US20080060852A1

US20080060852A1 - Gage configurations for drill bits

Info

Publication number: US20080060852A1
Application number: US11/517,179
Authority: US
Inventors: Parveen K. Chandila; Bryce Baker
Original assignee: Smith International Inc
Current assignee: Smith International Inc
Priority date: 2006-09-07
Filing date: 2006-09-07
Publication date: 2008-03-13
Also published as: GB2441654B; GB0717341D0; GB2441654A; CA2598411A1

Abstract

A drill bit includes a plurality of cutting elements are positioned on the at least two roller cones, wherein cutting elements contributing to an operative gage row of the drill bit comprise less than 31 percent of a total cutting elements of the drill bit that contact the bottom of the borehole. A method to design a roller cone drill bit includes designing an initial bit, testing the initial bit; and adjusting the bit design to optimize at least one of rate of penetration and wear resistance, wherein cutting elements contributing to an operative gage row of the adjusted bit design comprise less than 31 percent of a total of cutting elements on the adjusted bit design that contact a bottom of a borehole.

Description

BACKGROUND OF INVENTION

1. Field of the Invention
Embodiments disclosed herein relate generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas, and other minerals. More particularly, embodiments disclosed herein relate to roller cone drill bits and to the location of cutting elements on and design of roller cone drill bits to improve the rate of penetration of the bit and to enhance the ability of the bit to maintain gage.
2. Background Art
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated 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 formed in the drilling process will have a diameter generally equal to the diameter or “gage” of the drill bit.
A typical earth-boring bit 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 cutters thereby engaging and disintegrating the formation material in its path. The rotatable cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones. Such bits typically include a bit body with a plurality of journal segment legs. The cutters are mounted on bearing pin shafts which extend downwardly and inwardly from the journal segment legs. The borehole is formed as the gouging and scraping or crushing and chipping 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 drilling fluid carries the chips and cuttings in a slurry as it flows up and out of the borehole.
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 may be referred to as “TCI” bits, while those having teeth formed from the cone material are known as “steel tooth bits.” In each case, the cutter elements on the rotating cutters functionally breakup the formation to form new borehole by a combination of gouging and scraping or chipping and crushing.
The cost of drilling a borehole 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 in order to reach 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 or ability to maintain an acceptable ROP. The form and positioning of the cutter elements (both steel teeth and TCI inserts) upon the cutters greatly impact bit durability and ROP and thus are critical to the success of a particular bit design.
Bit durability is, in part, measured by a bit's ability to “hold gage,” meaning its ability to maintain a full gage borehole diameter over the entire length of the borehole. Gage holding ability is particularly vital in directional drilling applications which have become increasingly important. If gage is not maintained at a relatively constant dimension, it becomes more difficult, and thus more costly, to insert drilling apparatus into the borehole than if the borehole had a constant diameter. For example, when a new, unworn bit is inserted into an under-gage borehole, the new bit will be required to ream the under-gage hole as it progresses toward the bottom of the borehole. Thus, by the time it reaches the bottom, the bit may have experienced a substantial amount of wear that it would not have experienced had the prior bit been able to maintain full gage. This unnecessary wear will shorten the bit life of the newly-inserted bit, thus prematurely requiring the time consuming and expensive process of removing the drill string, replacing the worn bit, and reinstalling another new bit downhole.
A conventional rolling cone bit was described in U.S. Pat. No. 5,372,210 (the '210 patent), issued to Harrell, and includes the following nomenclature, which will be used herein. The '210 patent is hereby incorporated by reference herein in its entirety. Reaming insert rows are located on the portion of the cone closest to the sidewall of the borehole and closely adjacent to the bit body, reaming the already cut full gage diameter of the borehole well above the bottom of the borehole. These are often referred to as the heel row. The row of a cone which first engages the uncut full diameter of the borehole is the gage row. The intermediate rows of inserts cut the hole bottom. The nose rows are designed to cut near the center of the borehole. The intermediate and nose rows, collectively, are referred to as the inner rows of the bit, cutting closer to the center of the borehole than the gage row. Additionally, although rolling cone drill bits often contain more than one roller cone, an “operative row” is defined as one or more rows of a drill bit which act to cut substantially a single track along the borehole.
Nose inserts cut the core region of the borehole. The bottom region, concentric to the core, is cut by the intermediate rows of inserts. The gage region of the borehole is the cylindrical full diameter surface cut by the gage and reaming rows of inserts. And, transition inserts drill the transition region, the narrow ring between the outer edge of the borehole bottom and the gage.
