WO2015084342A1 - Outil de lâcher de bille et procédés d'utilisation - Google Patents

Outil de lâcher de bille et procédés d'utilisation Download PDF

Info

Publication number
WO2015084342A1
WO2015084342A1 PCT/US2013/073115 US2013073115W WO2015084342A1 WO 2015084342 A1 WO2015084342 A1 WO 2015084342A1 US 2013073115 W US2013073115 W US 2013073115W WO 2015084342 A1 WO2015084342 A1 WO 2015084342A1
Authority
WO
WIPO (PCT)
Prior art keywords
ball
tool
mandrel
drop
downhole
Prior art date
Application number
PCT/US2013/073115
Other languages
English (en)
Inventor
Helge RORVIK
Original Assignee
Halliburton Energy Services, 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 Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to PCT/US2013/073115 priority Critical patent/WO2015084342A1/fr
Priority to US15/021,028 priority patent/US20160222764A1/en
Priority to GB1606954.4A priority patent/GB2538386A/en
Priority to CA2928139A priority patent/CA2928139C/fr
Priority to AU2013406811A priority patent/AU2013406811B2/en
Priority to CN201380080123.4A priority patent/CN105793516A/zh
Publication of WO2015084342A1 publication Critical patent/WO2015084342A1/fr
Priority to NO20160663A priority patent/NO20160663A1/en

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
    • E21B10/26—Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers
    • E21B10/32—Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
    • E21B10/322—Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools cutter shifted by fluid pressure
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
    • E21B47/18—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry

Definitions

  • the present disclosure relates generally to methods and apparatus for dropping an activation ball from a downhole tool, and more particularly to a downhole ball drop tool that releases an activation ball in response to a downlink signal provided from the surface.
  • a borehole is drilled into the subterranean producing formation.
  • a drill bit creates a borehole with a diameter equal to the of the drill bit.
  • Such reamers will be in a retracted, or inactivated, state during drilling operations, but will then need to activated, with the reamer arms extended, to enlarge the borehole.
  • an activation ball is dropped to engage a seat operatively associated with the tool to be activated. Once the ball engages the seat and closes or restricts the flow passage containing the seat, fl uid can be pressurized above the ball to cause activation of the tool.
  • FIG. 1 depicts a schematic view of an example system for controlling the activation of a downhole tool.
  • FIG. 2 shows an example embodiment of a downhole tool that may be activated using an activation ball dropped from a ball drop tool.
  • FIG. 3 illustrates an example embodiment ball drop tool. DETAI LED DESCRI PTION
  • references to “one embodiment” or “an embodiment,” or to “one example” or “an example” mean that the feature being referred to is, or may be, included in at least one em bodiment.
  • references to “an embodiment” or “one embodiment” or to “one example” or “an example” in this description are not intended to necessarily refer to the same embodiment or example; however, neither are such embodiments mutually exclusive, unless so stated or as will be readily apparent to those of ordinary skill in the art having the benefit of this disclosure.
  • the present disclosure includes a variety of combinations and/or integrations of the embodiments and examples described herein, as well as further embodiments and examples as defined within the scope of all claims based on this disclosure, as well as all legal equivalents of such claims.
  • This disclosure describes a method and apparatus for dropping a ball from a subassembly in a tool string.
  • the tool string is run into a well with one or more balls retained within the sub-assembly, though in some cases, it may be possible to communicate the balls to the sub-assembly, after the tool string is in the borehole.
  • the sub-assembly can be actuated to drop a ball in response to a downlink control signal.
  • the ball drop tool is described specifically in the context of facilitating the opening of a reamer within the tool string.
  • One skilled in the art will readily recognize that although the description of this example is to use the ball drop tool for actuating a reamer, the embodiments described herein are similarly applicable to other tools that may utilize a dropped ball to engage a ball seat for activating a mechanism in a tool that has been lowered into a well bore.
  • fluid pressure can be increased in the tool string to raise the pressure in the blocked fluid path to activate a mechanism in the tool string such as a sliding sleeve mechanism or another form of piston, for example.
  • balls is used throughout this disclosure to be generic to other configurations of devices configured to engage a seat as described above, specifically including non-spherical configurations, for example, darts, plugs, semi-ellipsoidal configurations, and other configurations capable to sealing or restricting fluids by engaging a seat of an activation or de-activation mechanism in the tool string
  • FIG. 1 depicts a schematic view of an example system for controlling the activation and deactivation of a downhole tool by operator control in providing a downlink signal.
  • a drilling installation 100 includes a subterranean borehole 104 in which a drill string 108 is located.
  • the drill string 108 may comprise jointed sections of drill pipe 106 suspended from a drilling platform 112 secured at a wellhead, as known in the art.
  • a downhole assembly or bottom hole assembly (BHA) 151 at a bottom end of the drill string 108 includes a drill bit 116 to penetrate earth formations, and for purposes of this example, includes a reamer assembly 118 positioned uphole of the drill bit 116 to widen the borehole 104 by operation of selectively deployable cutting elements.
  • BHA bottom hole assembly
  • the BHA 151 may further include other components such as a rotary steerable system, measurement while drilling (MWD) and logging while drilling (LWD) tools.
  • a measurement and control assembly 120 may be included in the BHA 151, which includes measurement instruments to measure borehole and/or drilling parameters.
  • the borehole 104 is thus an elongated cavity that is substantially cylindrical, having a substantially circular cross-sectional outline that remains more or less constant along the length of the borehole 104.
  • the borehole 104 may in some cases be linear, but more commonly will include one or more curves, bends, doglegs, or angles along its length.
  • the "axis" of the borehole 104 (and therefore of the drill string 108 or part thereof) means the longitudinally extending centerline of the generally cylindrical borehole 104 (corresponding, for example, to longitudinal axis 367 in FIG. 3).
