WO1997038205A1 - Trepan a cones roulants dans lequel le positionnement et les materiaux constitutifs de l'element de coupe sont perfectionnes pour optimiser la capacite de coupe angulaire dans le trou de forage - Google Patents

Trepan a cones roulants dans lequel le positionnement et les materiaux constitutifs de l'element de coupe sont perfectionnes pour optimiser la capacite de coupe angulaire dans le trou de forage Download PDF

Info

Publication number
WO1997038205A1
WO1997038205A1 PCT/US1997/005948 US9705948W WO9738205A1 WO 1997038205 A1 WO1997038205 A1 WO 1997038205A1 US 9705948 W US9705948 W US 9705948W WO 9738205 A1 WO9738205 A1 WO 9738205A1
Authority
WO
WIPO (PCT)
Prior art keywords
gage
bit
cutter elements
cutter
inserts
Prior art date
Application number
PCT/US1997/005948
Other languages
English (en)
Inventor
Gary Ray Portwood
Gary Edward Garcia
James Carl Minikus
Per Ivar Nese
Dennis Cisneros
Chris Edward Cawthorne
Original Assignee
Smith International, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US08/630,517 external-priority patent/US6390210B1/en
Application filed by Smith International, Inc. filed Critical Smith International, Inc.
Priority to CA002228156A priority Critical patent/CA2228156C/fr
Priority to AU27259/97A priority patent/AU2725997A/en
Priority to GB9802230A priority patent/GB2319549B/en
Publication of WO1997038205A1 publication Critical patent/WO1997038205A1/fr
Priority to SE9800295A priority patent/SE9800295L/

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E21B10/50—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of roller type
    • E21B10/52—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of roller type with chisel- or button-type inserts
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/08—Roller bits
    • E21B10/16—Roller bits characterised by tooth form or arrangement