Referring now to FIG. 1, the above definitions are applied to a conventional rolling cone bit 10. To assist in maintaining the gage of a borehole, a conventional rolling cone bit 10 typically employs a heel row 12 of hard metal inserts 16 on the heel surface 14 of the rolling cone cutters A, B. C. The heel surface 14 is a generally frustoconical surface and is configured and positioned so as to generally align with and ream the sidewall of the borehole as the bit rotates. The inserts 16 in the heel surface 14 contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall. The heel inserts 16 function primarily to maintain a constant gage and secondarily to prevent the erosion and abrasion of the heel surface 14 of the rolling cone. Excessive wear of the heel inserts 16 leads to an under-gage borehole, decreased ROP, increased loading on the other cutter elements on the bit, and may accelerate wear of the cutter bearing and ultimately lead to bit failure.
The gage row 18 of cutter elements 20 is mounted adjacent to the heel surface 14 but orientated and sized in such a manner so as to cut the corner of the borehole. In this orientation, the gage cutter elements 20 generally are required to cut both the borehole bottom and sidewall. The lower surface of the gage row inserts 20 engages the borehole bottom while the radially outermost surface scrapes the sidewall of the borehole.
Conventional bits also include a number of additional rows 22, 24, 26 of cutter elements that are located on cones A, B, C in rows disposed radially inward from the gage row. These cutter elements are sized and configured for cutting the bottom of the borehole and are typically described as inner row cutter elements.
FIG. 2 a schematically depicts an assembly view of the cones A, B, C of a conventional drill bit 10, and FIG. 2 b schematically illustrates the positions of all of the cutter inserts from all three cones A, B, C rotated into a single plane. The cutting elements will be referred to by number and cone, where “20B” refers to gage element 20 on cone B. To assist in maintaining the gage of a borehole, conventional rolling cone bits typically employ a row of heel cutters 16A, 16B, and 16C on the heel surface 14 of each rolling cone. Gage rows 18 having gage cutter elements 20A, 20B, and 20C are mounted on the respective gage surfaces 25 (FIG. 1) and oriented and sized in such a manner so as to cut the corner of the borehole. Conventional bits also include a number of additional inner rows of cutter elements 22, 24, 26 that are located on the main, generally conical surface of each cone in rows disposed radially inward from the gage rows 18. The cutter elements in the heel rows (16A, 16B, 16C) and gage rows (20A, 20B, 20C) typically share a common position across all three cones, forming an operative heel or reaming row and an operative gage row, respectively, while the cutter elements in the inner rows 22, 24, 26 are radially spaced so as to cut the borehole bottom in a desired manner. Excessive or disproportionate wear on any of the cutter elements may lead to an under-gage borehole, decreased-ROP, or increased loading on the other cutter elements on the bit, and may accelerate wear of the cutter bearing and ultimately lead to bit failure.
Differing forces are applied to the cutter elements by the sidewall than the borehole bottom. Thus, requiring gage cutter elements to cut both portions of the borehole compromises the cutter design. In general, the cutting action operating on the borehole bottom is typically a crushing or gouging action, while the cutting action operating on the sidewall is a scraping or reaming action. Ideally, a crushing or gouging action requires a tough insert, one able to withstand high impacts and compressive loading, while the scraping or reaming action calls for a very hard and wear resistant insert. One grade of tungsten carbide cannot optimally perform both of these cutting functions as it cannot be as hard as desired for cutting the sidewall and, at the same time, as tough as desired for cutting the borehole bottom. As a result, compromises have been made in conventional bits such that the gage row cutter elements are not as tough as the inner row of cutter elements because they must, at the same time, be harder, more wear resistant and less aggressively shaped so as to accommodate the scraping action on the sidewall of the borehole.
In addition to inserts that cut gage (cutting the borehole corner, both bottom and side), some prior art bits have included off-gage inserts to aid the gage inserts in cutting the corner of the borehole. Off-gage inserts are cutting elements or inserts that are positioned so that their cutting surfaces are close to gage, but are off-gage by a small distance.
Several patents describe the off-gage concept of bit design, discussing optimal location of gage and off-gage cutter elements to separate sidewall and bottom hole cutting duty. U.S. Pat. Nos. 6,510,909 and 6,390,210 disclose a rolling cone bit including at least one cutter having a gage row of cutter elements and a first inner row of near but off-gage cutter elements that are positioned so as to divide the sidewall and bottom hole cutting duty. U.S. Pat. No. 5,833,020 discloses a rolling cone bit including a cone cutter having a pair of adjacent rows of cutter elements positioned to divide the sidewall and bottom hole cutting duty. Each of these patents is hereby incorporated by reference in their entireties.
U.S. Pat. Nos. 5,479,997 and 6,209,668 ('997 and '668, respectively) disclose bits having distinct rows of inserts to cut the corner of the borehole. Maintaining consistent terminology as used herein, the bits disclosed in '997 and '668 include two sets of “gage” inserts, referred to as inserts 51 and 43 in FIGS. 3A-3C of the '997 and '668 patents, each cutting on the gage curve. After minimal wear of inserts 43, inserts 51 exclusively cuts at full gage (see FIG. 3C of the '997 patent), with both inserts 43 and 51 contacting hole bottom, inserts 51 cutting the corner of the borehole. The '997 and '668 patents are hereby incorporated by reference herein in their entireties.
Due to the above described forces and cutting actions, bits are generally designed to have as many cutting elements as possible on the gage of the bit, cutting the hole bottom and corner, in order to prolong bit life. However, a high gage count may limit the penetration depth of the gage and inner row inserts and may limit ROP. Accordingly, there remains a need in the art for a drill bit and cutting structure that will yield greater rates of penetration and an increase in footage drilled while maintaining a full gage borehole.

