EP1227214B1 - Structure de coupe pour trépan de forage - Google Patents

Structure de coupe pour trépan de forage Download PDF

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Publication number
EP1227214B1
EP1227214B1 EP20010307913 EP01307913A EP1227214B1 EP 1227214 B1 EP1227214 B1 EP 1227214B1 EP 20010307913 EP20010307913 EP 20010307913 EP 01307913 A EP01307913 A EP 01307913A EP 1227214 B1 EP1227214 B1 EP 1227214B1
Authority
EP
European Patent Office
Prior art keywords
drill bit
gauge
cutter
bit
gauge surface
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.)
Expired - Lifetime
Application number
EP20010307913
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German (de)
English (en)
Other versions
EP1227214A3 (fr
EP1227214A2 (fr
Inventor
Steven Barton
Dean Travers Watson
Andrew Murdock
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.)
ReedHycalog UK Ltd
Original Assignee
Camco International UK Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from GBGB0102160.9A external-priority patent/GB0102160D0/en
Application filed by Camco International UK Ltd filed Critical Camco International UK Ltd
Publication of EP1227214A2 publication Critical patent/EP1227214A2/fr
Publication of EP1227214A3 publication Critical patent/EP1227214A3/fr
Application granted granted Critical
Publication of EP1227214B1 publication Critical patent/EP1227214B1/fr
Anticipated expiration legal-status Critical
Expired - Lifetime legal-status Critical Current

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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
    • E21B10/42—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
    • E21B10/43—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other 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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
    • E21B17/1092—Gauge section of drill bits
    • 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
    • E21B7/06—Deflecting the direction of boreholes
    • E21B7/064—Deflecting the direction of boreholes specially adapted drill bits therefor

