Patent Publication Number: US-7913778-B2

Title: Rock bit with hydraulic configuration

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. provisional application Ser. No. 60/979,806 filed Oct. 12, 2007, and entitled “Rock Bit with Hydraulics Configuration,” which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. provisional application Ser. No. 61/038,888 filed Mar. 24, 2008, and entitled “Rock Bit with Vectored Hydraulic Nozzle Retention Sleeves,” which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. non-provisional application Ser. No. 12/104,856 filed Apr. 17, 2008, and entitled “Rock Bit With Vectored Hydraulic Nozzle Retention Sleeves,” which is hereby incorporated herein by reference in its entirety. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     1. Field of the Invention 
     The present invention relates generally to roller cone rock bits that operate in “drilling mud.” More specifically, the invention relates to roller cone rock bits having nozzle arrangements configured to provide enhanced cutting structure cleaning while offering the potential to reduce cone erosion. 
     2. Background of the Invention 
     Rotary cone rock bits are used for drilling boreholes in various earth formations. Roller cone bits are conventionally manufactured using a segmented arc construction method. This method utilizes three 120° arcuate leg segments, each comprising one-third of the drill bit body and an individual leg portion with a bearing journal thereon. The three arcuate sections are usually forged and then machined to form the bearing surfaces on the bearing journals and the mating surfaces along each edge where the three sections are welded together. Prior to joining the three arcuate sections to form a bit body, the cutter assembly with bearings and retention means are mounted on the inwardly projecting bearing journals due to space limitations and associated difficulties of mounting the cutters after the three arcuate sections have been welded together. After the bearing assemblies and cutters are mounted on the machined bearing journals, the three leg segments are then placed in a welding jig and welded to each other to form the bit body. After welding has occurred a tapered thread is machined on the upper end of the bit, commonly referred to as the “pin” end, and the bit is ready for use. 
     To aid in the removal of drilling cuttings from the bottom of the borehole, mud or other fluids are introduced to the bottom of the borehole through nozzles or jet assemblies positioned in bores formed in the bit body. The fluid or mud pumped through the bit body also serves to remove heat from the rock bit. In general, as the efficiency of the cutting removal is increased, the cutting efficiency and associated rate of penetration (ROP) are also increased. 
     To efficiently remove cuttings from the borehole, the fluid or mud must carry the cuttings radially outward on the borehole bottom and then upward through the annulus (i.e., the annular space formed between the bit body and drill string, and the borehole). A fluid flow that will carry the cuttings radially outward from the center of the borehole and up the annulus may be created by introducing a downward fluid flow on the cutting structure of the bit. As the fluid flows past the cutting structure, the fluid impacts the borehole bottom and spreads radially outward to the annulus. 
     The amount of energy available at the bit is generally dictated by factors external to the bit such as the drilling rigs&#39; available hydraulic energy, drill pipe type, bottom hole assembly (BHA) configuration and drill depth. However, once the available energy for the rock bit is determined, properly configuring the hydraulics of the bit for the specific application can significantly affect the rate of penetration (ROP) of the bit in the formation. 
     When drilling softer formations and plastic formations, there is a strong tendency for cuttings to adhere to the teeth or inserts of bits. The adhesion of formation to teeth or inserts is commonly referred to as “bit balling”. As is known in the art, bit balling describes the packing of formation between the cones and bit body, or between the cutting elements on the bit, during drilling. When bit balling occurs, the cutting elements may be sufficiently packed off such that they are limited in their ability to effectively penetrate into the formation, thereby tending to slow the ROP of the drill bit. Thus, cuttings must be removed efficiently during drilling to maintain reasonable penetration rates. 
     In harder clays and shales, cuttings can become impacted or “balled up” between the teeth or inserts of the cutting structures. When formation sticks to cones or is impacted between cutting elements it limits the ability of the cutting element to penetrate the formation. Also, formation packed against the cone-shell constricts the flow channels needed to carry cuttings away. This promotes premature bit wear. In either instance, having sufficient drilling fluid directed toward the cones can help to clean the inserts and cones, allowing them to penetrate to a greater depth, thus maintaining the ROP of the bit. Furthermore, bit durability may be improved, even as the inserts begin to wear down since the cleaned inserts will continue to penetrate the formation even in their reduced state. 
     To combat bit balling and to allow for larger cones, the cutting elements on adjacent rolling cones are often arranged to intermesh. As a cutting element of a first cone intermeshes between two rows of cutting elements of a second cone, it dislodges formation packed between the two rows of cutting elements. Having the cutting elements intermesh also allows the diameter of the cones to be larger, providing for a larger bearing surface which results in a more durable cone. 
     To further facilitate cuttings removal, jets or nozzles are positioned on the bit to wash cuttings from the cutting structure and/or borehole bottom. Conventional nozzle arrangements include the placement of a nozzle between each of the cones proximal the outer periphery of the bit. In many applications, a jet may also be located at the center of the bit to channel fluid flow directly to the borehole bottom. For example, U.S. Pat. No. 5,853,055 describes an extended center jet on a bit to reduce diffusion and provide a substantially uninterrupted fluid flow that strikes the borehole bottom with maximum impact energy. U.S. Pat. No. 6,290,006 describes special nozzles that can be used to provide collimated streams of high velocity drilling fluid that strike different areas of the bottomhole with maximum energy for enhanced bottomhole cleaning. An alternative nozzle arrangement involves a jet positioned between each of the cones near the periphery of the bit body. U.S. Pat. No. 4,611,673 proposes orienting nozzles toward one of the adjacent cones so that the jet of fluid exiting the nozzle will strike the cutting elements on the cone. However, these arrangements may not be desirable in applications where bit balling is a concern because they do not provide cleaning along interior rows of cutting elements on the cones, and further, a concentrated flow of drilling fluid directed toward and impacting a cone shell may result in excessive erosion of the cones and premature loss of cutting elements from the cones. 
     To avoid balling problems, bits have been designed with additional nozzles positioned over each of the cones which direct a jet stream of fluid directly on top of the cones in the dome region. One problem with these designs is that the impact of fluid directly on top of the cones often results in severe erosion of the cone shell and a premature loss of cutting elements from the cones. The placement of these nozzles has been restricted in the prior art to nozzle bores where the nozzles are installed through the pin due to limited access to the dome region from the journal side of the forging to drill the required nozzle bores. 
     In the prior art, a cast bit body was proposed that allowed for the machining and installation of nozzles before the leg portions were attached to the body. Unfortunately, the method requires a cast body formed separately from the leg portions. In practice, this type of cast body method is not typically used, and is generally limited to the manufacture of extremely large bits. Further, these designs may require insertion of the nozzles in the bit body prior to assembly of the legs on the bit. In practice, nozzles are typically inserted in the field after assembly of the bit based on rig specifications and drilling requirements particular to a specific application. 
     Numerous efforts have been made by drill bit designers to solve the problem of bit balling yet the problem persists. Accordingly, there is a need in the art for bits having an improved nozzle configuration that provides sufficient cleaning for cutting elements along the inner rows and outer rows of the cones to minimize bit balling. Such bits with improved nozzle configurations would be particularly well received if they reduced impingement of the cone shell with drilling fluid, thereby offering the potential to reduce the likelihood of cone shell erosion and associated premature loss of cutting elements. 
     BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS 
     These and other needs in the art are addressed in one embodiment by a drill bit for drilling through an earthen formation to form a borehole with a radius R, a bottom and a sidewall, the drill bit having a full gage diameter with the radius R. In an embodiment, the drill bit comprises a bit body having a central bit axis and including a pin end, an internal plenum, and a dome side generally opposite the pin end. The dome side includes a central dome region extending from the bit axis to about 10% of the radius R, an annular intermediate dome region extending from the central region to about 50% of the radius R, and an annular outer dome region extending from the intermediate region to about 90% of the radius R. In addition, the drill bit comprises an intermediate receptacle having a central axis and extending through the intermediate dome region to the plenum. Further, the drill bit comprises a first and a second rolling cone, each cone being mounted to the bit body and adapted for rotation about a different cone axis. Each cone comprises a nose proximal the bit axis, a generally planar backface distal the bit axis, an inner cone region extending axially relative to the cone axis from the nose to an intermediate cone region, and an outer cone region extending axially relative to the cone axis from the backface to the intermediate region. A plurality of cutting elements are mounted to the inner region, the intermediate region, and the outer region of each cone, wherein the cutting elements mounted to the inner cone region of each cone are positioned to contact the borehole bottom between the bit axis and about 25% of the radius R, the cutting elements mounted to the intermediate cone region of each cone are positioned to contact the borehole bottom between about 25% and 75% of the radius R, and the cutting elements mounted to the outer cone region of each cone are positioned to contact the borehole bottom between about 75% and 100% of the radius R. Moreover, wherein a projection of the central axis passes between the intermediate region of the first cone and the intermediate region of the second cone. 