  • Axial and “longitudinal” thus means a direction along a line substantially parallel with the lengthwise direction of the borehole 104 at the relevant point or portion of the borehole 104 under discussion;
  • radial means a direction or including a directional component substantially along a line that intersects the borehole axis and lies in a plane perpendicular to the borehole axis;
  • tangential means a direction su bstantially along a line that does not intersect the borehole axis and that lies in a plane perpendicular to the borehole axis;
  • circumferential or “rotational” means a substantially arcuate or circular path described by rotation of a tangential vector about the borehole axis.
  • Rotation and its derivatives mean not only continuous or repeated rotation through 360° or more, but also includes angular or circumferential displacement of less than 360°.
  • movement or location “forwards” or “downhole” means axial movement or relative axial location towards the drill bit 116, away from the earth's surface.
  • backwards means movement or relative location axially along the borehole 104, away from the drill bit 116 and towards the earth's surface. Note that in FIGS. 2, 3, and 4 of the drawings, the uphole end of the depicted tool lies to the left.
  • Drilling fluid e.g. drilling "mud," or other fluids that may be in the well
  • Drilling fluid is circulated from a drilling fluid reservoir, for exa mple a storage pit, at the earth's surface (and coupled to the wellhead) by a pump system 132 that forces the drilling fluid down a drilling bore 128 provided by a hollow interior of the drill string 108, so that the drilling fluid exits under relatively high pressure through the drill bit 116.
  • the drilling fluid moves back upwards along the borehole 104, occupying a borehole annulus 134 defined between the drill string 108 and a wall of the borehole 104.
  • the drilling fluid is typically pumped along the inner diameter (i.e., the bore 128) of the drill string 108, with fluid flow out of the bore 128 being restricted at the drill bit 116.
  • the drilling fluid then flows upwards along the annulus 134, carrying cuttings from the bottom of the borehole 104 to the wellhead, where the cuttings are removed and the drilling fluid may be returned to the drilling fluid reservoir 132.
  • Fluid pressure in the bore 128 is therefore greater than fluid pressure in the annulus 134.
  • Pressure differentials exist between the bore 128 and the annulus 134, although downhole drilling fluid conditions may, in other embodiments, be referenced to isolated pressure values in the bore 128. Unless the context indicates otherwise, the term "pressure differential" means the difference between general fluid pressure in the bore 128 and pressure in the annulus 134.
  • System 100 includes a surface control system 140, to send and receive signals to and from downhole equipment incorporated in the drill string 108, for example, which may in some cases be part of the downhole measurement and control assembly 120.
  • the surface control system 140 may process data relating to the drilling operations, data from sensors and devices at the surface, data received from downhole, and may control one or more operations of downhole tools and/or surface devices.
  • the drill string 108 may include one or more downhole tools instead of or in addition to the reamer assembly 118.
  • the downhole tools of the drill string 108 in this example, includes a reamer assembly 118 located in the BHA 151 to enlarge the diameter of the borehole 104 as the BHA 151 penetrates the formation.
  • the drill string 108 may comprise multiple reamer assemblies 118.
  • Each reamer assembly 118 will comprise one or more circumferentially spaced blades or other structures that carry cutting elements (e.g., reamer arms 202 in FIG. 2).
  • the reamer assembly 118 includes a reamer 144 comprising a generally tu bular reamer housing 204 connected in-line in the drill string 108 and carrying the reamer arms 202, which are radially extendable and retractable from a radially outer surface of the reamer housing 204, to selectively expand and contract the reamer's effective diameter.
  • Controlling deployment and retraction of the reamer 144 may be controlled by controlling pressure conditions in the drilling fluid or hydraulically actuated by agency of the drilling fluid.
  • deployment of the reamer arms 202 may be actuated by a ball dropped to engage a ball seat a ball for activating a mechanism in the reamer 144.
  • FIG. 2 shows an example embodiment of a reamer assembly 118 that may form part of the drill string 108, with the reamer 144 that forms part of the reamer assembly 118 depicted in a deployed condition.
  • the reamer arms 202 and the supported cutting elements are radially extended from the reamer housing 204 and to enable contact with the borehole sidewall for reaming of the borehole 104 when the reamer housing 204 rotates with the drill string 108.
  • the reamer arms 202 are mounted on the reamer housing 204 in axially aligned, hingedly connected pairs that jackknife into deployment, when activated.
  • the reamer arms 202 are retracted into the tubular reamer housing 204, in which the reamer arms 202 do not project beyond the radially outer surface of the reamer housing 204, therefore clearing the annulus 134 and allowing axial and rotational displacement of the reamer housing 204 as part of the drill string 108, without engagement of a borehole wall by the reamer arms 202.