Definitions

  • This invention relates to earth boring drill bits, and in particular to a fixed cutter drill bit having cutting elements positioned so as to facilitate directional drilling.
  • drill bit designers worked primarily on designing drill bits which would drill straight holes through the earth. More recently, designers have been working on bit designs which, when used in conjunction with suitable downhole equipment, can be steered to permit directional drilling. In directional drilling, it is important to ensure that the drill bit does not wander from the desired path. In addition, the bits must be easy to steer and be able to hold a horizontal drilling trajectory.
  • One method is to use a downhole motor to rotate the drill bit, the motor and drill bit being mounted upon a drill string including an angled bend. In such an arrangement, the direction of drilling is dependent upon the angular position of the drill string. In use, the drill string is rotated until the drill bit is pointing in the desired direction. The drill string is then held against further angular movement while drilling in the desired direction takes place. This steering technique is sometimes known as "pointing the bit”.
  • a known drill bit suitable for use in a steerable drilling system of the "push the bit” type has a leading face from which a plurality of blades upstand, each blade carrying a plurality of cutting elements. Each blade terminates in a gauge pad.
  • the gauge pads are not provided with cutting elements, but may be provided with inserts designed to improve the wear resistance of the gauge pads. It has been found, however, to be advantageous in a "push the bit” type system to provide the gauge pads with cutting elements.
  • One disadvantage, however, of applying cutting elements to the gauge pads is that there is a tendency for a wellbore formed using the drill bit to drop.
  • the present invention provides a drill bit particularly suitable for use in a steerable drilling system of the "push the bit” type.
  • US 6092613 describes a drill bit having a plurality of blades, the outer parts of which define a gauge surface devoid of cutters.
  • a drill bit for drilling a borehole comprising a bit body having an axis of rotation, a leading face, a plurality of blades upstanding from the leading face, at least one of the blades terminating in a gauge pad having a gauge surface arranged, in use, to face a wall of the borehole, the gauge surface being devoid of cutting elements, the gauge surface terminating at an end thereof remote from the blade at a junction with a gauge pad end wall, wherein the gauge pad carries a single cutter having a face and a cutting edge located radially inward of the gauge surface, and wherein the junction of the gauge surface and the gauge pad end wall crosses, radially, between the face of the cutter and the wall of the borehole.
  • each blade terminates in a similar gauge pad, each gauge pad carrying a single cutter.
  • Each cutter conveniently comprises a table of superhard material bonded to a substrate.
  • the superhard material preferably comprises diamond.
  • the cutting edge is preferably spaced radially inward of the gauge surface by a distance greater than about 0.15mm, and preferably between about 0.2mm and 0.5mm.
  • a line drawn between the cutting edge and the junction conveniently makes an angle with the axis of the bit of less than about 0.1°.
  • the drill bit may be used in a drilling system which is, in effect, a combination of the "push the bit” and "point the bit” types, the system including, for example, a bias unit arranged to apply a side loading to a bent unit which carries a motor, the motor carrying the drill bit.
  • the system when the system is to be used to drill a curve, the drill string is held against rotation with the bent unit holding the drill bit in the desired orientation while the motor drives the drill bit, and the bias unit is operated to apply a side loading to the bent unit and the drill bit.
  • the gauge pads may be integral with one another and form a gauge surface extending around the bit body, additional similarly located cutters being carried by the bit body between the angular positions of the blades.
  • the bit therefore can be used with a wide range of bias units and there is no need to accurately angularly align the bit with the bias unit.
  • Figure 1 is a perspective view of an earth boring drill bit in accordance with an embodiment of the invention.
  • Figure 2 is a side view of the drill bit of Figure 1.
  • Figure 3 is a bottom view of the drill bit of Figure 1.
  • Figure 4 is a diagrammatic view of part of the drill bit.
  • Figures 4A and 4B are views similar to Figure 4 illustrating alternative arrangements.
  • Figures 5 and 6 are diagrammatic views illustrating the use of the drill bit in drilling a borehole.
  • Figure 7 is another diagrammatic view of part of the drill bit.
  • Figures 8 to 10 are diagrammatic views illustrating drilling systems including drill bits in accordance with the invention.
  • Figure 11 is a perspective view illustrating another embodiment of the invention.
  • Figures 12 to 15 are diagrammatic views illustrating various angular positions of the drill bit of Figure 11 relative to a bias unit.
  • a fixed cutter drill bit of the present invention is illustrated and generally designated by the reference numeral 10.
  • the drill bit 10 has a central axis of rotation 12 and a bit body 14 having a leading face 16, an end face 18, a gauge region 20, and a shank 22 for connection to a drill string.
  • a plurality of blades 26 are upstanding from the leading face 16 of the bit body and extend outwardly away from the central axis of rotation 12 of the bit 10.
  • Each blade 26 terminates in a gauge pad 28 having a gauge surface 29 which faces a wall 30 of the borehole 32 (as shown in Figures 5 and 6).
  • a number of cutters 34 are mounted on the blades 26 at the end face 18 of the bit 10 in both a cone region 36 and a shoulder region 38 of the end face 18.
  • Each of the cutters 34 partially protrude from their respective blade 26 and are spaced apart along the blade 26, typically in a given manner to produce a particular type of cutting pattern. Many such patterns exist which may be suitable for use on the drill bit 10 fabricated in accordance with the teachings provided herein.
  • a cutter 34 typically includes a preform cutting element 40 that is mounted on a carrier in the form of a stud which is secured within a socket in the blade 26.
  • each preform cutting element 40 is a curvilinear shaped, preferably circular tablet of polycrystalline diamond compact (PDC) or other suitable superhard material bonded to a substrate of tungsten carbide, so that the rear surface of the tungsten carbide substrate may be brazed into a suitably oriented surface on the stud which may also be formed from tungsten carbide.