     Theses and other needs in the art are addressed in another embodiment by a drill bit for drilling through an earthen formation to form a borehole with a radius R, a bottom and a sidewall, the drill bit having a full gage diameter with the radius R. In an embodiment, the drill bit comprises a bit body having a central bit axis and including a pin end, an internal plenum, a dome side generally opposite the pin end, a first leg, and a second leg circumferentially spaced from the first leg, each leg including a journal. The dome side includes a central dome region extending from the bit axis to about 10% of the radius R, an annular intermediate dome region extending from the central region to about 50% of the radius R, and an annular outer dome region extending from the intermediate region to about 90% of the radius R. In addition, the drill bit comprises an intermediate receptacle having a central axis and extending through the intermediate dome region to the plenum. Further, the drill bit comprises a first rolling cone mounted to the journal of the first leg and adapted for rotation about a first cone axis. Still further, the drill bit comprises a second rolling cone mounted to the journal of the second leg and adapted for rotation about a second cone axis. A reference plane parallel to and passing through the bit axis is positioned at the circumferential midpoint between the first leg and the second leg. A first boundary plane parallel to and passing through the bit axis is oriented at a boundary angle β 1  relative to the reference plane. A second boundary plane parallel to and passing through the bit axis is oriented at a boundary angle β 2  relative to the reference plane. The first boundary plane and the second boundary plane are disposed on opposite sides of the reference plane. The first boundary angle β 1  and the second boundary angle β 2  are each less than 30°. Moreover, a projection of the central axis of the intermediate receptacle is circumferentially bounded by the first boundary plane and the second boundary plane between the dome side and the borehole bottom. 
     Theses and other needs in the art are addressed in another embodiment by a drill bit for drilling an earthen formation to form a borehole with a radius R. In an embodiment, the drill bit comprises a bit body having a central axis and a dome side. The dome side includes a central dome region extending from the bit axis to about 10% of the radius R, an annular intermediate dome region extending from the central region to about 50% of the radius R, and an annular outer dome region extending from the intermediate region to about 90% of the radius R. In addition, the drill bit comprises a plurality of rolling cones, each of the cone cutters being mounted to the bit body and adapted for rotation about a different cone axis. Further, the drill bit comprises a plurality of intermeshing cutting elements mounted to each of the cones. Still further, the drill bit comprises a plurality of intermediate receptacles in the bit body. Each intermediate receptacle has a central axis and extends through the intermediate dome region to the plenum. One intermediate receptacle is circumferentially positioned between the cone axes of each pair of adjacent cones. Moreover, a projection of the central axis of each intermediate receptacle passes through the intermeshing cutting elements between each pair of adjacent cone cutters. 
     Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments, and by referring to the accompanying drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  is a perspective view of an embodiment of an earth-boring bit made in accordance with the principles described herein. 
         FIG. 2  is a partial section view taken through one leg and one rolling cone cutter of the bit shown in  FIG. 1 . 
         FIG. 3  is a schematic bottom end view of the rolling cone drill bit of  FIG. 1  with rings superimposed on the rolling cone cutters to indicate the boundaries of the central, intermediate, outer, and gage regions of the bit; 
         FIG. 4  is a partial view showing, schematically and in rotated profile, the cutting profiles of all of the cutting elements of the three cone cutters of the drill bit shown in  FIG. 1 ; 
         FIG. 5  is a schematic representation showing the intermesh of the three rolling cones of the bit shown in  FIG. 1 ; 
         FIG. 6  is a bottom end view of the bit of  FIG. 1  with the cones and cutting structure omitted for clarity purposes; 
         FIG. 7  is a bottom end view of one of the legs of the bit of  FIG. 1  prior to the assembly of the bit; 
         FIG. 8  is a perspective view of two of the legs of the bit of  FIG. 1  joined together and illustrating the position of an intermediate bore with respect to journal axes of adjacent rolling cone cutters; 
         FIG. 9  is a side view of one of the legs of the bit of  FIG. 1  illustrating the centerlines of the center, intermediate, and outer bores; 
         FIG. 10  is an enlarged side view of the bit of  FIG. 1  illustrating the exiting centerlines of the intermediate and outer bores; 
         FIG. 11  is a bottom end view of the bit of  FIG. 1  illustrating the exiting centerlines of the sleeves. 
         FIG. 12  is a bottom end view of the bit of  FIG. 1  with the borehole bottom shown in phantom to illustrate locations where drilling fluid trajectories impact with the borehole bottom; 
         FIG. 13  is a side view of the bit of  FIG. 1  with the borehole bottom and sidewall shown in phantom to illustrate locations where drilling fluid trajectories impact with the borehole; 
         FIG. 14  is a partial cross-sectional view of an embodiment of a leg with an intermediate bore including a wear sleeve; and 
         FIG. 15  is a plot illustrating a comparison of the normalized wall shear stress experienced by each cone of a bit made in accordance with the principles described herein and each cone of a conventional bit with drilling fluid trajectories that impinge the top of each cone shell. 
     
    
    
     DETAILED DESCRIPTION OF SOME OF THE PREFERRED EMBODIMENTS 
     The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment. 
     Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing Figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness. 
     In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections. 
     Referring first to  FIG. 1 , an embodiment of an earth-boring bit  10  made in accordance with the principles described herein is shown. Bit  10  includes a central axis  11  and a bit body  12  having a threaded section  13  at its upper or pin end  14  that is adapted for securing the bit  10  to a drill string (not shown). Bit  10  has a predetermined gage diameter, defined by the outermost reaches of three rolling cone cutters  1 ,  2 ,  3  which are rotatably mounted on bearing shafts that depend from the bit body  12 . Bit body  12  is composed of three sections or legs  19  that are welded together to form bit body  12 . The surface of bit body  12  extending between legs  19  and facing the borehole bottom is generally referred to as the underside or dome  21  of bit  10 . As will be described in more detail below, bit  10  further includes a plurality of sleeve receptacles, each with a nozzle retention sleeve disposed therein. The nozzle retention sleeves are each adapted to receive a drilling fluid jet or nozzle. In  FIG. 1 , one sleeve receptacle  35  including a nozzle retention sleeve  35   a  is shown. In general, the nozzle retention sleeves and nozzles disposed therein direct drilling fluid around cutters  1 - 3  and toward the bottom of the borehole. Although bit  10  shown in  FIG. 1  includes three rolling cone cutters  1 ,  2 ,  3 , in other embodiments, the bit may include one, two, or more cone cutters. 
     Bit  10  includes lubricant reservoirs  17  that supply lubricant to the bearings that support each of the cone cutters  1 - 3 . Bit legs  19  include a shirttail portion  16  that serves to protect the cone bearings and cone seals from damage caused by cuttings and debris entering between leg  19  and its respective cone cutter. 
     Referring now to both  FIGS. 1 and 2 , each cone cutter  1 - 3  is mounted on a pin or journal  20  extending from bit body  12 , and is adapted to rotate about a cone axis of rotation  22  oriented generally downwardly and inwardly toward the center of the bit. Each cutter  1 - 3  is secured on pin  20  by locking balls  26 , in a conventional manner. In the embodiment shown, radial thrust and axial thrust are absorbed by journal sleeve  28  and thrust washer  31 . The bearing structure shown is generally referred to as a journal bearing or friction bearing; however, the invention is not limited to use in bits having such structure, but may equally be applied in a roller bearing bit where cone cutters  1 - 3  would be mounted on pin  20  with roller bearings disposed between the cone cutter and the journal pin  20 . In both roller bearing and friction bearing bits, lubricant may be supplied from reservoir  17  to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of an annular seal  34  which may take many forms. In other embodiments, an open bearing bit design in which the bearings are not sealed may be employed. 
