US20010030066A1 - Rock bit with improved nozzle placement - Google Patents
Rock bit with improved nozzle placement Download PDFInfo
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- US20010030066A1 US20010030066A1 US09/788,624 US78862401A US2001030066A1 US 20010030066 A1 US20010030066 A1 US 20010030066A1 US 78862401 A US78862401 A US 78862401A US 2001030066 A1 US2001030066 A1 US 2001030066A1
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- bit body
- bit
- drill bit
- drill
- cavity
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B10/00—Drill bits
- E21B10/08—Roller bits
- E21B10/18—Roller bits characterised by conduits or nozzles for drilling fluids
Definitions
- the present invention relates generally to rotary drill bits used in drilling boreholes in the earth, and more particularly to a drill bit with enhanced hydraulic efficiency during drilling operations.
- a typical roller cone drill bit comprises a bit body with an upper end adapted for connection to a drill string.
- a plurality of support arms typically two or three, depend from a lower end portion of the bit body with each arm having a spindle protruding radially inward and downward with respect to a projected rotational axis of the bit body.
- An enlarged cavity or passageway is typically formed in the bit body to receive drilling fluids from the drill string.
- a cutter cone assembly is generally mounted on each spindle and supported rotatably on bearings acting between the spindle and the inside of a spindle receiving cavity or chamber in the cutter cone.
- One or more nozzle openings may be formed in the bit body adjacent to the support arms.
- a nozzle is typically positioned within each opening to direct drilling fluid passing downwardly from the drill string through the bit body toward the bottom of the borehole being drilled.
- Drilling fluid is generally provided by the drill string to perform several functions including washing away material removed from the bottom of the borehole, cleaning the associated cutter cone assemblies, and carrying the cuttings radially outward and then upward within the annulus defined between the exterior of the bit body and the wall of the borehole.
- extended nozzle tubes may be attached to existing nozzles.
- the tubes typically extend from the bit body toward the bottom of an associated borehole and direct drilling fluid flow toward the outermost extremity of the drill bit. Extended nozzle tube installation often requires a time consuming welding process for attachment with the bit body which generally increases manufacturing costs.
- Nozzles formed on the exterior of a bit body may close off a portion of the fluid return area from the bottom of the associated borehole. Also, previous nozzles frequently direct fluid flow inwardly toward the center of the borehole which may hinder the flow of drilling fluid from the bottom of the borehole up the borehole annulus. Extended nozzle tubes are subject to erosion due to deflection of the angle of fluid flow that occurs within the nozzle tube and breakage due to placement of extended nozzle tubes at the outer extremity of the bit body. Broken and damaged extended nozzle tubes can also damage cutter cone assemblies or other components typically associated with a rotary cone drill bit and drill string.
- the present invention provides rotary drill bits with multiple nozzles that substantially eliminate or reduce problems associated with drilling fluid flow through and around prior rotary drill bits.
- a drill bit may comprise a one piece or unitary bit body which provides increased fluid flow near the bottom of an associated borehole, resulting in enhanced removal of cuttings and other debris from the bottom of the borehole to the well surface.
- a web member may be attached or formed on a lower portion of the bit body to occupy an area between adjacent cutter cone assemblies.
- the web member preferably contains a plurality of passageways which receive drilling fluid from the associated drill string, through the bit body, and direct the drilling fluid to respective nozzles adjacent to the extreme lower end of the web member.
- a lower portion of a bit body may contain a plurality of nozzles for directing drilling fluid flow to optimize cleaning of cutting structures associated with the drill bit and to enhance removal of cuttings and other debris from the bottom of a borehole.
- the lower portion of the bit body, or the web member may contain a plurality of threaded openings for installation of respective nozzles with matching threads. Each threaded opening may have a substantially identical diameter allowing nozzles to be used interchangeably within the lower portion of the bit body or the web member.
- the nozzles may be provided with substantially identical outside diameters corresponding with the threaded openings in the bit body and varying inside diameters or nozzle bores such that fluid flow rates through the nozzles may vary.
- Various types of mechanical fasteners other than threads may be satisfactorily used to install nozzles within opening in the lower portion of a bit body or a web member incorporating teachings of the present invention.
- a further aspect of the present invention includes the ability to vary the volume of the drilling fluid flowing through each nozzle at different locations relative to the longitudinal axis of an associated rotary drill bit and associated borehole.
- nozzles at or near the outside diameter of the lower portion of the bit body may have the largest inside diameter or nozzle bore and thus the highest fluid flow rate.
- a nozzle at or near the centermost position on the lower portion of a bit body may have the largest inside diameter or nozzle bore and thus the highest fluid flow rate.
- the inside diameter of respective nozzles may decrease to encourage establishing an outward and upward flow pattern of drilling fluid with entrained cuttings and other downhole debris.
- the configuration of nozzles and associated fluid flow rates may be modified in accordance with teachings of the present invention to satisfy particular downhole drilling conditions.
- Important technical advantages of a bit body incorporating teachings of the present invention include the ability to provide an increased number of nozzles in the lower portion of a bit body and to optimize the direction and volume of fluid flow from each nozzle. Additional nozzles allow selecting the volume of drilling fluid provided during drilling operations to promote enhanced removal of cuttings and debris from the bottom of the borehole and from around the exterior surface of associated cutter cone assemblies and up the borehole annulus. Additional nozzles may also allow a decrease in velocity of drilling fluid exiting each nozzle, while maintaining the same equivalent total fluid flow rate. Reducing fluid velocity may substantially limit erosion of associated cutting structure caused by drilling fluid flow. The location of each fluid flow passageway formed in a bit body and respective nozzle may be selected to enhance cleaning of the associated cutting structure such as a rotary cone cutter with inserts or milled teeth.
- bit body which increases the surface area available for placement of nozzles.
- the convex lower portion also allows relatively straight fluid passageways to be provided between a cavity within the bit body and the respective nozzles which will decrease pressure losses and limit internal erosion.
- Still further technical advantages of the present invention include providing a rotary cone drill bit with a web member protruding from a lower portion of a bit body, occupying void spaces between respective support arms and cutter cone assemblies.
- the web member allows fluid passageways and nozzles to be located closer to the lower extremity of the cutter cone assemblies adjacent to the bottom of the associated borehole. By decreasing the distance between the bottom of the borehole and the nozzles, cutter cone erosion may be substantially reduced or limited.
- more drilling fluid can be directed toward the bottom of the borehole and away from void spaces between the lower portion of the bit body and the bottom of the borehole to increase hydraulic efficiency of the drilling fluid to lift cuttings and debris from the bottom of the borehole through the borehole annulus.
- the web member occupies void spaces between each support arm and cutter cone assembly, where debris and cuttings may tend to collect and hinder drilling operations.
- One aspect of the present invention includes providing a rotary cone drill bit with an increased number of fluid nozzles to provide better cleaning of associated cutter cone assemblies, enhanced lifting of cuttings and other debris from the bottom of a borehole and more efficient application of hydraulic energy to the bottom of the borehole from drilling fluid exiting the nozzles.
- a resulting drill bit may have an increased penetration rate for an extended downhole drilling time as compared to rotary cone drill bits without such additional fluid nozzles.
- FIG. 1 is a schematic drawing in elevation and in section with portions broken away showing a rotary cone drill bit attached to one end of a drill string disposed in a borehole;
- FIG. 2 is a schematic drawing showing a partially exploded isometric view of a rotary cone drill bit incorporating teachings of the present invention
- FIG. 3 is a schematic drawing in section showing an exploded view of portions of the bit body and one support arm/cutter cone assembly of FIG. 2.
- FIG. 4 is an enlarged schematic drawing in section with portions broken away showing the lower portion of the bit body and one nozzle of FIG. 3;
- FIG. 5 is a schematic showing an end view of the bit body of FIG. 3;
- FIG. 6 is a schematic drawing in section taken along line 6 - 6 of FIG. 3;
- FIG. 7 is a schematic drawing showing an isometric view of a rotary cone drill bit incorporating an alternative embodiment of the present invention.
- FIG. 8 is a schematic drawing showing an end view of the rotary cone drill bit of FIG. 7;
- FIG. 9 is a schematic drawing with portions broken away of an irregular section of a bit body incorporating a further embodiment of the present invention.
- FIG. 10 is a schematic drawing with portions broken away of an irregular section of a bit body incorporating still another embodiment of the present invention.
- FIG. 11 is a schematic drawing showing portions of a bit body incorporating a further embodiment of the present invention.
- FIG. 12 is a schematic drawing with portions broken away of an irregular section taken along lines 12 - 12 of FIG. 11.
- FIGS. 1 - 12 of the drawings in which like numerals refer to like parts.
- Rotary cone drill bit 20 may sometimes be referred to as a “rotary drill bit”, “rock bit” or “roller cone drill bit”.
- Rotary cone drill bit 20 preferably includes threaded connection or pin 44 for use in attaching drill bit 20 with drill string 22 .
- Threaded connection 44 and the corresponding threaded connection (not expressly shown) associated with drill string 22 are designed to allow rotation of drill bit 20 in response to rotation of drill string 22 at the well surface.
- drill bit 20 may be attached to drill string 22 and disposed in borehole 24 .
- Annulus 26 is formed between the exterior of drill string 22 and side wall or inside diameter 28 of borehole 24 .
- drill string 22 is often used as a conduit for communicating drilling fluids and other fluids from the well surface to drill bit 20 at the bottom of borehole 24 .
- drilling fluids may be directed to flow from drill string 22 to various nozzles 60 provided in drill bit 20 .
- Cuttings formed by drill bit 20 and any other debris at the bottom of borehole 24 will preferably mix with drilling fluids exiting from nozzles 60 and return to the well surface via annulus 26 .
- Cutter cone assemblies 100 For rotary cone drill bit 20 cutting action or drilling action occurs as cutter cone assemblies 100 are rolled around the bottom of borehole 24 by rotation of drill string 22 . Cutter cone assemblies 100 cooperate with each other to form side wall 28 of borehole 24 in response to rotation of drill bit 20 . The resulting inside diameter of borehole 24 defined by wall 28 corresponds approximately with the combined outside diameter or gauge diameter of cutter cone assemblies 100 . Cutter cone assemblies 100 may sometimes be referred to as “rotary cone cutters” or “roller cone cutters.” For some applications, drilling fluid exiting from nozzles 60 may apply hydraulic energy to the bottom borehole 24 to assist cutter cone assemblies 100 in forming borehole 24 .
- drill bit 20 includes a cutting structure defined in part by cutter cone assemblies 100 and protruding inserts 104 which may scrape, gouge or crush against the sides and bottom of borehole 24 in response to the weight and rotation applied to drill bit 20 from drill string 22 .
- the position of inserts 104 for each cutter cone assembly 100 may be varied to provide the desired downhole cutting action.
- Other types of cutter cone assemblies and cutting structures may be satisfactorily used with the present invention including, but not limited to, cutter cone assemblies having milled teeth (not expressly shown) instead of inserts 104 .
- Cuttings and other debris created by drill bit 20 and its associated cutting structure may be carried from the bottom of borehole 24 to the well surface by drilling fluid exiting from nozzles 60 .
- the debris carrying fluid generally flows radially outward from beneath drill bit 20 and then flows upward toward the well surface through annulus 26 .
- Drill bit 20 preferably comprises a one-piece or unitary bit body 40 with upper portion 42 having threaded connection or pin 44 adapted to secure drill bit 20 with the lower end of drill string 22 .
- Three support arms 70 are shown attached to and extending longitudinally from bit body 40 opposite from pin 44 .
- Each support arm 70 preferably includes spindle 82 connected to and extending from inside surface 76 of the respective support arm 70 .
- An important feature of the present invention includes the ability to selectively position a plurality of nozzles 60 in lower portion 46 of bit body 40 intermediate support arms 70 .