  • PDC polycrystalline diamond compact
  • the gauge region 20 is generally responsible for stabilizing the drill bit 10 within the borehole 32.
  • the gauge region 20 typically includes extensions of the blades 26 which create channels 52 through which drilling fluid may flow upwardly within the borehole 32 to carry away the cuttings produced by the leading face 16.
  • the gauge pads 28 are arranged such that the gauge surfaces 29 thereof are devoid of cutters.
  • the gauge surfaces 29 may be provided with means to improve the wear resistance thereof, for example wear resistant inserts or a coating of hardfacing material. Such means do not result in the gauge surfaces performing a cutting action but rather simply improve the wear resistance of these parts of the drill bit.
  • passaging (not shown) which allows pressurized drilling fluid to be received from the drill string and communicate with one or more orifices 54 located on or adjacent to the leading face 16. These orifices 54 accelerate the drilling fluid in a predetermined direction.
  • the surfaces of the bit body 14 are susceptible to erosive and abrasive wear during the drilling process.
  • a high velocity drilling fluid cleans and cools the cutters 34 and flows along the channels 52, washing the earth cuttings away from the end face 18.
  • the orifices 54 may be formed directly in the bit body 14, or may be incorporated into a replaceable nozzle.
  • each gauge pad 28 terminates at an end wall 56.
  • the end wall 56 is angled relative to the axis 12.
  • the end wall 56 joins the gauge surface 29 at a junction 58.
  • the end wall 56 is not of planar form, but rather is shaped to define a step 60. It will be appreciated, however, that the provision of such a step 60 is not essential, and that the end wall 56 could extend continuously to the junction 58.
  • the gauge pad 28 is shaped to define a socket 78 (see Figure 7) which receives a cutter 62 orientated aggressively.
  • the cutter 62 conveniently takes the form of a polycrystalline diamond compact tablet 79, conveniently of circular shape, mounted upon a suitable substrate 80, for example of tungsten carbide, the substrate 80 being brazed to the bit body.
  • the tablet 79 defines a generally planar face 64, part of the periphery of which defines a cutting edge 65.
  • the location of the cutter 62 is such as to ensure that the cutting edge 65 is located radially inward of the gauge surface.
  • the location of the cutter 62 relative to the junction 58 is such that the junction 58, radially, extends between the face 64 of the cutter 62 and the wall 30 of the borehole 32.
  • the axial position 72 of the junction 58 lies between the axial position 74 of the edge 75 of the cutter 62 closest to the blade 26 and the axial position 76 of the edge 77 furthest from the blade 26.
  • Figures 4A and 4B illustrate two possible alternative shapes, the cutter shown in Figure 4A being of pointed form whereas that of Figure 4B is shaped to define a flat. It will be appreciated that these shapes are only examples and that the cutter could take a number of other shapes.
  • FIG. 4 illustrates one suitable position of the cutter 62 relative to the junction 58, it will be appreciated that the relative positioning of the cutter 62 and the junction 58 may be changed without falling outside of the scope of the invention, and the bracket 66 of Figure 4 denotes a range of suitable positions of the junction 58 relative to the face 64 of the cutter 62.
  • the radial spacing of the cutting edge 65 of the cutter 62 from the gauge surface 29 is very small, and is conveniently greater than about 0.15mm, and preferably between about 0.2mm and about 0.5mm.
  • a notional line 70 drawn between the cutting edge 65 of the cutter 62 and the junction 58 conveniently makes an angle with the axis 12 of less than about 0.1°. In the arrangement illustrated, this angle (denoted by reference 68 in Figure 4) is conveniently approximately 0.0785°.
  • Figures 5 and 6 illustrate the drill bit in use, the description being directed to the use of the drill bit with a "push the bit” type system.
  • the bias unit 84 of the bottom hole assembly is operated to apply a side loading to the drill bit 10, for example as illustrated in Figure 6, then this will have the effect of tilting the drill bit 10 relative to the axis of the bore. If the tilting of the drill bit 10 is in the direction illustrated in Figure 6, then the tilting will cause the cutters 62 on the high or upper side of the drill bit 10 at any given time to move towards the wall 30, the cutters 62 on the low side of the drill bit 10 tending to move away from the wall 30. The tilting of the drill bit will also tend to move the cutters 34 provided on the blades 26 at the high side of the bit 10 away from the wall 30 whereas those at the low side of the bit 10 still encounter the well bore and so are active in drilling.
  • the bit 10 Since the cutters 62 are radially inwardly spaced from the gauge surfaces 29, clearly the bit 10 must be moved through an angle greater than a predetermined angle in order to bring the cutters 62 into engagement with the wellbore. In the illustrated embodiment, this angle is approximately 0.4°. Once the bit 10 has been tilted through a sufficiently large angle to bring the cutters 62 at the high side of the bit 10 at any given time into engagement with the wellbore, then it will be appreciated that these cutters assist in drilling of the formation and thus assist in the formation of a curve in the wellbore.
  • each cutter 62 is described as being spaced radially inwardly of the gauge surface radius by a distance of greater than about 0.15mm, and preferably between about 0.2mm and about 0.5mm, and a notional line drawn between the junction 58 and the cutting edge 65 makes an angle with the axis 12 of less than about 0.1°, it will be appreciated that the positioning of the cutters 62 will depend upon the equipment with which the drill bit is to be used, the factors to be taken into account including, for example, whether the drill bit is to be used with an undersize downhole stabilizer unit 82.
  • FIG 8 illustrates a drill bit of the type described hereinbefore in use with a "push the bit” type drilling system.
  • the drilling system includes a bottom hole assembly (BHA) 81 comprising a stabilizer unit 82 connected to a bias unit 84, the bias unit in turn being connected to the drill bit.
  • BHA bottom hole assembly
  • the bias unit 84 is designed to rotate with the drill string by which the bottom hole assembly 81 is supported, the bias unit 84 including a plurality of moveable pads (not shown), the pads being moveable outwardly to engage the wall of the borehole being drilled to apply a side force to the bias unit, and hence to the drill bit.
  • the bias unit 84 includes a control arrangement 85 adapted to ensure that the pads are extended and retracted at the correct time and in the correct positions to apply the side load to the drill bit in the desired direction to achieve drilling in the desired trajectory.
  • Figure 9 illustrates the drill bit in use in a "point the bit” type drilling system.
  • the drill string carries a bent or articulated unit 86 which in turn carries a downhole motor 88.
  • the motor is typically driven using wellbore fluid.
  • the motor 88 is arranged to drive the drill bit to rotate the drill bit 10 about its axis.
  • a stabilizer unit (not shown) is typically incorporated into the bottom hole assembly 81.
  • the motor 88 is used to drive the drill bit for rotation so that the drill bit performs a cutting action.
  • the motor and drill bit are carried by the bent unit 86, it will be appreciated that the axis of the drill bit is not coaxial with the borehole being drilled.
  • the drill string is rotated so that the bent unit rotates within the wellbore.
  • the drill string is held against rotation with the bent unit 86 orientated such that the drill bit is pointing in the direction in which the wellbore is to be drilled, and it will be appreciated that in this condition the drill bit is tilted such that the cutters 62 can become active.
  • bottom hole assembly 81 including a bent unit
  • other "point the bit" type units are possible.
  • the unit is adjustable between a position in which the drill bit lies coaxially with the bore and a condition in which the axis of the drill bit is angled relative to the bore.
  • the assembly 81 could incorporate a bias unit designed to apply a side loading to the drill bit.
  • Figure 10 illustrates a further drilling system.
  • the drill bit used is not identical to that described hereinbefore, but rather is modified to incorporate, in its gauge region, a plurality of moveable pads 90 which are moveable radially outwardly to engage the wall of the borehole to permit the application of a side loading to the drill bit.
  • the pads 90 are typically moveable under the action of hydraulic fluid, the application of fluid being controlled by a suitable control valve arrangement 92 to ensure that the pads 90 are extended and retracted at appropriate intervals to cause the application of the desired side loading to the drill bit.
  • the arrangement of Figure 10 is a drill bit with an integral bias unit.
  • the drilling efficiency of the downhole assembly when the drill bit is being used in the formation of a curve in the wellbore is not optimized.
  • the drill bit includes the same number or an even multiple of the number of blades as the bias unit has bias pads
  • optimization of the drilling efficiency during this phase of operation can be achieved.
  • Such optimization can only be achieved, however, by ensuring that the correct angular orientation is achieved to locate each bias pad opposite a respective blade, and this can only occur where the bit and bias unit have the correct number of blades and bias pads.
  • the bias unit and drill bit are each secured to the remainder of the drill string by screw threaded connections, and so it will be appreciated that it is difficult to consistently achieve the desired angular orientation of the bias unit and the drill bit.
  • Figure 11 illustrates a design of bit in which the drilling efficiency can be optimized without having to correctly angularly orientate the drill bit relative to a bias unit to locate each bias pad opposite a blade and also in which the bit need not be used with a bias unit having a number of bias pads determined by the number of blades of the drill bit.
  • the drill bit 100 in Figure 11 comprises a bit body 101 having a leading face 102 and a shank 104 for connection to a drill string.
  • a plurality of blades 106 are upstanding from the leading face 102, each blade 106 extending outwardly away from a central axis of rotation of the bit 100 and each carrying a plurality of cutters 108 for engagement with a formation within which a borehole is to be drilled.
  • flow channels 110 to which a drilling fluid is supplied, in use, through nozzles 112, the fluid being used to lubricate and clean the cutters 108, in use.
  • a gauge ring 114 encircles at least a portion of the bit body 101, the gauge ring 114 being integral with the remainder of the bit body 101 and defining a gauge surface 116.
  • the gauge ring 114 connects at least two, and preferably all the gauge pads 28 or blades 106 to extend substantially continuously around the bit body 101.
  • openings 118 are formed in the gauge ring 114 to allow drilling fluid from the channels 110 to flow to the annulus between the drill string and the wall of the borehole.
  • the gauge ring 114 terminates, at its edge remote from the blade 106, with a gauge ring end wall 120.
  • a plurality of cutters 122 are mounted on the gauge ring 114, the cutters 122 being positioned such that their cutting edges are located radially inward of the gauge surface 116, the axial position of each cutter 122 being such that the junction between the gauge surface 116 and the gauge pad end wall 120 crosses, radially, between the face of each cutter and the wall of the borehole.
  • each cutter 122 of the arrangement illustrated in Figure 11 is similar to that of the cutters 62 of the arrangements described hereinbefore, the main difference between the arrangement of Figure 11 and the arrangements described hereinbefore being that cutters 122 are provided on portions of the gauge ring 114 angularly between the positions of the blades 106.
  • Figures 12-15 are diagrammatic representations showing the positions of the cutters 108, the cutters 122 and the bias pads 124 of the bias unit. It is clear from each of Figures 12-15 that in each of the relative positions of the bias pads 124 relative to the drill bit, the bias pads 124 are located angularly opposite at least one of the cutters 122. In service the pads 124 continuously extend and retract as the bit 100 rotates. Generally, one or more pads are partially extended simultaneously, as shown. The direction in which the bit 100 is pushed is a result of which pads are extended, and the amount they extend. Further, although not illustrated, it will be appreciated that the drill bit of Figure 11 need not be used with a bias unit having three bias pads 124, but rather could be used with a bias unit having any number of bias pads.
  • the distance by which the cutters 122 are spaced from the gauge surface is preferably greater than about 0.15mm and is preferably between about 0.2mm and about 0.5mm.
  • a notional line drawn between a junction between the gauge surface 116 and the gauge ring end wall 120 and the cutting edge of each cutter 122 conveniently makes an angle with the axis of the drill bit of less than about 0.1°.
  • the provision of the gauge ring 114 further assists in stabilizing the drill bit and thus may allow a reduction in the number of blades carried by the drill bit as compared to a conventional design.

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

Claims (12)

  1. Trépan de forage pour forer un trou de forage, le trépan de forage comprenant un corps de trépan (14) comportant un axe de rotation (12), une face d'attaque (16), plusieurs lames (26) remontant de la face d'attaque, au moins une des lames (26) se terminant dans un patin de front de taille (28), comportant une surface de front de taille (29) agencée en service de sorte à faire face à une paroi du trou de forage, la surface de front de taille (29) ne comportant pas d'éléments de coupe, la surface de front de taille (29) se terminant au niveau d'une extrémité correspondante éloignée de la lame au niveau d'une jonction avec une paroi d'extrémité (56), caractérisé en ce que le patin de front de taille (28) supporte un dispositif de coupe (62) comportant une face et une arête de coupe agencée radialement vers l'intérieur de la surface de front de taille, la jonction (58) entre la surface de front de taille et la paroi d'extrémité s'étendant transversalement et radialement entre la face du dispositif de coupe et la paroi du trou de forage.
  2. Trépan de forage selon la revendication 1, dans lequel chaque patin de front de taille (28) supporte un seul dispositif de coupe (62).
  3. Trépan de forage selon la revendication 1, dans lequel chaque dispositif de coupe (62) comprend une table d'un matériau superdur reliée à un substrat.
  4. Trépan de forage selon la revendication 3, dans lequel le matériau superdur est composé de diamant.
  5. Trépan de forage selon la revendication 1, dans lequel l'arête de coupe est espacée radialement vers l'intérieur de la surface de front de taille d'une distance supérieure à environ 0,15 mm.
  6. Trépan de forage selon la revendication 5, dans lequel l'arête de coupe est espacée radialement vers l'intérieur de la surface de front de taille d'une distance comprise entre environ 0,2 mm et environ 0,55 mm.
  7. Trépan de forage selon la revendication 1, dans lequel une ligne théorique tracée entre l'arête de coupe et la jonction (58) forme avec l'axe (12) du trépan un angle inférieur à environ 0,1°.
  8. Trépan de forage selon la revendication 1, dans lequel au moins deux des lames se terminent dans des patins de front de taille interconnectés pour former une surface de front de taille continue.
  9. Trépan de forage selon la revendication 8, dans lequel tous les patins de front de taille (28) sont interconnectés pour former une surface de front de taille continue (29), s'étendant autour du trépan de forage.
  10. Trépan de forage selon la revendication 9, comprenant en outre au moins un dispositif de coupe additionnel comportant une face et une arête de coupe agencée radialement vers l'intérieur de la surface de front de taille, une jonction entre la surface de front de taille et la paroi d'extrémité étant agencée de sorte à s'étendre transversalement et radialement entre la face du dispositif de coupe additionnel et la paroi du trou de forage, le dispositif de coupe additionnel étant agencé angulairement entre deux lames adjacentes du trépan de forage.
  11. Trépan de forage selon la revendication 1, dans lequel une position axiale de la jonction (58) entre la surface de front de taille et la paroi d'extrémité du patin est située entre une position axiale de l'arête de la face du dispositif de coupe la plus proche de la lame et de l'arête correspondante la plus éloignée de la lame.
  12. Trépan de forage selon la revendication 1, dans lequel une position axiale de la jonction (58) entre la surface de front de taille et la paroi d'extrémité se situe entre une position axiale de l'arête du dispositif de coupe (62) la plus proche de la lame et une position axiale de l'arête du dispositif de coupe (62) la plus éloignée de la lame.
EP20010307913 2001-01-27 2001-09-18 Structure de coupe pour trépan de forage Expired - Lifetime EP1227214B1 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
GBGB0102160.9A GB0102160D0 (en) 2001-01-27 2001-01-27 Cutting structure for earth boring drill bits
GB0102160 2001-01-27
GB0117852A GB2371573B (en) 2001-01-27 2001-07-23 Cutting structure for earth boring drill bits
GB0117852 2001-07-23

Publications (3)

Publication Number Publication Date
EP1227214A2 EP1227214A2 (fr) 2002-07-31
EP1227214A3 EP1227214A3 (fr) 2003-03-19
EP1227214B1 true EP1227214B1 (fr) 2004-06-30

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EP20010307913 Expired - Lifetime EP1227214B1 (fr) 2001-01-27 2001-09-18 Structure de coupe pour trépan de forage

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EP (1) EP1227214B1 (fr)
DE (1) DE60104082T2 (fr)

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US8534380B2 (en) 2007-08-15 2013-09-17 Schlumberger Technology Corporation System and method for directional drilling a borehole with a rotary drilling system
US8550185B2 (en) 2007-08-15 2013-10-08 Schlumberger Technology Corporation Stochastic bit noise
US8763726B2 (en) 2007-08-15 2014-07-01 Schlumberger Technology Corporation Drill bit gauge pad control

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MX337972B (es) * 2007-08-15 2016-03-29 Schlumberger Technology Bv Metodo y sistema para dirigir un sistema de perforacion direccional.
US8720604B2 (en) 2007-08-15 2014-05-13 Schlumberger Technology Corporation Method and system for steering a directional drilling system
US8727036B2 (en) 2007-08-15 2014-05-20 Schlumberger Technology Corporation System and method for drilling
US20100038141A1 (en) 2007-08-15 2010-02-18 Schlumberger Technology Corporation Compliantly coupled gauge pad system with movable gauge pads
US8757294B2 (en) 2007-08-15 2014-06-24 Schlumberger Technology Corporation System and method for controlling a drilling system for drilling a borehole in an earth formation
US7926596B2 (en) 2007-09-06 2011-04-19 Smith International, Inc. Drag bit with utility blades
US8869919B2 (en) 2007-09-06 2014-10-28 Smith International, Inc. Drag bit with utility blades
GB2537266B (en) 2013-12-18 2017-09-27 Halliburton Energy Services Inc Cutting structure design with secondary cutter methodology
CN116241187B (zh) * 2023-05-12 2023-07-07 北京欧钻科技有限公司 方孔钻

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US5904213A (en) * 1995-10-10 1999-05-18 Camco International (Uk) Limited Rotary drill bits
US6089336A (en) * 1995-10-10 2000-07-18 Camco International (Uk) Limited Rotary drill bits
GB9521972D0 (en) 1995-10-26 1996-01-03 Camco Drilling Group Ltd A drilling assembly for drilling holes in subsurface formations

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8534380B2 (en) 2007-08-15 2013-09-17 Schlumberger Technology Corporation System and method for directional drilling a borehole with a rotary drilling system
US8550185B2 (en) 2007-08-15 2013-10-08 Schlumberger Technology Corporation Stochastic bit noise
US8720605B2 (en) 2007-08-15 2014-05-13 Schlumberger Technology Corporation System for directionally drilling a borehole with a rotary drilling system
US8763726B2 (en) 2007-08-15 2014-07-01 Schlumberger Technology Corporation Drill bit gauge pad control

Also Published As

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EP1227214A3 (fr) 2003-03-19
DE60104082T2 (de) 2005-07-28
EP1227214A2 (fr) 2002-07-31
DE60104082D1 (de) 2004-08-05

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