EP1023519A1 - Trepan a molette a disposition de tuyere amelioree - Google Patents

Trepan a molette a disposition de tuyere amelioree

Info

Publication number
EP1023519A1
EP1023519A1 EP98953355A EP98953355A EP1023519A1 EP 1023519 A1 EP1023519 A1 EP 1023519A1 EP 98953355 A EP98953355 A EP 98953355A EP 98953355 A EP98953355 A EP 98953355A EP 1023519 A1 EP1023519 A1 EP 1023519A1
Authority
EP
European Patent Office
Prior art keywords
bit body
bit
drill bit
drill
cavity
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP98953355A
Other languages
German (de)
English (en)
Inventor
Graham Macdonald Clydesdale
Alan Dee Huffstutler
Harry Morales Campos, Jr.
Edward Charles Spatz
Lawrence Lee Tso
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Campos Harry Morales Jr
CLYDESDALE, GRAHAM MACDONALD
HUFFSTUTLER ALAN DEE
SPATZ EDWARD CHARLES
TSO, LAWRENCE LEE
Halliburton Energy Services Inc
Original Assignee
Huffstutler Alan Dee
Campos Harry Morales Jr
Spatz Edward Charles
Dresser Industries Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Huffstutler Alan Dee, Campos Harry Morales Jr, Spatz Edward Charles, Dresser Industries Inc filed Critical Huffstutler Alan Dee
Publication of EP1023519A1 publication Critical patent/EP1023519A1/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/08—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.
  • 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.
  • 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.
  • FIGURE 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;
  • FIGURE 2 is a schematic drawing showing a partially exploded isometric view of a rotary cone drill bit incorporating teachings of the present invention;
  • FIGURE 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 FIGURE 2.
  • FIGURE 4 is an enlarged schematic drawing in section with portions broken away showing the lower portion of the bit body and one nozzle of FIGURE 3;
  • FIGURE 5 is a schematic showing an end view of the bit body of FIGURE 3;
  • FIGURE 6 is a schematic drawing in section taken along line 6-6 of FIGURE 3;
  • FIGURE 7 is a schematic drawing showing an isometric view of a rotary cone drill bit incorporating an alternative embodiment of the present invention.
  • FIGURE 8 is a schematic drawing showing an end view of the rotary cone drill bit of FIGURE 7;
  • FIGURE 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.
  • FIGURE 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
  • FIGURE 11 is a schematic drawing showing portions of a bit body incorporating a further embodiment of the present invention.
  • FIGURE 12 is a schematic drawing with portions broken away of an irregular section taken along lines 12-12 of FIGURE 11.
  • FIGURES 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 pm 44 for use m 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 m response to rotation of drill string 22 at the well surface .
  • drill bit 20 may be attached to drill string 22 and disposed m 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 m 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.
  • 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.
  • FIGURE 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 FIGURES 1, 2, 3, 7 and 8.
  • the various dimensions of each support arm 70 are selected to be compatible with the associated pocket 54.
  • 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 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 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 and second opening 77 are formed in
  • 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.
  • 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°) 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. For some applications, 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 FIGURE 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.
  • the length and diameter of 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 FIGURES 3 and 4 have been designated 60a, 60b and 60c.
  • nozzles 60a, 60b and 60c may have essentially the same dimensions and configurations which will result in approximately the same fluid flow rate through each nozzle 60.
  • nozzles 60c will preferably have a larger inside diameter or outlet orifice 59 as compared to nozzle 60a.
  • 60a will preferably have a larger inside diameter or outlet orifice 59 as compared to nozzles 60b.
  • nozzle 60a may have a larger outlet orifice 59 as compared with nozzles 60b and 60c.
  • nozzles 60b may have a larger outlet orifice 59 than nozzles 60c. Decreasing the size of the respective outlet orifices 59 for nozzles 60a, 60b and 60c 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 60a 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 60a may include more than one outlet orifice (not expressly shown) .
  • nozzle 60a 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 60a and possibly even nozzles 60b to minimize erosion and wear of the associated cutting structures.
  • Center nozzle 60a 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 60a and/or substantially reducing the fluid flow rate through nozzle 60a may reduce erosion and wear of the associated cutter cone assemblies 100.
  • nozzles 60b may be positioned to direct drilling fluid flow to a desired location relative to respective cutter cone assembly 100.
  • Nozzles 60c may be positioned to direct drilling fluid flow toward the bottom of borehole 24.
  • fluid flow exiting from nozzles 60c 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 60c 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 may be positioned to direct drilling fluid flow toward the bottom of borehole 24.
  • 60b and 60c may be varied to optimize the angle of drilling fluid exiting from the respective nozzles 60b and 60c to enhance cleaning of the cutting structure on the associated cutter cone assembly 100.
  • nozzle bore 130 formed in nozzle 60c 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.
  • FIGURES 5 and 6 illustrate various examples of different locations for fluid passageways 62 and their associated nozzles 60 within the respective bit body in accordance with the teachings of the present invention.
  • FIGURE 5 shows lower portion 46 with three pockets 54 spaced radially with respect to each other around the perimeter of bit body 40. For the specific example shown in FIGURE 5, seven (7) fluid passageways 62 and associated openings 61 are shown.
  • One fluid passageway 62 extends generally along longitudinal axis 50.
  • 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.