SUMMARY OF INVENTION

In one aspect, embodiments disclosed herein relate to a drill bit to drill a borehole to a predetermined gage. Preferably, the drill bit includes a bit body having a bit axis, and at least two roller cones rotatably secured to the bit body. The at least two roller cones have a generally conical surface and an adjacent heel surface, wherein the heel and conical surfaces form a circumferential shoulder therebetween. A plurality of cutting elements are positioned on the at least two roller cones, wherein cutting elements contributing to an operative gage row of the drill bit comprise less than 31 percent of a total cutting elements of the drill bit that contact the bottom of the borehole.
In another aspect, embodiments disclosed herein relate to a drill bit to drill a borehole to a predetermined gage. Preferably, the drill bit includes a bit body having a bit axis, and at least two roller cones rotatably secured to the bit body. The at least two roller cones have a generally conical surface and an adjacent heel surface, wherein the heel and conical surfaces form a circumferential shoulder therebetween. A plurality of cutting elements are positioned on the at least two roller cones, wherein at least one roller cone comprises no cutting elements contributing to the operative gage row of the drill bit.
In another aspect, embodiments disclosed herein relate to a method to design a roller cone drill bit. Preferably, the method includes designing an initial bit, wherein the initial bit includes a bit body having a bit axis, and at least two roller cones rotatably secured to the bit body, wherein the at least two roller cones have a generally conical surface and an adjacent heel surface, wherein the heel and conical surfaces form a circumferential shoulder therebetween, and a plurality of cutting elements positioned on the at least two roller cones. Furthermore, the method includes testing the initial bit and adjusting the bit design to optimize at least one of rate of penetration and wear resistance, wherein the cutting elements contributing to an operative gage row of the adjusted bit design comprise less than 31 percent of the total cutting elements on the adjusted bit design that contact the bottom of the borehole.
In another aspect, embodiments disclosed herein relate to a roller cone drill bit comprising a cutting element which terminates in a T-shaped crest.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a side view of a prior art drill bit.

FIG. 2 a is an assembly view, showing the intermeshing of the cutting structure of a prior art bit design.

FIG. 2 b is a schematic drawing illustrating a composite layout of the cutting structures of FIG. 2 a adjacent to the borehole bottom.

FIG. 3 is a perspective view of one embodiments of an earth-boring bit described herein.

FIG. 4 is a partial section view taken through one leg and one rolling cone cutter of the bit shown in FIG. 3.

FIG. 5 is a perspective view of one cutter of the bit of FIG. 3.

FIG. 6 is a perspective view of one embodiment of a cutter of an earth boring bit described herein.

FIG. 7 is a schematic drawing illustrating a composite layout of one embodiment of a cutting structures described herein adjacent to the borehole bottom.

FIG. 8 is a perspective view of one embodiment of a cutter of an earth boring bit described herein, where the cutter includes inserts having a weighted profile.

