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EP3931421B1 - Système de forage à grande vitesse et ses procédés d'utilisation - Google Patents

Système de forage à grande vitesse et ses procédés d'utilisation Download PDF

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Publication number
EP3931421B1
EP3931421B1 EP20766044.0A EP20766044A EP3931421B1 EP 3931421 B1 EP3931421 B1 EP 3931421B1 EP 20766044 A EP20766044 A EP 20766044A EP 3931421 B1 EP3931421 B1 EP 3931421B1
Authority
EP
European Patent Office
Prior art keywords
drill
drill bit
drill string
bit
drilling
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.)
Active
Application number
EP20766044.0A
Other languages
German (de)
English (en)
Other versions
EP3931421A1 (fr
EP3931421A4 (fr
Inventor
Christopher L. Drenth
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.)
Boart Longyear Manufacturing and Distribution Inc
Original Assignee
Boart Longyear Co
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 Boart Longyear Co filed Critical Boart Longyear Co
Priority to EP25174903.2A priority Critical patent/EP4624722A1/fr
Publication of EP3931421A1 publication Critical patent/EP3931421A1/fr
Publication of EP3931421A4 publication Critical patent/EP3931421A4/fr
Application granted granted Critical
Publication of EP3931421B1 publication Critical patent/EP3931421B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

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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
    • E21B10/006—Drill bits providing a cutting edge which is self-renewable during drilling
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E21B10/54—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
    • E21B10/55—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits with preformed cutting elements
    • 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
    • E21B10/60—Drill bits characterised by conduits or nozzles for drilling fluids
    • 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
    • E21B3/00—Rotary drilling
    • E21B3/02—Surface drives for rotary drilling
    • 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
    • E21B4/00—Drives for drilling, used in the borehole
    • E21B4/003—Bearing, sealing, lubricating details
    • 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
    • E21B4/00—Drives for drilling, used in the borehole
    • E21B4/006—Mechanical motion converting means, e.g. reduction gearings
    • 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
    • E21B4/00—Drives for drilling, used in the borehole
    • E21B4/20—Drives for drilling, used in the borehole combined with surface drive
    • 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
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling
    • E21B7/046—Directional drilling horizontal drilling
    • 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
    • E21B10/60—Drill bits characterised by conduits or nozzles for drilling fluids
    • E21B10/602—Drill bits characterised by conduits or nozzles for drilling fluids the bit being a rotary drag type bit with blades
    • 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
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/08—Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods

Definitions

  • the present application is directed to high speed drilling systems and methods, and in particular, to high speed drilling systems and methods that are used in underground and/or wireline drilling or mining applications.
  • Ranges can be expressed herein as from “about” one particular value, and/or to "about” another particular value. When such a range is expressed, another aspect includes from the one particular value and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent "about,” it will be understood that the particular value forms another aspect. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint.
  • the disclosed high speed drilling system can be used underground.
  • the high speed drilling system can be used to perform wireline drilling and mining operations.
  • the drill bit 200 can include a shank 20 and a crown 30.
  • the crown 30 can comprise a first and a second crown portions 34A, 34B.
  • each of the first and second crown portions 34A, 34B can have a cutting face 60A, 60B having a plurality of projections 66A, 66B extending therefrom.
  • each of the first and second crown portions 34A, 34B can define a plurality of bores 64A, 64B extending from the cutting faces 60A, 60B to an interior space 110 ( Figures 3F and 3G ).
  • the drill bit can optionally be a self-sharpening full-face rotary bit.
  • the drill bit 200 disclosed herein can be a diamond-impregnated bit, with the diamonds (including natural or synthetic diamonds) impregnated within a matrix.
  • the matrix can be configured to wear and/or erode to thereby expose the diamond material impregnated within the matrix.
  • drill bit 200 can comprise a plurality of selected materials, with each material being provided as a selected weight percentage of the drill bit.
  • drill bit 200 can comprise carbon (not including diamond) in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 7.00% by weight of the drill bit.
  • the drill bit 200 can comprise iron in any desired amount, such as, for example and without limitation, an amount ranging from about 50.00% to about 90.00% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise manganese in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 8.00% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise molybdenum in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 0.20% by weight of the drill bit.
  • the drill bit 200 can comprise nickel in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 6.00% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise silicon in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 0.50% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise silicon carbide in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 2.00% by weight of the drill bit.
  • the drill bit 200 can comprise silver in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 12.00% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise tin in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 6.00% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise tungsten in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 41.00% by weight of the drill bit.
  • the drill bit 200 can comprise tungsten carbide in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 35.00% by weight of the drill bit. It is further contemplated that the drill bit 200 can comprise zinc in any desired amount, such as, for example and without limitation, an amount ranging from about 0.00% to about 24.00% by weight of the drill bit.
  • the weight percentages referred to herein relate to the weight of the solidified, fully infiltrated drill bit.
  • the drill bit can comprise a matrix of diamonds and hard particulate material that is infiltrated with a binder using conventional methods, with the fully infiltrated drill bit comprising materials with the above-disclosed weight percentages.
  • the cutting media of the drill bit are generally referred to herein as "diamonds," it is contemplated that the bit can comprise other cutting media (e.g., tungsten carbide) as are known in the art.
  • the powdered hard particulate material can be placed in a mold of suitable shape.
  • the binder is typically placed on top of the powdered hard particulate material.
  • the binder and the powdered hard particulate material are then heated in a furnace to a flow or infiltration temperature of the binder so that the binder alloy can bond to the grains of powdered hard particulate material.
  • Infiltration can occur when the molten binder alloy flows through the spaces between the powdered hard particulate material grains by means of capillary action.
  • the powdered hard particulate material matrix, the diamonds, and the binder form a hard, durable, strong body.
  • natural or synthetic diamonds or other cutting media
  • a crown can comprise multiple matrices that can have different binder hardnesses.
  • a crown can comprise a first matrix 402 comprising a first binder of a first hardness and a second matrix 404 can comprise a second binder of a second hardness.
  • first hardness (of the first binder) can be greater than the second hardness (of the second binder).
  • the first matrix can extend from a central axis of the bit to a first radial distance
  • the second matrix can extend from the first matrix to the outer surface 40A, 40B.
  • the crown can comprise three matrices having binders with three different hardnesses.
  • the matrices can be arranged to have increasing hardness from or proximate the bit's central axis moving radially outwardly to the radial edges of the bit.
  • the matrix of the drill bits disclosed herein can be configured to form supporting structures behind the diamonds within the drill bits, thereby preventing the polishing of the impregnated diamonds during operation.
  • the drill bit 200 disclosed herein can further optionally comprise a plurality of wear-resistant members that are embedded therein portions of at least one of the base surface and/or the at least one inner surface of the crown portions of the drill bit. It is contemplated, optionally and without limitation, that the plurality of wear-resistant members can be embedded therein portions of the base surface adjacent to the at least one inner surface that serves as the impact wall (e.g., the trailing wall) as a result of the rotation of the drill bit in use. In this aspect, it is contemplated that the plurality of wear-resistant members can be embedded in an area of the base surface proximate to the juncture of the base surface and the respective inner surfaces.
  • the plurality of wear-resistant members in the base surface can be positioned in a desired, predetermined array.
  • the array of the plurality of wear-resistant members can comprise a series of rows of wear-resistant members.
  • each row can comprise a plurality of the wear-resistant members positioned substantially along a common axis.