  • Different activation mechanisms for the reamer 144 may be employed in various embodiments.
  • activation balls are dropped from the surface to travel down the drillstring or tubing and engage a ball seat.
  • there will be downhole devices in the tool string that have restrictions which would prevent a ball from passing therethrough to the reamer or other tool to be activated.
  • filter screens are often run downhole to keep debris and drilling fluid particulate from plugging off small passages in tools positioned below.
  • Activation balls are unable to pass through the filter screens.
  • a MWD (or LWD) tool also provides a flow path obstruction that prohibits a dropped ball from actuating tools positioned downhole of the MWD tool.
  • the use of a downhole ball drop assembly located with a clear path for a released ball to reach the ball seat to activate the desired tool, serves to facilitate ball/pressure actuation.
  • the drill string 108 may include a sub-assembly in the example form of a ball drop sub-assembly 148 that provides deployment control mechanisms configured to provide ball actuated deployment of the reamer 144 responsive to a downlink signal received at the ball drop sub-assembly 148.
  • the ball drop sub-assembly is preferably positioned downhole from any flow path obstructions that would prevent a dropped ball from landing on a seat operably associated with an activating mechanism.
  • the ball drop sub-assembly 148 will typically include body or housing 200 (see FIG. 2) connected in-line in the drill string 108.
  • the housing for the ball drop sub-assembly may be a portion of a housing (or housing assembly associated with another tool in the tool string.
  • the ball drop sub-assembly 148 is mounted directly uphole of the reamer 144, but in other embodiments, the positional arrangement of the ball drop sub-assembly 148 and the reamer 144 (or other tool to be actuated) may be different.
  • FIG. 3 illustrates an example ball drop tool 300, which may also be referred to as the ball drop sub-assembly 148, comprising a ball drop housing 302 having a central opening 304 defined by a central bore 306 running longitudinally therethrough, from an uphole end 308 to a downhole end 310.
  • the downhole end 310 of the ball drop housing 302 is open to allow the passage of balls and drilling fluids therethrough.
  • Each end of the ball drop tool 300 may include connecting means, such as threads, by which the ball drop tool 300 may be connected into a drill string, such that the central bore 306 through the ball drop housing 302 is continuous with a bore of the drill string.
  • threads 312 may be defined on inner surface 314 at the uphole end 308 of the ball drop housing 302.
  • the ball drop housing 302 is thus adapted to be connected to a lower end of a different portion of the drill string 108 (e.g., drill pipe 106) or a different component in the bottom hole assembly 151.
  • threads 316 may be defined on inner surface 318 at the downhole end 310 of the ball drop housing 302.
  • the ball drop housing 302 is thus adapted to be connected to an upper end of a reamer, a tool joint, or other threaded member positioned downhole of the ball drop tool 300.
  • the ball drop tool 300 has a mandrel for retaining balls to be dropped.
  • the mandrel is a side mandrel 320 that is offset from and extends alongside the central bore 306 of the ball drop housing 302.
  • the side mandrel 302 includes a radial bore 322 provided in the wall of the ball drop housing 302 to communicate a ball drop bore 324 of the side mandrel 320 with the central bore 306 of the ball drop housing 302.
  • the side mandrel 320 is adapted to contain drop balls in sealing and locking engagement therewith. Passage of drop balls from the ball drop bore 324 to the central bore 306 through the radial bore 322 is controlled by an electromechanical deployment mechanism 326 to access downhole components below.
  • the ball drop tool 300 may be utilized with one or more drop balls.
  • the embodiment shown in FIG. 3 has drop balls comprising at least a first or lower ball 328.
  • the ball drop tool 300 may further comprise a second or upper ball 330, which is an optional component for the ball drop tool 300 as indicated by the dashed lines identifying the additional drop ball and its orientation within the tool.
  • the first ball 328 and the second ball 330 are approximately the same size. Balls of differing sizes may be used depending on the configuration of the tool and the ball seats to be utilized.
  • first ball 328 may be smaller than the second ball 330.
  • first ball 328 may be larger than the second ball 330.
  • additional balls may be added by lengthening the ball drop bore 324 of the side mandrel 320 and placing the additional balls therein.
  • Downlink signaling or communicating from the surface to downhole tools, is typically performed to provide instructions in the form of commands to the drilling tools.
  • downlink commands may instruct the ball drop tool 300 to release a pre-installed ball (e.g., the first ball 328 or the second ball 330) for activating or deactivating the reamer assembly 148 positioned downhole of the ball drop tool 300.
  • a downlink command is communicated to the ball drop tool 300 from the surface and received at a downlink receiver 332.