     As best shown in  FIG. 2 , bit body  12  includes an interior fluid passage or plenum  24  which acts as a conduit for drilling fluid. In particular, drilling fluid is pumped from the surface through the drill string to fluid passage  24  where it is circulated through an internal passageway (not shown) to the receptacles and the nozzles disposed therein. The borehole created by bit  10  includes sidewall  5 , corner portion  6  and bottom  7 . 
     Referring still to  FIGS. 1 and 2 , each rolling cone cutter  1 - 3  includes a cone shell  36  and a plurality of cutting elements mounted to cone shell  36 . Each cone shell  36  includes a generally planar backface  40  and nose  42  generally opposite backface  40 . Adjacent to backface  40 , each cone shell  36  further include a generally frustoconical surface  44  that is adapted to retain cutting elements that scrape or ream the sidewalls of the borehole as the cone cutters  1 - 3  rotate about the borehole bottom. Frustoconical surface  44  will be referred to herein as the “heel” surface of cone cutters  1 - 3 . 
     Extending between heel surface  44  and nose  42  is a generally conical cone surface  46  adapted for supporting cutting elements that gouge or crush the borehole bottom  7  as the cone cutters rotate about the borehole. Frustoconical heel surface  44  and conical surface  46  converge in a circumferential edge or shoulder  50 . Although referred to herein as an “edge” or “shoulder,” it should be understood that shoulder  50  may be contoured, such as by a radius, to various degrees such that shoulder  50  will define a contoured zone of convergence between frustoconical heel surface  44  and the conical surface  46 . Conical surface  46  is divided into a plurality of generally frustoconical regions  48 , generally referred to as “lands”, which are employed to support and secure the cutting elements as described in more detail below. Grooves  49  are formed in cone surface  46  between adjacent lands  48 . 
     In the bit shown in  FIGS. 1 and 2 , each cone cutter  1 - 3  includes a plurality of wear resistant cutting elements in the form of inserts which are disposed about the cone and arranged in circumferential rows in the embodiment shown. More specifically, rolling cone cutter  1  includes a plurality of heel inserts  60  that are secured in a circumferential row  60   a  in the frustoconical heel surface  44 . Cone cutter  1  further includes a first circumferential row  70   a  of nestled gage inserts  70  secured to cone cutter  1  in locations along or near the circumferential shoulder  50 . Relieved areas or lands  78  (best shown in  FIG. 1 ) are formed about nestled gage inserts  70  to assist in mounting inserts  70 . Additionally, the cone cutter includes a second circumferential row  80   a  of gage inserts  80 . The cutting surfaces of inserts  70 ,  80  have differing geometries, but each extend to full gage diameter. The cone cutter  1  further includes inner row inserts  81 ,  82 ,  83  secured to cone surface  46  and arranged in concentric, spaced-apart inner rows  81   a,    82   a,    83   a,  respectively. 
     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 the heel surface  44 . Gage inserts  80  function primarily to cut the corner of the borehole. Binary row inserts  70  function primarily to scrape the borehole wall and limit the scraping action of gage inserts  80  thereby preventing gage inserts  80  from wearing as rapidly as might otherwise occur. Inner row cutter elements  81 ,  82 ,  83  of inner rows  81   a,    82   a,    83   a  are employed to gouge and remove formation material from the remainder of the borehole bottom  7 , and thus, may also be referred to here in as “bottomhole” cutting elements. 
     Insert rows  81   a,    82   a,    83   a  are arranged and spaced on rolling cone cutter  1  so as not to interfere with rows of inner row cutter elements on the other cone cutters  2 ,  3 . Cone  1  is further provided with relatively small “ridge cutter” cutter elements  84  in nose region  42  which tend to prevent formation build-up between the cutting paths followed by adjacent rows of the more aggressive, primary inner row cutter elements from different cone cutters. Cone cutters  2  and  3  have heel, gage and inner row cutter elements and ridge cutters that are similarly, although not identically, arranged as compared to cone  1 . The arrangement of cutter elements differs between the three cones in order to maximize borehole bottom coverage, and also to provide clearance for the cutter elements on the adjacent cone cutters. 
     In the embodiment shown, inserts  60 ,  70 ,  80 - 83  each includes a generally cylindrical base portion, a central axis, and a cutting portion that extends from the base portion, and further includes a cutting surface for cutting the formation material. The base portion is secured by interference fit into a mating socket drilled into the surface of the cone cutter. In general, the cutting surface of an insert refers to the surface of the insert that extends beyond the surface of the cone cutter. 
     As shown in  FIG. 1 , bottomhole cutter elements  62  are arranged on the conical surfaces  46  of cone cutters  1 - 3  so as to “intermesh” between adjacent cones. The term “intermesh” is well known in the art and can generally be defined as the overlap of any part of at least one primary cutter element on one cone cutter with the envelope defined by the extension of cutter elements on an adjacent cutter. Intermeshing is desired to reduce balling. As a row of cutting elements of one cone intermesh between the rows of cutting elements of another cone, it dislodges formation stuck between the rows of cutting elements on the adjacent cone. Moreover, having intermesh allows the diameter of the cones to be larger, providing for a larger bearing surface which results in a more durable cone. As shown in  FIG. 2 , grooves  49  allow bottomhole cutter elements  62  on adjacent cone cutters to intermesh farther between the cones  1 - 3 . In some cases, selected cutting elements may be arranged to intermesh over 50% of their length, wherein an intermeshed cutting element of one cone is overlapped over 50% of its length by a cutting element from an adjacent cone. 
     In some drilling applications, such as the drilling of carbonates in the Middle East, the relatively close spacing of cutting elements  80 ,  81  on cones  1 - 3  causes rows  80   a,    81   a  to experience “balling” or “balling-up” of cuttings between them. Balling also tends to occur on other places on cones  1 - 3 , such as between inner rows  81   a,    82   a,    83   a . When bit balling occurs, it impedes the progress and ROP of the bit by preventing the cutting elements from penetrating completely into the earth formation, thereby tending to reduce the rate of penetration. 
     To address bit balling in these and other applications, nozzles have been typically placed along the outer periphery of the bit between each pair of cones to clean cuttings from the cones and/or the borehole bottom. In some cases, an additional nozzle is also positioned at the center of the bit in the dome region to direct fluid flow on top of the cones near the center of the bit. While these configurations have led to reduced bit balling, bit balling still frequently occurs between the cutting elements of the inner rows due to insufficient cleaning along the inner rows. To further address bit balling, a new nozzle arrangement was proposed which replaced the conventional center jet in the dome region with three smaller nozzles which were closely spaced near the center of the dome, each nozzle positioned above a cone to direct a jet of fluid on top of inner rows of the cone. While this configuration has been shown to provide enhanced cleaning of the cones it has also resulted in severe erosion of cone shell surfaces and premature loss of cutting elements from the cones. 
     The location, spacing, and orientation of these additional nozzles in the dome region have traditionally been restricted because nozzle boreholes are conventionally drilled through the pin side of the bit (e.g., through passage  24  from pin end  14 ). In particular, due to limited access to the interior dome region of the bit once the bit is assembled, for bit designs comprising multiple rows of cutting elements intermeshing between the cones, the conventional approach has been to (a) drill the nozzle bores or receptacles in the interior the dome through the pin side of the bit and (b) install the nozzles from the pin side. 
     Referring briefly to  FIG. 3 , a schematic bottom view of bit  10  and cones  1 - 3  is shown. The radially outermost reaches of cones  1 - 3  and cutter elements mounted therein (e.g., cutter elements  60 ,  70 ,  80 ,  81 ,  82 ,  83 ) define the full gage diameter of bit  10  represented by line  90 . The full gage diameter  90  defines the bit radius R measured radially from bit axis  11 . For purposes of the discussion below, the bottom of bit  10  and dome  21  may be divided into a plurality of annular regions between bit axis  11  and the full gage diameter  90 . In particular, bit  10  may be described as having a first or central dome region  92  extending radially from bit axis  11  to about 10% of the bit radius R. Moving radially outward, bit  10  also includes a second or intermediate dome region  94  extending from central dome region  92  to about 50% of the bit radius R, a third or outer dome region  96  extending from intermediate dome region  94  to about 90% of the bit radius R, and a fourth or radially outermost gage dome region  98  extending from outer dome region  96  to full gage diameter  90  (i.e., extending to 100% the bit radius R). 