  • the common axis can be substantially parallel to the adjacent at least one inner surface.
  • the array of the plurality of wear-resistant members can comprise a series of rows of wear-resistant members in which each of the rows are substantially parallel to each other and to the adjacent at least one inner surface.
  • the plurality of wear-resistant members can be embedded therein portions of the inner surface that serves as the impact wall (e.g., the trailing wall) as a result of the rotation of the drill bit in use.
  • the plurality of wear-resistant members can be embedded in an area of the at least one inner surface proximate to the juncture of the base surface and the at least one inner surface.
  • the plurality of wear-resistant members in the base surface can be positioned in a desired, predetermined array.
  • the array of the plurality of wear-resistant members can comprise a series of rows of wear-resistant members.
  • each row can comprise a plurality of the wear-resistant members positioned substantially along a common axis.
  • the common axis can be substantially parallel to the adjacent base surface.
  • the array of the plurality of wear-resistant members can comprise a series of rows of wear-resistant members in which each of the rows are substantially parallel to each other and to the adjacent base surface.
  • the array of the plurality of wear-resistant members positioned on the at least one inner surface can be spaced away from the cutting faces of the drill bit 200 at a desired distance.
  • the plurality of wear resistant members can extend proudly from the respective base surface and/or at least one inner surface in which it is embedded.
  • the array can comprise additional rows of wear resistant members that are encapsulated within the drill bit 200 in an underlying relationship with the exposed rows of the wear-resistant members that are positioned in one of the base surface and/or the at least one inner surface of the drill bit 200. In this fashion, the additional wear-resistant members can be exposed upon the normal wear of the drill bit 200 during operation.
  • each wear-resistant member can be an elongated member, for example and without limitation, the elongate member can have a generally rectangular shape having a longitudinal axis. It is contemplated that the elongate members can be positioned such that the longitudinal axis of each elongate member is substantially parallel to the adjacent base surface and/or at least one inner surface.
  • each wear-resistant member can comprise at least one of Tungsten Carbide, TSD (thermally stable diamond), PDC (polycrystalline diamond compact), CBN (cubic boron nitride), single crystal Aluminum Oxide, Silicon Carbide, wear resistant ceramic materials, synthetic diamond materials, natural diamond, and polycrystalline diamond materials.
  • the drill string 150 can be an open tubular drill string.
  • the drill string can accommodate deployment of survey instrumentation into the drill string.
  • the open tubular drill string can enable real time measure while drilling (MWD) surveying or post-drilling verification pump-in instrumentation surveying.
  • MWD real time measure while drilling
  • the drill head assembly 110 can be configured to rotate the drill bit at a speed of at least 1000 rpm, or 1000-2000 rpm, or 2000-4000 rpm, or 4000-5000 rpm or greater. Accordingly, it is contemplated that the bit can rotate at least 50% faster than conventional technology and preferably three to four times faster than typical rotary drilling equipment. According to some aspects, although not essential for all purposes, the axial thrust applied at the cutting face of the drill bit can be reduced as compared to lower drill rotation speeds. The reduced axial force can reduce hole deviation, thereby enabling drill operators to hit drilling targets with greater accuracy.
  • a high-speed electric drive motor can be disposed at the drill head assembly 110.
  • a drive motor can comprise an integral multiplying gearbox so that the gearbox output provides the desired drill bit speed.
  • a gearbox can be coupled to a conventional drive motor of the drill head assembly 110.
  • a quick attach/detach gearbox can be mounted between the drill string and the drill rig. Conventional drill strings couple to the drill head via threaded coupling that can be difficult to disengage.
  • a quick attach/detach gearbox can include a split collar coupling 300 at its output, which couples to the drill string.
  • Each of the drill head's gearbox and the drill string can comprise a flange 302A, 302B.
  • the drill head gearbox's flange 302A can abut the drill string's flange 302B, and a split collar 304 can receive the pair of abutting flanges in an annular groove 306.
  • Respective ends 308 of the split collar 304 can be joined via known means, such as, for example, fasteners 310, thereby retaining the abutting flanges 302A, 302B. In this way, the drill head can be coupled to the drill string in a releasable fashion.
  • the split collar coupling can comprise an EPIROC V-LOK clamp system or equivalent system as is known in the art.
  • a quick pin coupling can releasably couple the drill head to the drill string.
  • other quick attach/detach couplings can be used to couple the gearbox to the drill string. In this way, the gearbox can be removed to allow easy and productive access to the open drill string.
  • a gearbox 220 can be disposed within the drill string.
  • the gearbox can be in communication between the drill string and the drill bit and can be configured to step up the rotation rate between the drill string and the drill bit so that rotation of the drill string at a first rate causes rotation of the drill bit at a second rate that is greater than the first rate.
  • the gearbox 220 can be disposed adjacent the drill bit to enable survey instrumentation to extend to a bottom of the borehole-if the gearbox 220 were positioned closer to the surface, then the presence of the gearbox would prevent survey instrumentation from advancing to the bottom of the borehole.
  • wireline boreholes can have very tight annuli (i.e. space between the borehole walls and the drill string). This can be, in part, due to the need for a sufficient outer diameter and wall thickness to maximize stiffness to withstand high rotary speed drilling while providing a bore sufficient to pass instrumentation therethrough.
  • the slip subs can be configured for thin-wall drill strings having tight annuli.
  • the drill string tubing can be 1 ⁇ 4 to 3/16 of an inch thick. In further embodiments, the thickness can be 1 ⁇ 2 inch thick or less. It is contemplated that the drill string-to-hole annulus radius differential can be equal to or less than the tubing thickness.
  • the threaded drill string component or drill rod 600 comprises a hollow elongate body 610 having a box end portion 620, an opposing pin end portion 630 and a cylindrical mid-body portion 640 that extends longitudinally between the respective box and pin end portions.