FIG. 9 is a perspective view of one embodiment of a cutter of an earth boring bit described herein, where the cutter includes inserts having a t-crested profile.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to drill bits having at least one roller cone having a limited number of cutting elements that contribute to the operative gage row of the drill bit. In another aspect, embodiments disclosed herein relate to drill bits having at least one roller cone having no cutting elements that contribute to the operative gage row of the drill bit.
Referring first to FIG. 3, one embodiment of an earth-boring bit 110 may include a central axis 111 and a bit body 112 having a threaded section 113 on its upper end for securing the bit 110 to the drill string (not shown). Bit 110 may have a predetermined gage diameter as defined by two or more rolling cone cutters rotatably mounted on bearing shafts that depend from the bit body 112. As illustrated, bit 110 has three rolling cone cutters 114, 115, 116. Bit body 112 may be composed of three sections or legs 119 (two are shown in FIG. 3) that are welded together to form bit body 112. Bit 110 may also include a plurality of nozzles 118 that are provided for directing drilling fluid toward the bottom of the borehole and around cutters 114, 115, 116. Bit 110 may further include lubricant reservoirs 117 that supply lubricant to the bearings of each of the cutters.
Referring now to FIG. 4, in conjunction with FIG. 3, each rolling cone cutter 114, 115, 116 may be rotatably mounted on a pin or journal 120, with an axis of rotation 122 orientated generally downwardly and inwardly toward the center of the bit. Drilling fluid may be pumped from the surface through fluid passage 124 where it may circulate through an internal passageway (not shown) to nozzles 118 (FIG. 3). Each rolling cone cutter 114, 115, 116 may be secured on pin 120 by ball bearings 126. In the embodiment shown, radial and axial thrust are absorbed by roller bearings 128, 130, thrust washer 131 and thrust plug 132; however, the drill bits described herein are not limited to use in a roller bearing bit, but may equally be applied in a friction bearing bit. In such instances, the cones 114, 115, 116 would be mounted on pins 120 without roller bearings 128, 130. In both roller bearing and friction bearing bits, lubricant may be supplied from reservoir 117 to the bearings by apparatus that is omitted from the figures for clarity. The lubricant is sealed and drilling fluid excluded by means of an annular seal 134. The borehole created by bit 110 includes sidewall 5, corner portion 6, and bottom 7, best shown in FIG. 4. Referring still to FIGS. 3 and 4, each cutter 114-116 includes a backface 140 and nose portion 142 spaced apart from backface 140. Rolling cone cutters 114-116 further include a frustoconical surface 144 that is adapted to retain cutter elements that scrape or ream the sidewalls of the borehole as cones 114-116 rotate about the borehole bottom. Frustoconical surface 144 will be referred to herein as the “heel” surface of cutters 114-116, 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 144 and nose 142 is a generally conical surface 146 adapted for supporting cutter elements that gouge or crush the borehole bottom 7 as the cone cutters rotate about the borehole. Conical surface 146 may include a plurality of generally frustoconical segments 148 generally referred to as “lands” which are employed to support and secure the cutter elements as described in more detail below. Grooves 149 may be formed in cone surface 146 between adjacent lands 148. Frustoconical heel surface 144 and conical surface 146 converge in a circumferential edge or shoulder 150. Although referred to herein as an “edge” or “shoulder,” it should be understood that shoulder 150 may be contoured, such as a radius, to various degrees such that shoulder 150 will define a contoured zone of convergence between frustoconical heel surface 144 and the conical surface 146.
In the embodiment shown in FIGS. 3 and 4, each cone 114-116 may include a plurality of wear resistant inserts 160, 170, 180 that may include cylindrical base portions that are secured by interference fit into mating sockets drilled into the lands of the cone cutter, and cutting portions connected to the base portions having cutting surfaces that extend from cone surfaces 144, 146 for cutting formation material. Particular embodiments of the drill bits disclosed herein may be understood with reference to one such cone 114; cones 115, 116 may be similarly, although not necessarily identically, configured.
Cone 114 may include a plurality of heel row inserts 160 that are secured in a circumferential row 160 a in the frustoconical heel surface 144. Cone 114 may further include a circumferential row 180 a of gage inserts 180 secured to cone 114 in locations along or near the circumferential shoulder 150. Cone 114 may optionally include a circumferential row 170 a of wall cutting inserts 170 along or near the circumferential shoulder 150. Wall cutting inserts 170 may be interspersed or staggered between gage inserts 180. Wall cutting inserts 170 may be located such that they do not contact the hole bottom during cutting, splitting the duty of hole wall cutting and hole bottom cutting between gage inserts 180 and wall cutting inserts 170. Cone 114 may further include a plurality of inner row inserts 181, 182, and 183 secured to cone surface 146 and arranged in spaced-apart inner rows 181 a, 182 a, and 183 a, respectively. Relieved areas or lands 178 (best shown in FIG. 5) may be formed about wall cutting elements 170 to assist in mounting inserts 170 when used.
As understood by those skilled in this art, heel inserts 160 generally function to scrape or ream the borehole sidewall 5 to maintain the borehole at full gage and prevent erosion and abrasion of heel surface 144. Cutter elements 181, 182 and 183 of inner rows 181 a, 182 a, and 183 a are employed primarily to gouge and remove formation material from the borehole bottom 7. Inner rows 180 a, 181 a, 182 a, and 183 a are intermeshed, arranged and spaced on cutter 114 so as not to interfere with the inner rows on each of the other cone cutters 115, 116.
As described above, the active gage cutting elements are referred to as gage inserts, and the passive gage cutting elements are described as the heel inserts. And, typically, the gage inserts actively engage in both the hole wall and hole bottom cutting action. Since the heel inserts cut the hole wall after it has already been trimmed by the gage inserts, their cutting action is generally passive in nature