- two nozzles 60 may be provided for cutter cone assembly 100 to increase cleaning of the respective cutting structure.
- drilling fluid flowing from nozzles 60 may be directed toward void spaces between adjacent cutter cone assemblies 100 .
- Drilling fluid flowing from one or more additional nozzles 60 may also be directed toward the bottom of borehole 24 to assist cutter cone assemblies 100 in forming borehole 24 .
- optimum cleaning of the associated cutting structures may be obtained by directing fluid flow from nozzle 60 to locations at the approximate midpoint between adjacent cutter cone assemblies 100 .
- optimum cleaning of the associated cutting structures may be obtained by directing fluid flow from nozzle 60 to locations which are closer to the leading edge of the associated cutting structures.
- Nozzles 60 will generally be positioned to avoid direct impact or impingement of cutter cone assemblies 100 with fluid flowing from respective nozzles 60 .
- bit body 40 includes lower portion 46 having a generally convex exterior surface 48 formed thereon, and middle portion 52 disposed between upper portion 42 and lower portion 46 .
- Longitudinal axis or central axis 50 extends through bit body 40 and corresponds generally with the projected axis of rotation for drill bit 20 .
- Middle portion 52 preferably has a generally cylindrical configuration with pockets 54 formed in the exterior thereof and spaced radially from each other. The number of pockets 54 is selected to correspond with the number of support arms 70 which will be attached thereto.
- the spacing between pockets 54 in the exterior of middle portion 52 is selected to correspond with desired spacing between support arms 70 and their associated cutter cone assemblies 100 .
- the spacing between pockets 54 also allows positioning nozzles 60 to optimize the flow of drilling fluid at the bottom of borehole 24 to increase removal of cuttings and penetration rate of drill bit 20 .
- bit body 40 may be fabricated or machined from a generally cylindrical, solid piece of raw material or bar stock (not shown) having the desired metallurgical characteristics for the resulting drill bit 20 .
- Bit body 40 may also be formed from an appropriately sized forging.
- bit body 40 may be formed using precision casting techniques. the present invention allows using machinery, forging and/or casting techniques as appropriate to form bit body 40 .
- Each support arm 70 has a longitudinal axis 72 extending therethrough.
- Support arms 70 are preferably mounted in their respective pockets 54 with their respective longitudinal axis 72 aligned generally parallel with each other and with longitudinal axis 50 of the associated bit body 40 .
- FIG. 3 is an exploded drawing which shows the relationship between bit body 40 , one of the support arms 70 and its associated cutter cone assembly 100 .
- Each cutter cone assembly 100 is preferably constructed and attached to its associated spindle 82 in a substantially identical manner.
- Each support arm 70 is preferably constructed and mounted in its associated pocket 54 in substantially the same manner. Therefore, only one support arm 70 and cutter cone assembly 100 will be described in detail since the same description applies generally to the other two support arms 70 and their associated cutter cone assemblies 100 .
- Support arm 70 may have a generally rectangular configuration with respect to longitudinal axis 72 .
- Support arm 70 may have various cross-sections taken normal to longitudinal axis 72 depending upon the configuration of the associated pocket 54 and other features which may be incorporated into support arm 70 in accordance with the teachings of the present invention.
- Support arm 70 includes top surface 74 , inside surface 76 , bottom edge 78 and exterior surface 80 .
- Support arm 70 also includes sides 84 and 86 which preferably extend substantially parallel with longitudinal axis 72 .
- a bit body having fluid passageways and nozzles incorporating teachings of the present invention may be satisfactorily used with support arms and cutter cone assemblies having a wide variety of designs and configurations.
- the present invention is not limited to use with support arms 70 , cutter cone assemblies 100 or the type of cutting structures shown in FIGS. 1, 2, 3 , 7 and 8 .
- each support arm 70 is selected to be compatible with the associated pocket 54 . As shown in FIGS. 2 and 3, a portion of each support arm 70 including upper end or top surface 74 and adjacent portions of inside surface 76 along with sides 84 and 86 extending therefrom, are sized to fit within the associated pocket 54 .
- Inside surface 76 may be modified as desired for various downhole applications.
- the configuration of inside surface 76 may be varied substantially between top surface 74 and bottom edge 78 .
- the configuration of inside surface 76 with respect to sides 84 and 86 may be varied depending upon the configuration of the associated pockets.
- Inside surface 76 and exterior surface 80 are contiguous at bottom edge 78 of support arm 70 .
- the portion of exterior surface 80 formed adjacent to bottom edge 78 is often referred to as shirttail surface 88 .
- first opening 75 and second opening 77 are formed in inside surface 76 of each support arm 70 .
- First post 53 and second post 55 may be formed on back wall 64 of each pocket 54 .
- Post 53 and 55 extend radially from each back wall 64 to cooperate respectively with first opening 75 and second opening 77 to position each support arm 70 within its associated pocket 54 .
- first opening 75 preferably comprises a longitudinal slot extending from top surface 74 and size to receive first post 53 therein.
- Second opening 77 preferably has a generally circular configuration to receive second post 55 therein.
- Posts 53 and 55 and openings 75 and 77 may be used to position each support arm 70 within the associated pocket 54 prior to welding.
- posts 53 and 55 may be dowels inserted into appropriate sized openings in each back wall 64 .
- Spindle 82 is preferably angled downwardly and inwardly with respect to both longitudinal axis 72 of support arm 70 and the projected axis of rotation of drill bit 20 . This orientation of spindle 82 results in the exterior of cutter cone assembly 100 engaging the side and bottom of borehole 24 during drilling operations.
- lug 170 is preferably disposed on the exterior of each support arm 70 .
- Lugs 170 are preferably formed as an integral part of respective support arms 70 and covered with hardfacing layer 172 .
- lugs 170 may be attached as a separate component to the exterior of each support arm 70 . Further information concerning lugs 170 may be found in U.S. Pat. No. 5,755,297 issued May 26, 1998.
- each cutter cone assembly 100 includes base portion 108 with a conically shaped shell or tip 106 extending therefrom.
- base portion 108 includes frustroconically shaped outer surface 110 which is preferably angled in a direction opposite from the angle of shell 106 .
- Base 108 also includes backface 112 which may be disposed adjacent to portions of inside surface 76 of the associated support arm 70 .
- Base 108 preferably includes opening 120 with chamber 114 extending therefrom. Chamber 114 extends through base 108 and into tip 106 . The dimensions of opening 120 and chamber 114 are selected to allow mounting each cutter cone assembly 100 on its associated spindle 82 .
- One or more bearing assemblies 122 may be mounted on spindle 82 and disposed between a bearing wall within chamber 114 and annular bearing surface 81 on spindle 82 .
- a conventional ball retaining system 124 may be used to secure cutter cone assembly 100 to spindle 82 .
- Cutter cone assembly 100 may be manufactured of any hardenable steel or other high strength engineering alloy which has adequate strength, toughness, and wear resistance to withstand the rigors of downhole drilling. Protection of bearing assembly 122 and any other bearings within chamber 114 , which allow rotation of cutter cone assembly 100 , can lengthen the useful service life of drill bit 20 . Once drilling debris is allowed to infiltrate between the bearing surfaces of cutter cone assembly 100 and spindle 82 , failure of drill bit 20 will follow shortly.
- the size of drill bit 20 is generally determined by the combined outside diameter or gauge diameter associated with the three cutter cone assemblies 100 .
- the position of each cutter cone assembly 100 and their combined gauge diameter relative to the projected axis of rotation of drill bit 20 is a function of the dimensions of pockets 54 and their associated support arms 70 with cutter cone assemblies 100 mounted respectively thereon.
- each pocket 54 includes back wall 64 and a pair of side walls 66 and 68 .
- the dimensions of back wall 64 and side walls 66 and 68 are selected to be compatible with the adjacent inside surface 76 and sides 84 and 86 of the associated support arm 70 .
- side walls 66 and 68 are formed at an angle of forty-five degrees (45+20) relative to back wall 64 .
- each pocket 54 preferably includes upper surface 65 formed as an integral part thereof to engage top surface 74 of the associated support arm 70 .
- lower portion 46 of bit body 40 preferably includes convex surface 48 .
- various teachings of the present invention may be satisfactorily incorporated into a bit body wherein the lower portion comprises a flat surface or a concave surface.
- enlarged cavity 56 may be formed within upper portion 42 of bit body 40 .
- Opening 58 is provided in upper portion 42 for communicating fluids between drill string 22 and cavity 56 .
- Cavity 56 preferably has a generally uniform inside diameter extending from opening 58 to a position intermediate bit body 40 .
- Second end of cavity 56 opposite from opening 58 has a generally spherical configuration.
- cavity 56 may be formed concentric with longitudinal axis 50 of bit body 40 .
- One or more fluid passageways 62 may be formed in bit body 40 extending between cavity 56 and convex surface 48 formed on lower portion 46 of bit body 40 . Opening 61 may be provided in each fluid passageway 62 adjacent to convex surface 48 . A plurality of threaded recesses 63 are preferably provided within each opening 61 to allow installing various types of nozzles or nozzle inserts 60 within each fluid passageway 62 . O-ring seal 67 may be provided with each nozzle insert 60 to prevent undesired fluid flow from the associated fluid passageway 62 through the respective nozzle bore 130 . See FIG. 4.
- nozzles 60 may be formed from tungsten carbide or other suitable materials to resist erosion from fluids flowing therethrough.
- one or more access ports may be provided in bit body 40 adjacent to openings 61 to allow lock screws or pins and/or plug welds (not expressly shown) to secure nozzles 60 within respective openings 61 .
- Nozzles 60 are preferably disposed in each fluid passageway 62 to regulate fluid flow from cavity 56 through the respective fluid passageway 62 and the associated nozzle 60 to the exterior of bit body 40 .
- Each nozzle 60 preferably include at least one outlet orifice 59 . For some applications nozzles with multiple outlet orifices may be satisfactorily used with the present invention.
- each fluid passageway 62 may be selected for some applications to provide laminar flow between cavity 56 and the respective nozzle 60 .
- the present invention allows forming fluid passageways 62 with a total fluid flow area larger than previously possible with conventional rotary cone drill bits.
- the relatively straight, large inside diameter of each passageway 62 will minimize erosion or washout of respective nozzles 60 .
- the length of nozzles 60 and associated threaded recesses 63 is selected such that the respective outlet orifices 59 are disposed adjacent to surface 48 of lower portion 46 of bit body 40 .
- the length of nozzles 60 may be increased and/or the length of nozzle bores 130 decreased such that the resulting nozzles 60 extend from lower portion 46 of bit body 40 .
- nozzles 60 shown in FIGS. 3 and 4 have been designated 60 a , 60 b and 60 c .
- nozzles 60 a , 60 b and 60 c may have essentially the same dimensions and configurations which will result in approximately the same fluid flow rate through each nozzle 60 .
- nozzles 60 c will preferably have a larger inside diameter or outlet orifice 59 as compared to nozzle 60 a .
- 60 a will preferably have a larger inside diameter or outlet orifice 59 as compared to nozzles 60 b.
- nozzle 60 a may have a larger outlet orifice 59 as compared with nozzles 60 b and 60 c .
- nozzles 60 b may have a larger outlet orifice 59 than nozzles 60 c . Decreasing the size of the respective outlet orifices 59 for nozzles 60 a , 60 b and 60 c will generally cause a corresponding decrease in the flow rate of drilling fluid exiting from each nozzle 60 . Having the largest fluid flow rate from nozzle 60 a at the center of lower portion 48 may enhance the flow of drilling fluid from the bottom of borehole 24 radially outward and upward through annulus 26 .
- nozzle 60 a may include more than one outlet orifice (not expressly shown).
- nozzle 60 a may be removed and a plug installed therein or fluid passageway 62 extending along longitudinal axis 50 may be omitted.
