negative.

5. The drill bit of claim 3 wherein the first and second plurality of cutter elements each include a circumferential row of gage inserts, wherein the number of gage inserts mounted to the first rolling cone cutter is different than the number of gage inserts mounted to the second rolling cone cutter.

6. The drill bit of claim 2 wherein the first cone offset is less than the second cone offset and wherein the first journal angle is less than the second journal angle.

7. The drill bit of claim 1 wherein the first rolling cone cutter is mounted on a first journal pin extending from the bit body and the second rolling cone cutter is mounted on a second journal pin extending from the bit body, wherein the diameter of the first journal pin is different than the diameter of the second journal pin.

8. A drill bit for drilling through earthen formations comprising:

a bit body having a bit axis;

at least three rolling cone cutters mounted on the bit body and adapted for rotation about a different cone axis, each of the cone cutters including a circumferential row of gage cutter elements and at least one circumferential row of inner row cutter elements spaced apart from the row of gage cutter elements, wherein at least one of the inner row cutter elements of one rolling cone cutter intermeshes with the inner row cutter elements of a different rolling cone cutter; wherein each of the rolling cone cutters defines a journal angle and a cone offset; and

wherein the journal angle of a first of the cone cutters differs from the journal angle of a second of the cone cutters.

9. The drill bit of claim 8 wherein at least one cone cutter has an offset that is different from the offset of another of the cone cutters.

10. The drill bit of claim 9 wherein at least one of the cone cutters has a positive offset and at least one of the cone cutters has negative offset.

11. The drill bit of claim 8 wherein each of the cone cutters is mounted on a different journal pin extending from the bit body, and wherein the diameter of at least one journal pin is different from the diameter of another journal pin.

12. The drill bit of claim 8 wherein each of the cone cutters is mounted on a different journal pin and wherein the journal pin of at least one cone cutter differs from the journal pin of another of the cone cutters in at least one characteristic selected from the group consisting of journal length and journal diameter.

13. The drill bit of claim 8 wherein at least one of the cone cutters is mounted with roller bearings and at least a second cone cutter is mounted with journal bearings.

14. The drill bit of claim 8 wherein the bit includes at least one cone seal disposed between each cone and the journal pin upon which it is mounted, and wherein the bit includes cone seals of differing types.

15. The drill bit of claim 8 wherein a first cone cutter is disposed between and immediately adjacent a second cone cutter and a third cone cutter, wherein the first cone cutter is separated from the second cone cutter by a first separation angle and separated from the third cone cutter by a second separation angle that is different than the first separation angle.

16. A drill bit for drilling through earthen formations, comprising:

a bit body having a bit axis;

at least three rolling cone cutters mounted on the bit body and adapted for rotation about a different cone axis;

wherein each of the cone cutters includes a circumferential row of gage cutter elements and at least one circumferential row of inner row cutter elements spaced apart from the row of gage cutter elements, wherein at least one of the inner row cutter elements of one rolling cone cutter intermeshes with the inner row cutter elements of a different rolling cone cutter;

wherein a first of the cone cutters differs from a second of the cone cutters in at least one characteristic selected from the group consisting of cone offset, journal angle, seal type, journal length, and journal diameter.

17. The drill bit of claim 16 wherein a first cone cutter has a first cone offset and a second cone cutter has a second cone offset that is different from the first cone offset, and wherein the first cone cutter is mounted having a first journal angle that differs from the journal angle of at least one other of the cone cutters.

18. The drill bit of claim 17 wherein each of the cone cutters differs in cone offset and journal angle from each of the other cone cutters.

19. The drill bit of claim 17 wherein the second cone cutter is mounted having a second journal angle, and wherein first cone offset is greater than the second cone offset and the first journal angle is less than the second journal angle.

20. The drill bit of claim 17 wherein the second cone cutter is mounted having a second journal angle, and wherein the first cone offset is less than the second cone offset and the first journal angle is less than the second journal angle.

21. A drill bit for drilling through earthen formations comprising:

a bit body having a bit axis;

a plurality of bit legs, each of the legs including a rolling cone cutter mounted thereon and adapted for rotation about a different cone axis;

wherein each of the cone cutters includes at least one circumferential row of inner row cutter elements, wherein at least one of the inner row cutter elements of one cone cutter intermeshes with the inner row cutter elements of a different cone cutter;

wherein at least a first of the cone cutters differs from a second of the cone cutters in at least one characteristic selected from the group consisting of journal angle, cone offset, seal type and bearing configuration.

22. The drill bit of claim 21 wherein the first of the cone cutters has a first cone offset and the second of the cone cutters has a second cone offset that is different from the first cone offset, and wherein the first of the cone cutters is mounted having a first journal angle that differs from the journal angle of at least one other of the cone cutters.

23. The drill bit of claim 22 wherein the second of the cone cutters is mounted having a second journal angle, and wherein first cone offset is greater than the second cone offset and the first journal angle is less than the second journal angle.

24. A drill bit for drilling through earthen formations comprising:

a bit body having a bit axis;

at least three rolling cone cutters mounted on the bit body and adapted for rotation about a different cone axis, each of the cone cutters including a circumferential row of gage cutter elements and at least one circumferential row of inner row cutter elements spaced apart from the row of gage cutter elements, wherein at least one of the inner row cutter elements of one rolling cone cutter intermeshes with the inner row cutter elements of a different rolling cone cutter; wherein each of the cone cutters defines a journal angle and a cone offset; and

wherein the cone offset of at least one cone cutter is different from the cone offset of another of the cone cutters.

25. The drill bit of claim 24 wherein the journal angle of a first of the cone cutters differs from the journal angle of a second of the cone cutters.

26. The drill bit of claim 24 wherein at least one of the cone cutters has a positive offset and at least one of the cone cutters has negative offset.

27. The drill bit of claim 24 wherein each of the cone cutters is mounted on a different journal pin and wherein the journal pin of at least one cone cutter differs from the journal pin of another of the cone cutters in at least one characteristic selected from the group consisting of journal length and journal diameter.

28. The drill bit of claim 24 wherein at least one of the cone cutters is mounted with roller bearings and at least a second cone cutter is mounted with journal bearings.

29. The drill bit of claim 24 wherein the bit includes at least one cone seal disposed between each cone and the journal pin upon which it is mounted, and wherein the bit includes at least two cone seals of differing types.

30. The drill bit of claim 24 wherein a first cone cutter is disposed between and immediately adjacent a second cone cutter and a third cone cutter, wherein the first cone cutter is separated from the second cone cutter by a first separation angle and separated from the third cone cutter by a second separation angle that is different than the first separation angle.