Definitions

  • the invention relates generally to earth-boring bits used to drill a borehole for the o ultimate recovery of oil, gas or minerals. More particularly, the invention relates to rolling cone rock bits and to an improved cutting structure for such bits. Still more particularly, the invention relates to enhancements in cutter element placement and materials to increase bit durability and rate of penetration and enhance the bit's ability to maintain gage.
  • 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 o 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 5 may be described as generally conical in shape and are therefore sometimes referred to as rolling cones.
  • 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 as it flows up and out of the borehole. 0
  • 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, while those having teeth formed from the cone material are known as “steel tooth bits.”
  • the cutting surfaces of inserts are, in some instances, coated with a very hard and abrasion resistant coating such as polycrystaline diamond (PCD).
  • PCD polycrystaline diamond
  • the teeth of steel tooth bits are many times coated with a hard metal layer generally referred to as hardfacing. In each instance, the cutter elements on the rotating cutters breakup the formation to form new borehole by a combination of gouging and scraping or chipping and crushing.
  • 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.
  • ROP rate of penetration
  • the form and positioning of the cutter elements (both steel teeth and tungsten carbide 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 undergage borehole, the new bit will be required to ream the undergage hole as it progresses toward the bottom of the borehole.
  • 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.
  • conventional rolling cone bits typically 5 employ a heel row of hard metal inserts on the heel surface of the rolling cone cutters.
  • the heel surface 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 in the heel surface contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall.
  • the heel inserts function primarily to maintain a 0 constant gage and secondarily to prevent the erosion and abrasion of the heel surface of the rolling cone. Excessive wear of the heel inserts leads to an undergage 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.
  • conventional bits typically include a gage row of 5 cutter elements mounted adjacent to the heel surface but orientated and sized in such a manner so as to cut the corner of the borehole. In this orientation, the gage cutter elements generally are required to cut both the borehole bottom and sidewall. The lower surface of the gage row insert engages the borehole bottom while the radially outermost surface scrapes the sidewall of the borehole.
  • Conventional bits also include a number of additional rows of cutter elements that are o located on the cones 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.
  • the cutting action operating on the borehole bottom is typically a crushing or gouging action
  • the cutting action operating on the sidewall is a scraping or reaming action.
  • 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.
  • cemented tungsten carbide cannot optimally o 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.
  • PCD grades differ in hardness and toughness and, although PCD coatings are extremely resistant to wear, they are particularly vulnerable to damage caused by impact loading as typically encountered in bottom hole cutting duty.
  • 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 5 aggressively shaped so as to accommodate the scraping action on the sidewall of the borehole.
  • a drill bit and cutting structure that is more durable than those conventionally known and that will yield greater ROP's and an increase in footage drilled while maintaining a full gage borehole.
  • the bit and cutting structure would not require the compromises in cutter element toughness, wear resistance and o hardness which have plagued conventional bits and thereby limited durability and ROP.
  • the present invention provides an earth boring bit having enhancements in cutter element placement and materials for optimizing borehole corner duty.
  • Such enhancements provide the potential for increased bit durability, ROP and footage drilled (at full gage) as 5 compared with similar bits of conventional technology.
  • the bit includes a bit body and one or more rolling cone cutters rotatably mounted on the bit body.
  • the rolling cone cutter includes a generally conical surface, an adjacent heel surface and, preferably, a circumferential shoulder therebetween.
  • the cone cutter also includes groups of first and second cutter elements that are mounted in separate, o radially-spaced, circumferential rows.
  • the first cutter elements have cutting surfaces of a first nominal hardness and are positioned on the cone cutter such that their cutting surfaces cut along a first cutting path having a most radially distant point P, as measured from the bit axis.
  • the second cutter elements have cutting surfaces of a different nominal hardness and are positioned on the cone cutter so that 5 their cutting surfaces cut along a second cutting path having a most radially distant point P 2 as measured from the bit axis.
  • the first and second rows are positioned such that the radial distance from the bit axis to P, exceeds the radial distance from the bit axis to P 2 by a distance D that is selected such that the first and second cutter elements cooperatively cut the comer of the borehole, and such that the first cutter elements primarily cut the borehole sidewall and the o second cutter elements primarily cut the borehole bottom.
  • the cutter elements may be hard metal inserts having cutting portions attached to generally cylindrical base portions which are mounted in the cone cutter, or may comprise steel teeth that are milled, cast, or otherwise integrally formed from the cone material.
  • the distance D may be the same for all the cone cutters on the bit, or may differ among the various cone cutters in order to achieve a desired balance of durability and wear characteristics for the cone cutters.
  • the first cutter elements are gage cutter elements that cut to full gage, while the second cutter elements are mounted in a first inner row of off-gage cutter elements positioned so that their cutting surfaces are close to gage, but are off-gage by the distance D.
  • gage row cutter elements may be mounted along or near the circumferential shoulder, either on the heel surface or on the adjacent conical surface.
  • the cutting surfaces of both the first and second cutter elements are off-gage, with the second cutter elements having cutting surfaces that are further off-gage than the first cutter elements.
  • the cutting surfaces of these elements may be optimized by use of material enhancements to further improve bit ROP, durability and footage drilled at full gage.
  • the materials for the cutting surfaces of the first and second cutter elements will be varied and optimized depending primarily upon the characteristics of the formation to be drilled. In most applications, the cutting surfaces of the first cutter elements will be harder than those of the second cutter elements due to the fact that the first cutter elements will be exposed to more sidewall cutting duty and thus will typically be subject to more wear and abrasion than the second cutter elements. Similarly, in most applications, the cutting surfaces of the second cutter elements will be tougher and more impact resistant than those of the first cutter elements.
  • the hardness and toughness of the cutter elements that are in the rows that cooperate to cut the borehole corner may be varied by employing differing formulations of cemented tungsten carbide, or by applying a coating of super abrasives (such as PCD or PCBN) having the appropriate hardness, toughness and thermal stability for the particular application.
  • a preferred embodiment of the invention includes gage row inserts made from cemented tungsten carbide having a hardness greater than or equal to 88.8 HRa, and most preferably at least 90.8 HRa.
  • a preferred embodiment of the invention includes off-gage cutter elements of cemented tungsten carbide having a hardness not greater than 88.8 HRa, and preferably not greater than 87.4 HRa.
  • a coating of PCD and PCBN or other super abrasive may be applied to vary the hardness and toughness of the first and second cutter elements as required or desirable for various formations and drilling techniques.
  • the invention includes cutter elements having a PCD coating having an average grain size not greater than 25 ?m.
  • Such PCD coatings have particular application in gage row elements.
  • the invention includes cutter elements with a PCD coating having an average grain size greater than 25 ?m.
  • the present invention comprises a combination of features and advantages which enable it to substantially advance the drill bit art.
  • enhanced ROP, bit durability and footage drilled at full gage may be achieved.
  • this placement of the cutter elements permits the cutting function of a cutter element in each of the different rows to be enhanced further through the selective use of materials that are best suited for the particular duty the cutter element will experience.
  • Such material enhancements provide opportunity for still greater improvement in cutter element life and thus bit durability and ROP potential.
  • Figure 1 is a perspective view of an earth-boring bit made in accordance with the principles of the present invention
  • Figure 2 is a partial section view taken through one leg and one rolling cone cutter of the bit shown in Figure 1 ;
  • Figure 3 is a perspective view of one cutter of the bit of Figure 1 ;
  • Figure 4 is a enlarged view, partially in cross-section, of a portion of the cutting structure of the cutter shown in Figures 2 and 3, and showing the cutting paths traced by certain of the cutter elements mounted on that cutter;
  • Figure 5 is a view similar to Figure 4 showing an alternative embodiment of the invention.
  • Figure 6 is a partial cross sectional view of a set of prior art rolling cone cutters (shown in rotated profile) and the cutter elements attached thereto;
  • Figure 7 is an enlarged cross sectional view of a portion of the cutting structure of the prior art cutter shown in Figure 6 and showing the cutting paths traced by certain of the cutter elements;