Gage inserts, or inserts that contribute to the operative gage row of a drill bit, typically account for over 30 percent of the total number of inserts that contact hole bottom for a roller cone on a drill bit. The number of inserts may also be referred to as “count,” where gage count refers to the number of gage inserts, for example. In contrast to the gage count, the total surface area for the ring of material that the gage inserts must cut is approximately 10 to 15 percent of the borehole. Reducing (minimizing or eliminating) the total gage count on a roller cone cutter may increase the penetration depth of the inserts that contact hole bottom, and thus increase the rate of penetration of the bit.
Referring now to FIG. 6, one embodiment of a roller cone cutter 200 having a limited number of gage inserts is schematically illustrated. Cone 200 may include a circumferential row 202 a of gage cutting elements 202, circumferential rows 204 a, 206 a of inner row cutting elements 204, 206, and a circumferential row 208 a of nose inserts 208. During drilling, the gage cutting elements 202 and inner row cutting elements 204, 206 typically contact the hole bottom.
In some embodiments, gage cutting elements that contribute to the operative gage row of a drill bit may be 30 percent or less of the total count of cutting elements on at least one roller cone cutter of a multi-cone drill bit. In other embodiments, gage cutting elements contributing to the operative gage row may be 28 percent or less of the total count of cutting elements on at least one roller cone; 26 percent or less in other embodiments; 23 percent or less in other embodiments; and 20 percent or less, 15 percent or less, and 10 percent or less in yet other various embodiments.
In some embodiments, gage cutting elements that contribute to the operative gage row of a drill bit may be 30 percent or less of the total count of cutting elements that contact hole bottom on at least one roller cone cutter of a multi-cone drill bit. In other embodiments, gage cutting elements contributing to the operative gage row may be 28 percent or less of the total count of cutting elements that contact hole bottom; 26 percent or less in other embodiments; 23 percent or less in other embodiments; and 20 percent or less, 15 percent or less, and 10 percent or less in yet other various embodiments.
In some embodiments, a roller cone cutter may have no cutting elements contacting hole bottom contributing to the operative gage row of the drill bit. In embodiments where a roller cone does not include inserts contributing to the operative gage row, the gage inserts on the other roller cones of the drill bit may maintain the borehole diameter.
In other embodiments, gage cutting elements that contribute to the operative gage row of a drill bit may be less than 31 percent of the total count of cutting elements that contact the hole bottom and the transition region of the borehole on at least one roller cone cutter of a multi-cone drill bit. In other embodiments, gage cutting elements contributing to the operative gage row may be 28 percent or less of the total count of cutting elements that contact the hole bottom and the transition region of the borehole; 26 percent or less in other embodiments; 23 percent or less in other embodiments; and 20 percent or less, 15 percent or less, and 10 percent or less in yet other various embodiments. In other embodiments, a roller cone cutter may have no cutting elements contributing to the operative gage row of the drill bit that contact hole bottom or the transition region of the borehole on at least one roller cone cutter of a multi-cone drill bit.
Referring still to FIG. 6, exclusive of any heel inserts (not shown), roller cone cutter 200 may also include rows of off-bottom cutting elements, cutting elements that do not contact the hole bottom during drilling. As used herein, the term “off-bottom inserts” does not include heel inserts. For example, cone 200 may include a circumferential row 210 a of wall cutting elements 210. The wall cutting elements may be interspersed among the gage cutting elements 202, or staggered between the gage cutting elements 202, as illustrated. In some embodiments, row 202 a and row 210 a may cooperatively cut the borehole corner: row 202 a may cut the borehole bottom in the gage region of the borehole, and row 210 a may cut the borehole wall. In other embodiments, row 202 a may cut both the borehole bottom and the borehole wall, and row 210 a may operatively ream the wall of the borehole as previously cut by other operative gage cutting rows or elements located on another cone of the drill bit. In other embodiments, roller cone cutter 200 may also include inner rows 212 a, 214 a of reaming elements 212, 214 that do not contact the hole bottom during drilling.
In some embodiments, it may be desired to prevent premature contact of the off-bottom inserts with the hole bottom. For example, if the off-bottom inserts contacted hole bottom after minimal wear of cutter elements in adjacent rows, the additional cutting material contacting hole bottom could limit ROP. In some embodiments, the off-bottom elements may extend from the cone surface such that the outermost point on the cutting surface is at least 0.100 inches from contacting the bottom of the borehole prior to any wear on the bit. In other embodiments, the off-bottom elements may extend from the cone surface such that the outermost point on the cutting surface is at least 0.125 inches from contacting the bottom of the borehole prior to any wear on the bit; at least 0.150 inches in yet other embodiments.
In some embodiments, off-bottom cutting elements may be located between the heel row of cutting elements and the shoulder of the roller cone cutter, contacting and cutting along the transition region of the borehole and/or cutting the hole wall. For example, referring again to FIG. 4, off-bottom inserts, such as wall cutting elements 170, may be positioned in a circumferential row anywhere along the frustoconical surface 144 between heel row 160 and shoulder 150.
In some embodiments, a drill bit having a limited number of gage inserts or no gage inserts contributing to the operative gage row, as described above, may include off-gage inserts. Off-gage inserts, as mentioned above, are cutting elements or inserts that are positioned so that their cutting surfaces are close to gage, but are off-gage by a small distance. The off-gage inserts do not lie on the gage curve, but are spaced from the gage curve such that they do not contribute to the operative gage row of the drill bit.