  • Bit bodies 240a, 240b and 240c incorporating alternative embodiments of the present invention are shown in FIGURES 9, 10, 11 and 12. Except for some of the differences which will be discussed later in more detail, bit bodies 240a, 240b and 240c are similar to bit body 40 and bit body 140. Bit bodies 240a, 240b and 240c may be used to manufacture a wide variety of rotary cone drill bits including drill bits 20 and 120.
  • FIGURES 9, 10 and 12 are schematic drawings showing a cross section of the respective bit body 240a, 240b and 240c.
  • each cross section is taken at an angle of approximately 120 degrees relative to the respective longitudinal axis 50. See for example FIGURE 11.
  • Bit bodies 240a, 240b and 240c may be generally described as one piece or unitary bit bodies. Upper portion 42 of each bit body 240a, 240b and 240c 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 240a, 240b and 240c preferably include generally convex exterior surface 48.
  • Middle portion 52 of each bit body 240a, 240b and 240c 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 240a, 240b and 240c.
  • the pockets are not shown in FIGURES 9, 10, 11 and 12.
  • Longitudinal axis or central axis 50 extends through each bit body 240a, 240b and 240c. Longitudinal axis 50 corresponds generally with the projected axis of rotation for the resulting drill bit.
  • bit bodies 240a, 240b and 240c 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 240a, 240b and 240c may be initially formed using conventional forging techniques appropriate for fabrication of equipment used to drill oil and gas wells. The resulting forgmgs may then be further machined to have the desired configuration and dimensions for the respective bit bodies 240a, 240b and 240c.
  • bit bodies 240a, 240b and 240c 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 240b may be particularly beneficial.
  • Bit body 240a as shown m FIGURE 9 includes enlarged cavity 256a formed within upper portion 42. Opening 258 is provided m upper portion 42 for communicating drilling fluids between an attached drill string and cavity 256a. Cavity 256a preferably has a generally uniform inside diameter portion 260 extending from opening 258 to a position intermediate bit body 240a. For some applications, cavity 256a may be formed concentric with longitudinal axis 50. Cavity 256a includes a first end defined in part by opening 258 and a second end defined m 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 256a and 256b provides additional surface area for forming respective fluid passageways 262a and 262b extending therefrom.
  • a plurality of fluid passageways 262a may be formed in bit body 240a extending between cavity 256a 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 262a adjacent to convex surface 48 to allow installing various types of nozzles or nozzle inserts within each fluid passageway 262a. As a result of forming generally parabolic surface 261 on the second end of cavity 256a disposed within bit body 240a, additional spacing is provided between adjacent fluid passageways 262a at their intersection with surface 261. For purposes of illustration, this increased spacing is designated 264a in FIGURE 9.
  • Generally parabolic surface 261 allows forming an increased number of fluid passageways 262a within bit body 240a with the optimum orientation and dimensions to optimize fluid flow from cavity 256a through respective fluid passageways 262a to the bottom of an associated borehole.
  • generally parabolic surface 261 may allow forming the same number of fluid passageways 262a with larger inside diameters.
  • bit body 240b includes enlarged cavity 256b formed in upper portion 42. Opening 258 is provided in upper portion 42 for communicating fluids between a drill string and enlarged cavity 256b.
  • cavity 256b includes inside diameter 260 and generally parabolic surface 261 as previously described with respect to cavity 256a.
  • a plurality of fluid passageways 262b are preferably formed in bit body 240b extending between cavity 256b and convex surface 48 of lower portion 46.
  • fluid passageways 262b preferably include an arc or radius of curvature relative to longitudinal axis 50. As a result, each fluid flow passageway 262b may be located to intersect convex surface 48 at a generally perpendicular angle .
  • Fluid passageways 262b are preferably formed within bit body 240b using precision casting techniques. Combining fluid passageways 262b 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 262b which may be formed within bit body 240b to optimize fluid flow therethrough.
  • End 261 of cavities 256a and 256b may have various elliptical and/or parabolic configurations as desired to optimize the location of the associated fluid passageways 262a and 262b extending respectively therefrom.
  • fluid passageway 263a and 263b which extend along longitudinal axis 50 may be eliminated if desired.
  • fluid passageways 262a, 263a, 262b and 263b are shown with approximately the same diameter.
  • the fluid passageways located closest to the outside diameter of bit bodies 240a and 240b 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 240a and 240b 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 240c incorporating a further embodiment of the present invention is shown in FIGURES 11 and 12.
  • Enlarged cavity 256c may be formed within upper portion 42 of bit body 240c.
  • the cavity 256c includes a first end defined in part by opening 258 and second end 261c.
  • end 261c is relatively flat and has a diameter corresponding approximately with inside diameter 260.
  • bit body 240c preferably includes three fluid flow passageways 262c which extend from cavity 256c to exterior surface 48 proximate the outside diameter of lower portion 46. Fluid passageways 262c extend at an angle relative to longitudinal axis 50 and relative to each other. Bit body 240c also includes fluid passageway 263c which extends along longitudinal axis 50 from end 261c to a location intermediate middle portion 52 of bit body 240c. Three additional fluid flow passageways designated 266, 267 and 268 extend formed from convex surface 48 to intersect fluid flow passageway 263c. As a result there are only four openings within end 261c of fluid cavity 256c. However, 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 263c may be larger than the inside diameter or fluid flow area of fluid passageways 262c.
  • the increased diameter may be desirable to provide desired fluid flow to passageways 266, 267 and 268.
  • the spacing between adjacent fluid passageways 262c and 263c within end 261c may be increased.
  • additional fluid passageways may be formed from convex surface 38 to intersect with fluid passageway 262c.
  • parabolic surface 261 and/or forming one or more additional fluid passageways as shown in FIGURES 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.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Abstract