- the drilling fluid which will be used with the resulting rotary cone drill bit contains abrasive materials, it may be preferable to eliminate center nozzle 60 a and possibly even nozzles 60 b to minimize erosion and wear of the associated cutting structures.
- Center nozzle 60 a may also be omitted and/or the associated fluid passageway 62 closed when downhole drilling conditions require relatively high fluid flow rates through bit body 40 . Eliminating nozzle 60 a and/or substantially reducing the fluid flow rate through nozzle 60 a may reduce erosion and wear of the associated cutter cone assemblies 100 .
- nozzles 60 b may be positioned to direct drilling fluid flow to a desired location relative to respective cutter cone assembly 100 .
- Nozzles 60 c may be positioned to direct drilling fluid flow toward the bottom of borehole 24 .
- fluid flow exiting from nozzles 60 c will preferably impact the bottom of borehole 24 at a radial distance approximately one inch less than the radius of borehole 24 .
- drilling fluid exiting from nozzles 60 c will apply hydraulic energy to the bottom of borehole 24 in a manner that will encourage drilling fluid and cuttings to flow readily upward through annulus 26 .
- applying hydraulic energy to the bottom of borehole 24 at a location approximately one inch radially inward from wall 28 may enhance the penetration rate of the associated cutter cone assemblies 100 .
- the present invention allows varying the location at which fluid flow exiting from nozzles 60 will impact the bottom of borehole 24 depending upon the diameter of the respective borehole and other downhole conditions.
- the position of nozzles 60 b and 60 c may be varied to optimize the angle of drilling fluid exiting from the respective nozzles 60 b and 60 c to enhance cleaning of the cutting structure on the associated cutter cone assembly 100 .
- nozzle bore 130 formed in nozzle 60 c is generally aligned concentric with the associated fluid passageway 62 .
- a nozzle bore (not expressly shown) may be formed in one or more nozzles 60 extending at an angle from the associated fluid passageway 62 .
- drill bits having a nominal diameter larger than approximately twelve to fourteen inches in ten or more fluid passageways 62 and associated nozzles 60 may be formed within the associated bit body 40 .
- additional fluid passageway 62 and associated nozzles 60 may be added to provide the desired drilling fluid flow rate to optimize downhole performance of the associated drill bit 20 .
- An important feature of the present invention includes the ability to vary the number and position of fluid passageways 62 and associated nozzles 60 within bit body 40 without affecting the location of pockets 54 and the associated support arms 70 .
- FIG. 5 shows lower portion 46 with three pockets 54 spaced radially with respect to each other around the. perimeter of bit body 40 .
- FIG. 5 shows seven (7) fluid passageways 62 and associated openings 61 are shown.
- One fluid passageway 62 extends generally along longitudinal axis 50 .
- the other six fluid passageways 62 and associated openings 61 are spaced radially approximately one hundred twenty degrees (120°) from each other.
- each support pocket 54 may be spaced radially approximately one hundred twenty degrees (120°) from an adjacent pocket 54 .
- the radial spacing between adjacent pockets 54 and associated support arms 70 may be other than one hundred and twenty degrees.
- An example of such alternative radial spacing would be one hundred and ten degrees (110°) between respective longitudinal centerlines of a first support arm and a second support arm, one hundred and twenty degrees (120°) between respective longitudinal centerlines of the second support arm and a third support arm and one hundred and thirty degrees (130°) between respective longitudinal centerlines of the third support arm and the second support arm.
- Teachings of the present invention may also be used to provide multiple nozzles in a rotary cone drill bit having two support arms and cutter cone assemblies (not expressly shown) or four support arms and cutter cone assemblies (not expressly shown).
- Bit body 140 is essentially the same as previously described bit body 40 with the exception of web member 148 .
- Web member 148 preferably extends from lower portion 46 of bit body 140 toward associated cutter cone assemblies 200 .
- Cutter cone assemblies 200 may be similar to cutter cone assemblies 100 but proportionally smaller to provide void spaces for web member 148 to occupy between adjacent cutter cone assemblies 200 .
- web member 148 includes three legs or blades designated 149 , 150 , and 151 .
- Legs 149 , 150 and 151 may extend at an angle of approximately one hundred twenty degrees (120°) relative to each other and relative to the longitudinal center line extending through bit body 140 .
- Each cutter cone assembly 200 is preferably disposed between respective legs 149 , 150 and 151 .
- the configuration of web member 148 may be varied in accordance with teachings of the present invention to correspond with the number, dimension and location of the associated cutter cone assemblies.
- blades 149 , 150 and 151 may extend at angles other than one hundred twenty degrees (120°).
- Web member 148 preferably includes a plurality of fluid passageways (not expressly shown) which communicate with respective fluid passageways 62 extending through bit body 140 .
- a plurality of openings 161 are preferably formed in the extreme end of web member 148 opposite from convex surface 48 of bit body 140 .
- a plurality of nozzles 60 may be disposed within respective openings 161 as previously described with respect to openings 61 of bit body 40 .
- Providing web member 148 in accordance with teachings with the present invention may improve hydraulic efficiency of rotary cone drill bit 138 by placing a plurality of nozzles 60 as close as possible to the bottom of the associated borehole. For some applications, at least one nozzle 60 will be placed near the longitudinal axis associated with drill bit 138 with other nozzles 60 positioned radially outward on blades 149 , 150 , and 151 of web member 148 .
- web member 148 includes two nozzle 60 disposed in each blade 149 , 150 and 151 and one nozzle 60 disposed at the intersection of blades 149 , 150 , and 151 .
- the fluid passageways extending through web member 148 to the associated nozzles 60 will be essentially straight with no turns or sharp bends to prevent loss of drilling fluid pressure and eliminate the possibility of internal erosion.
- web member 148 is preferably formed as an integral part of bit body 140 .
- web member 148 may be attached to the bit body 140 using conventional welding techniques.
- Web member 148 and nozzles 60 cooperate with each other to sweep cuttings and other debris from the bottom of the borehole to an associated annulus area to flow upwardly to the well surface.
- nozzles 60 may be placed approximately one or two inches from the bottom of the associated borehole.
- nozzles 60 may be installed even closer to the bottom of the associated borehole.
- cutter cones assemblies 200 may be reduced as compared to cutter cone assemblies associated with similar sized drill bits.
- Cutter cone assemblies 200 and blades 149 , 150 and 151 associated with web member 148 cooperate with each other to minimize erosion thereof.
- Nozzles 60 are positioned such that maximum hydraulic energy exiting from the outlet orifice of each nozzle 60 can be used throughout the drilling operation to lift cuttings and debris from the bottom of the associated borehole and to sweep the cuttings in the direction of the associated annulus.
- the use of web member 148 and nozzles 60 eliminates generally downward flow streams of drilling fluid that may interfere with upward flow of cuttings and other borehole debris.
- Nozzles 60 can be located radially from the longitudinal axis of rotary cone drill bit 140 in various ways. Either in groups of three or each nozzle 60 may have its own unique radial and angular position.
- Bit bodies 240 a , 240 b and 240 c incorporating alternative embodiments of the present invention are shown in FIGS. 9, 10, 11 and 12 . Except for some of the differences which will be discussed later in more detail, bit bodies 240 a , 240 b and 240 c are similar to bit body 40 and bit body 140 . Bit bodies 240 a , 240 b and 240 c may be used to manufacture a wide variety of rotary cone drill bits including drill bits 20 and 120 .
- FIGS. 9, 10 and 12 are schematic drawings showing a cross section of the respective bit body 240 a , 240 b and 240 c .
- each cross section is taken at an angle of approximately 120 degrees relative to the respective longitudinal axis 50 . See for example FIG. 11.
- Bit bodies 240 a , 240 b and 240 c may be generally described as one piece or unitary bit bodies. Upper portion 42 of each bit body 240 a , 240 b and 240 c includes threaded connection or pin 44 which may be used to secure the resulting drill bit with the lower end of a drill string. Lower portion 46 of each bit body 240 a , 240 b and 240 c preferably include generally convex exterior surface 48 .
- Middle portion 52 of each bit body 240 a , 240 b and 240 c has a generally cylindrical configuration disposed between upper portion 42 and lower portion 46 .
- a plurality of pockets as previously discussed with respect to drill bits 20 and 120 are preferably formed in the exterior of each bit body 240 a , 240 b and 240 c .
- the pockets are not shown in FIGS. 9, 10, 11 and 12 .
- Longitudinal axis or central axis 50 extends through each bit body 240 a , 240 b and 240 c . Longitudinal axis 50 corresponds generally with the projected axis of rotation for the resulting drill bit.
- bit bodies 240 a , 240 b and 240 c may be fabricated or machined from a generally cylindrical, solid piece of raw material or bar stock (not expressly shown) having desired metallurgical characteristics for the resulting rotary cone drill bit.
- bit bodies 240 a , 240 b and 240 c may be initially formed using conventional forging techniques appropriate for fabrication of equipment used to drill oil and gas wells. The resulting forgings may then be further machined to have the desired configuration and dimensions for the respective bit bodies 240 a , 240 b and 240 c .
- bit bodies 240 a , 240 b and 240 c may formed using precision casting techniques (sometimes referred to as “investment castings”) in combination with various machining steps as desired. As discussed later in more detail, precision casting of bit body 240 b may be particularly beneficial.
- Bit body 240 a as shown in FIG. 9 includes enlarged cavity 256 a formed within upper portion 42 . Opening 258 is provided in upper portion 42 for communicating drilling fluids between an attached drill string and cavity 256 a .
- Cavity 256 a preferably has a generally uniform inside diameter portion 260 extending from opening 258 to a position intermediate bit body 240 a .
- cavity 256 a may be formed concentric with longitudinal axis 50 .
- Cavity 256 a includes a first end defined in part by opening 258 and a second end defined in part by surface 261 .
- surface 261 has a generally parabolic configuration extending from inside diameter portion 260 along longitudinal axis 50 .
- the resulting cross-section of enlarged cavities 256 a and 256 b provides additional surface area for forming respective fluid passageways 262 a and 262 b extending therefrom.
- a plurality of fluid passageways 262 a may be formed in bit body 240 a extending between cavity 256 a and convex surface 48 of lower portion 46 . As previously discussed for drill bits 20 and 120 , appropriate sized openings may be formed in each fluid passageway 262 a adjacent to convex surface 48 to allow installing various types of nozzles or nozzle inserts within each fluid passageway 262 a.
- bit body 240 b includes enlarged cavity 256 b formed in upper portion 42 . Opening 258 is provided in upper portion 42 for communicating fluids between a drill string and enlarged cavity 256 b .
- cavity 256 b includes inside diameter 260 and generally parabolic surface 261 as previously described with respect to cavity 256 a.
- a plurality of fluid passageways 262 b are preferably formed in bit body 240 b extending between cavity 256 b and convex surface 48 of lower portion 46 .
- fluid passageways 262 b preferably include an arc or radius of curvature relative to longitudinal axis 50 .
- each fluid flow passageway 262 b may be located to intersect convex surface 48 at a generally perpendicular angle.
- Fluid passageways 262 b are preferably formed within bit body 240 b using precision casting techniques. Combining fluid passageways 262 b having a generally smooth, gradual curve or bend with generally parabolic surface 261 provides even more flexibility in the number and location of fluid passageways 262 b which may be formed within bit body 240 b to optimize fluid flow therethrough. End 261 of cavities 256 a and 256 b may have various elliptical and/or parabolic configurations as desired to optimize the location of the associated fluid passageways 262 a and 262 b extending respectively therefrom. For some applications, fluid passageway 263 a and 263 b which extend along longitudinal axis 50 may be eliminated if desired.
- fluid passageways 262 a , 263 a , 262 b and 263 b are shown with approximately the same diameter.
- the fluid passageways located closest to the outside diameter of bit bodies 240 a and 240 b may have a larger inside diameter or fluid flow area and fluid passageways located closer to respective longitudinal axis 50 may have a smaller inside diameter or fluid flow area. This configuration will result in increasing the fluid flow rate towards the exterior of the associated drill bit.