  • a central longitudinal axis LA extends through the hollow body 610 between the respective box and pin end portions 620, 630.
  • Each of the respective box and pin end portions 620, 630 have an end portion inner wall 622, 632 having a first inner diameter D1.
  • the end portion inner wall 622, 632 can have a substantially cylindrical shape that is positioned uniformly about the central longitudinal axis.
  • Each trough can also have a first frustoconical portion 664 that is sloped outwardly from the central longitudinal axis LA and extends between the respective distal end 624 of the box end portion 620 and proximal end 634 of the pin end portion 30 to the substantially cylindrical portion 62 and has a variable inner diameter that is greater than the first inner wall diameter D1.
  • at least a portion of the substantially cylindrical portion of each trough 660 can further comprise a plurality of longitudinally extending ridges that extend inwardly toward the central longitudinal axis LA.
  • the acute angle ⁇ can be between about 0.01 to about 10 degrees; preferably less than about 8 degrees; and, more preferred, less than about 6 degrees. In exemplary aspects, the acute angle ⁇ can range from about 0.5 to about 8 degrees, from about 0.5 to about 6 degrees, from about 0.5 to about 5 degrees, from about 1 to about 7 degrees, from about 1 to about 6 degrees, from about 1 degrees to about 5 degrees, or from about 2 degrees to about 6 degrees.
  • the inner diameter of the hollow body 10 can transition from the second inner diameter D2 of the male projection inner wall face 646 to the first trough diameter along a first longitudinal transition length L1.
  • the inner diameter of the hollow body 610 can transition from the first inner diameter D1 of the respective box and pin end portions 620, 630 to the first trough diameter along a second longitudinal transition length L2.
  • the total of the respective first and second transition lengths L1, L2 is less than about 15%, preferably less than about 12.5% and, more preferred, less than about 10% of the overall length of the drill rod.
  • the elongate length of the plurality of troughs can comprise greater than 60% of the elongate length of the mid-body portion; preferably greater than 70% of the elongate length of the mid-body portion, and more preferred, greater than 80% of the elongate length of the mid-body portion.
  • the at least one male projection 644 of each projecting portion can comprise a single male projection, which can optionally extend circumferentially about the central longitudinal axis LA.
  • the at least one male projection 644 of each projecting portion can comprise a plurality of circumferentially spaced male projections.
  • the at least one projecting portion can comprise a single projecting portion (i.e., a single axial location with at least one male projection) that is positioned at a desired axial location in the mid-body portion.
  • the respective end portion inner walls 622, 632 of the box and pin end portions 620, 630 can effectively act as an additional internal male projection or upset 644' that is located at the respective outer end portions of the hollow body 610 of the drill rod 600.
  • the axial spacing between sequential projecting portions e.g., sequential axial locations with at least one male projection 644 and/or the axial spacing between the pin and box end portions 620, 630, 644' and a sequential projecting portion (e.g., at least one male projection 644), which effectively corresponds to the spacing between the internal upsets in the drill string component, can reflect a selected separation distance.
  • the selected separation distance e.g., the spacing between sequential male projections 644 and/or the spacing between a male projection and the pin and box end portions 620, 630, 644'
  • the selected separation distance can be made relative to and as a percentage of the elongate length of the individual respective drill string components being passed therethrough. For example, if a drill string component being passed through the drill rod is 10 feet in length, then the selected separation distance would be less than 100% of the elongate length of the drill string component passing through the drill rod.
  • the selected separation distance can correspond to a distance that is less than about 90%, less than about 80%, less than about 70%, less than about 60%, less than about 50%, less than about 40%, or less than about 30% of the elongate length of the individual drill string components that are passed therethrough the hollow body 10 of the drill rod 100 (or other drill string component).
  • the selected separation distance can range from about 0.30m to about 1.83m (1 foot to about 6 feet) and more preferably, from about 0.61m to about 1.52m (2 feet to about 5 feet) and, most preferably, from about 0.91m to about 1.52m (3 feet to about 5 feet). In further exemplary aspects, it is contemplated that the selected separation distance can be less than about 1.52m (5 feet).
  • the drilling system 100 can be electrically powered. This can provide an advantage over conventional diesel-powered drilling systems that require costly ventilation in mines. Moreover, electrically powered drilling systems can have lower maintenance costs than diesel-powered drilling rigs.
  • the drilling system 100 can further be automated to eliminate the need for an operator, which can further reduce ventilation requirements in a mine where the drilling system is disposed.
  • the drilling system 100 as disclosed herein can provide various improvements over prior drilling systems.
  • the drilling system 100 can be less environmentally and economically costly than percussive drilling systems.
  • the penetration rates can be improved over traditional rotary drilling equipment.
  • the drilling system 100 disclosed herein can produce penetration rates ranging from 0.5 to 1.0 meters per minute.
  • the drilling system 100 can provide an open drill string in order to deploy survey instrumentation.
  • the drilling system 100 can maintain minimum hole deviation throughout drilling in order to accurately hit drill targets.
  • the drilling system 100 can implement bits that stay sharp and, therefore, have a longer life, than surface-set diamond or PCD insert drag rotary bits.
  • a method of drilling can include drilling at a first, high angular drill speed to a first depth, and subsequently drilling at a second, lower angular drill speed to a second depth.
  • the first depth can be 10 meters, or preferably 5 meters or less. In this way, buckling of the drill string due to drilling with a high angular drill speed in deep bores can be avoided while still taking advantage of higher penetration rates of high angular speed drilling.