  • Various methods of downlink signaling may be performed to communicate the downl ink command to the downlink receiver 332.
  • mud pulse telemetry may be used to create a series of momentary pressure changes, or pulses, in the drilling fluid to be detected at the downlink receiver 332.
  • the pulse duration, amplitude, and time between pulses, is detected by the downlink receiver 332 and interpreted as a particular instruction to release a pre-installed ball in the ball drop tool 300.
  • Mud pulse telemetry may include various methods for introducing positive or negative pressure pulses into the drilling fluid.
  • the downlink receiver 332 may comprises either a flow meter or a pressure sensor (e.g., a pressure transducer), and a microprocessor, programmed with a telemetry scheme and algorithm for filtering and decoding the pressure pulses received downhole.
  • the pressure sensor may be a differential pressure transducer.
  • a differential pressure transducer having a relatively low-pressure range (as compared to the drilling fluid pressure in the central bore 306 of the ball drop tool 300) tends to advantageously increase a signal amplitude (and therefore the signal to noise ratio).
  • a differential transducer having a differential pressure range from 0 to 1000 psi may be advantageously utilized.
  • the ball drop tool 300 may be further used with bidirectional communication, allowing for downlink and uplink signals to be sent at the same time without interference between the two signals. Such interference is avoided by sending downlink and uplink pulses within different frequency bands.
  • the uplink pulses may have a high frequency, while the downlink pulses may have a low frequency, or vice versa.
  • bi-directional communication including the downlink signaling described herein, is achievable using mud pulse telemetry, other types of telemetry schemes may be used, or a combination of telemetry schemes may be used.
  • uplink signals may be generated using another type of telemetry, such as electromagnetic telemetry, for example, or vice versa. If the telemetry media is the same for uplink and downlink signaling, then the frequency band of the uplink and downlink signals may be sufficiently different to achieve bi-directional communication. Bi-directional communication may be achieved using any telemetry system with its appropriate uplink receivers and transmitters, for example, pressure transducers for mud pulse telemetry. Bi-directional communication provides the advantage of continuous communication between the surface and downhole tools. In some cases, the downlink may include signals communicated from the surface (or from a lower location in the tool string) through wired pipe.
  • the downlink receiver 332 disposed in the downhole ball drop tool 300 receives the downlink signals for decoding.
  • a downlink command decoded from the downlink signal may be limited to a narrow frequency band over a particular time interval. Therefore, a relevant metric for the downlink receiver 332 may be a frequency band and time of reception for detected downlink signals.
  • the downlink receiver 332 will detect noise associated with drilling operations in addition to the downlink signal. Therefore, decoding the downlink signal at the downlink receiver 332 comprises filtering steps to remove the noise and using a detection algorithm to match a pressure pulse sequence of the downlink signal to a particular pre-programmed downlink command.
  • downlink signals may first pass through a lock-in amplifier filter to separate a narrow-band frequency signal from interfering noise.
  • the shape or duration of each pressure pulse may be analyzed to determine a data value associated with each pressure pulse and decode the downlink command being transmitted.
  • the downlink receiver 332 is illustrated as being positioned within the ball drop tool 300 for instructing the release of a pre-installed ball.
  • the down link receiver 332 present in the ball drop tool 300 is useful in a broad range of applications, such as instructing another tool in a different downhole assembly.
  • the ball drop tool 300 may be implemented without a downlink receiver present within the ball drop housing 302, but in communication with a downhole receiver located in a different downhole assembly.
  • the downhole receiver may work in conjunction with a master controller disposed in the downhole assembly for facilitating communication.
  • the telemetry scheme and algorithm for decoding downlink signals are programmed primarily into the downhole receiver.
  • the master controller completes the signal decoding and distributes decoded downlink commands to the an appropriate downhole tool, such as the ball drop tool 300.
  • the master controller housed in the downhole assembly determines which particular tool the instruction is directed to.
  • the master controller then distributes the instruction to that tool, and the particular downhole tool is thereby controlled and changed as a result of the signals being sent.
  • the downlink command is received at the downlink receiver 332 housed in the ball drop tool 300 and instructs the electromechanical deployment mechanism 326 to release a pre-installed ball from the side mandrel 320 into the central bore 306 of the ball drop tool 300.
  • the electromechanical deployment mechanism 326 comprises a solenoid-driven actuator that responds to a downlink command received at the downlink receiver 332 to linearly transition between a retaining position 334 and a releasing position 336.
  • Electromechanical actuators such as the solenoid-driven actuator, provide control over a force and a motion profile between the retaining position 334 and the releasing position 336.
  • Electromechanical actuators may have an integrated encoder that can be used to accurately control velocity and position.
  • the solenoid-driven actuator comprises an electromagnetically inductive coil, wound around an armature (e.g., movable steel or iron slug).
  • the electromagnetically inductive coil is shaped such that the armature can be moved in and out of the center, altering the electromagnetically inductive coil's inductance and thereby becoming an electromagnet.
  • the armature is used in the retaining position 334 to hold the pre-installed balls (e.g., the first ball 328 or the second ball 330) within the ball drop bore 324 of the side mandrel 320.
  • the force applied to the armature is proportional to the change in inductance of the electromagnetically inductive coil with respect to a change in position of the armature, and the current flowing through the coil that is applied in response to the downlink command is received at the downlink receiver 332.
  • the force applied to the armature will always move the armature in a direction that increases the inductance of the electromagnetically inductive coil.
  • other types of linear actuators may be utilized for transitioning between the retaining position 334 and the releasing position 336, including: mechanical, hydraulic, pneumatic, and piezoelectric actuators.
  • a single ball (e.g., the first ball 328) is released from the ball drop bore 324 of the side mandrel 320.
  • the first ball 328 travels along the radial bore 322 and drops down the central bore 306 of the ball drop tool 300. Flow of drilling fluid within the central bore 306 will displace the first ball 328 downwardly until it lands in a ball seat or a ball seat mandrel disposed in a tool located downhole of the ball drop tool 300, such as the reamer 144.
  • the first ball 328 When the first ball 328 reaches and engages the ball seat, it operates as an activation ball by allowing the increase pressure in the tool string to activate a desired mechanism associated with the ball seat, including the reaming operations described above, or any other tool or mechanism that requires an increase in pressure, or a redirection of drilling fluid flow caused by an activation ball engaging a ball seat.
  • a near bit reamer (not shown) may be activated while drilling a borehole to enlarge the borehole diameter, thus avoiding a long rathole that would require an extra trip to enlarge.
  • Ratholes may result from a reamer positioned at a distance from the drill bit (e.g., above the rotary steerable system and LWD tools).
  • the near bit reamer may be placed just above the drill bit, thereby minimizing the length of the rathole after enlarging the borehole.
  • the reamer may be placed higher in the BHA, for example, above the rotary steerable system or between the drill bit and the rotary steerable system.
  • the near bit reamer is dormant during drilling and may be activated using a dropped activation ball to enlarge the rathole.
  • the ball set mandrel may include at least two ball seats configured to engage dropped balls.
  • the first ball 328 may land in a ball seat in the near bit reamer and fluid pressure is then applied to the top of the first ball 328.
  • Positive surface pressure on the first ball 328 increases the flow rate of the drilling fluid and hydraulically activates the reamer, causing borehole enlargement.
  • Pressure drop through the ball seat mandrel is used to maintain the reamer in an activated, open position.
  • the reamer may be deactivated to resume normal drilling ahead or tripping out operations.
  • sufficient drilling fluid pressure is applied to the top of the first ball 328 to extrude it through the ball seat.
  • the second ball 330 when dropped, acts as a de-activation ball by engaging with a second ball seat of the ball seat mandrel and further increasing drilling fluid pressure in the tool string.
  • ball drop tool 300 is shown disposed in the drill string 108, it is apparent that the tool can be utilized in production tubing or in wellbore casing. It will be seen, therefore, that the ball drop tool is well adapted to carry out the ends and advantages mentioned, as well as those inherent therein.
  • the ball drop tool 300 can be utilized with any tool which requires that a ball be dropped to engage a ball seat therein and is not limited by the specific examples provided. While specific example embodiments of the apparatus have been described for the purposes of this disclosure, numerous changes in the arrangement and construction of parts may be made by those skilled in the art. Various modifications and changes may be made to these embodiments without departing from the broader spirit and scope of the invention. Accordingly, the specification and drawings are to be regarded in an illustrative rather than a restrictive sense. All such changes are encompassed within the spirit and scope of the claims.