- the fluid passageways located closest to longitudinal axis 50 may have the largest inside diameter or fluid flow area while fluid passageways located closest to the exterior or respective bit bodies 240 a and 240 b may have a smaller inside diameter or fluid flow area.
- increased fluid flow may exit from the resulting drill bit along the axis of rotation.
- Bit body 240 c incorporating a further embodiment of the present invention is shown in FIGS. 11 and 12.
- Enlarged cavity 256 c may be formed within upper portion 42 of bit body 240 c .
- the cavity 256 c includes a first end defined in part by opening 258 and second end 261 c .
- end 261 c is relatively flat and has a diameter corresponding approximately with inside diameter 260 .
- bit body 240 c preferably includes three fluid flow passageways 262 c which extend from cavity 256 c to exterior surface 48 proximate the outside diameter of lower portion 46 .
- Fluid passageways 262 c extend at an angle relative to longitudinal axis 50 and relative to each other.
- Bit body 240 c also includes fluid passageway 263 c which extends along longitudinal axis 50 from end 261 c to a location intermediate middle portion 52 of bit body 240 c .
- Three additional fluid flow passageways designated 266 , 267 and 268 extend formed from convex surface 48 to intersect fluid flow passageway 263 c .
- a total of six openings 61 are available for adjacent to convex surface for installing nozzles 60 .
- the inside diameter or flow area of fluid passageway 263 c may be larger than the inside diameter or fluid flow area of fluid passageways 262 c .
- the increased diameter may be desirable to provide desired fluid flow to passageways 266 , 267 and 268 .
- the spacing between adjacent fluid passageways 262 c and 263 c within end 261 c may be increased.
- additional fluid passageways may be formed from convex surface 38 to intersect with fluid passageway 262 c .
- parabolic surface 261 and/or forming one or more additional fluid passageways as shown in FIGS. 11 and 12 allows increasing the spacing between the intersection of fluid passageways and the respective enlarged cavity. Increasing the spacing improves manufacturability of the associated bit body and minimizing possible erosion within the second end of the respective cavity.
Abstract
A rotary cone drill bit is provided with enhanced fluid flow near the bottom of an associated borehole resulting in improved removal of cuttings and other debris from the bottom of the borehole. The drill bit includes a plurality of fluid passageways extending from the bit body to the exterior of the drill bit. The bit body may include an enlarged cavity with the fluid passageways extending therefrom. One end of the cavity preferably includes an opening to receive fluid from a drill string attached to the drill bit. The end of the cavity opposite from the opening may have a generally parabolic configuration. For one application, a web member extends from the lower portion of the bit body, occupying a void area between each cutter cone assembly. The web member preferably contains a plurality of fluid passageways which direct drilling fluid from the drill string, through the bit body, through the web member, and exiting at nozzles adjacent to the bottom of the associated borehole.
Description
- This application claims the benefit of U.S. provisional application Ser. No. 60/061,808 filed Oct. 14, 1997 entitled Rock Bit with Improved Nozzle Placement.
- The present application is related to patent application Ser. No. 08/675,626 filed Jul. 3, 1996 entitled Rotary Cone Drill Bit with Integral Stabilizers, now U.S. Pat. No. 5,755,297 issued May 26, 1998.
- The present invention relates generally to rotary drill bits used in drilling boreholes in the earth, and more particularly to a drill bit with enhanced hydraulic efficiency during drilling operations.
- Various types of rotary drill bits or rock bits may be used to form a borehole in the earth. Examples of such rock bits include roller cone drill bits or rotary cone drill bits used in drilling oil and gas wells. A typical roller cone drill bit comprises a bit body with an upper end adapted for connection to a drill string. A plurality of support arms, typically two or three, depend from a lower end portion of the bit body with each arm having a spindle protruding radially inward and downward with respect to a projected rotational axis of the bit body. An enlarged cavity or passageway is typically formed in the bit body to receive drilling fluids from the drill string.
- A cutter cone assembly is generally mounted on each spindle and supported rotatably on bearings acting between the spindle and the inside of a spindle receiving cavity or chamber in the cutter cone. One or more nozzle openings may be formed in the bit body adjacent to the support arms. A nozzle is typically positioned within each opening to direct drilling fluid passing downwardly from the drill string through the bit body toward the bottom of the borehole being drilled. Drilling fluid is generally provided by the drill string to perform several functions including washing away material removed from the bottom of the borehole, cleaning the associated cutter cone assemblies, and carrying the cuttings radially outward and then upward within the annulus defined between the exterior of the bit body and the wall of the borehole.
- In order to reduce the distance between the nozzles and the bottom of the borehole, to increase hydraulic flow, and to minimize roller cone erosion, extended nozzle tubes may be attached to existing nozzles. The tubes typically extend from the bit body toward the bottom of an associated borehole and direct drilling fluid flow toward the outermost extremity of the drill bit. Extended nozzle tube installation often requires a time consuming welding process for attachment with the bit body which generally increases manufacturing costs.
- Nozzles formed on the exterior of a bit body may close off a portion of the fluid return area from the bottom of the associated borehole. Also, previous nozzles frequently direct fluid flow inwardly toward the center of the borehole which may hinder the flow of drilling fluid from the bottom of the borehole up the borehole annulus. Extended nozzle tubes are subject to erosion due to deflection of the angle of fluid flow that occurs within the nozzle tube and breakage due to placement of extended nozzle tubes at the outer extremity of the bit body. Broken and damaged extended nozzle tubes can also damage cutter cone assemblies or other components typically associated with a rotary cone drill bit and drill string.
- With a maximum of only three nozzles available on most conventional drill bits (one nozzle per roller cone assembly), the volume and direction of the drilling fluid flow are limited. Any increase in the volume of drilling fluid supplied through the associated drill string increases the velocity of drilling fluid flowing through the nozzles, which may result in excessive erosion of adjacent roller cone assemblies and/or nozzles.
- Accordingly, a need has arisen in the art for improved rotary drill bits. The present invention provides rotary drill bits with multiple nozzles that substantially eliminate or reduce problems associated with drilling fluid flow through and around prior rotary drill bits.
- In accordance with teachings of the present invention, a drill bit may comprise a one piece or unitary bit body which provides increased fluid flow near the bottom of an associated borehole, resulting in enhanced removal of cuttings and other debris from the bottom of the borehole to the well surface. For some, applications, a web member may be attached or formed on a lower portion of the bit body to occupy an area between adjacent cutter cone assemblies. The web member preferably contains a plurality of passageways which receive drilling fluid from the associated drill string, through the bit body, and direct the drilling fluid to respective nozzles adjacent to the extreme lower end of the web member.
- In accordance with one embodiment of the present invention a lower portion of a bit body, or alternatively a web member, may contain a plurality of nozzles for directing drilling fluid flow to optimize cleaning of cutting structures associated with the drill bit and to enhance removal of cuttings and other debris from the bottom of a borehole. The lower portion of the bit body, or the web member, may contain a plurality of threaded openings for installation of respective nozzles with matching threads. Each threaded opening may have a substantially identical diameter allowing nozzles to be used interchangeably within the lower portion of the bit body or the web member. The nozzles may be provided with substantially identical outside diameters corresponding with the threaded openings in the bit body and varying inside diameters or nozzle bores such that fluid flow rates through the nozzles may vary. Various types of mechanical fasteners other than threads may be satisfactorily used to install nozzles within opening in the lower portion of a bit body or a web member incorporating teachings of the present invention.
- A further aspect of the present invention includes the ability to vary the volume of the drilling fluid flowing through each nozzle at different locations relative to the longitudinal axis of an associated rotary drill bit and associated borehole. For some applications nozzles at or near the outside diameter of the lower portion of the bit body may have the largest inside diameter or nozzle bore and thus the highest fluid flow rate. For other applications a nozzle at or near the centermost position on the lower portion of a bit body may have the largest inside diameter or nozzle bore and thus the highest fluid flow rate. As the radial distance away from the longitudinal axis of the bit body or associated borehole increases, the inside diameter of respective nozzles may decrease to encourage establishing an outward and upward flow pattern of drilling fluid with entrained cuttings and other downhole debris. The configuration of nozzles and associated fluid flow rates may be modified in accordance with teachings of the present invention to satisfy particular downhole drilling conditions.
- Important technical advantages of a bit body incorporating teachings of the present invention include the ability to provide an increased number of nozzles in the lower portion of a bit body and to optimize the direction and volume of fluid flow from each nozzle. Additional nozzles allow selecting the volume of drilling fluid provided during drilling operations to promote enhanced removal of cuttings and debris from the bottom of the borehole and from around the exterior surface of associated cutter cone assemblies and up the borehole annulus. Additional nozzles may also allow a decrease in velocity of drilling fluid exiting each nozzle, while maintaining the same equivalent total fluid flow rate. Reducing fluid velocity may substantially limit erosion of associated cutting structure caused by drilling fluid flow. The location of each fluid flow passageway formed in a bit body and respective nozzle may be selected to enhance cleaning of the associated cutting structure such as a rotary cone cutter with inserts or milled teeth.
- Other technical advantages of the present invention include providing a convex lower portion of the bit body which increases the surface area available for placement of nozzles. The convex lower portion also allows relatively straight fluid passageways to be provided between a cavity within the bit body and the respective nozzles which will decrease pressure losses and limit internal erosion.
- Still further technical advantages of the present invention include providing a rotary cone drill bit with a web member protruding from a lower portion of a bit body, occupying void spaces between respective support arms and cutter cone assemblies. The web member allows fluid passageways and nozzles to be located closer to the lower extremity of the cutter cone assemblies adjacent to the bottom of the associated borehole. By decreasing the distance between the bottom of the borehole and the nozzles, cutter cone erosion may be substantially reduced or limited. Also, more drilling fluid can be directed toward the bottom of the borehole and away from void spaces between the lower portion of the bit body and the bottom of the borehole to increase hydraulic efficiency of the drilling fluid to lift cuttings and debris from the bottom of the borehole through the borehole annulus. Furthermore, the web member occupies void spaces between each support arm and cutter cone assembly, where debris and cuttings may tend to collect and hinder drilling operations.
- One aspect of the present invention includes providing a rotary cone drill bit with an increased number of fluid nozzles to provide better cleaning of associated cutter cone assemblies, enhanced lifting of cuttings and other debris from the bottom of a borehole and more efficient application of hydraulic energy to the bottom of the borehole from drilling fluid exiting the nozzles. As a result of providing additional fluid nozzles and selecting both the direction and volume of fluid flowing through each nozzle in accordance with teachings of the present invention, a resulting drill bit may have an increased penetration rate for an extended downhole drilling time as compared to rotary cone drill bits without such additional fluid nozzles.
- For a more complete understanding of the present invention, and advantages thereof, reference is now made to the following brief descriptions, taken in conjunction with the accompanying drawings and detailed description, wherein like reference numerals represent like parts, in which:
- FIG. 1 is a schematic drawing in elevation and in section with portions broken away showing a rotary cone drill bit attached to one end of a drill string disposed in a borehole;
- FIG. 2 is a schematic drawing showing a partially exploded isometric view of a rotary cone drill bit incorporating teachings of the present invention;
- FIG. 3 is a schematic drawing in section showing an exploded view of portions of the bit body and one support arm/cutter cone assembly of FIG. 2.