     Referring briefly to  FIG. 4 , the profiles of all three cones  1 - 3  and associated cutting elements are shown rotated into a single profile termed herein the “composite rotated profile view.” In the composite rotated profile view, the overlap of the cutting profiles of cutting elements within each row is shown, as well as the overlap of different rows that are positioned on different cones. Consequently, the composite rotated profile view illustrated in  FIG. 4  illustrates the bottomhole coverage of the entire bit  10 . 
     Referring now to  FIG. 5 , the intermeshed relationship between the cones  1 - 3  is shown. In this view, commonly termed a “cluster view,” cone  3  is schematically represented in two halves so that the intermesh between cones  2  and  3  and between cones  1  and  3  may be simultaneously depicted. The term “intermesh” as used herein is defined to mean overlap of any part of at least one cutter element on one cone cutter with the envelope defined by the maximum extension of the cutter elements on an adjacent cutter. As shown in  FIG. 5 , each cone cutter  1 ,  2 ,  3  has an envelope  101 - 1 ,  101 - 2 ,  101 - 3 , respectively, defined by the maximum extension height of the cutter elements on that particular cone. The cutter elements that “intersect” or “break” the envelope  101 - 1 ,  101 - 2 ,  101 - 3  of an adjacent cone “intermesh” with that adjacent cone. For example, cutting elements  82 ,  83  of cone  1  break envelope  101 - 2  of cone  2 , and break envelope  101 - 3  of cone  3  and therefore intermeshes with both cone  2  and cone  3 . However, cutting elements  60 ,  70 ,  80 ,  81  and  84  of cone  1  do not break envelope  101 - 2  or  101 - 3 , and therefore, do not intermesh with either cone  2  or cone  3 . Similarly, cutting elements  82 ,  83  of cone  3  break envelope  101 - 1  of cone  1 , and break envelope  101 - 2  of cone  2  and therefore intermeshes with both cone  1  and cone  2 , while cutting elements  60 ,  70 ,  80 ,  81 , and  84  of cone  3  do not intermesh with either cone  1  or cone  2 . Still further, cutting elements  81 ,  82 ,  83  of cone  2  break envelope  101 - 1  of cone  1 , and break envelope  101 - 3  of cone  3  and therefore intermeshes with both cone land cone  3 , while cutting elements  60 ,  70 ,  80  of cone  2  do not intermesh with either cone  1  or cone  3 . 
     The intermeshing arrangement of cones  1 - 3  is also desirable to reduce balling. As a row of cutting elements of one cone intermesh between the rows of cutting elements of another cone, it dislodges balling between the rows of cutting elements on the adjacent cone. As shown in  FIG. 4 , grooves  49  allow the cutting surfaces of certain cutting elements of adjacent cone cutters  1 - 3  to pass between the cutting elements of adjacent cones  1 - 3  without contacting cone surface  46  of the adjacent cone cutter  1 - 3 . In some cases, selected cutting elements may be arranged to intermesh over 50% of their length, wherein an intermeshed cutting element of one cone is overlapped over 50% of its length by a cutting element from an adjacent cone. 
     Moreover, having intermesh allows the diameter of the cones to be larger, providing for a larger bearing surface which results in a more durable cone. In general, performance expectations of rolling cone bits typically require that the cone cutters be as large as possible within the borehole diameter so as to allow use of the maximum possible bearing size and to provide a retention depth adequate to secure the cutter element base within the cone steel. Intermeshing cutting elements of adjacent cones offers the potential to achieve maximum cone cutter diameter and still have acceptable insert retention and protrusion. 
     As best shown in  FIG. 4 , moving axially relative to cone axis  22  from proximal bit axis  11  toward backface  40 , each cone  1 - 3  may be divided into three bands or regions—an inner cone region  102 , an intermediate cone region  103 , and an outer cone region  104 . Inner cone region  102  is disposed 360° about cone axis  22  and extends axially (relative to cone axis  22 ) from proximal bit axis  11  to intermediate cone region  103 . The intersection of inner cone region  102  and intermediate cone region  103  is denoted by a first boundary line  107  generally perpendicular to cone axis  22 . Intermediate cone region  103  is disposed 360° about cone axis  22  and extends axially (relative to cone axis  22 ) from inner cone region  102  to outer cone region  104 . The intersection of intermediate cone region  103  and outer cone region  104  is denoted by a second boundary line  108  generally perpendicular to cone axis  22 . Outer cone region  104  is disposed 360° about cone axis  22  and extends from intermediate cone region  103  to cone backface  40 . 
     Intermediate cone region  103  has an associated cone shell surface  103   a,  and in this embodiment, generally includes all of the intermeshing cutting elements (e.g., cutting elements  82 ,  83 ). Inner cone region  102  has an associated cone shell surface  102   a  including nose  42 , and in this embodiment, generally includes the radially inner (relative to bit axis  11 ) non-intermeshing cutting elements (e.g., cutting elements  84 ). Outer cone region  104  has an associated cone shell surface  104   a,  and in this embodiment, generally includes the radially outer (relative to bit axis  11 ) non-intermeshing cutting elements (e.g., gage cutting elements  80  and first inner row cutting elements  81 ). 
     Referring still to  FIG. 4 , relative to the borehole bottom and the position of the cutting elements at their lowermost position (i.e., at bottom dead center), inner cone region  102  extends radially (relative to bit axis  11 ) from proximal bit axis  11  to an first radius R 102 , intermediate cone region  103  extends radially (relative to bit axis  11 ) from inner cone region  102  to a second radius R 103 , and outer cone region  104  extends radially (relative to bit axis  11 ) from intermediate region  103  to bit radius R previously described with reference to  FIG. 3 . In this embodiment, first radius R 102  is about 25% of bit radius R, and second radius R 103  is about 75% of bit radius R. 
       FIGS. 6-9  illustrate the structural design and layout of the hydraulics of bit  10 . For purposes of clarity, cones  1 - 3  and the cutting elements mounted thereon are omitted from  FIG. 6 . The resulting drilling fluid flow trajectories, cutting structure cleaning, and bottomhole cleaning of bit  10  will be described in more detail below in conjunction with  FIGS. 10-13 . 
     Referring now to  FIGS. 6-9 , bit  10  includes a central sleeve receptacle  15 , a plurality of intermediate sleeve receptacles  25 , and a plurality of outer sleeve receptacles  35 . As used herein, the phrase “sleeve receptacle” may be used to refer to a receptacle or bore in the bit body that receives a sleeve. As will be explained in more detail below, each sleeve is adapted to receive a jet or nozzle in its downstream end. In other words, a sleeve is employed to couple a jet or nozzle to a sleeve receptacle. Although receptacles  15 ,  25 ,  35  have each been described as a “sleeve receptacle,” in other embodiments, one or more of the receptacles (e.g., receptacles  15 ,  25 ,  35 ) may be tapped to directly receive a nozzle without the use of a sleeve. 
     As best shown in  FIG. 6 , central sleeve receptacle  15  is positioned proximal the center of dome  21  within central dome region  92  previously described. Outer sleeve receptacles  35  are radially positioned at the outer periphery of dome  21  within outer dome region  96  previously described. Intermediate sleeve receptacles  25  are radially positioned radially between central sleeve receptacle  15  and outer sleeve receptacles  35  within intermediate dome region  94  previously described. More specifically, referring briefly to  FIG. 7 , each outer sleeve receptacles  35  is positioned such that the center of its downstream end at dome side  21  is located at a radius R o , measured perpendicularly from bit axis  11 , preferably between 60% and 90% of the bit radius R, more preferably between 60% and 80% of the bit radius R. Further, each intermediate receptacle is positioned such that the center of its downstream end at dome side  21  is positioned at a radius R i , measured perpendicularly from bit axis  11 , preferably between 15% and 45% of the bit radius R, more preferably between 25% and 35% of the bit radius R, and even more preferably between 25% and 30% of the bit radius R. 