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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)
  • Processing Of Stones Or Stones Resemblance Materials (AREA)

Claims (11)

  1. Un système (100) comprenant :
    une avance de forage (120) ;
    une tête de forage (110) comprenant un moteur et couplée à l'avance de forage ;
    un train de tiges (150) présentant une extrémité proximale, dans lequel le train de tiges comprend au moins une tige de forage (140) couplée à la tête de forage de sorte que la tête de forage est configurée pour entraîner axialement et par rotation le train de tiges ; et
    un trépan (160) couplé à l'extrémité inférieure du train de tiges,
    caractérisé par le fait que la tête de forage est configurée pour faire tourner le trépan à au moins 1 000 tr/min, et
    le système comprend en outre une boîte d'engrenage (220) disposée à côté de la sortie du moteur et configurée pour augmenter la vitesse de rotation entre la sortie du moteur et l'extrémité proximale du train de tiges.
  2. Le système de la revendication 1, dans lequel la boîte d'engrenage est fixée de manière amovible entre le train de tiges et la tête de forage.
  3. Le système de l'une des revendications précédentes, dans lequel le système de forage comprend en outre un dispositif de glissement de train de tiges (400).
  4. Le système de l'une des revendications précédentes, dans lequel le trépan comprend une première matrice (402) présentant une première dureté de liant et une deuxième matrice (404) présentant une deuxième dureté de liant, dans lequel la première matrice est disposée dans un premier rayon par rapport à un axe longitudinal du trépan et la deuxième matrice est disposée hors du premier rayon par rapport à l'axe longitudinal du trépan.
  5. Le système de l'une des revendications précédentes, dans lequel au moins une tige de forage présente une épaisseur de paroi variable.
  6. Un procédé consistant à :
    faire tourner le trépan du système de forage de l'une des revendications précédentes, dans lequel le trépan tourne à au moins 1 000 tr/min.
  7. Le procédé de la revendication 6, dans lequel la rotation du trépan du système de forage à au moins 1 000 tr/min est en fait une rotation du trépan à au moins 4 000 tr/min.
  8. Le procédé de la revendication 6, dans lequel le train de tiges du système de forage est un train de tiges ouvert.
  9. Le procédé de la revendication 6, consistant en outre à faire tourner le trépan à une vitesse inférieure à 1 000 tr/min après une profondeur déterminée.
  10. Le procédé de la revendication 9, dans lequel la profondeur déterminée est égale à 10 mètres ou moins.
  11. Le procédé de la revendication 6, dans lequel le système de forage est positionné sous terre et dans lequel le trépan avance dans une formation (165).
EP20766044.0A 2019-03-01 2020-02-28 Système de forage à grande vitesse et ses procédés d'utilisation Active EP3931421B1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
EP25174903.2A EP4624722A1 (fr) 2019-03-01 2020-02-28 Système de forage à grande vitesse et ses procédés d'utilisation

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201962812730P 2019-03-01 2019-03-01
PCT/US2020/020401 WO2020180687A1 (fr) 2019-03-01 2020-02-28 Système de forage à grande vitesse et ses procédés d'utilisation

Related Child Applications (1)

Application Number Title Priority Date Filing Date
EP25174903.2A Division EP4624722A1 (fr) 2019-03-01 2020-02-28 Système de forage à grande vitesse et ses procédés d'utilisation

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AU (1) AU2020231331A1 (fr)
CA (1) CA3132076A1 (fr)
CL (1) CL2021002288A1 (fr)
FI (1) FI3931421T3 (fr)
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US12460481B2 (en) * 2024-01-26 2025-11-04 Saudi Arabian Oil Company Bottom hole apparatus RPM regulator

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FI3931421T3 (fi) 2025-06-25
EP4624722A1 (fr) 2025-10-01
PE20212018A1 (es) 2021-10-18
WO2020180687A1 (fr) 2020-09-10
EP3931421A1 (fr) 2022-01-05
CL2021002288A1 (es) 2022-04-01
CA3132076A1 (fr) 2020-09-10
AU2020231331A1 (en) 2021-10-28
EP3931421A4 (fr) 2023-01-04
US20220136329A1 (en) 2022-05-05

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