- FIG. 4 is an enlarged schematic drawing in section with portions broken away showing the lower portion of the bit body and one nozzle of FIG. 3;
- FIG. 5 is a schematic showing an end view of the bit body of FIG. 3;
- FIG. 6 is a schematic drawing in section taken along line6-6 of FIG. 3;
- FIG. 7 is a schematic drawing showing an isometric view of a rotary cone drill bit incorporating an alternative embodiment of the present invention;
- FIG. 8 is a schematic drawing showing an end view of the rotary cone drill bit of FIG. 7;
- FIG. 9 is a schematic drawing with portions broken away of an irregular section of a bit body incorporating a further embodiment of the present invention;
- FIG. 10 is a schematic drawing with portions broken away of an irregular section of a bit body incorporating still another embodiment of the present invention;
- FIG. 11 is a schematic drawing showing portions of a bit body incorporating a further embodiment of the present invention; and
- FIG. 12 is a schematic drawing with portions broken away of an irregular section taken along lines12-12 of FIG. 11.
- Preferred embodiments of the present invention and some of its advantages are best understood by referring in more detail to FIGS.1-12 of the drawings, in which like numerals refer to like parts.
- For purposes of illustration, the present invention may be embodied in rotary
cone drill bit 20 of the type used in drilling a borehole in the earth. Rotarycone drill bit 20 may sometimes be referred to as a “rotary drill bit”, “rock bit” or “roller cone drill bit”. Rotarycone drill bit 20 preferably includes threaded connection or pin 44 for use in attachingdrill bit 20 withdrill string 22. Threadedconnection 44 and the corresponding threaded connection (not expressly shown) associated withdrill string 22 are designed to allow rotation ofdrill bit 20 in response to rotation ofdrill string 22 at the well surface. - As shown in FIG. 1,
drill bit 20 may be attached todrill string 22 and disposed inborehole 24.Annulus 26 is formed between the exterior ofdrill string 22 and side wall orinside diameter 28 ofborehole 24. In addition to rotatingdrill bit 20,drill string 22 is often used as a conduit for communicating drilling fluids and other fluids from the well surface to drillbit 20 at the bottom ofborehole 24. Such drilling fluids may be directed to flow fromdrill string 22 tovarious nozzles 60 provided indrill bit 20. Cuttings formed bydrill bit 20 and any other debris at the bottom ofborehole 24 will preferably mix with drilling fluids exiting fromnozzles 60 and return to the well surface viaannulus 26. - For rotary
cone drill bit 20 cutting action or drilling action occurs ascutter cone assemblies 100 are rolled around the bottom ofborehole 24 by rotation ofdrill string 22.Cutter cone assemblies 100 cooperate with each other to formside wall 28 ofborehole 24 in response to rotation ofdrill bit 20. The resulting inside diameter ofborehole 24 defined bywall 28 corresponds approximately with the combined outside diameter or gauge diameter ofcutter cone assemblies 100.Cutter cone assemblies 100 may sometimes be referred to as “rotary cone cutters” or “roller cone cutters.” For some applications, drilling fluid exiting fromnozzles 60 may apply hydraulic energy to thebottom borehole 24 to assistcutter cone assemblies 100 in formingborehole 24. - As shown in FIGS. 1, 2, and3
drill bit 20 includes a cutting structure defined in part bycutter cone assemblies 100 and protrudinginserts 104 which may scrape, gouge or crush against the sides and bottom ofborehole 24 in response to the weight and rotation applied to drillbit 20 fromdrill string 22. The position ofinserts 104 for eachcutter cone assembly 100 may be varied to provide the desired downhole cutting action. Other types of cutter cone assemblies and cutting structures may be satisfactorily used with the present invention including, but not limited to, cutter cone assemblies having milled teeth (not expressly shown) instead ofinserts 104. - Cuttings and other debris created by
drill bit 20 and its associated cutting structure may be carried from the bottom ofborehole 24 to the well surface by drilling fluid exiting fromnozzles 60. The debris carrying fluid generally flows radially outward from beneathdrill bit 20 and then flows upward toward the well surface throughannulus 26. -
Drill bit 20 preferably comprises a one-piece orunitary bit body 40 withupper portion 42 having threaded connection or pin 44 adapted to securedrill bit 20 with the lower end ofdrill string 22. Threesupport arms 70 are shown attached to and extending longitudinally frombit body 40 opposite frompin 44. Eachsupport arm 70 preferably includesspindle 82 connected to and extending frominside surface 76 of therespective support arm 70. An important feature of the present invention includes the ability to selectively position a plurality ofnozzles 60 inlower portion 46 ofbit body 40intermediate support arms 70. - For some applications, two
nozzles 60 may be provided forcutter cone assembly 100 to increase cleaning of the respective cutting structure. For some applications, drilling fluid flowing fromnozzles 60 may be directed toward void spaces between adjacentcutter cone assemblies 100. Drilling fluid flowing from one or moreadditional nozzles 60 may also be directed toward the bottom ofborehole 24 to assistcutter cone assemblies 100 in formingborehole 24. - For some downhole drilling conditions optimum cleaning of the associated cutting structures may be obtained by directing fluid flow from
nozzle 60 to locations at the approximate midpoint between adjacentcutter cone assemblies 100. For other downhole drilling conditions, optimum cleaning of the associated cutting structures may be obtained by directing fluid flow fromnozzle 60 to locations which are closer to the leading edge of the associated cutting structures.Nozzles 60 will generally be positioned to avoid direct impact or impingement ofcutter cone assemblies 100 with fluid flowing fromrespective nozzles 60. - As shown in FIGS. 2 and 3,
bit body 40 includeslower portion 46 having a generally convexexterior surface 48 formed thereon, andmiddle portion 52 disposed betweenupper portion 42 andlower portion 46. Longitudinal axis orcentral axis 50 extends throughbit body 40 and corresponds generally with the projected axis of rotation fordrill bit 20.Middle portion 52 preferably has a generally cylindrical configuration withpockets 54 formed in the exterior thereof and spaced radially from each other. The number ofpockets 54 is selected to correspond with the number ofsupport arms 70 which will be attached thereto. The spacing betweenpockets 54 in the exterior ofmiddle portion 52 is selected to correspond with desired spacing betweensupport arms 70 and their associatedcutter cone assemblies 100. The spacing betweenpockets 54 also allows positioningnozzles 60 to optimize the flow of drilling fluid at the bottom ofborehole 24 to increase removal of cuttings and penetration rate ofdrill bit 20. - For some applications,
bit body 40 may be fabricated or machined from a generally cylindrical, solid piece of raw material or bar stock (not shown) having the desired metallurgical characteristics for the resultingdrill bit 20.Bit body 40 may also be formed from an appropriately sized forging. For still other applications,bit body 40 may be formed using precision casting techniques. the present invention allows using machinery, forging and/or casting techniques as appropriate to formbit body 40. - Each
support arm 70 has alongitudinal axis 72 extending therethrough.Support arms 70 are preferably mounted in theirrespective pockets 54 with their respectivelongitudinal axis 72 aligned generally parallel with each other and withlongitudinal axis 50 of the associatedbit body 40. - FIG. 3 is an exploded drawing which shows the relationship between
bit body 40, one of thesupport arms 70 and its associatedcutter cone assembly 100. Eachcutter cone assembly 100 is preferably constructed and attached to its associatedspindle 82 in a substantially identical manner. Eachsupport arm 70 is preferably constructed and mounted in its associatedpocket 54 in substantially the same manner. Therefore, only onesupport arm 70 andcutter cone assembly 100 will be described in detail since the same description applies generally to the other twosupport arms 70 and their associatedcutter cone assemblies 100. -
Support arm 70 may have a generally rectangular configuration with respect tolongitudinal axis 72.Support arm 70 may have various cross-sections taken normal tolongitudinal axis 72 depending upon the configuration of the associatedpocket 54 and other features which may be incorporated intosupport arm 70 in accordance with the teachings of the present invention.Support arm 70 includestop surface 74, insidesurface 76,bottom edge 78 andexterior surface 80.Support arm 70 also includessides longitudinal axis 72. - A bit body having fluid passageways and nozzles incorporating teachings of the present invention may be satisfactorily used with support arms and cutter cone assemblies having a wide variety of designs and configurations. The present invention is not limited to use with
support arms 70,cutter cone assemblies 100 or the type of cutting structures shown in FIGS. 1, 2, 3, 7 and 8. - The various dimensions of each
support arm 70 are selected to be compatible with the associatedpocket 54. As shown in FIGS. 2 and 3, a portion of eachsupport arm 70 including upper end ortop surface 74 and adjacent portions ofinside surface 76 along withsides pocket 54. - Inside
surface 76 may be modified as desired for various downhole applications. The configuration ofinside surface 76 may be varied substantially betweentop surface 74 andbottom edge 78. Also, the configuration ofinside surface 76 with respect tosides surface 76 andexterior surface 80 are contiguous atbottom edge 78 ofsupport arm 70. The portion ofexterior surface 80 formed adjacent tobottom edge 78 is often referred to asshirttail surface 88. - For one embodiment of the present invention,
first opening 75 andsecond opening 77 are formed ininside surface 76 of eachsupport arm 70.First post 53 andsecond post 55 may be formed onback wall 64 of eachpocket 54.Post back wall 64 to cooperate respectively withfirst opening 75 andsecond opening 77 to position eachsupport arm 70 within its associatedpocket 54. For some applications,.first opening 75 preferably comprises a longitudinal slot extending fromtop surface 74 and size to receivefirst post 53 therein.Second opening 77 preferably has a generally circular configuration to receivesecond post 55 therein.Posts openings support arm 70 within the associatedpocket 54 prior to welding. For some applications posts 53 and 55 may be dowels inserted into appropriate sized openings in eachback wall 64. -
Spindle 82 is preferably angled downwardly and inwardly with respect to bothlongitudinal axis 72 ofsupport arm 70 and the projected axis of rotation ofdrill bit 20. This orientation ofspindle 82 results in the exterior ofcutter cone assembly 100 engaging the side and bottom ofborehole 24 during drilling operations. - For the embodiment shown in FIGS. 1, 2 and3,
lug 170 is preferably disposed on the exterior of eachsupport arm 70.Lugs 170 are preferably formed as an integral part ofrespective support arms 70 and covered withhardfacing layer 172. For some applications, lugs 170 may be attached as a separate component to the exterior of eachsupport arm 70. Furtherinformation concerning lugs 170 may be found in U.S. Pat. No. 5,755,297 issued May 26, 1998. - As shown in FIGS. 1, 2 and3, each
cutter cone assembly 100 includesbase portion 108 with a conically shaped shell ortip 106 extending therefrom. For some applications,base portion 108 includes frustroconically shapedouter surface 110 which is preferably angled in a direction opposite from the angle ofshell 106.Base 108 also includesbackface 112 which may be disposed adjacent to portions ofinside surface 76 of the associatedsupport arm 70.Base 108 preferably includesopening 120 withchamber 114 extending therefrom.Chamber 114 extends throughbase 108 and intotip 106. The dimensions ofopening 120 andchamber 114 are selected to allow mounting eachcutter cone assembly 100 on its associatedspindle 82. One or morebearing assemblies 122 may be mounted onspindle 82 and disposed between a bearing wall withinchamber 114 andannular bearing surface 81 onspindle 82. A conventionalball retaining system 124 may be used to securecutter cone assembly 100 tospindle 82. -
Cutter cone assembly 100 may be manufactured of any hardenable steel or other high strength engineering alloy which has adequate strength, toughness, and wear resistance to withstand the rigors of downhole drilling. Protection of bearingassembly 122 and any other bearings withinchamber 114, which allow rotation ofcutter cone assembly 100, can lengthen the useful service life ofdrill bit 20. Once drilling debris is allowed to infiltrate between the bearing surfaces ofcutter cone assembly 100 andspindle 82, failure ofdrill bit 20 will follow shortly. - The size of
drill bit 20 is generally determined by the combined outside diameter or gauge diameter associated with the threecutter cone assemblies 100. The position of eachcutter cone assembly 100 and their combined gauge diameter relative to the projected axis of rotation ofdrill bit 20 is a function of the dimensions ofpockets 54 and their associatedsupport arms 70 withcutter cone assemblies 100 mounted respectively thereon. - As best shown in FIGS. 2, 3,5 and 6, each
pocket 54 includes backwall 64 and a pair ofside walls back wall 64 andside walls inside surface 76 andsides support arm 70. For one application,side walls wall 64. Also, eachpocket 54 preferably includesupper surface 65 formed as an integral part thereof to engagetop surface 74 of the associatedsupport arm 70. - Additional information concerning the design and construction of