  • Figure 8 is a partial elevational view of a rolling cone cutter showing still another alternative embodiment of the invention.
  • Figure 9 is a cross sectional view of a portion of rolling cone cutter showing another alternative embodiment of the invention.
  • Figure 10 is a perspective view of a steel tooth cutter showing an alternative embodiment of the present invention.
  • Figure 1 1 is an enlarged cross-sectional view similar to Figure 4, showing a portion of the cutting structure of the steel tooth cutter shown in Figure 10;
  • Figure 12 is a view similar to Figure 4 showing another alternative embodiment of the invention.
  • Figure 13 is a view similar to Figure 4 showing another alternative embodiment of the invention.
  • an earth-boring bit 10 made in accordance with the present invention includes a central axis 11 and a bit body 12 having a threaded section 13 on its upper end for securing the bit to the drill string (not shown).
  • Bit 10 has a predetermined gage diameter as defined by three rolling cone cutters 14, 15, 16 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 Figure 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 cutters 14-16.
  • Bit 10 further includes lubricant reservoirs 17 that supply lubricant to the bearings of each of the cutters.
  • each cutter 14-16 is rotatably mounted on a pin or journal 20, with an axis of rotation 22 orientated generally downwardly and inwardly toward the center of the bit. Drilling fluid is pumped from the surface through fluid passage 24 where it is circulated through an intemal passageway (not shown) to nozzles 18 ( Figure 1). Each cutter 14-16 is typically secured on pin 20 by ball bearings 26.
  • each cutter 14-16 includes a backface 40 and nose portion 42 spaced apart from backface 40.
  • Cutters 14-16 further include a frustoconical surface 44 that is adapted to retain cutter elements that scrape or ream the sidewalls of the borehole as cutters 14-16 rotate about the borehole bottom.
  • Frustoconical surface 44 will be referred to herein as the "heel” surface of cutters 14-16, 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 the cone cutters rotate about the borehole.
  • Conical surface 46 typically includes a plurality of generally frustoconical segments 48 generally referred to as "lands" which are employed to support and secure the cutter elements as described in more detail below. Grooves 49 are formed in cone surface 46 between adjacent lands 48. 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 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.
  • each cutter 14-16 includes a plurality of wear resistant inserts 60, 70, 80 that include generally cylindrical base portions that are secured by interference fit into mating sockets drilled into the lands of the cone cutter, and cutting portions that are connected to the base portions and that extend beyond the surface of the cone cutter.
  • the cutting portion includes a cutting surface that extends from cone surfaces 44, 46 for cutting formation material.
  • Cone cutter 14 includes a plurality of heel row inserts 60 that are secured in a circumferential row 60a in the frustoconical heel surface 44.
  • Cutter 14 further includes a circumferential row 70a of gage inserts 70 secured to cutter 14 in locations along or near the circumferential shoulder 50.
  • Cutter 14 further includes a plurality of inner row inserts 80, 81, 82, 83 secured to cone surface 46 and arranged in spaced-apart inner rows 80a, 81a, 82a, 83a, respectively.
  • Relieved areas or lands 78 are formed about gage cutter elements 70 to assist in mounting inserts 70.
  • heel inserts 60 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 44.
  • Cutter elements 81, 82 and 83 of inner rows 81a, 82a, 83a are employed primarily to gouge and remove formation material from the borehole bottom 7.
  • Inner rows 80a, 81a, 82a, 83a are arranged and spaced on cutter 14 so as not to interfere with the inner rows on each of the other cone cutters 15, 16.
  • gage cutter elements 70 are a position along circumferential shoulder 50.
  • This mounting position enhances bit 10's ability to divide comer cutter duty among inserts 70 and 80 as described more fully below.
  • This position also enhances the drilling fluid's ability to clean the inserts and to wash the formation chips and cuttings past heel surface 44 towards the top of the borehole.
  • gage inserts 70 are positioned adjacent to circumferential shoulder 50, on either conical surface 46 ( Figure 9) or on heel surface 44 ( Figure 5) .
  • gage cutter elements 70 For bits having gage cutter elements 70 positioned adjacent to shoulder 50, the precise distance of gage cutter elements 70 to shoulder 50 will generally vary with bit size: the larger the bit, the larger the distance can be between shoulder 50 and cutter element 70 while still providing the desired division of comer cutting duty between cutter elements 70 and 80.
  • the benefits of the invention diminish, however, if gage cutter elements are positioned too far from shoulder 50, particularly when placed on heel surface 44.
  • the distance between shoulder 50 to cutter elements 70 is measured from shoulder 50 to the nearest edge of the gage cutter element 70, the distance represented by "d" as shown in Figures 9 & 5.
  • the term "adjacent" shall mean on shoulder 50 or on either surface 46 or 44 within the ranges set forth in the following table:
  • FIG. 2 The spacing between heel inserts 60, gage inserts 70 and inner row inserts 80-83, is best shown in Figure 2 which also depicts the borehole formed by bit 10 as it progresses through the formation material.
  • Figure 2 also shows the cutting profiles of inserts 60, 70, 80 as viewed in rotated profile, that is with the cutting profiles of the cutter elements shown rotated into a single plane.
  • the rotated cutting profiles and cutting position of inner row inserts 81?, 82?, inserts that are mounted and positioned on cones 15, 16 to cut formation material between inserts 81, 82 of cone cutter 14, are also shown in phantom.
  • Gage inserts 70 are positioned such that their cutting surfaces cut to full gage diameter, while the cutting surfaces of off-gage inserts 80 are strategically positioned off-gage. Due to this positioning of the cutting surfaces of gage inserts
  • gage inserts 70 cut primarily against sidewall 5 while inserts 80 cut primarily against the borehole bottom 7.
  • the cutting paths taken by heel row inserts 60, gage row inserts 70 and the first inner row inserts 80 are shown in more detail in Figure 4.
  • each cutter element 60, 70, 80 will cut formation material as cone 14 is rotated about its axis 22.
  • the cutting paths traced by cutters 60, 70, 80 may be depicted as a series of curves. In particular: heel row inserts 60 will cut along curve 66; gage row inserts 70 will cut along curve 76; and cutter elements 80 of first inner row 80a will cut along curve 86.
  • curve 76 traced by gage insert 70 extends further 5 from the bit axis 11 ( Figure 2) than curve 86 traced by first inner row cutter element 80.
  • the most radially distant point on curve 76 as measured from bit axis 11 is identified as P,.
  • the most radially distant point on curve 86 is denoted by P 2 .
  • curves 76, 86 show, as bit 10 progresses through the formation material to form the borehole, the first inner row cutter elements 80 do not extend radially as far into the formation as gage inserts 70.
  • inserts 80 of first inner row 80a extend to a position that is
  • gage curve is commonly employed as a design tool to ensure that a bit made in accordance to a particular design will cut 5 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 o cutting elements to be accurately located in two dimensional space which is easier to visualize.
  • gage curve should not be confused with the cutting path of any individual cutting element as described previously.
  • gage curve 90 of bit 10 is depicted in Figure 4.
  • the cutting surface of off-gage cutter 80 is spaced radially inward from gage curve 90 by distance D', D' 5 being the shortest distance between gage curve 90 and the cutting surface of off-gage cutter element 80.
  • D' the first inner row of cutter elements 80 may be described as "off-gage,” both with respect to the gage curve 90 and with respect to the cutting path 76 of gage cutter elements 70.
  • off gage refers to the difference in distance that cutter elements 70 and 80 radially extend into the formation (as described above) and not to whether or not cutter elements 80 extend far enough to meet an API definition for being on gage. That is, for a given size bit made in accordance with the present invention, cutter elements 80 of a first inner row 80a may be "off gage" with respect to gage cutter elements 70, but may still 5 extend far enough into the formation such that cutter elements 80 of inner row 80a would fall within the API tolerances for being on gage for that given bit size.
  • cutter elements 80 would be “off gage” as that term is used herein because of their relationship to the cutting path taken by gage inserts 70. In more preferred embodiments of the invention, however, cutter elements 80 that are “off gage” (as herein defined) will also fall outside the API o tolerances for the given bit diameter.
  • cutter elements 70 and 80 cooperatively operate to cut the comer 6 of the borehole, while inner row inserts 81, 82, 83 attack the borehole bottom. Meanwhile, heel row inserts 60 scrape or ream the sidewalls of the borehole, but perform no comer cutting duty because of the relatively large distance that heel s row inserts 60 are separated from gage row inserts 70.
  • Cutter elements 70 and 80 may be referred to as primary cutting structures in that they work in unison or concert to simultaneously cut the borehole comer, cutter elements 70 and 80 each engaging the formation material and performing their intended cutting function immediately upon the initiation of drilling by bit 10. Cutter elements 70, 80 are thus to be distinguished from what are sometimes referred to as o "secondary" cutting structures which engage formation material only after other cutter elements have become worn.