     Referring again to  FIGS. 6-9 , in this embodiment, intermediate sleeve receptacles  25  are uniformly spaced about 120° apart about bit axis  11 , and outer sleeve receptacles  35  are uniformly spaced about 120° apart about bit axis  11 . However, in other embodiments, one or more of the intermediate nozzle receptacles, the outer sleeve receptacles, or combinations thereof may be spaced differently. 
     In general, each leg  19  may be formed by conventional manufacturing techniques. Once leg  19  is formed, sleeve receptacles  25 ,  35  may be drilled or bored into leg  19 . It should be appreciated that intermediate sleeve receptacles  25  are in close proximity to finished journal pin  20 . Consequently, the drilling or boring operation to form receptacles  25  is preferably performed with great care and attention to avoid damaging the journal surface. 
     In this embodiment, each receptacle  15 ,  25 ,  35  is a substantially straight, cylindrical bore having a single central axis  15 ′,  25 ′,  35 ′, respectively. However, in other embodiments, one or more receptacles (e.g., receptacles  15 ,  25 ,  35 ) may include a turn or bend. In other words, in other embodiments, one or more receptacles may have a first or upstream section extending along a first central axis and a second or downstream section extending along a second central axis that is skewed relative to the first central axis as described in U.S. patent application Ser. No. 12/104,856 filed Apr. 17, 2008, and entitled “Rock Bit with Vectored Hydraulic Nozzle Sleeves”, which is hereby incorporated herein by reference in its entirety. 
     Although a central sleeve receptacle (e.g., central sleeve receptacle  15 ) is included in this embodiment, in other embodiments, the central sleeve receptacle may be omitted. Inclusion of a central sleeve receptacle may be dictated by a variety of factors including, without limitation, the size of the bit. For example, in relatively larger bits (e.g., bits a diameter greater than about 20.00 inches), there may be sufficient space on the underside (e.g., dome  21 ) for a central sleeve receptacle, intermediate sleeve receptacles (e.g., intermediate sleeve receptacles  25 ), and outer sleeve receptacles (e.g., outer sleeve receptacles  35 ). However, as the bit diameter decreases (e.g., bits having a diameter less than 20.00 inches), the intermediate sleeve receptacles are often moved radially inward toward the bit axis. If the intermediate sleeve receptacles are moved sufficiently inward, there may not be adequate space to include a central sleeve receptacle. 
     As best shown in  FIG. 7 , each bit leg  19  includes one intermediate sleeve receptacle  25  and one outer sleeve receptacle  35 . On a given leg  19 , sleeve receptacles  25 ,  35  are laterally offset and angularly spaced from the cone or journal axis  22  relative to the bit axis  11 . The radially innermost portion of each leg  19  defines a portion of central sleeve receptacle  15 . Upon assembly of legs  19  to form bit body  12 , one intermediate sleeve receptacle  25  and one outer sleeve receptacle  35  is circumferentially positioned between cone or journal axes  22  of adjacent cones  1 - 3 , and circumferentially positioned between each pair of adjacent legs  19 . Further, upon assembly of legs  19  to form bit body  12 , central sleeve receptacle  15  is formed by the radially innermost portions of legs  19 . 
     Referring now to  FIGS. 6 ,  7 , and  9 , a central sleeve  15   a  is at least partially disposed in central sleeve receptacle  15 , an intermediate sleeve  25   a  is at least partially disposed in each intermediate sleeve receptacle  25 , and an outer sleeve  35   a  is at least partially disposed in each outer sleeve receptacle  35 . In this embodiment, the geometry of the inserted portion of each sleeve  15   a,    25   a,    35   a  is adapted to mate with the geometry of its respective receptacle  15 ,  25 ,  35 . In this particular embodiment, receptacles  15 ,  25 ,  35  are cylindrical, and thus, the inserted portions of sleeves  15   a,    25   a,    35   a,  respectively, are also cylindrical. However, other suitable geometries and shapes may be employed for the sleeves and receptacles. In general, each sleeve  15   a,    25   a,    35   a  may be secured in mating sleeve receptacle  15 ,  25 ,  35 , respectively, by any suitable means including, without limitation, threading, press-fitting, welding, and retention by snap rings. However, to form a rigid connection capable of withstanding extreme downhole drilling conditions, sleeves  15   a,    25   a,    35   a  are preferably positioned in mating receptacles  15 ,  25 ,  35 , respectively, and then welded to bit body  12  from dome side  21 . 
     As best shown in  FIG. 9 , once positioned in receptacles  15 ,  25 ,  35 , each sleeve  15   a,    25   a,    35   a  has an upstream end in fluid communication with plenum  24  and a downstream end proximal or extending from dome  21 . In this embodiment, central sleeve  15   a  and intermediate sleeves  25   a  are generally flush with bit body  12 , however, outer sleeves  35   a  extend from bit body  12 . 
     As previously described, central sleeve receptacle  15  is radially positioned within central dome region  92 , outer sleeve receptacles  35  are each radially positioned within outer dome region  96 , and intermediate sleeve receptacles  25  are each radially positioned within intermediate dome region  94 . More specifically, as best shown in  FIG. 6 , the downstream end of each sleeve  25   a,    35   a  has a center  25   d,    35   d,  respectively, disposed at a radius R 25d , R 35d , respectively, measured perpendicularly from bit axis  11 . Each intermediate receptacle  25  and associated intermediate sleeve  25   a  is positioned such that each radius R 25d  is preferably between 15% and 45% of the bit radius R, more preferably between 25% and 35% of the bit radius R, and even more preferably between 25% and 30% of the bit radius R. Further, ach outer receptacle  35  and associated outer sleeve  35   a  is positioned such that each radius R 35d  is preferably between 60% and 90% of the bit radius R, more preferably between 60% and 80% of the bit radius R. An exemplary bit designed in accordance with this aspect and having a diameter of 17.5 inches includes thee outer sleeve receptacles (e.g., outer sleeve receptacles  35 ), each having a downstream exiting center (e.g., center  35   d ) radially positioned at about 70% of the bit radius (e.g., R 35d  is about 70% of radius R), and three intermediate nozzle receptacles (e.g., intermediate sleeve receptacles  25 ), each having a downstream exiting center (e.g., center  25   d ) radially positioned at about 26% of the bit radius (e.g., R 25d  is about 26% of radius R). In this embodiment, each intermediate sleeve  25   d  is disposed at substantially the same radius R 25d , and each outer sleeve  35   d  is disposed at substantially the same radius R 35d , however, in other embodiments, one or more intermediate sleeve and/or outer sleeve may be disposed at a different or unique radial position. 
     Prior to drilling, a jet or nozzle (not shown) is disposed in the downstream end of each sleeve  15   a,    25   a,    35   a . Consequently, each sleeve  15   a,    25   a,    35   a  may also be referred to as “nozzle retention sleeve.” In general, each nozzle may be secured within the downstream end of its mating nozzle retention sleeve (e.g., sleeve  15   a,    25   a,    35   a ) by any suitable means including, without limitation, mating threads, press-fitting, welding, snap rings, or combinations thereof. Each nozzle is preferably releasably received by its mating nozzle retention sleeve such that the nozzles may be replaced or changed in the field depending on the desired flow rate through each nozzle and desired flow pattern. In some embodiments, one or more of the sleeves (e.g., central sleeve  15   a ) may be “blanked,” such that the downstream end of the sleeve is completely closed off, thereby preventing the flow of drilling fluid through the sleeve. 