As understood by those skilled in the art of designing bits, a “gage curve” is commonly employed as a design tool to ensure that a bit made in accordance to a particular design will cut the specified hole diameter. The gage curve is a complex mathematical formulation which, based upon the parameters of bit diameter, journal angle, and journal offset, takes all the points that will cut the specified hole size, as located in three dimensional space, and projects these points into a two dimensional plane which contains the journal centerline and is parallel to the bit axis. The use of the gage curve greatly simplifies the bit design process as it allows the gage cutting elements to be accurately located in two-dimensional space, which is easier to visualize. The gage curve, however, should not be confused with the cutting path of any individual cutting element as described previously.
As known to those skilled in the art, the American Petroleum Institute (API) sets standard tolerances for bit diameters, tolerances that vary depending on the size of the bit. The term “off gage,” as used herein to describe an inner row of cutter elements, refers to the difference in distance that cutter elements radially extend into the formation and not to whether or not cutter elements extend far enough to meet an API definition for being on gage. That is, for a given size bit made in accordance with embodiments disclosed herein, cutter elements may be “off gage,” but may still extend far enough into the formation such that the cutter elements would fall within the API tolerances for being on gage for that given bit size. Nevertheless, cutter elements would be “off gage” as that term is used herein because of their relationship to the cutting path taken by inserts cutting gage. For example, a circumferential row of cutter elements may form a distinct operative row overlapping, adjacent, or proximate the operative gage row. In other embodiments, cutter elements that are “off gage” (as herein defined) may also fall outside the API tolerances for the given bit diameter.
Referring now to FIG. 7, a bit having off-gage inserts and no gage element contributing to the operative gage row contacting hole bottom on at lest one of the cones (on a multi-cone drill bit) is illustrated. FIG. 7 shows the cutting profiles of the cutting elements for the multiple cones shown rotated into a single plane, again where a numeral relates to the cutting element row, and an alpha character relates to the particular cone for which the cutting element is located. As illustrated, cone C has an off gage row, but does not have a row of cutting elements contributing to the operative gage row. Inner row inserts 324 a and 324 b, as well as other inner row inserts, may be positioned on their respective cones to cut formation material along adjacent cutting paths. Gage inserts 326 a and 326 b are positioned such that their cutting surfaces cut to full gage diameter, their cut path falling on gage curve 328. The cutting surfaces of off-gage inserts 329 c are strategically positioned off-gage. Cutting elements 326 a, 326 b may cut against the bottom and sidewall of the borehole, whereas cutting elements 329 c cuts primarily against the borehole bottom. Cutting elements 326 a and 326 b thus form the operative gage row, whereas cutting element 329 c does not form part of the operative gage row.
Although illustrated where one cone has no gage inserts, two or three of the cones may have no gage inserts. In some embodiments, where a cone does not have gage inserts contacting hole bottom, the gage may include off-bottom inserts as described above. In other embodiments, the cone may include off-gage inserts and heel inserts. For embodiments where a cone does not have gage inserts contacting hole bottom, the gage inserts on the other roller cones may maintain the borehole diameter.
The range of off-gage distance D may range from 0.010 inches to 0.250 inches, depending upon bit diameter. In some embodiments, where the bit diameter is less than 10 inches, the off-gage distance D may range from 0.015 to 0.150 inches. In other embodiments, where the bit diameter is greater than 10 inches and less than 15 inches, the off-gage distance D may range from 0.025 to 0.200 inches. In yet other embodiments, where the bit diameter is greater than 15 inches, the off-gage distance D may range from 0.030 to 0.250 inches. In other embodiments, the off-gage distance D may be at least 0.020 inches; at least 0.050 inches in yet other embodiments.
The off-bottom and off-gage inserts described above may be of any desired geometry. For example, in one embodiment, as illustrated in FIG. 8, a circumferential row of cutting elements 402 a may have one or more cutting elements 402 having a weighted profile. Weighted profile inserts 402 may provide a thicker carbide (abrasive) layer 404 closer to the gage of the bit (closer to shoulder 406), where higher forces are encountered while drilling. The amount of abrasive provided may taper to a thinner abrasive layer 405 on the portion of the weighted profile insert furthest from shoulder 406. Heel row 408 a and inner row 410 are also illustrated, showing prospective locations for the various inserts.
In other embodiments, the geometry of off-bottom and off-gage inserts may also be t-crested. As illustrated in FIG. 9, a circumferential row of cutting elements 422 a may have one or more cutting elements 422 having a t-crested profile. T-crested inserts 422 may again provide a thicker carbide (abrasive) layer 404 on the portion of the insert that is closest to the gage of the bit (closer to shoulder 406), where higher forces are encountered while drilling. In other embodiments, the geometry of off-bottom and off-gage inserts may include shapes and geometries such as chisel, conical, bowed or flat slant crested, semi-round top, DOG BONE®, or any other possible shapes yielding a desired functionality, or combinations thereof. Slant crested inserts may be used such that the crest profile lies flat against the hole wall during penetration, reaming previously cut portions of the borehole. Depending on the application, an optimal geometry may be used to achieve maximum benefits (ROP, wear resistance, etc.). In some embodiments, a roller cone may include gage cutting elements having a T-crested geometry, where the extended or top portion of the T may provide a thicker abrasive layer at the corner of the borehole, where higher forces are encountered while drilling.
In some embodiments, a roller cone not having an operative gage row (actively cutting gage) may have a heel row spaced further up on the heel surface such that the heel row is generally aligned with the heel rows of the other cones. In this manner, the heel row does not overlap with the coverage of the off-gage row of the cone or the operative gage row of the other cones. The heel row thus functions as a reaming row, or an operative heel row, maintaining the gage previously cut by the gage inserts on the other cones. This concept is encompassed as illustrated in FIG. 7, where heel inserts 330 a, 330 b, and 330 c cut overlapping gage sections.