drill bit 20 such as shown in FIGS. 1, 2 and 3 may be found in U.S. Pat. U.S. 5,641,029 entitled “Rotary Cone Drill Bit Modular Arm.” As previously noted,lower portion 46 ofbit body 40 preferably includesconvex surface 48. However, various teachings of the present invention may be satisfactorily incorporated into a bit body wherein the lower portion comprises a flat surface or a concave surface. - As shown in FIG. 3,
enlarged cavity 56 may be formed withinupper portion 42 ofbit body 40.Opening 58 is provided inupper portion 42 for communicating fluids betweendrill string 22 andcavity 56.Cavity 56 preferably has a generally uniform inside diameter extending from opening 58 to a positionintermediate bit body 40. Second end ofcavity 56 opposite from opening 58 has a generally spherical configuration. For some applications,cavity 56 may be formed concentric withlongitudinal axis 50 ofbit body 40. - One or more
fluid passageways 62 may be formed inbit body 40 extending betweencavity 56 andconvex surface 48 formed onlower portion 46 ofbit body 40.Opening 61 may be provided in eachfluid passageway 62 adjacent toconvex surface 48. A plurality of threadedrecesses 63 are preferably provided within each opening 61 to allow installing various types of nozzles or nozzle inserts 60 within eachfluid passageway 62. O-ring seal 67 may be provided with eachnozzle insert 60 to prevent undesired fluid flow from the associatedfluid passageway 62 through the respective nozzle bore 130. See FIG. 4. - Various techniques are commercially available for satisfactorily installing each
nozzle 60 within its associatedopening 61. For some applications,nozzles 60 may be formed from tungsten carbide or other suitable materials to resist erosion from fluids flowing therethrough. Also, one or more access ports (not shown) may be provided inbit body 40 adjacent toopenings 61 to allow lock screws or pins and/or plug welds (not expressly shown) to securenozzles 60 withinrespective openings 61. -
Nozzles 60 are preferably disposed in eachfluid passageway 62 to regulate fluid flow fromcavity 56 through therespective fluid passageway 62 and the associatednozzle 60 to the exterior ofbit body 40. Eachnozzle 60 preferably include at least oneoutlet orifice 59. For some applications nozzles with multiple outlet orifices may be satisfactorily used with the present invention. - The length and diameter of each
fluid passageway 62 may be selected for some applications to provide laminar flow betweencavity 56 and therespective nozzle 60. The present invention allows formingfluid passageways 62 with a total fluid flow area larger than previously possible with conventional rotary cone drill bits. The relatively straight, large inside diameter of eachpassageway 62 will minimize erosion or washout ofrespective nozzles 60. - For the embodiment shown in FIGS. 3 and 4, the length of
nozzles 60 and associated threaded recesses 63 is selected such that therespective outlet orifices 59 are disposed adjacent to surface 48 oflower portion 46 ofbit body 40. For some applications, the length ofnozzles 60 may be increased and/or the length of nozzle bores 130 decreased such that the resultingnozzles 60 extend fromlower portion 46 ofbit body 40. - For purposes of illustration,
nozzles 60 shown in FIGS. 3 and 4 have been designated 60 a, 60 b and 60 c. For some applications,nozzles nozzle 60. For other applications,nozzles 60 c will preferably have a larger inside diameter oroutlet orifice 59 as compared tonozzle 60 a. For this same application, 60 a will preferably have a larger inside diameter oroutlet orifice 59 as compared tonozzles 60 b. - For still other applications,
nozzle 60 a may have alarger outlet orifice 59 as compared withnozzles nozzles 60 b may have alarger outlet orifice 59 thannozzles 60 c. Decreasing the size of therespective outlet orifices 59 fornozzles nozzle 60. Having the largest fluid flow rate fromnozzle 60 a at the center oflower portion 48 may enhance the flow of drilling fluid from the bottom ofborehole 24 radially outward and upward throughannulus 26. For still other applications,nozzle 60 a may include more than one outlet orifice (not expressly shown). - For some downhole
drilling conditions nozzle 60 a may be removed and a plug installed therein orfluid passageway 62 extending alonglongitudinal axis 50 may be omitted. For example, if the drilling fluid which will be used with the resulting rotary cone drill bit contains abrasive materials, it may be preferable to eliminatecenter nozzle 60 a and possibly even nozzles 60 b to minimize erosion and wear of the associated cutting structures.Center nozzle 60 a may also be omitted and/or the associatedfluid passageway 62 closed when downhole drilling conditions require relatively high fluid flow rates throughbit body 40. Eliminatingnozzle 60 a and/or substantially reducing the fluid flow rate throughnozzle 60 a may reduce erosion and wear of the associatedcutter cone assemblies 100. - For some applications,
nozzles 60 b may be positioned to direct drilling fluid flow to a desired location relative to respectivecutter cone assembly 100.Nozzles 60 c may be positioned to direct drilling fluid flow toward the bottom ofborehole 24. For some applications, fluid flow exiting fromnozzles 60 c will preferably impact the bottom ofborehole 24 at a radial distance approximately one inch less than the radius ofborehole 24. As a result, drilling fluid exiting fromnozzles 60 c will apply hydraulic energy to the bottom ofborehole 24 in a manner that will encourage drilling fluid and cuttings to flow readily upward throughannulus 26. Also, applying hydraulic energy to the bottom ofborehole 24 at a location approximately one inch radially inward fromwall 28 may enhance the penetration rate of the associatedcutter cone assemblies 100. The present invention allows varying the location at which fluid flow exiting fromnozzles 60 will impact the bottom ofborehole 24 depending upon the diameter of the respective borehole and other downhole conditions. - For still other applications, the position of
nozzles respective nozzles cutter cone assembly 100. - For the embodiment shown in FIG. 4, nozzle bore130 formed in
nozzle 60 c is generally aligned concentric with the associatedfluid passageway 62. For some applications, a nozzle bore (not expressly shown) may be formed in one ormore nozzles 60 extending at an angle from the associatedfluid passageway 62. For drill bits having a nominal diameter larger than approximately twelve to fourteen inches in ten or morefluid passageways 62 and associatednozzles 60 may be formed within the associatedbit body 40. As the size of rotarycone drill bit 20 increasesadditional fluid passageway 62 and associatednozzles 60 may be added to provide the desired drilling fluid flow rate to optimize downhole performance of the associateddrill bit 20. - An important feature of the present invention includes the ability to vary the number and position of
fluid passageways 62 and associatednozzles 60 withinbit body 40 without affecting the location ofpockets 54 and the associatedsupport arms 70. - FIGS. 5 and 6 illustrate various examples of different locations for
fluid passageways 62 and their associatednozzles 60 within the respective bit body in accordance with the teachings of the present invention. FIG. 5 showslower portion 46 with threepockets 54 spaced radially with respect to each other around the. perimeter ofbit body 40. For the specific example shown in FIG. 5, seven (7)fluid passageways 62 and associatedopenings 61 are shown. Onefluid passageway 62 extends generally alonglongitudinal axis 50. The other sixfluid passageways 62 and associatedopenings 61 are spaced radially approximately one hundred twenty degrees (120°) from each other. In a similar manner, eachsupport pocket 54 may be spaced radially approximately one hundred twenty degrees (120°) from anadjacent pocket 54. - For some applications the radial spacing between
adjacent pockets 54 and associatedsupport arms 70 may be other than one hundred and twenty degrees. An example of such alternative radial spacing (not expressly shown) would be one hundred and ten degrees (110°) between respective longitudinal centerlines of a first support arm and a second support arm, one hundred and twenty degrees (120°) between respective longitudinal centerlines of the second support arm and a third support arm and one hundred and thirty degrees (130°) between respective longitudinal centerlines of the third support arm and the second support arm. Teachings of the present invention may also be used to provide multiple nozzles in a rotary cone drill bit having two support arms and cutter cone assemblies (not expressly shown) or four support arms and cutter cone assemblies (not expressly shown). - Another embodiment of the present invention is represented by rotary
cone drill bit 138 andbit body 140 shown in FIGS. 7 and 8.Bit body 140 is essentially the same as previously describedbit body 40 with the exception ofweb member 148.Web member 148 preferably extends fromlower portion 46 ofbit body 140 toward associatedcutter cone assemblies 200.Cutter cone assemblies 200 may be similar tocutter cone assemblies 100 but proportionally smaller to provide void spaces forweb member 148 to occupy between adjacentcutter cone assemblies 200. - For the embodiment of the present invention as shown in FIGS. 7 and 8,
web member 148 includes three legs or blades designated 149, 150, and 151.Legs bit body 140. Eachcutter cone assembly 200 is preferably disposed betweenrespective legs web member 148 may be varied in accordance with teachings of the present invention to correspond with the number, dimension and location of the associated cutter cone assemblies. Forexample blades -
Web member 148 preferably includes a plurality of fluid passageways (not expressly shown) which communicate withrespective fluid passageways 62 extending throughbit body 140. A plurality ofopenings 161 are preferably formed in the extreme end ofweb member 148 opposite fromconvex surface 48 ofbit body 140. A plurality ofnozzles 60 may be disposed withinrespective openings 161 as previously described with respect toopenings 61 ofbit body 40. - Providing
web member 148 in accordance with teachings with the present invention may improve hydraulic efficiency of rotarycone drill bit 138 by placing a plurality ofnozzles 60 as close as possible to the bottom of the associated borehole. For some applications, at least onenozzle 60 will be placed near the longitudinal axis associated withdrill bit 138 withother nozzles 60 positioned radially outward onblades web member 148. For the embodiment shown in FIGS. 7 and 8,web member 148 includes twonozzle 60 disposed in eachblade nozzle 60 disposed at the intersection ofblades - For some applications, the fluid passageways extending through
web member 148 to the associatednozzles 60 will be essentially straight with no turns or sharp bends to prevent loss of drilling fluid pressure and eliminate the possibility of internal erosion. For some applications,web member 148 is preferably formed as an integral part ofbit body 140. For other applications,web member 148 may be attached to thebit body 140 using conventional welding techniques. -
Web member 148 andnozzles 60 cooperate with each other to sweep cuttings and other debris from the bottom of the borehole to an associated annulus area to flow upwardly to the well surface. For some applications,nozzles 60 may be placed approximately one or two inches from the bottom of the associated borehole. For other applications,nozzles 60 may be installed even closer to the bottom of the associated borehole. - For some applications, the size of
cutter cones assemblies 200 may be reduced as compared to cutter cone assemblies associated with similar sized drill bits.Cutter cone assemblies 200 andblades web member 148 cooperate with each other to minimize erosion thereof.Nozzles 60 are positioned such that maximum hydraulic energy exiting from the outlet orifice of eachnozzle 60 can be used throughout the drilling operation to lift cuttings and debris from the bottom of the associated borehole and to sweep the cuttings in the direction of the associated annulus. The use ofweb member 148 andnozzles 60 eliminates generally downward flow streams of drilling fluid that may interfere with upward flow of cuttings and other borehole debris.Nozzles 60 can be located radially from the longitudinal axis of rotarycone drill bit 140 in various ways. Either in groups of three or eachnozzle 60 may have its own unique radial and angular position. -
Bit bodies bit bodies bit body 40 andbit body 140.Bit bodies drill bits - FIGS. 9, 10 and12 are schematic drawings showing a cross section of the
respective bit body longitudinal axis 50. See for example FIG. 11. -
Bit bodies Upper portion 42 of eachbit body Lower portion 46 of eachbit body exterior surface 48. -
Middle portion 52 of eachbit body upper portion 42 andlower portion 46. A plurality of pockets as previously discussed with respect to drillbits bit body central axis 50 extends through eachbit body Longitudinal axis 50 corresponds generally with the projected axis of rotation for the resulting drill bit. - For some applications,
bit bodies bit bodies respective bit bodies bodies bit body 240 b may be particularly beneficial. -
Bit body 240 a as shown in FIG. 9 includesenlarged cavity 256 a formed withinupper portion 42.Opening 258 is provided inupper portion 42 for communicating drilling fluids between an attached drill string andcavity 256 a.Cavity 256 a preferably has a generally uniforminside diameter portion 260 extending from opening 258 to a positionintermediate bit body 240 a. For some applications,cavity 256 a may be formed concentric withlongitudinal axis 50.Cavity 256 a includes a first end defined in part by opening 258 and a second end defined in part bysurface 261. - For the embodiment of the present invention as shown in FIGS. 9 and 10,