     For purposes of the following explanation, the nozzles secured within outer sleeves  35   a  will be referred to as “outer nozzles,” the nozzles secured within intermediate sleeves  25   a  will be referred to as “intermediate nozzles,” and the nozzle secured within central sleeve  15   a  will be referred to as the “central nozzle.” In general, the outer nozzles, the intermediate nozzles, and the central nozzle may be any suitable type of nozzle including, without limitation, straight bore nozzles, multistage nozzles, diffusing nozzles, etc. In a straight bore nozzle, the area of the nozzle throat is generally the same size as the nozzle outlet. In a multistage nozzle, the upstream portion of the nozzle has a converging section and the downstream end includes a distributor having a plurality of exit holes, usually three exit holes. Drilling fluid flowing through a multistage nozzle is accelerated towards the distributor, where the fluid flow is divided into multiple streams by the distributor, which may target different areas of the bit and/or borehole. Due to impingement with the distributor, streams of drilling fluid exiting a multistage nozzle tend to have lower velocities and energy, and thus, generally present a reduced likelihood of causing cone erosion. A variety of multistage nozzles are described in U.S. Pat. Nos. 6,585,063 and 7,188,682, each of which is incorporated herein by reference in its entirety. In a diffusing nozzle, the outlet portion diverges from a smaller diameter portion within the orifice. Consequently, drilling fluid exiting a diffuser nozzles diffuses and diverges so as to potentially cover an increased target cleaning area. A variety of diffusion nozzles are described in U.S. Pat. No. 5,601,153, which is hereby incorporated herein by reference in its entirety. Since cone shell erosion and associated premature loss of cutting elements is more likely with streamlined or culminated flow, the outer nozzles and intermediate nozzles are preferably diffuser nozzles, and the central nozzle is preferably a diffuser nozzle or multistage nozzle. Each nozzle is preferably formed of a wear resistant material such as cemented tungsten carbide. 
     Without being limited by this or any particular theory, the greater the nozzle orifice diameter (or the sum of the orifice diameters in a multistage nozzle), the greater the total drilling fluid volumetric flow through the nozzle. Thus, the orifice diameters of the nozzles may be sized or selected to provide the desired drilling fluid flow allocation through the plurality of nozzles. In this embodiment, each outer nozzle has an orifice of a selected minimum diameter D, and each intermediate nozzle has an orifice of a selected minimum diameter d that is less than diameter D. Consequently, a drilling fluid volumetric flow through the outer nozzles is greater than the drilling fluid volumetric flow through the intermediate nozzles. In one embodiment, the nozzle orifice diameters D, d are preferably selected to provide a drilling fluid volumetric flow allocation ranging from 45% to 80% through the outer nozzles and from 20% to 55% through the intermediate nozzles, and more preferably a drilling fluid volumetric flow of 55% to 70% through the outer nozzles and 30 to 45% through the intermediate nozzles. In embodiments including a center nozzle, preferably at least 10% of the drilling fluid volumetric flow rate is directed through the center nozzle to alleviate bit balling near the center of the cones and/or to ensure that the fluid or mud flow carrying cuttings will flow radially outward from the center of the borehole and up the annulus formed between the bit and the borehole. 
       FIGS. 10-13  illustrate the stream or trajectory of drilling fluid exiting each sleeve  25   a,    35   a  and associated nozzle (not shown). For purposes of clarity, the stream or trajectory of drilling fluid exiting center sleeve  15   a  and associated center nozzle are not shown. Although the jet or stream of drilling fluid exiting each sleeve (e.g., sleeve  25   a,    35   a ) and each nozzle (e.g., intermediate nozzle, outer nozzle, etc.) behaves in a complex manner, the general direction and orientation of discharged drilling fluid is generally represented by a projected centerline from the sleeve and nozzle outlets to simplify the discussion and to emphasize the general direction of drilling fluid flow. In particular, centerlines  25   c,    35   c  generally indicate the stream or trajectory of drilling fluid exiting sleeves  25   a,    35   a,  respectively, and the intermediate and outer nozzles, respectively, disposed therein. Centerlines  25   c,    35   c  are generally coincident with the projection of the central axis of receptacles  25 ,  35 , respectively, at its respective downstream end. Further, contact points  25   c ′,  35   c ′ generally indicate the intersection of centerlines  25   c,    35   c,  respectively, with borehole bottom  7 . Although intermediate sleeve receptacles  25  and intermediate sleeves  25   a  are disposed beneath cones  1 - 3  in  FIG. 11 , and thus, are not visible in  FIG. 11  their general location has been labeled so that the exiting point of each centerline  25   c  from its respective sleeve  25   a  and associated nozzle is clear. 
     As indicated by each centerline  35   c,  outer sleeves  35   a  and associated outer nozzles are generally positioned and oriented to direct drilling fluid generally downward toward the cutting elements between outer regions  104  of each pair of adjacent cones  1 - 3 . More specifically, the stream of drilling fluid represented by centerline  35   c  first strikes the tips of gage cutting elements  80  and inner row cutter elements  81  in outer regions  104  as they rotate between cones  1 - 3  to wash cuttings from therefrom ( FIGS. 10 and 11 ). The stream of drilling fluid represented by centerline  35   c  continues along its generally downward trajectory until it impinges borehole bottom  7  at contact points  35   c ′ to flush cuttings from the portion of borehole bottom  7  extending along outer regions  104  ( FIGS. 12 and 13 ). 
     As indicated by centerlines  25   c,  intermediate sleeves  25   a  and associated intermediate nozzles are generally positioned and oriented to direct drilling fluid generally downward toward the cutting elements between intermediate regions  103  of each pair of adjacent cones  1 - 3 . More specifically, the stream of drilling fluid represented by centerline  25   c  first strikes cutting elements  82 ,  83  in inner rows  82   a,    83   a  in intermediate regions  103  as they rotate between cones  1 - 3  to wash cuttings therefrom ( FIGS. 10 and 11 ). The stream of drilling fluid represented by centerline  25   c  continues along its generally downward trajectory until it impinges borehole bottom  7  at contact points  25   c ′ to flush cuttings from the portion of borehole bottom  7  extending along intermediate regions  103  ( FIGS. 12 and 13 ). 
     As best shown in  FIG. 8 , the orientation of each centerline  25   c,  and hence the trajectory of the drilling fluid exiting each intermediate sleeve  25   a  and associated nozzle, may also be defined in terms of a ratio of two distances measured between centerline  25   c  and each adjacent journal axis  22 . In particular, a first distance A is the shortest distance measured between centerline  25   c  and a first of the adjacent journal axes  22  (left journal axis in  FIG. 8 ), and a second distance B is the shortest distance measured between centerline  25   c  and a second of the adjacent journal axes  22  (right journal axis in  FIG. 8 ). The ratio of distance A to distance B is preferably between 0.5 and 2.0. In such case, this range would also be the same for a ratio of distance B to distance A. For most applications, such a preferred ratio of distance A to distance B will result in a drilling fluid trajectory centerline  25   a  that at least partially directed toward the cutting elements between intermediate regions  103  of each pair of adjacent cones  1 - 3 . 
     As best shown in  FIG. 11 , each intermediate sleeve receptacle  25 , intermediate sleeve  25   a,  and associated nozzles is positioned and oriented such that its respective centerline  25   c  is bounded by a first boundary plane  28  and a second boundary plane  29 . In other words, each centerline  25   c  does not intersect or cross its respective boundary planes  28 ,  29  along its path from its respective nozzle to the borehole bottom  7 . Boundary planes  28 ,  29  are circumferentially positioned between each pair of adjacent legs  19 . More specifically, each boundary plane  28 ,  29  is parallel to and passes through bit axis  11 , and is oriented at a boundary angle β 1 , β 2 , respectively, relative to a reference plane  27  that is parallel to and passes through bit axis  11 , and is circumferentially disposed at the midpoint between adjacent legs  19 . Each boundary angle β 1 , β 2  is preferably less than 30°, and more preferably less than 20°. In most applications, such orientations avoid direct impingement on top of a cone, but still allow for some oblique impingement of fluid flow across the surface of a cone. As a result, the flow impingement pressure will be lower than in conventional bits where fluid is directed to impinge directly on top of the cone shell in the dome region. 
     Although intermediate sleeve receptacles  25  and intermediate sleeves  25   a  are described as being positioned and oriented to direct drilling fluid toward the cutting elements between each pair of adjacent cones  1 - 3  to reduce the potential for cone erosion, in other embodiments, the intermediate receptacles (e.g., intermediate sleeve receptacles  25 ) and associated intermediate sleeves (e.g., intermediate sleeves  25   a ) may be positioned and oriented to direct drilling fluid toward the cone shell surface (e.g., cone shell surface  102   a,    103   a,    104   a ) of one of the cone cutters between which the intermediate sleeve is disposed. For example, in cases of extreme bit balling, it may be desirable to increase the hydraulic energy on the cone shell surface to enhance the cone cleaning capabilities. Consequently, the intermediate receptacle, intermediate sleeve, and associated nozzle may be positioned and oriented to direct drilling fluid towards the cone shell surface of one of the adjacent cones in order to disburse significantly more hydraulic energy on that cone shell surface than the adjacent cone shell surface. This offers the potential for increased cone cleaning in applications with extreme balling tendencies. The bit designer may determine how much energy to project onto a given cone shell based on a variety of factors including, without limitation, the abrasiveness of the application, the amount of hydraulic energy that will be expended thru the bit hydraulic system and the number of hours the bit will be run. For such embodiments where some cone shell impingement is desired, each boundary angle β 1 , β 2  may be as great as 50°. 