L'invention concerne un trépan à cône rotatif (20) présentant un écoulement fluide amélioré à proximité du fond d'un trou de forage associé, ce qui facilite le retrait de déblais de forage et autres débris du fond du trou de forage. Le trépan comprend plusieurs passages de fluides (62) s'étendant du corps de trépan (40) à l'extérieur du trépan. Le corps de trépan peut comprendre une cavité (56) élargie à partir de laquelle s'étendent les passages de fluides. Une extrémité de la cavité comprend de préférence une ouverture (58) permettant de recevoir un fluide provenant d'une garniture de forage fixée au trépan. L'extrémité de la cavité opposée à l'ouverture peut présenter une configuration (57) généralement parabolique. Dans un mode de réalisation, une membrure d'âme s'étend à partir de la partie inférieure du corps de trépan, occupant une zone vide entre chaque ensemble cône de molette. La membrure d'âme contient de préférence plusieurs passages de fluides par lesquels un fluide de forage provenant de la garniture de forage est acheminé dans le corps de trépan, dans la membrure d'âme, et est évacué par des tuyères contiguës au fond du trou de forage associé.
EP98953355A 1997-10-14 1998-10-09 Trepan a molette a disposition de tuyere amelioree Withdrawn EP1023519A1 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US6180897P 1997-10-14 1997-10-14
US61808P 1997-10-14
PCT/US1998/021363 WO1999019597A1 (fr) 1997-10-14 1998-10-09 Trepan a molette a disposition de tuyere amelioree

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EP1023519A1 true EP1023519A1 (fr) 2000-08-02

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US (1) US20010030066A1 (fr)
EP (1) EP1023519A1 (fr)
AU (1) AU1075499A (fr)
WO (1) WO1999019597A1 (fr)

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US20110111424A1 (en) 2001-06-21 2011-05-12 Cell Signaling Technology, Inc. Analysis of ubiquitinated polypeptides
US7040423B2 (en) * 2004-02-26 2006-05-09 Smith International, Inc. Nozzle bore for high flow rates
US7694608B2 (en) * 2005-12-20 2010-04-13 Smith International, Inc. Method of manufacturing a matrix body drill bit
US20150232540A1 (en) 2006-07-11 2015-08-20 Cell Signaling Technology, Inc. Analysis of ubiquitnated polypeptides
US8678111B2 (en) 2007-11-16 2014-03-25 Baker Hughes Incorporated Hybrid drill bit and design method
EP2478177A2 (fr) 2009-09-16 2012-07-25 Baker Hughes Incorporated Ensembles de palier en carbone de diamant polycristallin divorcés externes pour trépans de forage hybrides
SA111320565B1 (ar) 2010-06-29 2014-09-10 Baker Hughes Inc لقمة تروس حفر ذات خواص مضادة للتعقب
US9782857B2 (en) 2011-02-11 2017-10-10 Baker Hughes Incorporated Hybrid drill bit having increased service life
EP2673451B1 (fr) 2011-02-11 2015-05-27 Baker Hughes Incorporated Système et procédé pour retenue de patte sur trépans hybrides
BR112014011743B1 (pt) 2011-11-15 2020-08-25 Baker Hughes Incorporated broca de perfuração de furação de terreno, método utilizando a mesma e broca de perfuração para a perfuração de um furo de poço em formações de terreno
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
WO2015179792A2 (fr) 2014-05-23 2015-11-26 Baker Hughes Incorporated Trépan hybride avec ensemble de fraise fixé mécaniquement
US11428050B2 (en) 2014-10-20 2022-08-30 Baker Hughes Holdings Llc Reverse circulation hybrid bit
CN107091056B (zh) * 2017-05-11 2023-06-09 能诚集团有限公司 一种冲击钻头及冲击钻机
CN110145237A (zh) * 2019-06-25 2019-08-20 无锡贝佳尔科技有限公司 一种用于钻孔扩孔的潜孔钻头
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US20010030066A1 (en) 2001-10-18
AU1075499A (en) 1999-05-03
WO1999019597A1 (fr) 1999-04-22

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