  • gage row cutter elements 70 may be positioned on heel surface 44 according to the invention, such an arrangement being shown in Figure 5 where the cutting paths traced by cutter elements 60, 70, 80 are depicted as previously described with 5 reference to Figure 4. Like the arrangement shown in Figure 4, the cutter elements 80 extend to a position that is off-gage by a distance D, and the borehole comer cutting duty is divided among the gage cutter elements 70 and inner row cutter elements 80. Although in this embodiment gage row cutter elements 70 are located on the heel surface, heel row inserts 60 are still too far away to assist in the comer cutting duty. o Referring to Figures 6 and 7, a typical prior art bit 110 is shown to have gage row inserts
  • gage row inserts 100 are required to cut the borehole co er without any significant assistance from any other cutter 5 elements as best shown in Figure 7. This is because the first inner row inserts 103 are mounted a substantial distance from gage inserts 100 and thus are too far away to be able to assist in cutting the borehole comer.
  • gage inserts 100 are too distant from gage cutter 100 to assist in cutting the borehole comer. Accordingly, gage inserts 100 traditionally have had to cut both the borehole sidewall 5 along cutting surface 106, as well as cut the borehole bottom 7 o along the cutting surface shown generally at 108. Because gage inserts 100 have typically been required to perform both cutting functions, a compromise in the toughness, wear resistance, shape and other properties of gage inserts 100 has been required.
  • the failure mode of cutter elements usually manifests itself as either breakage, wear, or mechanical or thermal fatigue. Wear and thermal fatigue are typically results of abrasion as the s elements act against the formation material. Breakage, including chipping of the cutter element, typically results from impact loads, although thermal and mechanical fatigue of the cutter element can also initiate breakage.
  • gage inserts 100 were sometimes subject to rapid wear and thermal fatigue due to the compromise in wear resistance that was made in order to allow the gage inserts 100 to simultaneously withstand the impact loading typically present in bottom hole cutting.
  • gage row 70 will be required to perform more bottom hole cutting than would be preferred, subjecting it to more impact loading than if it were protected by a closely-positioned but off- gage cutter element 80.
  • inner row cutter element 80 is positioned too close to the gage curve, then it would be subjected to loading similar to that experienced by gage inserts 70, and would experience more side hole cutting and thus more abrasion and wear than would be otherwise prefe ⁇ ed.
  • gage inserts 70 and inner row inserts 80 a more aggressive cutting structure may be employed by having a comparatively fewer number of first inner row cutter elements 80 as compared to the number of gage row inserts 100 of the prior art bit shown in Figure 6.
  • gage inserts 70 cut the sidewall of the borehole and are positioned and configured to maintain a full gage borehole
  • first inner row elements 80 that do not have to function to cut sidewall or maintain gage, may be fewer in number and may be further spaced so as to better concentrate the forces applied to the formation. Concentrating such forces tends to increase ROP in certain formations.
  • chordal penetration being the maximum penetration of an insert into the formation before adjacent inserts in the same row contact the hole bottom.
  • chordal penetration is the maximum penetration of an insert into the formation before adjacent inserts in the same row contact the hole bottom.
  • Increasing the chordal penetration allows the cutter elements to penetrate deeper into the formation, thus again tending to improve ROP.
  • Increasing the pitch between inner row inserts 80 has the additional advantages that it provides greater space between the inserts which results in improved cleaning of the inserts and enhances cutting removal from hole bottom by the drilling fluid.
  • the present invention may also be employed to increase durability of bit 10 given that inner row cutter elements 80 are positioned off-gage where they are not subjected to the load from the sidewall that is instead assumed by the gage row inserts.
  • inner row inserts 80 are not as susceptible to wear and thermal fatigue as they would be if positioned on gage. Further, compared to conventional gage row inserts 100 in bits such as that shown in Figure 6, inner row inserts 80 of the present invention are called upon to do substantially less work in cutting the borehole sidewall.
  • the work performed by a cutter element is proportional to the force applied by the cutter element to the formation multiplied by the distance that the cutter element travels while in contact with the formation, such distance generally referred to as the cutter element's "strike distance.”
  • the effective or unassisted strike distance of inserts 80 is lessened due to the fact that cutter elements 70 will assist in cutting the borehole wall and thus will lessen the distance that insert 80 must cut unassisted. This results in less wear, thermal fatigue and breakage for inserts 80 relative to that experienced by conventional gage inserts 100 under the same conditions.
  • the distance referred to as the "unassisted strike distance” is identified in Figures 4 and 5 by the reference “USD.”
  • USD The distance referred to as the "unassisted strike distance”
  • the closer that inner row cutter elements 80 are off-gage the shorter the unassisted strike distance is for cutter elements 80.
  • cutter elements 80 are required to do less work against the borehole sidewall, such work instead being performed by gage row inserts 70. This can be confirmed by comparing the relatively long unassisted strike distance USD for gage inserts 100 in the prior art bit of Figure 7 to the unassisted strike distance USD of the present invention ( Figures 4 and 5 for example).
  • gage row cutter elements 70 be circumferentially positioned at locations between each of the inner row elements 80. With first inner row cutter elements 80 moved off-gage where they are not responsible for substantial sidewall cutting, the pitch between inserts 80 may be increased as previously described in order to increase ROP. Additionally, with increased spacing between adjacent cutter elements 80 in row 80a, two or more gage inserts 70 may be disposed between adjacent inserts 80 as shown in Figure 8. This configuration further enhances the durability of bit 10 by providing a greater number of gage cutter elements 70 adjacent to circumferential shoulder 50.
  • gage inserts 70 and off-gage inserts 80 An additional advantage of dividing the borehole cutting function between gage inserts 70 and off-gage inserts 80 is the fact that it allows much smaller diameter cutter elements to be placed on gage than conventionally employed for a given size bit. With a smaller diameter, a greater number of inserts 70 may be placed around the cutter 14 to maintain gage, and because gage inserts 70 are not required to perform substantial bottom hole cutting, the increase in number of gage inserts 70 will not diminish or hinder ROP, but will only enhance bit 10's ability to maintain full gage. At the same time, the invention allows relatively large diameter or large extension inserts to be employed as off-gage inserts 80 as is desirable for gouging and breaking up formation on the hole bottom.
  • the ratio of the diameter of gage inserts 70 to the diameter of first inner row inserts 80 is preferably not greater than 0.75.
  • a still more preferred ratio of these diameters is within the range of 0.5 to 0.725.
  • the invention preferably positions gage inserts 70 and inner row inserts 80 such that the ratio of distance D that inserts 80 are off-gage to the diameter of gage insert 70 should be less than 0.3, and even more preferably less than 0.2. It is desirable in certain applications that this ratio be within the range of 0.05 to 0.15. 5 Positioning inserts 70 and 80 in the manner previously described means that the cutting profiles of the inserts 70, 80, in many embodiments, will partially overlap each other when viewed in rotated profile as is best shown in Figures 4 or 9.
  • the extent of overlap is a function of the diameters of the inserts 70, 80, the off-gage distance D of insert 80, and the inserts' orientation, shape and extension from cutter 14.
  • the distance of o overlap 91 is defined as the distance between parallel planes P 3 and P 4 shown in Figure 9.
  • Plane P 3 is a plane that is parallel to the axis 74 of gage insert 70 and that passes through the point of intersection between the cylindrical base portion of the inner row insert 80 and the land 78 of gage insert 70.
  • P 4 is a plane that is parallel to P 3 and that coincides with the edge of the cylindrical base portion of gage row insert 70 that is closest to bit axis as shown in Figure 9. s This definition also applies to the embodiment shown in Figure 4.
  • the o ratio of the distance of overlap to the diameter of the gage inserts 70 is preferably greater than 0.40.
  • LADC Intemational Association of Drilling Contractors
  • an LADC classification range of between “41-62” should be understood to mean bits having an LADC classification within series 4 (types 1-4), series 5 (types 1-4) or series 6 (type 1 or type 2) or within any later adopted LADC classification that describes TCI bits that are intended for use in formations softer than those for which bits of current series 6 (type 1 or 2) are intended.
  • cutter elements 80 extend further from cone 14 than elements 70 (relative to cone axis 22). This is especially true in bits designated to drill in soft through some medium hard formations, such as in steel tooth bits or in TCI insert bits having the IADC formation classifications of between 41-62.
  • This difference in extensions may be described as a step distance 92, the "step distance" being the distance between planes P 5 o and P 6 measured perpendicularly to cone axis 22 as shown in Figure 9.
  • Plane P 5 is a plane that is parallel to cone axis 22 and that intersects the radially outermost point on the cutting surface of cutter element 70.
  • Plane P 6 is a plane that is parallel to cone axis 22 and that intersects the radially outermost point on the cutting surface of cutter element 80.
  • the ratio of the step distance to the extension of gage 5 row cutter elements 70 above cone 14 should be not less than 0.8 for steel tooth bits and for TCI formation insert bits having LADC classification range of between 41-62. More preferably, this ratio should be greater than 1.0.
  • first inner row cutter elements 80 be mounted off-gage within the ranges specified in Table 2.