     In general, the column of exiting drilling fluid tends to increase in diameter with distance from the nozzle exit. Thus, one or more of the outer nozzle exits, intermediate nozzle exits, or combinations thereof may be extended or retracted relative to dome  21  through different nozzle designs or sleeve designs as desired to provide a fluid flow that impacts the cutting structure and borehole bottom with a desired amount of energy. For example, one or more sleeves (e.g., intermediate sleeves  25   a,  outer sleeves  35   a,  etc.) may extend from dome  21  to a point below a highest horizontal plane perpendicular to bit axis  11  intersected by the rolling cone cutters (e.g., cones  1 - 3 ). Generally, this highest plane is the plane intersected by the gage rows of inserts when positioned in an uppermost position. As shown in  FIGS. 8 and 9 , outer sleeve  35   a  extends downward from dome  21  to deliver a more concentrated impingement of fluid flow between the cones  1 - 3  and borehole bottom  7 . By positioning the downstream end of a nozzle retention sleeve, and associated nozzle, closer to the borehole bottom, the impact energy of the fluid flow striking the cutting elements and/or the borehole bottom may be increased. 
     Receptacles  25 ,  35 , sleeves  25   a,    35   a,  and associated intermediate and outer nozzles, respectively, are positioned and oriented to direct drilling fluid flow between adjacent cones  1 - 3  in a generally downward direction toward borehole bottom  7 , thereby minimizing impingement of cone shells  36 . As a result, embodiments described herein offer the potential to provide improved cleaning of both radially inner and radially outer cutter elements, and reduced likelihood of undesirable erosion of cone shells  36 . In addition, by reducing impingement of cone shells  36 , embodiments described herein also offer the potential to enhance the energy and impact force of the drilling fluid flowing across the cutting elements to borehole bottom  7 . To further reduce the potential for cone erosion, in some embodiments, one or more of the intermediate and/or outer nozzles may comprise a diffuser nozzle which diffuses fluid flow exiting the nozzle outlet. The diffuser nozzle reduces the fluid velocity at the nozzle exit which aids in reducing cone shell erosion, and also increases the surface area of cutting elements are cleaned as the fluid flows downward toward the borehole bottom. 
     Although sleeves  25   a,    35   a,  and intermediate and outer nozzles, respectively, are described as being positioned and oriented to direct drilling fluid generally downward between adjacent cones  1 - 3 , they may be slightly angled toward one of the two adjacent cones they are disposed between in order to direct drilling fluid closer to the leading side or trailing side of one of the adjacent cones. For instance, in this embodiment, each outer sleeves  35   a  and associated outer nozzles (and hence centerlines  35   c ) are slightly angled toward the leading side of cones  1 - 3 . As used herein, the phrase “leading side” may be used to refer to the side of a cone cutter that is rotating towards and into the formation, whereas the term “trailing side” may be used to refer to the side of a cone cutter that is rotating out of and away from the formation. 
     Moreover, although each centerline  25   c  is oriented similarly relative to its adjacent journal axes  22 , cones  1 - 3  and associated cutting elements, in other embodiments, the receptacles, sleeves, and/or associated nozzles may be positioned and oriented such that one or more of the drilling fluid trajectory centerlines (e.g., centerlines  25 ,  35 ) is oriented differently. This selective positioning and orienting of receptacles, sleeves, and nozzles may be done to provide an optimized flow regime for a given bit design based on a Computational Fluid Dynamic (“CFD”) analysis of the fluid flow around the bit and bottomhole during drilling. 
     Referring now to  FIGS. 6 and 11 , center sleeve  15   a  and associated center nozzle are preferably positioned and oriented to direct drilling fluid across the radially inner rows of cutting elements (e.g., cutting elements  84 ) in inner cone region  102  each cone  1 - 3 . To enable cleaning of the radially inner rows of each cone  1 - 3 , the center nozzle is preferably a multistage nozzle capable of forming three exiting streams of drilling fluid—one stream directed towards the inner rows of each cone  1 - 3 . Since the velocity and energy of the streams of drilling fluid exiting a multistage nozzle are relatively low as previously described, a center multistage nozzle may be positioned in center sleeve  15   a  to direct drilling fluid over the top of each cone  1 - 3  with a reduced risk of cone erosion. In relatively small bits having insufficient space for both intermediate receptacles and a center receptacle (e.g., bits with a diameter less than 13.5), the intermediate receptacles and sleeves may be eliminated, and their cleaning duty taken over by a multistage center nozzle. In such embodiments, the center sleeve and associated multistage center nozzle are preferably positioned and oriented to direct drilling fluid across the cutting elements in the intermediate region of each cone cutter. 
     The positioning and orientation of nozzle sleeves  15   a,    25   a,    35   a  and associated nozzles previously described offers the potential to increase the ROP and durability of bit  10  by enhancing cutting element cleaning and reducing cone shell impingement. Although preferred locations and orientations of the receptacles (e.g., receptacles  15 ,  25 ,  35 ), the sleeves (e.g., sleeves  15   a,    25   a,    35   a ), and the associated nozzles may have been described, the optimal positioning and orientation of each receptacle, sleeve, and nozzle may be varied depending on a variety of factors including, without limitation, the bit size, the formation being drilled, and the hydraulic energy provided to the bit from the surface. Thus, it should be appreciated that in other embodiments, the size, location, and orientation of each receptacle, sleeve, and nozzle may be different than that shown. 
     Embodiments described herein including three outer receptacles (e.g., outer sleeve receptacles  35 ), three intermediate receptacles (e.g., intermediate sleeve receptacles  25 ), and a center receptacle (e.g., center receptacle  15 ) are particularly suited for relatively larger bits with diameters greater than about 16.0 inches, and especially for those bits with diameters greater than about 20.00 inches. Relatively smaller bits inches may not provide sufficient space in the underside for both intermediate receptacles and a center receptacle. Consequently, in such smaller bits, the center receptacle or the intermediate receptacles may be eliminated. Moreover, in relatively smaller bits, fewer than six receptacles and nozzles may provide sufficient cleaning capability for the cutting elements and the borehole bottom. For instance, in smaller bits the surface area of the cutting structure to be cleaned is reduced. However, in relatively larger bits, the surface area of the cutting structure and borehole to be cleaned is increased, and may require additional receptacles and nozzles. Consequently, embodiments described herein including six or more receptacles are preferred for relatively larger bits having diameters greater than about 9.00 inches, and even more preferred for bits having diameters greater than about 15 inches. 
     Although the embodiment of bit  10  shown in  FIG. 9  includes a sleeve  15   a,    25   a,    35   a  in each receptacle  15 ,  25 ,  35 , in other embodiments, one or more receptacles may be bored and then tapped such that a nozzle is directly received by the receptacle, as opposed to a sleeve disposed within the receptacle. Since inclusion of a sleeve generally requires additional space, this option may be particularly suited to smaller bits where space is at a premium. 
     In some cases, it may be geometrically possible and practical to achieve the preferred drilling fluid trajectory by simply drilling or boring a straight receptacle in the dome region in alignment with the desired drilling fluid trajectory. With the sleeve coaxially disposed in the receptacle, the drilling fluid will flow through the sleeve and exit the nozzle disposed in the sleeve in a direction substantially aligned with the desired trajectory. For example, in this embodiment, receptacle  25  is a straight bore through dome  21  within which a straight cylindrical sleeve  25   a  is disposed. Receptacle  25  and sleeve  25   a  share a common central axis  25 ′ that is aligned with the desired drilling fluid trajectory centerline  25   c . Consequently, drilling fluid flowing through sleeve  25   a  and the nozzle disposed in the downstream end of sleeve  25   a  will exit along centerline  25   c . However, in other cases, it may be geometrically impossible and/or impractical to bore the nozzle receptacle in alignment with the desired drilling fluid exiting trajectory. For example, in this embodiment, due to space limitations proximal the periphery of dome  21 , outer sleeve receptacle  35  is bored through dome  21  along a centerline  35 ′ that is out of alignment with the desired drilling fluid trajectory centerline  35   c . Thus, the direction of drilling fluid flowing from plenum  24  through outer sleeve receptacle  35  must be adjusted to achieve the desired centerline  35   c . Such adjustment in the direction of the drilling fluid may be achieved by the sleeve as described in U.S. patent application Ser. No. 12/104,856 filed Apr. 17, 2008, and entitled “Rock Bit with Vectored Hydraulic Nozzle Sleeves”, which is hereby incorporated herein by reference in its entirety. 
     The portions of the cone shell (e.g., cone shell  36 ) proximal the cutting elements impinged by the drilling fluid exiting a nozzle may be coated with an abrasion resistant material to increase erosion resistance. This erosion, referred to as cone shell erosion, typically occurs in areas near the paths of mud or fluid emitted from the nozzles of the bit or in areas proximate the borehole surfaces struck by the mud or fluid flow. In the areas near the flow, the mud or fluid may strike or may be deflected onto the cones and cutters resulting in their erosion. A typical erosion resistant coating would comprise a conventional hardfacing with tungsten carbide particles or a coating of tungsten carbide. These coatings can be applied via a high velocity implantation method such as the Super D-Gun method. To reduce erosion, the cutting elements proximate a fluid flow may also be fabricated of a material with enhanced wear resistance properties. 
     Erosion of the leg forging itself may also occur as the abrasive drilling fluid flows at relatively high velocities from the plenum through the receptacles. Consequently, an erosion resistant wear sleeve may be disposed in one or more of the outer and/or intermediate receptacles. For example, referring now to  FIG. 14 , one leg  219  of a rolling cone bit is shown. Leg  219  includes an intermediate receptacle  225 . A tungsten carbide wear sleeve  225   a  is fixed in receptacle  225  and provides erosion protection to the steel leg forging. Wear sleeve  225   a  may be fixed in receptacle  225  by any suitable means including, without limitation, by welding, gluing, threading, with the use of a snap ring or combinations thereof. In this embodiment, wear sleeve  225   a  extends from the plenum  224  to an O-ring gland  227  where it abuts a nozzle assembly  230 . Nozzle assembly  230  includes a wear resistant cemented tungsten carbide nozzle  235  and a steel retaining ring  236  which is threaded into forging  110 . Although retaining ring  236  is used in this embodiment to secure nozzle  235  within receptacle  225 , in general, any suitable means may be used to install nozzle  235  including, without limitation, snap rings, nail retention, brazing, or combinations thereof. 
     The use of erosion resistant wear sleeve  225   a  is particularly useful in relatively smaller bits where larger nozzle bores are prohibitive due to the lack of available space in the smaller leg forgings. In general, the inclusion of wear sleeve  225   a  allows for higher drilling fluid flow rates through receptacle  225  nozzle than would be possible with steel due to the risk of internal erosion of the steel leg forging. 
     In the manufacture of a leg as shown in  FIGS. 7 and 8 , generally the larger the bit, the longer the milling tool needed to reach the desired location for the placement of the intermediate receptacles for the ultimate placement of the intermediate nozzles. Conventionally, milling receptacles and bores in the interior of dome  21  proximal a journal (e.g., in the dome region) has been avoided for several reasons including the increased risk of damaging the journal during milling, the time required to carefully mill close to a journal, and the longer milling tools required to reach desired locations. In general, the longer the milling tools used, the greater the vibrations and chatter experienced during milling, and the more difficult to achieve the desired tolerances for the bores drilled. However, embodiments described herein offer the potential to reduce such problems by using a weld-in sleeves that may be machined to desired tolerances and then welded or otherwise attached to the receptacles. The jet or nozzle is then disposed in the downstream end of the sleeve. An O-ring may be provided to seal between the sleeve and nozzle. The use of a weld-in sleeve is further discussed in U.S. Pat. No. 5,538,093, which is assigned to the assignee of the present invention and incorporated herein by reference. 
     Embodiments described herein offer the potential for dome side installation and/or removal of the intermediate nozzles using a suitable tool such as a tool comprising a T-wrench handle, extension, universal joint, and wrench head. This tool also permits removal of the nozzle from the bit and replacement of a different nozzle size or type as desired. The ability to mill and install nozzles from the underside of the bit permits increased flexibility in the location and orientation of nozzles in the intermediate region of the underside as compared to nozzles placed in receptacles milled through the pin side of the bit. Milling and installation through the pin side of the bit is generally limited because of the limited line of sight provided in the interior of the bit and the limited space available for maneuvering a traditional (straight) nozzle wrench for installing nozzles. Because of these limitations orientation of nozzle bores located in the intermediate region of the underside of conventional bits has been largely limited to orientations that result in direct impingement of fluid flow on top of the cones. While installation from a dome side of the bit has been discussed, it should be appreciated that in other embodiments the intermediate nozzles may be installed from the pin end. 
     Although the embodiments described herein were described as having three rolling cones cutters  1 - 3 , the principles described may also be applied to a bit having any number of cones (e.g.,  1 ,  2 ,  4 , etc.). Further, although three intermediate sleeve receptacles  25  and three outer sleeve receptacles  35  are shown in the embodiments described herein, in other embodiments any suitable number of receptacles and associated nozzles. For example, in one embodiment, a three cone bit may include two intermediate receptacles and associated nozzles and three outer receptacles and nozzles, with one intermediate receptacle and outer receptacle disposed between two pair of adjacent cones, and only an outer receptacle disposed between the third pair of adjacent cones. It is believed that this configuration may result in sufficient cleaning of the cones in many applications because the intermediate and outer nozzles between two pairs of adjacent cones may be arranged to clean opposite cones and the single outer nozzle between the third pair of adjacent cones may be arranged to clean between the intermesh of the third pair of cones and may include a diffuser nozzle such that cutting structure cleaning is provided one each of the cones near gage and intermesh regions of the cones. In such an embodiment, and center nozzle may also be added for enhanced cone cleaning near the nose portions of the cones. 
     As previously described, the placement and directionality of the receptacles and associated nozzles, as well as the nozzle sizing and nozzle extension, can significantly affect the rate of penetration for the drill bit and bit life. The optimal placement, directionality and sizing of each nozzle can change depending on the bit size, the formation type being drilled, and the hydraulic energy provided to the bit from the surface. Thus, it should be appreciated that in other embodiments, nozzle sizes, locations, orientations, and extensions may be different than that shown for embodiments herein to best suit drilling requirements for a particular application. 
     EXAMPLES 
     The following examples are given as to particular aspects of the embodiments described herein and to demonstrate the practice and advantages thereof. It is understood that the examples are given by way of illustration and are not intended to limit the specification of the claims to follow in any manner. 
     Example 1 
     Cone Shell Wall Shear Stress as a Function of Radial Position 
     A computational study was performed to compare the energy levels on the surface of each cone of a conventional three-cone bit and an embodiment of a three-cone bit in accordance with the principles herein. for two case studies. The conventional bit was a 16.00 inch three-cone bit having an intermediate nozzle positioned and oriented to direct drilling fluid on the top of each cone. The bit in accordance with the principles described herein was also a 16.00 inch bit, however, an intermediate nozzle was positioned and oriented to direct drilling fluid through the intermesh in between each pair of adjacent cones. The intermediate nozzles in both bits were of the same size and type. To determine the energy levels on the cone surfaces, the shear stress was evaluated in the area where the high velocity drilling fluid had the most direct and greatest impact on the cone shell surface. The maximum shear stresses on the cone surface for each cone was measured for both bits and then normalized. Normalizing was performed on a cone-by-cone basis by dividing the maximum shear stress measured for each cone by the maximum shear stress measured for the analogous cone of the intermesh impingement bit (i.e., the bit in accordance with the principles described herein) Thus, the normalized surface shear stress experienced by each cone of the intermesh impingement bit always had a value of one. As shown in  FIG. 15 , the surface shear stress experienced by each cone of the conventional bit was about 400% greater than that experienced by the intermesh impingement bit. 
     While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.