surface 261 has a generally parabolic configuration extending frominside diameter portion 260 alonglongitudinal axis 50. The resulting cross-section ofenlarged cavities fluid passageways - A plurality of
fluid passageways 262 a may be formed inbit body 240 a extending betweencavity 256 a andconvex surface 48 oflower portion 46. As previously discussed fordrill bits fluid passageway 262 a adjacent toconvex surface 48 to allow installing various types of nozzles or nozzle inserts within eachfluid passageway 262 a. - As a result of forming generally
parabolic surface 261 on the second end ofcavity 256 a disposed withinbit body 240 a, additional spacing is provided between adjacentfluid passageways 262 a at their intersection withsurface 261. For purposes of illustration, this increased spacing is designated 264 a in FIG. 9. Generallyparabolic surface 261 allows forming an increased number offluid passageways 262 a withinbit body 240 a with the optimum orientation and dimensions to optimize fluid flow fromcavity 256 a through respectivefluid passageways 262 a to the bottom of an associated borehole. Alternative, generallyparabolic surface 261 may allow forming the same number offluid passageways 262 a with larger inside diameters. - As shown in FIG. 10,
bit body 240 b includesenlarged cavity 256 b formed inupper portion 42.Opening 258 is provided inupper portion 42 for communicating fluids between a drill string andenlarged cavity 256 b. For purposes of illustrating various features of the present invention,cavity 256 b includes insidediameter 260 and generallyparabolic surface 261 as previously described with respect tocavity 256 a. - A plurality of
fluid passageways 262 b are preferably formed inbit body 240 b extending betweencavity 256 b andconvex surface 48 oflower portion 46. As best shown in FIG. 10,fluid passageways 262 b preferably include an arc or radius of curvature relative tolongitudinal axis 50. As a result, eachfluid flow passageway 262 b may be located to intersectconvex surface 48 at a generally perpendicular angle. -
Fluid passageways 262 b are preferably formed withinbit body 240 b using precision casting techniques. Combiningfluid passageways 262 b having a generally smooth, gradual curve or bend with generallyparabolic surface 261 provides even more flexibility in the number and location offluid passageways 262 b which may be formed withinbit body 240 b to optimize fluid flow therethrough.End 261 ofcavities fluid passageways fluid passageway longitudinal axis 50 may be eliminated if desired. - For the embodiments shown in FIGS. 9 and 10,
fluid passageways bit bodies longitudinal axis 50 may have a smaller inside diameter or fluid flow area. This configuration will result in increasing the fluid flow rate towards the exterior of the associated drill bit. - For other applications, the fluid passageways located closest to
longitudinal axis 50 may have the largest inside diameter or fluid flow area while fluid passageways located closest to the exterior orrespective bit bodies -
Bit body 240 c incorporating a further embodiment of the present invention is shown in FIGS. 11 and 12.Enlarged cavity 256 c may be formed withinupper portion 42 ofbit body 240 c. Thecavity 256 c includes a first end defined in part by opening 258 andsecond end 261 c. For the embodiment shown in FIGS. 11 and 12end 261 c is relatively flat and has a diameter corresponding approximately withinside diameter 260. - For the embodiment shown in FIGS. 11 and 12,
bit body 240 c preferably includes threefluid flow passageways 262 c which extend fromcavity 256 c toexterior surface 48 proximate the outside diameter oflower portion 46.Fluid passageways 262 c extend at an angle relative tolongitudinal axis 50 and relative to each other. -
Bit body 240 c also includesfluid passageway 263 c which extends alonglongitudinal axis 50 fromend 261 c to a location intermediatemiddle portion 52 ofbit body 240 c. Three additional fluid flow passageways designated 266, 267 and 268 extend formed fromconvex surface 48 to intersectfluid flow passageway 263 c. As a result there are only four openings withinend 261 c offluid cavity 256 c. However, a total of sixopenings 61 are available for adjacent to convex surface for installingnozzles 60. - For some applications, the inside diameter or flow area of
fluid passageway 263 c may be larger than the inside diameter or fluid flow area offluid passageways 262 c. The increased diameter may be desirable to provide desired fluid flow topassageways fluid passageways fluid passageway 263 c, the spacing between adjacentfluid passageways end 261 c may be increased. - For some applications, additional fluid passageways (not expressly shown) may be formed from convex surface38 to intersect with
fluid passageway 262 c. Generally,parabolic surface 261 and/or forming one or more additional fluid passageways as shown in FIGS. 11 and 12 allows increasing the spacing between the intersection of fluid passageways and the respective enlarged cavity. Increasing the spacing improves manufacturability of the associated bit body and minimizing possible erosion within the second end of the respective cavity. - Although the present invention has been described by several embodiments, various changes and modifications may be suggested to one skilled in the art. It is intended that the present invention encompasses such changes and modifications as fall within the scope of the present appended claims.
Claims (25)
1. A rotary cone drill bit for forming a borehole, comprising:
a bit body having an upper portion adapted for connection to a drill string for rotation of the drill bit;
a number of support arms attached to the bit body and extending opposite from the upper portion, each of the support arms having a spindle connected thereto, each spindle projecting generally downwardly and inwardly with respect to its associated support arm;
a number of cutter cone assemblies equal to the number of support arms and mounted respectively on one of the spindles;
an enlarged cavity formed within the upper portion of the bit body for communicating fluids between the drill string and the cavity;
the bit body having a lower portion opposite from the upper portion;
more than four fluid passageways formed in the bit body extending between the cavity and the lower portion of the bit body; and
a nozzle disposed in each of the fluid passageways adjacent to the lower portion of the bit body.
2. The drill bit as defined by wherein the lower portion of the bit body further comprises a generally convex exterior surface formed thereon.
claim 1
3. The drill bit as defined by wherein each fluid passageway further comprises:
claim 1
an opening adjacent to the lower portion of the bit body; and
the respective opening having a threaded portion to receive the associated nozzle.
4. The drill bit as defined by wherein the threaded portion of each fluid passageway is identical in size to the threaded portion of all other fluid passageways contained within the bit body.
claim 3
5. The drill bit as defined by wherein the threaded portion of at least one opening varies in size as compared to the threaded portion of the other openings.
claim 3
6. The drill bit as defined by further comprising:
claim 1
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation of the drill bit;
at least six fluid passageways extending through the bit body at a respective angle relative to the longitudinal axis of the bit body; and
at least one nozzle positioned to direct fluid flow between each cutter cone assembly and an adjacent cutter cone assembly.
7. The drill bit as defined in wherein the cavity further comprises a generally uniform inside diameter extending from the opening to a position intermediate the bit body along a longitudinal axis of the bit body.
claim 1
8. The drill bit as defined in further comprising each nozzle having a respective outlet orifice of approximately the same size.
claim 1
9. The drill bit as defined in further comprising each nozzle having a respective outlet orifice and at least one nozzle having an outlet orifice larger than the outlet orifice of the other nozzles.
claim 1
10. The drill bit as defined by further comprising:
claim 1
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation for the drill bit;
first, second and third support arms attached to the bit body and extending therefrom with first, second and third cutter cone assemblies respectively mounted on the support arms;
the first and second support arms mounted on the exterior of the bit body spaced radially approximately one hundred ten degrees relative to each other;
the second and third support arms attached to the exterior of the bit body and spaced radially from each other approximately one hundred twenty degrees; and
the third support arm and the first support arm mounted on the exterior of the bit body and radially spaced approximately one hundred thirty degrees from each other on the exterior of the bit body.
11. The drill bit as defined in further comprising:
claim 1
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation of the drill bit; and
at least one nozzle disposed adjacent to the longitudinal axis having a fluid flow rate which is substantially greater than the fluid flow rate through the other nozzles.
12. The drill bit as defined in further comprising:
claim 1
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation of the drill bit; and
each of the nozzles spaced from the intersection of the longitudinal axis with the lower portion of the bit body whereby fluid flow from the nozzles is generally directed away from the axis of rotation of the drill bit.
13. A rotary cone drill bit for forming a borehole, comprising:
a bit body having an upper portion adapted for connection to a drill string for rotation of the drill bit;
a number of support arms attached to the bit body and extending opposite from the upper portion;
a number of cutter cone assemblies equal to the number of support arms with each cutter cone assembly rotatably mounted on one of the support arms;
a void space formed between each cutter cone assembly and the cutter cone assembly disposed adjacent thereto;
a web member extending from a lower portion of the bit body and occupying the void space between each cutter cone assembly; and
a nozzle disposed in each fluid passageway adjacent to a lower portion of the web member.
14. The drill bit of wherein the web member further comprises three blades with each blade disposed between adjacent cutter cone assemblies.
claim 13
15. The drill bit of further comprising at least one fluid passageway formed in the bit body and extending through the web member.
claim 13
16. A rotary cone drill bit for forming a borehole having a side wall and a bottom comprising:
a bit body having an upper portion with a threaded connection formed on the exterior of the upper portion for connecting the drill bit to a drill string for rotation of the drill bit;
a number of support arms attached to the bit body and extending opposite from the upper portion, each of the support arms having a spindle connected thereto, each spindle projecting generally downwardly and inwardly with respect to its associated support arm;
a number of cutter cone assemblies equal to the number of support arms with one of the cutter cone assemblies mounted respectively on each spindle for engagement with the side wall and bottom of the borehole;
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation of the drill bit;
an enlarged cavity formed within the upper portion of the bit body for communicating fluids between the drill string and the cavity;
the enlarged cavity having a generally cylindrical configuration disposed along the longitudinal axis;
the bit body having a lower portion opposite from the upper portion; and
at least six fluid passageways formed in the bit body extending between the cavity and the lower portion of the bit body.
17. The drill bit of further comprising:
claim 16
at least six of the fluid passageways extending through the bit body at an angle relative to the longitudinal axis of the bit body;
at least one additional fluid passageway extending from the cavity along the longitudinal axis to the lower portion of the bit body; and
a nozzle positioned in each fluid passageway to direct fluid flow toward the bottom of the borehole;
18. The drill bit of further comprising:
claim 16
one of the nozzles located a first distance (R1) away from the intersection of the lower portion of the bit body and the longitudinal axis, with a first inside diameter (d1);
one of the nozzles located a second distance (R2) away from the intersection of the member and the longitudinal axis, with a second inside diameter (d2);
the distance (R2) greater than the distance (R1); and
the inside diameter (d2) larger than the inside diameter (d1) creating a drilling fluid flow away from the longitudinal axis along the bottom of the borehole.
19. A rotary cone drill bit for forming a borehole comprising:
a bit body having an upper portion adapted for connection to a drill string for rotation of the drill bit;
a number of support arms attached to the bit body and extending therefrom;
a number of cutter cone assemblies equal to the number of support arms with each cutter cone assembly rotatably mounted on one of the support arms;
an enlarged cavity formed within the upper portion of the bit body;
the cavity having a first end defined in part by an opening for communicating fluids between the drill string and the cavity;
the cavity having a second end disposed within the bit body;
the second end of the cavity having a generally parabolic configuration;
a number of fluid passageways formed in the bit body extending between the second end of the cavity and a lower portion of the bit body; and
a nozzle disposed in each of the fluid passageways adjacent to the lower portion of the bit body.