  • the off-gage distance D will be selected to be the same for all the cone cutters on the bit. This is a departure from prior art multi-cone bits which generally have required that the off- gage distance of the first inner row of cutter elements be different for some of the cone cutters on the bit.
  • the number of gage cutter elements 70 may be the same for each cone cutter and, simultaneously, 5 all the cone cutters may have the same number of off-gage cutter elements 80.
  • cutter elements 80 on cutter 14 are disposed 0.040 inches off-gage, while cutter elements 80 on cones 15 and 16 are positioned 0.060 inches o off-gage.
  • Varying among the cone cutters 14-16 the distance D that first inner row cutter elements 80 are off-gage allows a balancing of durability and wear characteristics for all the cones on the bit. More specifically, it is typically desirable to build a rolling cone bit in which the number of gage row and inner row inserts vary from cone to cone. In such instances, the cone having the fewest cutter elements cutting the sidewall or borehole comer will experience higher wear or impact loading compared to the other rolling cones which include a larger number of cutter 5 elements. If the off-gage distance D was constant for all the cones on the bit, there would be no means to prevent the cutter elements on the cone having the fewest cutter elements from wearing or breaking prematurely relative to those on the other cones.
  • gage cutter elements 70 and first inner row cutter elements 80 By dividing the borehole comer cutting duty between gage cutter elements 70 and first inner row cutter elements 80, further and significant additional enhancements in bit durability and ROP are made possible.
  • the materials that are used to form elements 70, 80 o can be optimized to correspond to the demands of the particular application for which each element is intended.
  • the elements can be selectively and variously coated with super abrasives, including polycrystalline diamond (“PCD”) or cubic boron nitride (“PCBN”) to further optimize their performance.
  • PCD polycrystalline diamond
  • PCBN cubic boron nitride
  • the gage cutter element of a conventional bit is subjected to high wear loads from the contact with borehole wall, as well as high stresses due to bending and impact loads from contact with the borehole bottom.
  • the high wear load can cause thermal fatigue, which initiates surface cracks on the cutter element. These cracks are further propagated by a mechanical fatigue mechanism that is caused by the cyclical bending stresses and/or impact loads applied to the cutter element. These result in chipping and, more severely, in catastrophic cutter element breakage and failure.
  • gage cutter elements 70 of the present invention are subjected to high wear loads, but are subjected to relatively low stress and impact loads, as their primary function consists of scraping or reaming the borehole wall. Even if thermal fatigue should occur, the potential of mechanically propagating these cracks and causing failure of a gage cutter element 70 is much lower compared to conventional bit designs. Therefore, the present gage cutter element exhibits greater ability to retain its original geometry, thus improving the ROP potential and durability of the bit.
  • the invention thus includes using a different grade of hard metal, such as cemented tungsten carbide, for gage cutter elements 70 than that used for first inner row cutter elements 80. Additionally, the use of super abrasive coatings that differ in abrasive resistance and toughness, alone or in combination with hard metals, yields improvements in bit durability and penetration rates. Specific grades of cemented tungsten carbide and PCD or PCBN coatings can be selected depending primarily upon the characteristics of the formation and operational drilling practices to be encountered by bit 10.
  • Cemented tungsten carbide inserts formed of particular formulations of tungsten carbide and a cobalt binder (WC-Co) are successfully used in rock drilling and earth cutting applications.
  • This material's toughness and high wear resistance are the two properties that make it ideally suited for the successful application as a cutting structure material. Wear resistance can be determined by several ASTM standard test methods. It has been found that the ASTM B611 test correlates well with field performance in terms of relative insert wear life. It has further been found that the ASTM B771 test, which measures the fracture toughness (Klc) of cemented tungsten carbide material, correlates well with the insert breakage resistance in the field.
  • Klc fracture toughness
  • the wear resistance of a particular cemented tungsten carbide cobalt binder formulation is dependent upon the grain size of the 5 tungsten carbide, as well as the percent, by weight, of cobalt that is mixed with the tungsten carbide.
  • cobalt is the preferred binder metal
  • other binder metals such as nickel and iron can be used advantageously.
  • wear resistance is not the only design criteria for cutter elements 70, 80, however.
  • fracture toughness Another trait critical to the usefulness of a cutter element is its fracture toughness, or ability to withstand impact loading.
  • the fracture toughness of the material is increased with larger grain size tungsten carbide and greater percent weight of cobalt.
  • fracture toughness and wear resistance tend to be inversely related, as grain size changes s that increase the wear resistance of a specimen will decrease its fracture toughness, and vice versa.
  • the average grain size of a particular specimen can be subject to interpretation. Because for a fixed weight percent of cobalt the hardness of a o specimen is inversely related to grain size, the specimen can be adequately defined in terms of its hardness and weight percent cobalt, without reference to its grain size. Therefore, in order to avoid potential confusion arising out of generally less precise measurements of grain size, specimens will hereinafter be defined in terms of hardness (measured in hardness Rockwell A (HRa)) and weight percent cobalt.
  • HRa hardness Rockwell A
  • the term "differs" means that the value or magnitude of the characteristic being compared varies by an amount that is greater than that resulting from accepted variances or tolerances normally associated with the manufacturing processes that are used to formulate the raw materials and to process and form those materials o into a cutter element.
  • materials selected so as to have the same nominal hardness or the same nominal wear resistance will not "differ,” as that term has thus been defined, even though various samples of the material, if measured, would vary about the nominal value by a small amount.
  • each of the grades of cemented tungsten carbide and PCD identified in the Tables herein "differs" from each of the others in terms of hardness, wear resistance and fracture toughness.
  • Inner rows 103-105 of petroleum bits intended for use in softer formations have conventionally been formed of coarser grained tungsten carbide grades having nominal hardnesses in the range of 85.8-86.4 HRa, with cobalt contents of 14-16 percent by weight because of this material's ability to withstand impact loading.
  • This formulation was employed despite the fact that this material has a relatively low wear resistance and despite the fact that, even in bottom hole cutting, significant wear can be experienced by inner row cutter elements 103-105 of conventional bits in particular formations.
  • the choice of materials for prior art gage inserts 100 ( Figure 6) was a compromise.
  • gage inserts 100 experienced both significant side wall and bottom hole cutting duty, they could not be made as wear resistant as desirable for side wall cutting, nor as tough as desired for bottom hole cutting. Making the gage insert more wear resistant caused the insert to be less able to withstand the impact loading. Likewise, making the insert 100 tougher so as to enable it to withstand greater impact loading caused the insert to be less wear resistant. Because the choice of material for conventional gage inserts 100 was a compromise, the prior art softer formation petroleum bits typically employed a medium grained cemented tungsten carbide having nominal hardness around 88.1-88.8 HRa with cobalt contents of 10-11% by weight. The following table reflects the wear resistance and other mechanical properties of various commercially-available cemented tungsten carbide compositions: Table 3: Properties of Typical Cemented Tungsten Carbide Insert Grades Used in Oil/Gas Drilling
  • gage cutter elements 70 from a very wear resistant carbide grade for most formations.
  • gage cutter elements 70 should be formed from a finer grained tungsten carbide grade having a nominal hardness in the range of approximately 88.1-90.8 HRa, with a cobalt content in the range of about 6-11 percent by weight.
  • Suitable tungsten carbide grades include those having the following compositions:
  • the tungsten carbide grades are listed from top to bottom in Table 4 above in order of decreasing wear resistance, but increasing fracture toughness.
  • a harder grade of tungsten carbide with a lower cobalt content is less prone to thermal fatigue.
  • the division of cutting duties provided by the present invention allows use of a gage cutter element 70 that is a harder and more thermally stable than is possible in prior art bit designs, which in turn improves the durability and ROP potential of the bit.
  • first inner row of cutter elements 80 which must withstand the bending moments and impact loading inherent in bottom hole drilling, it is preferred that a tougher and more impact resistant material be used, such as the tungsten carbide grades shown in the following table:
  • Table 5 Properties of Grades of Cemented Tungsten Carbide Presently Preferred for Off- Gage Cutter Element 80 for Oil/Gas Drilling
  • the tungsten carbide grades identified from top to bottom in Table 5 increase in fracture toughness and decrease in wear resistance (the grade having 12% cobalt and a nominal hardness of 87.4 HRa being tougher than the grade having 16% cobalt and a hardness of 87.3 HRa).
  • the off-gage cutter elements 80 will, in most all instances, be made of a tungsten carbide grade having a hardness that is less than that the gage cutter element 70. In most applications, cutter elements 80 will be of a material that is less wear resistant and more impact resistant. The relative difference in hardness between gage and off-gage cutter elements is dependent upon the application.
  • gage inserts 70 will be formed of a cemented tungsten carbide grade having a nominal hardness of 90.8 HRa and a cobalt content of 6% by weight and thus will have the wear resistance that previously was used in heel inserts 102 of the prior art ( Figure 6).
  • the closely spaced but off-gage inserts 80 will be formed of a tungsten carbide grade having a nominal hardness of 86.4 HRa and a cobalt content of 14% by weight, this grade having the impact resistance conventionally employed on inner rows 103-105 in prior art bits ( Figure 6).
  • inserts 80 may have longer extensions or more aggressive cutting shapes, or both, so as to increase the ROP potential of the bit.
  • first inner row cutter elements 80 from a tougher material than has been conventionally used for gage row cutter elements, the number of cutter elements 80 can be decreased and the pitch or distance between adjacent cutter elements 80 can be increased (relative to the distance between adjacent prior art gage inserts 100 of Figure 6). This can lead to improvements in ROP, as described previously.
  • the longest strike distance on the borehole wall for the gage cutter inserts 70 occurs in large diameter, soft formation bit types with large offset. For those bits, a hard and wear-resistant tungsten carbide grade for the gage inserts 70 is important, particularly in abrasive formations.
  • a bit made in accordance to the present invention can be particularly designed to have sufficient strength/durability to enable it to drill harder or more abrasive sections of the borehole, and also to drill with competitive ROP in sections of the borehole where softer formations are encountered.
  • cutter elements 70, 80 having coatings comprising differing grades of super abrasives.
  • Such super abrasives may be, for example, PCD or PCBN coatings applied to the cutting surfaces of preselected cutter elements 70, 80. All cutter elements in a given row may not be required to have a coating of super abrasive.
  • the desired improvements in wear resistance, bit life and durability may be achieved where only every other insert in the row, for example, includes the coating.
  • Super abrasives are significantly harder than cemented tungsten carbide.
  • the hardness of super abrasives is not usually expressed in terms of Rockwell A (HRa).
  • the term "super abrasive” means a material having a hardness of at least 2,700 Knoop (kg/mm 2 ).
  • PCD grades have a hardness range of about 5,000- 5 8,000 Knoop (kg/mm 2 ) while PCBN grades have hardnesses which fall within the range of about 2,700-3,500 Knoop (kg/mm 2 ).
  • the hardest grade of cemented tungsten carbide identified in Tables 3-5 has a hardness of about 1475 Knoop (kg/mm 2 ).
  • cutter elements 70, 80 with PDC or PCBN coatings are well known. Examples of these methods are described, for example, in U.S. Patent 0 Numbers 4,604,106, 4,629,373, 4,694,918 and 4,811,801, the disclosures of which are all incorporated herein by this reference.
  • Cutter elements with coatings of such super abrasives are commercially available from a number of suppliers including, for example, Smith Sii Megadiamond, Inc., General Electric Company, DeBeers Industrial Diamond Division, or Dennis Tool Company. Additional methods of applying super abrasive coatings also may be s employed, such as the methods described in the co-pending U.S.
  • Typical PCD coated inserts of conventional bit designs are about 10 to 1000 times more o wear resistant than cemented tungsten carbide depending, in part, on the test methods employed in making the comparison.
  • the use of PCD coatings on inserts has, in some applications, significantly increased the ability of a bit to maintain full gage, and therefore has increased the useful service life of the bit.
  • Typical failure modes of PCD coated inserts of conventional designs are chipping and spalling of the diamond coating. These 5 failure modes are primarily a result of cyclical loading, or what is characterized as a fatigue mechanism.
  • the fatigue life, or load cycles until failure, of a brittle material like a PCD coating is dependent on the magnitude of the load. The greater the load, the fewer cycles to failure. Conversely, if the load is decreased, the PCD coating will be able to withstand more load cycles o before failure will occur.
  • gage and off-gage insets 70, 80 of the present invention cooperatively cut the comer of the borehole, the loads (wear, frictional heat and impact) from the cutting action is shared between the gage and off-gage inserts. Therefore, the magnitude of the resultant load applied to the individual inserts is significantly less than the load that would otherwise be applied to a conventional gage insert such as insert 100 of the bit of Figure 6 which alone was required to perform the comer cutting duty. Since the magnitude of the resultant force is reduced on cutter elements 70, 80 in the present invention, the fatigue life, or cycles to failure of the PCD coated inserts is increased.
  • the super abrasive coating is more resistant to chipping or impact damage than if only a portion of the cutting surface were coated.
  • the term "fully capped” as used herein means an insert whose entire cutting portion is coated with super abrasive.
  • PCD coated inserts in the gage row 70a, or in the first inner row 80a, or both has additional significant benefits over conventional bit designs, benefits arising from the superior wear resistance and thermal conductivity of PCD relative to tungsten carbide.
  • PCD has about 5.4 times better thermal conductivity than tungsten carbide. Therefore, PCD conducts the frictional heat away from the cutting surfaces of cutter elements 70, 80 more efficiently than tungsten carbide, and thus helps prevent thermal fatigue or thermal degradation.
  • PCD starts degrading around 700?C.
  • PCBN is thermally stable up to about 1300?C.
  • PCBN coatings on the gage row cutter elements 70 in a bit 10 of the present invention could perform better than PCD coatings.
  • the strength of PCD is primarily a function of diamond grain size distribution and diamond to diamond bonding.
  • the diamond coatings may be made so as to have differing functional properties.
  • a PCD grade with optimized wear resistance will have a different diamond grain size distribution than a grade optimized for increased toughness.
  • the following table shows three categories of diamond coatings presently available from Smith Sii MegaDiamond Inc.
  • bit 10 of the present invention may include gage inserts 70 having a cutting surface with a coating of super abrasives.
  • gage inserts 70 may be coated with a high wear resistant PCD grade having an average grain size range of less than 4 ?m.
  • the PCD grade may be optimized for toughness, having an average grain size range of larger than 25 ?m.
  • gage insert 70 will enable the preselected gage insert 70 to withstand abrasion better than a tungsten carbide insert that does not include the super abrasive coating, and will permit the cutting structure of bit 10 to retain its original geometry longer and thus prevent reduced ROP and possibly a premature or unnecessary trip of the drill string.
  • gage inserts 70 having such coating will be slower to wear, off-gage inserts 80 will be better protected from the sidewall loading that would otherwise be applied to them if gage inserts 70 were to wear prematurely.
  • off-gage inserts 80 may be made with longer extensions or with more aggressive cutting shapes, or both (leading to increased ROP potential) than would be possible if off-gage inserts 80 had to be configured to be able to bear sidewall cutting duty 5 after gage inserts 70 (without a super abrasive coating) wore due to abrasion and erosion.
  • first inner row inserts 80 in this configuration must be able to withstand some impact loading, the most wear resistant super abrasive material is generally not suitable, the application instead requiring a compromise in wear resistance and toughness.
  • a suitable diamond coating 5 for off-gage insert 80 in such an application would have relatively high toughness and relatively lower wear resistance and be made of a diamond grade with average grain size range larger than 25 ?m.
  • Gage insert 70 in this example could be manufactured without a super abrasive coating, and preferably would be made of a finer grained cemented tungsten carbide grade having a nominal hardness of 90.8 HRa and a cobalt content of 6% by weight.
  • Gage inserts 70 of such a 0 grade of tungsten carbide exhibit 2.5 times the nominal resistance and have significantly better thermal stability than inserts formed of a grade having a nominal hardness 88.8 HRa and cobalt content of about 11%, a typical grade for conventional gage inserts 100 such as shown in Figure 6.
  • gage inserts 70 are mounted between inserts 80 along circumferential shoulder 50 in the configuration shown in Figures 1-4, inserts 70 of this example are believed capable of 5 resisting wear and thermal loading in these formations even without a super abrasives coating.
  • gage inserts 70 may be undesirable in bits employed when drilling high inclination wells with steerable drilling systems due to potentially severe impact loads experienced by the gage inserts 70 as the drill string is rotated within the well casing — loading that would not be exposed by the more protected inner row off-gage cutter o elements 80.
  • gage inserts 70 and off-gage inserts 80 each having coatings of super abrasive material.
  • both gage inserts 70 and off-gage inserts 80 may include the same grade of PCD coating.
  • the preselected inserts 70, 80 may include extremely wear resistant coatings such as a PCD grade having an average grain size range of less than 4 ?m.
  • a coating of super abrasive material having high thermal stability is important.
  • coatings on inserts 70 and 80 that have greater thermal stability than the coating described above, such as coatings having an average grain size range of 4-25 ?m.
  • coatings having an average grain size range of 4-25 ?m In drilling direction wells through abrasive formations having varying compressive strengths (nonhomogeneous abrasive formations), it may be desirable to include super abrasive coatings on both gage inserts 70 and off-gage inserts 80.
  • off-gage inserts 80 may be subjected to a more severe impact loading than gage inserts 70. In this instance, it would be desirable to include a tougher or more impact resistant coating on off-gage insert 80 than on gage inserts 70.
  • gage insert 70 may employ more wear resistant, but not as tough diamond coating, such as one having an average grain size within the range of 4-25 ?m or smaller.
  • a rolling cone cutter such as cutter 14 shown in Figures 1-4 is provided with both gage and off-gage inserts 70, 80 consisting of uncoated tungsten carbide.
  • the gage inserts 70 have a nominal hardness in the range of 88.8 to at least 90.8 HRa and cobalt content in the range of about 11 to about 6 weight percent, while the first inner row inserts 80 have a nominal hardness in the range of 85.8 to 88.8 HRa and cobalt content in the range of about 16 to about 10 weight percent.
  • the wear resistance of the gage elements 70 would exceed that of the off gage element 80 by about 48%.
  • a most preferred embodiment of this example however has inserts 70 in the gage row 70a with a nominal hardness of 90.8 HRa and cobalt content of about 6 percent and inserts 80 in the off-gage row 80a with a nominal hardness of 87.4 HRa and cobalt content of about 12 percent, such that gage inserts 70 are more than three times as wear resistant as off-gage inserts 5 80, but where off-gage inserts 80 are more than 30% tougher than gage inserts 70.
  • a rolling cone cutter such as cutter 14 as shown in Figures 1-4 is provided with PCD- coated gage inserts 70 and off-gage inserts 80 consisting of uncoated tungsten carbide.
  • the coating on the gage inserts 70 may be any suitable PCD coating, while the inserts 80 in the off- 0 gage row 80a have a nominal hardness in the range of 85.8 to 88.8 HRa and cobalt content in the range of about 16 to about 10 weight percent.
  • the most preferred embodiment of this example has inserts 80 in the off-gage row with a nominal hardness of 87.4 to 88.1 HRa and cobalt content in the range of about 12 to about 10 weight percent.
  • Example 3 5 A rolling cone cutter such as cutter 14 as shown in Figures 1-4 is provided with PCD- coated gage inserts 70 and off-gage inserts 80.
  • the coating on the gage inserts 70 or off-gage inserts 80 may be any suitable PCD coating.
  • the coating on the gage inserts 70 is optimed for wear resistance and has an average grain size range of less than or equal to 25 ?m.
  • the PCD coating on the off-gage inserts 80 is optimized for o toughness and preferably has an average grain size range of greater than 25 ?m.
  • a rolling cone cutter such as cutter 14 as shown in Figures 1- 4 is provided with gage inserts 70 of uncoated tungsten carbide and off-gage inserts 80 coated with a suitable PCD coating.
  • the gage inserts 70 have a nominal hardness in the range of 89.4 to 90.8 HRa and 5 cobalt content in the range of about 11 to about 6 weight percent.
  • the most preferred embodiment of this example has gage inserts 70 with a nominal hardness of 90.8 HRa and cobalt content about 6 percent and off-gage inserts 80 having a coating optimized for toughness and preferably having an average grain size range of greater than 25 ?m.
  • gage inserts 70 and off-gage inserts 80 allow the use of more aggressive cutting shapes in gage rows 70a and off-gage rows 80a leading to increased ROP potential.
  • Preferred chisel o cutter shapes include those shown and described in U.S. Patent No. 5,172,777, 5,322,138 and 4,832,139, the disclosures of which are all inco ⁇ orated herein by this reference.
  • a chisel insert presently-preferred for use in bit 10 of the present invention is shown in Figure 13.
  • both gage insert 170 and off-gage insert 180 are sculptured chisel inserts having no non- tangential intersections of the cutting surfaces and having an inclined crest 190.
  • the inserts s 170, 180 are oriented such that the crests 190 are substantially parallel to cone axis 22 and so that the end 191 of the crest that extends furthest from cone axis 22 is closest to the bit axis 11.
  • Crest 190 of gage insert 170 extends to gage curve 90, while the insert 190 of insert 180 is off gage by a distance D previously described.
  • inserts 170, 180 may be formed different grades of o cemented tungsten carbide or may have super abrasive coatings in various combinations, all as previously described above. In most instances, gage insert 170 will be more wear-resistance than off-gage insert 180. Inserts 170, 180 having super abrasive coatings should be fully capped.
  • Example 5 5 A particularly desirable combination employing chisel inserts in rows 70a and 80a include gage insert 170 having a PCD coating with an average grain size of less than or equal to 25 ?m and an off-gage insert 180 of cemented tungsten carbide having a nominal hardness of 88.1 HRa.
  • insert 180 shown in Figure 13 may instead be coated with a PCD coating such as one having an average grain size o greater than 25 ?m.
  • a steel tooth cone 130 is adapted for attachment to a bit body 12 in a like manner as previously described with reference to cones 14- 16.
  • the bit would include a plurality of cutters such as rolling cone cutter 130.
  • Cutter 130 includes a backface 40, a generally conical surface 46 and a heel surface 44 which is formed between conical surface 46 and backface 40, all as previously described with reference to the TCI bit shown in Figures 1-4.
  • steel tooth cutter 130 includes heel row inserts 60 embedded within heel surface 44, and gage row cutter elements such as inserts 70 disposed adjacent to the circumferential shoulder 50 as previously defined.
  • gage cutter elements 70 may likewise be steel teeth or some other type of cutter element.
  • Relief 122 is formed in heel surface 44 about each insert 60.
  • relief 124 is formed about gage cutter elements 70, relieved areas 122, 124 being provided as lands for proper mounting and orientation of inserts 60, 70.
  • steel tooth cutter 130 includes a plurality of first inner row cutter elements 120 generally formed as radially-extending teeth.
  • Steel teeth 120 include an outer layer or layers of wear resistant material 121 to improve durability of cutter elements 120.
  • the first row of teeth are integrally formed in the cone cutter so as to be "on gage.” This placement requires that the teeth be configured to cut the borehole comer without any substantial assistance from any other cutter elements, as was required of gage insert 100 in the prior art TCI bit shown in Figure 6.
  • cutter elements 120 are off-gage within the ranges specified in Table 2 above so as to form the first inner row of cutter elements 120a. In this configuration, best shown in Figure 11, gage inserts 70 and first inner row cutter elements 120 cooperatively cut the borehole comer with gage inserts 70 primarily responsible for sidewall cutting and with steel teeth cutter elements 120 of the first inner row primarily cutting the borehole bottom.
  • gage inserts 70 cut along path 76 having a radially outermost point P,.
  • inner row cutter element 120 cuts along the path represented by curve 126 having a radially outermost point P 2 .
  • the distance D that cutter elements 120 are "off-gage” is the difference in radial distance between P, and P 2 .
  • the distance that cutter elements 120 are "off-gage” may likewise be understood as being the distance D' which is the minimum distance between the cutting surface of cutter element 120 and the gage curve 90 shown in Figure 11, D' being equal to D.
  • Steel tooth cutters such as cutter 130 have particular application in relatively soft formation materials and are preferred over TCI bits in many applications. Nevertheless, even in relatively soft formations, in prior art bits in which the gage row cutters consisted of steel teeth, the substantial sidewall cutting that must be performed by such steel teeth may cause the teeth to wear to such a degree that the bit becomes undersized and cannot maintain gage. Additionally, because the formation material cut by even a steel tooth bit frequently includes strata having various degrees of hardness and abrasiveness, providing a bit having insert cutter elements 70 on gage between adjacent off-gage steel teeth 120 as shown in Figures 10 and 11 provides a division of comer cutting duty and permits the bit to withstand very abrasive formations and to prevent premature bit wear.
  • a steel tooth bit having a cone cutter 130 such as shown in Figure 11 is provided with gage row inserts 70 of tungsten carbide with a nominal hardness within the range of 88.1-90.8
  • gage inserts 70 have a nominal hardness within the range of 89.4 to 90.8 HRa.
  • Off-gage teeth 120 include an outer layer of conventional wear resistant hardfacing material such as tungsten carbide and metallic binder compositions to improve their durability.
  • a steel tooth bit having a cone cutter 130 such as shown in Figure 11 is provided with tungsten carbide gage row inserts 70 having a coating of super abrasives of PCD or PCBN. Where PCD is employed, the PCD has an average grain size that is not greater than 25 ?m.
  • Off- gage steel teeth 120 include a layer of conventional hardfacing material.
  • bit 10 includes a heel row of cutter elements 60 which have cutting surfaces that extend to full gage and that cut along curve 66 which includes a radially most distant point P, as measured from bit axis 11.
  • the bit 10 further includes a row of cutter elements 140 that have cutting surfaces that cut along curve 146 that includes a radially most distant point P 2 .
  • Cutter elements 140 are positioned so that their cutting surfaces are off-gage a distance D, from gage curve 90, where D, is also equal to the difference in the radial distance between point P, and P 2 as measured from bit axis 11.
  • bit 10 further includes a row of off-gage cutter elements 150 that cut along curve 156 having radially most distant point P 3 .
  • D 2 (not shown in Figure 12 for clarity) is equal to the difference in radial distance between points P 2 and P 3 as measured from bit axis 11. In this embodiment, D 2 should be selected to be within the range of distances shown in Table 2 above. D, may be less than or equal to D 2 , but preferably is less than D 2 . So positioned, cutter elements 140, 150 cooperatively cut the borehole comer, with cutter elements 140 primarily cutting the borehole sidewall and cutter elements 150 primarily cutting the borehole bottom. Heel cutter elements 60 serve to ream the borehole to full gage diameter by removing the remaining uncut formation material from the borehole sidewall.

Landscapes

  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Mechanical Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Excavating Of Shafts Or Tunnels (AREA)
  • Control Of Metal Rolling (AREA)

Abstract

Un trépan à cônes roulants (10) comporte un cône de coupe (14, 15, 16) présentant une paire de rangées adjacentes d'éléments coupants (70, 80) positionnés de manière à diviser la capacité de coupe dans la paroi latérale (5) et dans le fond (7) du trou. La résistance à l'usure, la dureté et la robustesse des éléments coupants (70, 80) dans les rangées adjacentes sont optimisées en fonction du type de coupe réalisée par les rangées respectives. Dans la plupart des applications, les éléments coupants (70) effectuant la coupe dans la paroi latérale vont présenter des surfaces de coupe plus résistantes ou plus dures que les surfaces de coupe des éléments coupants (80) situés dans les rangées et chargés plus spécialement de la coupe dans le fond du trou. De même, les éléments coupants (80) vont généralement être plus robustes que ceux (70) réalisant la taille essentiellement dans la paroi latérale. Les perfectionnements apportés aux matériaux constitutifs permettent de faire varier les qualités du carbure de tungstène mis en oeuvre dans les éléments coupants (70, 80) et concernent l'emploi sélectif de couches d'abrasifs extra-durs tels que le PCD ou le PCBN. Les éléments coupants (70, 80) sont soit des lames rapportées, soit des dents en acier.
PCT/US1997/005948 1996-04-10 1997-04-10 Trepan a cones roulants dans lequel le positionnement et les materiaux constitutifs de l'element de coupe sont perfectionnes pour optimiser la capacite de coupe angulaire dans le trou de forage WO1997038205A1 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CA002228156A CA2228156C (fr) 1996-04-10 1997-04-10 Trepan a cones roulants dans lequel le positionnement et les materiaux constitutifs de l'element de coupe sont perfectionnes pour optimiser la capacite de coupe angulaire dans le trou de forage
AU27259/97A AU2725997A (en) 1996-04-10 1997-04-10 Rolling cone bit with enhancements in cutter element placement and materials to optimize borehole corner cutting duty
GB9802230A GB2319549B (en) 1996-04-10 1997-04-10 Earth boring bit
SE9800295A SE9800295L (sv) 1996-04-10 1998-02-02 Rullkon-borrkrona med förbättringar i skärelement placering och -material för optimering av skärarbete vid borrhålets hörn

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US08/630,517 US6390210B1 (en) 1996-04-10 1996-04-10 Rolling cone bit with gage and off-gage cutter elements positioned to separate sidewall and bottom hole cutting duty
US08/630,517 1996-04-10
US08/667,758 1996-06-21
US08/667,758 US5833020A (en) 1996-04-10 1996-06-21 Rolling cone bit with enhancements in cutter element placement and materials to optimize borehole corner cutting duty

Publications (1)

Publication Number Publication Date
WO1997038205A1 true WO1997038205A1 (fr) 1997-10-16

Family

ID=27091174

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US1997/005948 WO1997038205A1 (fr) 1996-04-10 1997-04-10 Trepan a cones roulants dans lequel le positionnement et les materiaux constitutifs de l'element de coupe sont perfectionnes pour optimiser la capacite de coupe angulaire dans le trou de forage

Country Status (5)

Country Link
AU (1) AU2725997A (fr)
CA (1) CA2228156C (fr)
GB (1) GB2319549B (fr)
SE (1) SE9800295L (fr)
WO (1) WO1997038205A1 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
BE1013520A3 (fr) * 1998-06-25 2002-03-05 Baker Hughes Inc Trepan tricones hybride.

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6345673B1 (en) 1998-11-20 2002-02-12 Smith International, Inc. High offset bits with super-abrasive cutters
GB2378725B (en) * 1998-11-20 2003-06-11 Smith International Earth boring bit
CA2348188C (fr) 2000-05-18 2006-08-01 Smith International, Inc. Trepan de cone de roulement avec elements en eventail le long de la courbe de jauge

Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5353885A (en) * 1991-05-01 1994-10-11 Smith International, Inc. Rock bit
US5542485A (en) * 1993-07-08 1996-08-06 Baker Hughes Incorporated Earth-boring bit with improved cutting structure

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5353885A (en) * 1991-05-01 1994-10-11 Smith International, Inc. Rock bit
US5542485A (en) * 1993-07-08 1996-08-06 Baker Hughes Incorporated Earth-boring bit with improved cutting structure

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
BE1013520A3 (fr) * 1998-06-25 2002-03-05 Baker Hughes Inc Trepan tricones hybride.

Also Published As

Publication number Publication date
GB9802230D0 (en) 1998-04-01
AU2725997A (en) 1997-10-29
SE9800295D0 (sv) 1998-02-02
GB2319549B (en) 2000-09-06
GB2319549A (en) 1998-05-27
SE9800295L (sv) 1998-02-10
CA2228156A1 (fr) 1997-10-16
CA2228156C (fr) 2006-08-22

Similar Documents

Publication Publication Date Title
US5833020A (en) Rolling cone bit with enhancements in cutter element placement and materials to optimize borehole corner cutting duty
US5967245A (en) Rolling cone bit having gage and nestled gage cutter elements having enhancements in materials and geometry to optimize borehole corner cutting duty
CA2288923C (fr) Outils de coupe a fort decentrage avec lames superabrasives
US7950476B2 (en) Drill bit and cutter element having chisel crest with protruding pilot portion
CA2233382C (fr) Dent d'outil de coupe en acier a rechargement dur
US5839526A (en) Rolling cone steel tooth bit with enhancements in cutter shape and placement
US5868213A (en) Steel tooth cutter element with gage facing knee
US8205692B2 (en) Rock bit and inserts with a chisel crest having a broadened region
US7757789B2 (en) Drill bit and insert having bladed interface between substrate and coating
US7258177B2 (en) Fracture and wear resistant compounds and rock bits
CA2348188C (fr) Trepan de cone de roulement avec elements en eventail le long de la courbe de jauge
US20080060852A1 (en) Gage configurations for drill bits
CA2228156C (fr) Trepan a cones roulants dans lequel le positionnement et les materiaux constitutifs de l'element de coupe sont perfectionnes pour optimiser la capacite de coupe angulaire dans le trou de forage
CA2257883C (fr) Tricone muni d'elements de coupe au diametre habituels et d'elements de coupe au diametre emboites a materiaux et geometrie ameliores dans le but d'optimiser le travail de coupe angulaire d'un forage
GB2349405A (en) Rolling cone bit

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AU CA GB SE SG

ENP Entry into the national phase

Ref document number: 2228156

Country of ref document: CA

Ref country code: CA

Ref document number: 2228156

Kind code of ref document: A

Format of ref document f/p: F

WWE Wipo information: entry into national phase

Ref document number: 98002959

Country of ref document: SE

WWP Wipo information: published in national office

Ref document number: 98002959

Country of ref document: SE