In some embodiments, the roller cone not having an operative gage row may have as many passive gage cutting elements as possible, optimizing the location of off-gage inserts and heel inserts on a cone without gage inserts.
The cutting elements used in embodiments of the drill bits described above may include tungsten carbide inserts, polycrystalline diamond compacts, milled steel teeth, or any other cutting elements of materials hard and strong enough to deform or cut through the formation. Furthermore, hardfacing may also be applied to the cutting elements and other portions of the bit to reduce wear on the bit and to increase the life of the bit. In some embodiments, the cutting elements may comprise abrasive particles such as synthetic diamond, CVD coated synthetic diamond, natural diamond, CBN, TSP, or combinations thereof. In certain embodiments, the following materials may be used to form the cutting elements: tungsten carbide (WC), tungsten (W), sintered tungsten carbide/cobalt (WC—Co) (spherical or crushed), cast tungsten carbide (spherical or crushed) or combinations of these materials (all with an appropriate binder phase such as cobalt, iron, nickel, or copper to facilitate bonding of particles and diamonds), and the like. In some embodiments, sintered tungsten carbide-cobalt alloy, macrocrystalline tungsten carbide, cast tungsten carbide, reclaimed natural or synthetic diamond grit, tungsten, silicon carbide, boron carbide, aluminum oxide, tool steel, and combinations thereof, may be used. In various embodiments, the coating or hardfacing may comprise titanium-based coatings, tungsten based coatings, nickel coatings, silicon coatings, various carbides, nitrides, and other materials known to those skilled in the art.
Drill bits designed in accordance with embodiments disclosed herein deviate from typical drill bits in at least two fashions. First, as described above, the drill bit does not place as many cutting inserts as possible on the gage of the bit. Typical bits are designed to have as many inserts on gage, where the highest drilling forces are encountered, in order to prolong bit life. As detailed above, limiting the number of gage inserts may allow larger inserts, use of harder inserts may be possible, or bit life may be offset by a higher ROP.
Second, drill bits designed in accordance with embodiments disclosed herein deviate from typical drill bits by not requiring that each roller cone cutter have a gage row. In contrast, bits disclosed herein may include a roller cone cutter having no cutting elements contributing to an operative gage row.
Bits designed according to embodiments disclosed herein may be designed to maximize rate of penetration and/or to maximize wear resistance. In other embodiments, bits disclosed herein may be designed to optimize a combination of these variables to promote the desired performance. As such, bits made in accordance with embodiments disclosed herein may be designed according to the following method.
An initial bit design may first be provided. The initial bit may be tested for performance characteristics, where the testing may include modeling and/or actual testing of the bit. The initial bit design may then be iteratively adjusted to maximize rate of penetration, maximize wear resistance, or optimize a combination thereof, where the bit design is bounded by the following limitations. In some embodiments, cutting elements contributing to an operative gage row of the drill bit on at least one roller cone cutter comprises 30 percent or less of the total count of cutting elements on the at least one roller cone cutter that contact hole bottom during drilling. In other embodiments, at least one roller cone cutter does not comprise cutting elements contributing to an operative gage row of the drill bit. In other embodiments, where the at least one roller cone cutter has a limited count of cutting elements contacting hole bottom or no cutting elements contributing to an operative gage row, the at least one roller cone cutter may include off-gage and/or off-bottom inserts as described above.
Embodiments of the drill bits described herein may be employed in steel tooth bits as well as TCI bits. Advantageously, the embodiments described herein provide for roller cone drill bits having reduced gage insert count on at least one roller cone. A reduced gage count may increase the penetration depth of the gage and inner row inserts, and may increase the rate of penetration of the bit. A reduced gage count may also allow for larger gage inserts, having a larger wear surface and increased impact resistance, which may also increase the rate of penetration of the bit. Increased gage diameter may also allow a harder, more wear resistant carbide grade to be used compared to a smaller insert.
Reduced gage count may also allow for a large hole wall cutting insert to be staggered between each gage insert. This may split the duty between hole wall cutting and bottom hole cutting. The overall carbide volume contacting the hole wall may also be increased. As the hole wall cutting insert is not in contact with the hole bottom, the carbide grade may be much more wear resistant, optimally maintaining gage.
Embodiments described herein also provide a roller cone drill bit having no active gage inserts contacting hole bottom on at least one roller cone. Eliminating gage inserts may allow independent count and location of off-gage inserts. Eliminating gage inserts on at least one roller cone may also allow for deeper penetration of the off-gage inserts, improving the rate of penetration of the bit.
The differences in formations encountered while drilling and the type of drilling (straight, directional, etc.) should also be taken into account when designing or choosing a bit. In certain drilling environments, such as directional drilling, it may be preferential to use a bit that may allow a faster rate of penetration, while bit wear may not be as critical. Some formations may require a high gage count, such as when drilling a hard formation. Although the bits described herein allow for improved penetration of gage and off-gage inserts, the bits described herein may perform better in soft to medium-hard formations, where a high gage count may not be needed. Additionally, the bits described herein may advantageously be used when drilling curved sections at a higher rate of penetration.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
All priority documents are herein fully incorporated by reference for all jurisdictions in which such incorporation is permitted. Further, all documents cited herein, including testing procedures, are herein fully incorporated by reference for all jurisdictions in which such incorporation is permitted to the extent such disclosure is consistent with the description of the present invention.