20. A rotary cone drill bit for forming a borehole comprising:
a bit body having an upper portion adapted for connection to a drill string for rotation of the drill bit;
a number of support arms attached to the bit body and extending therefrom;
a number of cutter cone assemblies equal to the number of support arms with each cutter cone assembly rotatably mounted on one of the support arms;
an enlarged cavity formed within the upper portion of a bit body;
the enlarged cavity having a first end defined in part by an opening in the upper portion of the bit body for communicating drilling fluids between the drill string and the cavity;
the enlarged cavity having a second end disposed within the bit body;
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation of the drill bit;
a first fluid passageway formed in the bit body and extending from the second end of the cavity to a position spaced from a lower portion of the bit body; and
at least two additional fluid passageways formed in the bit body extending through the lower portion of the bit body and intersecting the first fluid passageway.
21. The drill bit of further comprising:
claim 20
the first fluid passageway extending along the longitudinal axis of the bit body; and
three additional fluid passageways extending through the lower portion of the bit body and intersecting the first fluid passageway.
22. A rotary cone drill bit for forming a borehole comprising:
a bit body having an upper portion adapted for connection to a drill string for rotation of the drill bits;
first, second and third support arms attached to the exterior of the bit body and extending therefrom;
a respective cutter cone assembly rotatably mounted on each of the support arms;
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation of the drill bit;
the first support arm and the second support arm spaced radially a first number of degrees from each other on the exterior of the bit body;
the second support arm and the third support spaced radially a second number of degrees from each other on the exterior of the bit body;
the third support arm spaced radially from the first support arm at a third number of degrees; and
the first number of degrees plus the second number of degrees plus the third number of degrees equal to three hundred sixty degrees.
23. The drill bit of further comprising:
claim 22
the first number of degrees approximately equal to one hundred ten;
the second number of degrees approximately equal to one hundred twenty; and
the third number of degrees approximately equal to one hundred thirty.
24. A rotary cone drill bit for forming a borehole comprising:
a bit body having an upper portion adapted for connection to a drill string for rotation of the drill bit;
the bit body having a longitudinal axis corresponding generally with a projected axis of rotation for the drill bit;
a number of support arms attached to the bit body and extending therefrom;
a number of cutter cone assemblies equal to the number of support arms with each cutter cone assembly rotatably mounted on one of the support arms;
an enlarged cavity formed within the upper portion of the bit body;
the cavity having a first end defined in part by an opening for communicating fluids between the drill string and the cavity;
the cavity having a second end disposed within the bit body;
the second end of the cavity having a generally parabolic configuration;
a number of fluid passageways formed in the bit body extending between the second end of the cavity and a lower portion of the bit body; and
at least one of the fluid passageways having a generally curved configuration relative to the longitudinal axis.
25. The drill bit of further comprising a nozzle disposed in each of the fluid passageways adjacent to the lower portion of the bit body.
claim 24
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US09/788,624 US20010030066A1 (en) | 1997-10-14 | 2001-02-16 | Rock bit with improved nozzle placement |
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US6180897P | 1997-10-14 | 1997-10-14 | |
US16937198A | 1998-10-09 | 1998-10-09 | |
US09/788,624 US20010030066A1 (en) | 1997-10-14 | 2001-02-16 | Rock bit with improved nozzle placement |
Related Parent Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US16937198A Division | 1997-10-14 | 1998-10-09 |
Publications (1)
Publication Number | Publication Date |
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US20010030066A1 true US20010030066A1 (en) | 2001-10-18 |
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Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US09/788,624 Abandoned US20010030066A1 (en) | 1997-10-14 | 2001-02-16 | Rock bit with improved nozzle placement |
Country Status (4)
Country | Link |
---|---|
US (1) | US20010030066A1 (en) |
EP (1) | EP1023519A1 (en) |
AU (1) | AU1075499A (en) |
WO (1) | WO1999019597A1 (en) |
Cited By (13)
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US20060054355A1 (en) * | 2004-02-26 | 2006-03-16 | Smith International, Inc. | Nozzle bore for PDC bits |
US20070143086A1 (en) * | 2005-12-20 | 2007-06-21 | Smith International, Inc. | Method of manufacturing a matrix body drill bit |
US20120205160A1 (en) * | 2011-02-11 | 2012-08-16 | Baker Hughes Incorporated | System and method for leg retention on hybrid bits |
US20130341017A1 (en) * | 2012-06-21 | 2013-12-26 | Yang Xu | Downhole debris removal tool capable of providing a hydraulic barrier and methods of using same |
US8950514B2 (en) | 2010-06-29 | 2015-02-10 | Baker Hughes Incorporated | Drill bits with anti-tracking features |
US9004198B2 (en) | 2009-09-16 | 2015-04-14 | Baker Hughes Incorporated | External, divorced PDC bearing assemblies for hybrid drill bits |
US9353575B2 (en) | 2011-11-15 | 2016-05-31 | Baker Hughes Incorporated | Hybrid drill bits having increased drilling efficiency |
US9782857B2 (en) | 2011-02-11 | 2017-10-10 | Baker Hughes Incorporated | Hybrid drill bit having increased service life |
US10107039B2 (en) | 2014-05-23 | 2018-10-23 | Baker Hughes Incorporated | Hybrid bit with mechanically attached roller cone elements |
US10316589B2 (en) | 2007-11-16 | 2019-06-11 | Baker Hughes, A Ge Company, Llc | Hybrid drill bit and design method |
CN110145237A (en) * | 2019-06-25 | 2019-08-20 | 无锡贝佳尔科技有限公司 | A kind of down-the-hold drill bit for bore expanded hole |
CN110561547A (en) * | 2019-09-27 | 2019-12-13 | 广东鼎泰高科精工科技有限公司 | Drill bit for target hole drilling of high TG plate |
US11428050B2 (en) | 2014-10-20 | 2022-08-30 | Baker Hughes Holdings Llc | Reverse circulation hybrid bit |
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Publication number | Priority date | Publication date | Assignee | Title |
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US20120244594A9 (en) | 1998-09-04 | 2012-09-27 | Cell Signaling Technology, Inc. | Immunoaffinity isolation of modified peptides from complex mixtures |
US7198896B2 (en) | 1998-09-04 | 2007-04-03 | Cell Signaling Technology, Inc. | Immunoaffinity isolation of modified peptides from complex mixtures |
US20110111424A1 (en) | 2001-06-21 | 2011-05-12 | Cell Signaling Technology, Inc. | Analysis of ubiquitinated polypeptides |
US20150232540A1 (en) | 2006-07-11 | 2015-08-20 | Cell Signaling Technology, Inc. | Analysis of ubiquitnated polypeptides |
CN107091056B (en) * | 2017-05-11 | 2023-06-09 | 能诚集团有限公司 | Percussion bit and percussion drill |
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US3645346A (en) * | 1970-04-29 | 1972-02-29 | Exxon Production Research Co | Erosion drilling |
US4369849A (en) * | 1980-06-05 | 1983-01-25 | Reed Rock Bit Company | Large diameter oil well drilling bit |
US4417629A (en) * | 1981-05-13 | 1983-11-29 | Reed Rock Bit Company | Drill bit and method of manufacture |
US5224560A (en) * | 1990-10-30 | 1993-07-06 | Modular Engineering | Modular drill bit |
FR2719626B1 (en) * | 1994-05-04 | 1996-07-26 | Total Sa | Anti-jamming drilling tool. |
US5755297A (en) | 1994-12-07 | 1998-05-26 | Dresser Industries, Inc. | Rotary cone drill bit with integral stabilizers |
US5641029A (en) | 1995-06-06 | 1997-06-24 | Dresser Industries, Inc. | Rotary cone drill bit modular arm |
-
1998
- 1998-10-09 EP EP98953355A patent/EP1023519A1/en not_active Withdrawn
- 1998-10-09 AU AU10754/99A patent/AU1075499A/en not_active Abandoned
- 1998-10-09 WO PCT/US1998/021363 patent/WO1999019597A1/en not_active Application Discontinuation
-
2001
- 2001-02-16 US US09/788,624 patent/US20010030066A1/en not_active Abandoned
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US7325632B2 (en) | 2004-02-26 | 2008-02-05 | Smith International, Inc. | Nozzle bore for PDC bits |
US20060054355A1 (en) * | 2004-02-26 | 2006-03-16 | Smith International, Inc. | Nozzle bore for PDC bits |
US20070143086A1 (en) * | 2005-12-20 | 2007-06-21 | Smith International, Inc. | Method of manufacturing a matrix body drill bit |
US7694608B2 (en) | 2005-12-20 | 2010-04-13 | Smith International, Inc. | Method of manufacturing a matrix body drill bit |
US10871036B2 (en) | 2007-11-16 | 2020-12-22 | Baker Hughes, A Ge Company, Llc | Hybrid drill bit and design method |
US10316589B2 (en) | 2007-11-16 | 2019-06-11 | Baker Hughes, A Ge Company, Llc | Hybrid drill bit and design method |
US9476259B2 (en) | 2008-05-02 | 2016-10-25 | Baker Hughes Incorporated | System and method for leg retention on hybrid bits |
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US9657527B2 (en) | 2010-06-29 | 2017-05-23 | Baker Hughes Incorporated | Drill bits with anti-tracking features |
US8950514B2 (en) | 2010-06-29 | 2015-02-10 | Baker Hughes Incorporated | Drill bits with anti-tracking features |
US10132122B2 (en) | 2011-02-11 | 2018-11-20 | Baker Hughes Incorporated | Earth-boring rotary tools having fixed blades and rolling cutter legs, and methods of forming same |
US9782857B2 (en) | 2011-02-11 | 2017-10-10 | Baker Hughes Incorporated | Hybrid drill bit having increased service life |
US20120205160A1 (en) * | 2011-02-11 | 2012-08-16 | Baker Hughes Incorporated | System and method for leg retention on hybrid bits |
US10072462B2 (en) | 2011-11-15 | 2018-09-11 | Baker Hughes Incorporated | Hybrid drill bits |
US9353575B2 (en) | 2011-11-15 | 2016-05-31 | Baker Hughes Incorporated | Hybrid drill bits having increased drilling efficiency |
US10190366B2 (en) | 2011-11-15 | 2019-01-29 | Baker Hughes Incorporated | Hybrid drill bits having increased drilling efficiency |
US8973662B2 (en) * | 2012-06-21 | 2015-03-10 | Baker Hughes Incorporated | Downhole debris removal tool capable of providing a hydraulic barrier and methods of using same |
US20130341017A1 (en) * | 2012-06-21 | 2013-12-26 | Yang Xu | Downhole debris removal tool capable of providing a hydraulic barrier and methods of using same |
US10107039B2 (en) | 2014-05-23 | 2018-10-23 | Baker Hughes Incorporated | Hybrid bit with mechanically attached roller cone elements |
US11428050B2 (en) | 2014-10-20 | 2022-08-30 | Baker Hughes Holdings Llc | Reverse circulation hybrid bit |
CN110145237A (en) * | 2019-06-25 | 2019-08-20 | 无锡贝佳尔科技有限公司 | A kind of down-the-hold drill bit for bore expanded hole |
CN110561547A (en) * | 2019-09-27 | 2019-12-13 | 广东鼎泰高科精工科技有限公司 | Drill bit for target hole drilling of high TG plate |
Also Published As
Publication number | Publication date |
---|---|
AU1075499A (en) | 1999-05-03 |
WO1999019597A1 (en) | 1999-04-22 |
EP1023519A1 (en) | 2000-08-02 |
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Legal Events
Date | Code | Title | Description |
---|---|---|---|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |