EP3207206A1 - Trépan équipé de patins auto-réglables - Google Patents

Trépan équipé de patins auto-réglables

Info

Publication number
EP3207206A1
EP3207206A1 EP15850810.1A EP15850810A EP3207206A1 EP 3207206 A1 EP3207206 A1 EP 3207206A1 EP 15850810 A EP15850810 A EP 15850810A EP 3207206 A1 EP3207206 A1 EP 3207206A1
Authority
EP
European Patent Office
Prior art keywords
piston
rate
control device
fluid
rate control
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.)
Granted
Application number
EP15850810.1A
Other languages
German (de)
English (en)
Other versions
EP3207206B1 (fr
EP3207206A4 (fr
Inventor
Jayesh R. Jain
Benjamin Baxter
Chaitanya K. Vempati
Steven R. Radford
Volker Peters
Gregory L. Ricks
Juan Miguel Bilen
Holger Stibbe
David A. Curry
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.)
Baker Hughes Holdings LLC
Original Assignee
Baker Hughes 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
Priority claimed from US14/516,340 external-priority patent/US9708859B2/en
Application filed by Baker Hughes Inc filed Critical Baker Hughes Inc
Publication of EP3207206A1 publication Critical patent/EP3207206A1/fr
Publication of EP3207206A4 publication Critical patent/EP3207206A4/fr
Application granted granted Critical
Publication of EP3207206B1 publication Critical patent/EP3207206B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

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
    • E21B10/62—Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable

Definitions

  • Oil wells are drilled with a drill string that includes a tubular member having a drilling assembly (also referred to as the "bottomhole assembly” or “BHA”).
  • BHA typically includes devices and sensors that provide information relating to a variety of parameters relating to the drilling operations (“drilling parameters”), behavior of the BHA (“BHA parameters”) and parameters relating to the formation surrounding the wellbore (“formation parameters”).
  • drilling parameters parameters relating to the drilling operations
  • BHA parameters behavior of the BHA
  • formation parameters parameters
  • a drill bit attached to the bottom end of the BHA is rotated by rotating the drill string and/or by a drilling motor (also referred to as a "mud motor”) in the BHA to
  • FIG. 2 shows a partial cross-sectional view of an exemplary drill bit with a pad and a rate control device for controlling the rates of extending and retracting the pad from a drill bit surface, according to one embodiment of the disclosure
  • FIG. 5 shows placement of a rate control device of FIG. 3 in the crown section of the drill bit
  • FIG. 7 shows a drill bit, wherein the rate control device and the pad are placed on an outside surface of the drill bit
  • FIG. 10 shows an embodiment of a rate control device configured to operate multiple pads
  • Drill string 1 18 is shown conveyed into the wellbore 1 10 from a rig 180 at the surface 167.
  • the exemplary rig 180 shown is a land rig for ease of explanation.
  • the apparatus and methods disclosed herein may also be utilized with an offshore rig used for drilling wellbores under water.
  • a rotary table 169 or a top drive (not shown) coupled to the drill string 118 may be utilized to rotate the drill string 1 18 to rotate the BHA 130 and thus the drill bit 150 to drill the wellbore 1 10.
  • a drilling motor 155 (also referred to as the "mud motor”) may be provided in the BHA 130 to rotate the drill bit 150. The drilling motor 155 may be used alone to rotate the drill bit 150 or to superimpose the rotation of the drill bit by the drill string 118.
  • a control unit (or controller) 190 which may be a computer-based unit, may be placed at the surface 167 to receive and process data transmitted by the sensors in the drill bit 150 and the sensors in the BHA 130, and to control selected operations of the various devices and sensors in the BHA 130.
  • the surface controller 190 may include a processor 192, a data storage device (or a computer-readable medium) 194 for storing data, algorithms and computer programs 196.
  • the data storage device 194 may be any suitable device, including, but not limited to, a read-only memory (ROM), a
  • the crown 230 includes a face or face section 232 that faces the formation during drilling.
  • the crown 230 includes a number of blades, such as blades 234a, 234b, etc.
  • a typical PDC bit includes 3-7 blades.
  • Each blade has a face (also referred to as a "face section") and a side (also referred to as a "side section").
  • blade 234a has a face 232a and a side 236a
  • blade 234b has a face 232b and a side 236b.
  • the sides 236a and 236b extend along the longitudinal or vertical axis 202 of the drill bit 200.
  • Each blade further includes a number of cutters. In the particular embodiment of FIG.
  • the drill bit 200 includes one or more elements or members (also referred to herein as pads) that extend and retract from a surface 252 of the drill bit 200.
  • FIG. 2 shows a pad 250 movably placed in a cavity or recess 254 in the crown section 230.
  • An activation device 260 may be coupled to the pad 250 to extend and retract the pad 250 from a drill bit surface location 252.
  • the activation device 260 controls the rate of extension and retraction of the pad 250.
  • the device 260 extends the pad at a first rate and retracts the pad at a second rate.
  • the first rate and second rate may be the same or different rates.
  • the rate of extension of the pad 250 may be greater than the rate of retraction.
  • the device 260 also is referred to herein as a "rate control device” or a “rate controller.”
  • the pad 250 is directly coupled to the device 260 via a mechanical connection or connecting member 256.
  • the device 260 includes a chamber 270 that houses a double acting reciprocating member, such as a piston 280, that sealingly divides the chamber 270 into a first chamber 272 and a second chamber or
  • Both chambers 272 and 274 are filled with a hydraulic fluid 278 suitable for downhole use, such as oil.
  • a biasing member, such as a spring 284, in the first chamber 272, applies a selected force on the piston 280 to cause it to move outward. Since the piston 280 is connected to the pad 250, moving the piston outward causes the pad 250 to extend from the surface 252 of the drill bit 200.
  • the chambers 272 and 274 are in fluid communication with each other via a first fluid flow path or flow line 282 and a second fluid flow path or flow line 286.
  • a flow control device, such as a check valve 285, placed in the fluid flow line 282, may be utilized to control the rate of flow of the fluid from chamber 274 to chamber 272.
  • another flow control device such as a check valve 287, placed in fluid flow line 286, may be utilized to control the rate of flow of the fluid 278 from chamber 272 to chamber 274.
  • the flow control devices 285 and 287 may be configured at the surface to set the rates of flow through fluid flow lines 282 and 286, respectively.
  • the rates may be set or dynamically adjusted by an active device, such as by controlling fluid flows between the chambers by actively controlled valves.
  • the fluid flow is control actively by adjusting fluid properties by using electro or magneto rhological fluids and controllers.
  • piezo electronics are utilized to control fluid flows.
  • one or both flow control devices 285 and 287 may include a variable control biasing device, such as a spring, to provide a constant flow rate from one chamber to another. Constant fluid flow rate exchange between the chambers 272 and 274 provides a first constant rate for the extension for the piston 280 and a second constant rate for the retraction of the piston 280 and, thus, corresponding constant rates for extension and retraction of the pad 250.
  • the size of the flow control lines 282 and 286 along with the setting of their corresponding biasing devices 285 and 287 define the flow rates through lines 282 and 286, respectively, and thus the corresponding rate of extension and retraction of the pad 250.
  • the pads 250 are wear resistant elements, such as cutters, ovoids, elements making rolling contact, or other elements that reduce friction with earth formations. In certain embodiments, pads 250 are directly in front and in the same cutting groove as the cutters 239a, 238b.
  • device 260 is oriented with a tilt against the direction of rotation to minimize the tangential component of friction force experienced by the piston 280. In certain embodiments, the device 260 is located inside the blades 234a, 234b, etc. supported by the bit body 201 with a press fit near the face 232a of the bit 200 and a threaded cap or retainer or a snap ring near the top end of the side portion 234a, 234b.
  • each of the pads 350a, 350b ... 350n is housed in separate chambers 352a, 352b ... 352n respectively.
  • the fluid 395 from chamber 394 is supplied to all chambers, thereby automatically and simultaneously extending and retracting each of the pads 350a, 350b ... 350n based on external forces applied to each such pad during drilling.
  • the rate control device 400 may include a suitable pressure compensator 499 for downhole use.
  • any of the rate controllers made according to any of the embodiments may employ a suitable pressure compensator.
  • FIG. 5 shows an isometric view of a drill bit 500, wherein a rate control device 560 is placed in a crown section 530 of the drill bit 500.
  • the rate control device 560 is the same as shown in FIG. 2, but is coupled to a pad 550 via a hydraulic connection 540 and a fluid line 542.
  • the rate control device 560 is shown placed in a recess 580 accessible from an outside surface 582 of the crown section 530.
  • the pad 550 is shown placed at a face location section 552 on the drill bit face 532, while the hydraulic connection 540 is shown placed in the crown 530 between the pad 550 and the rate control device 560.
  • rate control device 560 may be placed at any desired location in the drill bit, including in the shank 520 and neck section 510 and the hydraulic line 542 may be routed in any desired manner from the rate control device 560 to the pad 550. Such a configuration provides flexibility of placing the rate control device substantially anywhere in the drill bit.
  • the pad is shown connected to a side 720a of a blade 720 of the drill bit 700.
  • the device 750 may be attached or placed at any other suitable location in the drill bit 700. Alternatively or in addition thereto, the device 750 may be integrated into a blade so that the pad will extend toward a desired direction from the drill bit.
  • FIG. 8A shows an integrated rate control device 800.
  • rate control devices 800 are individual self-contained cartridges to be disposed inside the blades of a bit, such as the bits previously described.
  • rate control functionality is achieved through a pressure management device, such as multi-stage orifice 899.
  • FIG. 8B shows the multi-stage orifice 899 with a plurality of orifices 898 that provide a tortuous path for fluid 878 between upper chamber 872 and lower chamber 874.
  • upper chamber 872 and lower chamber 874 shows the multi-stage orifice 899 with a plurality of orifices 898 that provide a tortuous path for fluid 878 between upper chamber 872 and lower chamber 874.
  • upper chamber 872 and lower chamber 874 In an exemplary embodiment, upper
  • rate control devices 900 are self-contained cartridges disposed inside the blades of a bit, such as the bits previously described.
  • the rate control functionality is achieved through a pressure management device, such as high-precision gap 999 between the piston 980 and the cylinder 994.
  • annular gap 1299 is a pressure management device, such as a high precision gap to restrict flow of fluid 1278 to control the movement of piston 1280.
  • fluid flow 1278 moves through ports 1299a and 1299b to interface with both sides of piston 1280.
  • ports 1299a and 1299b have check valves to restrict fluid flow 1278.
  • fluid 1278 is restricted by gap 1299 to control the flow of fluid 1278, resulting in the controlled movement of piston 1280.
  • a pressure compensator 1297 is utilized to compensate the pressure of lower chamber 1274 to downhole fluid pressure.
  • FIG. 14 shows a rate control device 1400 that utilizes a rotary seal 1496 at the mud-oil interface when disposed within a drill bit (shown schematically as 1401).
  • a cam 1492 is located outside of the drill bit 1401 and the rotary motion is transmitted via shaft 1491 into the bit body through a rotary seal 1496.
  • the rotary motion is converted into a translational motion inside the bit body using a second cam 1493 and a follower 1494 attached to the piston 1480.
  • another flow control device such as a check valve 1587, placed in fluid flow line 1586, may be utilized to control the rate of flow of the fluid 1578 from chamber 1572 to reservoir 1574.
  • the flow control devices 1585 and 1587 may be configured at the surface to set the rates of flow through fluid flow lines 1582 and 1586, respectively.
  • the pressure exerted from downhole fluid 1575 biases the piston 1580 downward.
  • a drill bit including: a bit body; a pad associated with the bit body; a rate control device coupled to the pad that extends from a bit surface at a first rate and retracts from an extended position to a retracted position at a second rate in response to external force applied onto the pad, the rate control device including: a piston for applying a force on the pad; a biasing member that applies a force on the piston to extend the pad at the first rate; a fluid chamber associated with the piston; and a pressure management device for controlling a fluid pressure within the fluid chamber.
  • the second rate is less than the first rate.
  • the fluid chamber is divided by the piston into a first fluid chamber and a second fluid chamber.
  • the pressure is less than the first rate.
  • the rate control device includes an accumulator associated with the first side of the piston and the second side of the piston.
  • the piston is a plurality of hydraulically linked pistons.
  • the pad is a plurality of pads that extend from the rate control device, wherein the rate control device is centrally disposed.
  • the rate control device is oriented with a tilt against the direction of rotation of the drill bit.
  • the rate control device is a self-contained cartridge. In certain embodiments, the self-contained cartridge is associated with the drill bit via a press fit or a retainer.
  • the second rate is less than the first rate.
  • the fluid chamber is divided by the piston into a first fluid chamber and a second fluid chamber.
  • the pressure management device is a multi-stage orifice. In certain embodiments, the pressure management device is a high precision gap disposed between the piston and the fluid chamber.
  • a drill bit including: a bit body; a pad associated with the bit body; a rate control device coupled to the pad that extends from a bit surface at a first rate and retracts from an extended position to a retracted position at a second rate in response to an external force applied, the rate control device including: a piston for applying a force on the pad; a biasing member that applies a force on the piston to expose the pad at the first rate; and a rotary device that applies a force on the piston to hide the pad at the second rate.
  • the second rate is less than the first rate.

Landscapes

  • 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)
  • Drilling And Boring (AREA)

Abstract

Selon un aspect, l'invention concerne un trépan, comprenant : un corps de trépan ; un patin associé au corps de trépan ; un dispositif de commande de vitesse couplé au patin qui se déploie à partir d'une surface du trépan à une première vitesse et se rétracte depuis une position déployée vers une position rétractée à une seconde vitesse en réponse à une force extérieure appliquée sur le patin, le dispositif de commande de vitesse comprenant : un piston pour appliquer une force sur le patin ; un élément de sollicitation qui applique une force sur le piston afin de déployer le patin à la première vitesse ; une chambre de fluide associée au piston ; et un dispositif de gestion de pression pour commander la pression d'un fluide à l'intérieur de la chambre de fluide.
EP15850810.1A 2014-10-16 2015-10-16 Trépan équipé de patins auto-réglables Active EP3207206B1 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US14/516,340 US9708859B2 (en) 2013-04-17 2014-10-16 Drill bit with self-adjusting pads
US14/864,436 US10000977B2 (en) 2013-04-17 2015-09-24 Drill bit with self-adjusting pads
PCT/US2015/055944 WO2016061458A1 (fr) 2014-10-16 2015-10-16 Trépan équipé de patins auto-réglables

Publications (3)

Publication Number Publication Date
EP3207206A1 true EP3207206A1 (fr) 2017-08-23
EP3207206A4 EP3207206A4 (fr) 2018-05-30
EP3207206B1 EP3207206B1 (fr) 2021-06-23

Family

ID=55747400

Family Applications (1)

Application Number Title Priority Date Filing Date
EP15850810.1A Active EP3207206B1 (fr) 2014-10-16 2015-10-16 Trépan équipé de patins auto-réglables

Country Status (7)

Country Link
EP (1) EP3207206B1 (fr)
CN (1) CN107135658B (fr)
CA (1) CA2964366C (fr)
MX (1) MX2017004879A (fr)
RU (1) RU2708444C2 (fr)
SG (1) SG11201702865UA (fr)
WO (1) WO2016061458A1 (fr)

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN108843246A (zh) * 2018-06-13 2018-11-20 中国石油天然气股份有限公司 用于抑止钻具粘滑振动的自适应限位齿控制单元和钻头

Family Cites Families (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2169502A (en) * 1938-02-28 1939-08-15 Grant John Well bore enlarging tool
US4007797A (en) * 1974-06-04 1977-02-15 Texas Dynamatics, Inc. Device for drilling a hole in the side wall of a bore hole
GB9708428D0 (en) * 1997-04-26 1997-06-18 Camco Int Uk Ltd Improvements in or relating to rotary drill bits
GB0503742D0 (en) * 2005-02-11 2005-03-30 Hutton Richard Rotary steerable directional drilling tool for drilling boreholes
US7591327B2 (en) 2005-11-21 2009-09-22 Hall David R Drilling at a resonant frequency
US7240744B1 (en) 2006-06-28 2007-07-10 Jerome Kemick Rotary and mud-powered percussive drill bit assembly and method
US8763726B2 (en) * 2007-08-15 2014-07-01 Schlumberger Technology Corporation Drill bit gauge pad control
GB2454697B (en) * 2007-11-15 2011-11-30 Schlumberger Holdings Anchoring systems for drilling tools
US20090133931A1 (en) * 2007-11-27 2009-05-28 Schlumberger Technology Corporation Method and apparatus for hydraulic steering of downhole rotary drilling systems
US9915138B2 (en) * 2008-09-25 2018-03-13 Baker Hughes, A Ge Company, Llc Drill bit with hydraulically adjustable axial pad for controlling torsional fluctuations
RU2418938C1 (ru) * 2010-02-26 2011-05-20 Николай Митрофанович Панин Алмазная буровая коронка
US9080399B2 (en) * 2011-06-14 2015-07-14 Baker Hughes Incorporated Earth-boring tools including retractable pads, cartridges including retractable pads for such tools, and related methods
US9631461B2 (en) * 2012-02-17 2017-04-25 Halliburton Energy Services, Inc. Well flow control with multi-stage restriction

Also Published As

Publication number Publication date
WO2016061458A1 (fr) 2016-04-21
CN107135658B (zh) 2019-04-16
RU2708444C2 (ru) 2019-12-06
EP3207206B1 (fr) 2021-06-23
CN107135658A (zh) 2017-09-05
SG11201702865UA (en) 2017-05-30
RU2017115554A3 (fr) 2019-03-04
MX2017004879A (es) 2017-07-05
CA2964366C (fr) 2019-07-02
EP3207206A4 (fr) 2018-05-30
RU2017115554A (ru) 2018-11-19
CA2964366A1 (fr) 2016-04-21

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