Claims

1. A drill bit to drill a borehole to a predetermined gage, the drill bit comprising:

a bit body having a bit axis;

at least two roller cones rotatably secured to the bit body, wherein the at least two roller cones have a generally conical surface and an adjacent heel surface, wherein the heel and conical surfaces form a circumferential shoulder therebetween; and

a plurality of cutting elements positioned on the at least two roller cones;

wherein cutting elements contributing to an operative gage row of the drill bit comprise less than 31 percent of a total of cutting elements of the drill bit that contact a bottom of the borehole.

2. The drill bit of claim 1, wherein cutting elements contributing to the operative gage row of the drill bit comprise less than 29 percent of the total of cutting elements of the drill bit that contact the bottom of the borehole.

3. (canceled)

4. The drill bit of claim 1, wherein at least one roller cone comprises at least one circumferential row of off-bottom cutting elements positioned on at least one of the heel surface, the conical surface, and the circumferential shoulder.

5. The drill bit of claim 4, wherein the off-bottom cutting elements are at least 0.100 inches from contacting the bottom of the borehole prior to any wear on the bit.

6. (canceled)

7. The drill bit of claim 4, wherein the off-bottom cutting elements are smaller than the gage inserts contacting the bottom of the borehole.

8. (canceled)

9. The drill bit of claim 1, wherein at least one roller cone comprises at least one circumferential row of off-bottom cutting elements, wherein at least one cutting element of the circumferential row of off-bottom cutting elements has a geometry selected from the group consisting of weighted profiles, t-crests, bowed slant crests, flat slant crests, conical elements, and semi-round top elements.

10. The drill bit of claim 1, wherein at least one roller cone comprises a circumferential row of off-gage cutting elements positioned on a portion of the conical surface and that contacts the bottom of the borehole.

11. The drill bit of claim 10, wherein the off gage cutting elements are offset from a gage curve a distance of at least 0.020 inches.

12. (canceled)

13. The drill bit of claim 10, wherein at least one cutting element of the circumferential row of off-gage cutting elements has a geometry selected from the group consisting of weighted profiles, t-crests, bowed slant crests, flat slant crests, conical elements, and semi-round top elements.

14. (canceled)

15. The drill bit of claim 1, wherein at least one roller cone comprises no cutting elements contributing to the operative gage row of the drill bit.

16. The drill bit of claim 15, wherein the at least one roller cone comprises a circumferential row of off gage cutting elements positioned on a portion of the conical surface and that contact the bottom of the borehole.

17. The drill bit of claim 16, wherein the at least one roller cone comprises at least one circumferential row of off-bottom cutting elements positioned on at teast one of the heel surface, the conical surface, and the circumferential shoulder.

18. A drill bit to drill a borehole at a predetermined gage, the drill bit comprising:

a bit body having a bit axis;

at least two roller cones rotatably secured to the bit body, the at least two roller cones having a generally conical surface and an adjacent heel surface, wherein the heel and conical surfaces form a circumferential shoulder therebetween; and

a plurality of cutting elements positioned on the at least two roller cones;

wherein at least one roller cone comprises no cutting elements contributing to an operative gage row of the drill bit.

19. The drill bit of claim 18, wherein the at least one roller cone comprises at least one circumferential row of off-bottom cutting elements positioned on at least one of the group consisting of the heel surface, the conical surface, and the circumferential shoulder.

20. (canceled)

21. The drill bit of claim 18, wherein the at least one roller cone comprises a circumferential row of off-gage cutting elements positioned on a portion of the conical surface and that contact a bottom of the borehole.

22. (canceled)

23. The drill bit of claim 21, wherein the off-gage cutting elements are offset from a gage curve a distance of at least 0.020 inches.

24. (canceled)

25. The drill bit of claim 21, wherein the at least one roller cone comprises at least one circumferential row of off-bottom cutting elements positioned on at least one of the group consisting of the heel surface, the conical surface, and the circumferential shoulder.

26. The drill bit of claim 25, wherein the off-bottom cutting elements comprise a harder material than the cuffing elements of the operative gage row of the drill bit.

27. The drill bit of claim 25, wherein the off-gage cutting elements comprise a softer material than the cutting elements of the operative gage row of the drill bit.

28. A method to design a roller cone drill bit, the method comprising:

designing an initial bit, wherein the initial bit comprises:

a bit body having a bit axis;

at least two roller cones rotatably secured to the bit body, wherein the at least two roller cones comprises a generally conical surface and an adjacent heel surface, wherein the heel and conical surfaces form a circumferential shoulder therebetween; and

a plurality of cutting elements positioned on the at least two roller cones;

testing the initial bit; and

adjusting the bit design to optimize at least one of rate of penetration and wear resistance;

wherein cutting elements contributing to an operative gage row of the adjusted bit design comprise less than 31 percent of a total of cutting elements on the adjusted bit design that contact a bottom of a borehole.

29. The method of claim 28, wherein at least one roller cone comprises at least one circumferential row of off-bottom cutting elements positioned on at least one selected from the group consisting of the heel surface, the conical surface, and the circumferential shoulder, wherein the off-bottom cutting elements are at least 0.100 inches from contacting the bottom of the borehole.

30. The method of claim 28, wherein at least one roller cone comprises no cutting elements contributing to the operative gage row of the drill bit, wherein the at least one roller cone comprises a circumferential row of off-gage cutting elements positioned on a portion of the conical surface and that contact the bottom of the borehole, and wherein the off-gage cutting elements are offset from a gage curve a distance of at least 0.020 inches.

31. A roller cone drill bit comprising a cutting element, wherein the cutting element terminates in a T-shaped crest.

32. The roller cone drill bit of claim 31, wherein the T-crest contacts a gage of a borehole during drilling.

33. The roller cone drill bit of claim 31, wherein an extended portion of the T-crest cuts at gage.