Landscapes

  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Remote Sensing (AREA)
  • Geophysics (AREA)
  • Acoustics & Sound (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)
  • Coating Apparatus (AREA)
  • Pens And Brushes (AREA)
  • Gripping On Spindles (AREA)
  • Closures For Containers (AREA)

Abstract

La présente invention concerne des modes de réalisation d'un procédé et d'un appareil destinés à lâcher une bille dans un train d'outils. Un exemple de mode de réalisation est un outil de lâcher de bille de fond de trou qui libère une bille d'activation en réponse à un signal en liaison descendante produit depuis la surface. L'outil de lâcher de bille est fourni comme partie d'un train d'outils. Une variété d'outils reliés à un train d'outils peuvent comprendre un siège de bille destiné à recevoir une bille d'activation lâchée depuis l'outil de lâcher de bille. Une fois que la bille est en contact avec le siège de bille, la pression du fluide peut être augmentée dans le train d'outils afin d'activer un mécanisme dans un outil de fond de trou.
PCT/US2013/073115 2013-12-04 2013-12-04 Outil de lâcher de bille et procédés d'utilisation WO2015084342A1 (fr)

Priority Applications (7)

Application Number Priority Date Filing Date Title
PCT/US2013/073115 WO2015084342A1 (fr) 2013-12-04 2013-12-04 Outil de lâcher de bille et procédés d'utilisation
US15/021,028 US20160222764A1 (en) 2013-12-04 2013-12-04 Ball drop tool and methods of use
GB1606954.4A GB2538386A (en) 2013-12-04 2013-12-04 Ball drop tool and methods of use
CA2928139A CA2928139C (fr) 2013-12-04 2013-12-04 Outil de lacher de bille et procedes d'utilisation
AU2013406811A AU2013406811B2 (en) 2013-12-04 2013-12-04 Ball drop tool and methods of use
CN201380080123.4A CN105793516A (zh) 2013-12-04 2013-12-04 球降落工具及使用方法
NO20160663A NO20160663A1 (en) 2013-12-04 2016-04-21 Ball drop tool and methods of use

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2013/073115 WO2015084342A1 (fr) 2013-12-04 2013-12-04 Outil de lâcher de bille et procédés d'utilisation

Publications (1)

Publication Number Publication Date
WO2015084342A1 true WO2015084342A1 (fr) 2015-06-11

Family

ID=53273901

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2013/073115 WO2015084342A1 (fr) 2013-12-04 2013-12-04 Outil de lâcher de bille et procédés d'utilisation

Country Status (7)

Country Link
US (1) US20160222764A1 (fr)
CN (1) CN105793516A (fr)
AU (1) AU2013406811B2 (fr)
CA (1) CA2928139C (fr)
GB (1) GB2538386A (fr)
NO (1) NO20160663A1 (fr)
WO (1) WO2015084342A1 (fr)

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9708894B2 (en) 2014-08-27 2017-07-18 Baker Hughes Incorporated Inertial occlusion release device
US9745847B2 (en) 2014-08-27 2017-08-29 Baker Hughes Incorporated Conditional occlusion release device
US10100601B2 (en) 2014-12-16 2018-10-16 Baker Hughes, A Ge Company, Llc Downhole assembly having isolation tool and method
US10428623B2 (en) 2016-11-01 2019-10-01 Baker Hughes, A Ge Company, Llc Ball dropping system and method

Families Citing this family (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9290998B2 (en) * 2013-02-25 2016-03-22 Baker Hughes Incorporated Actuation mechanisms for downhole assemblies and related downhole assemblies and methods
WO2016190850A1 (fr) 2015-05-26 2016-12-01 Halliburton Energy Services, Inc. Outil de lâcher de bille et procédés d'utilisation
CN109594944A (zh) * 2018-12-18 2019-04-09 中国石油集团川庆钻探工程有限公司 微球式测量仪预存储与井下自动释放方法及装置
US11396788B2 (en) 2020-12-17 2022-07-26 Halliburton Energy Services, Inc. Fluid activated metal alloy shut off device
US11840898B2 (en) 2021-12-21 2023-12-12 Baker Hughes Oilfield Operations Llc Intelligent section mill, method, and system

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1132565A2 (fr) * 2000-03-09 2001-09-12 Halliburton Energy Services, Inc. Méthode et Dispositif pour lancer de billes dans des puits de forage
US20030155115A1 (en) * 2002-02-21 2003-08-21 Weatherford/Lamb, Inc. Ball dropping assembly
US20120085548A1 (en) * 2010-10-06 2012-04-12 Colorado School Of Mines Downhole Tools and Methods for Selectively Accessing a Tubular Annulus of a Wellbore
US20130062055A1 (en) * 2010-05-26 2013-03-14 Randy C. Tolman Assembly and method for multi-zone fracture stimulation of a reservoir using autonomous tubular units
US8596359B2 (en) * 2010-10-19 2013-12-03 Halliburton Energy Services, Inc. Remotely controllable fluid flow control assembly

Family Cites Families (21)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2737244A (en) * 1952-04-25 1956-03-06 Baker Oil Tools Inc Multiple ball release devices for well tools
US3568768A (en) * 1969-06-05 1971-03-09 Cook Testing Co Well pressure responsive valve
US5425423A (en) * 1994-03-22 1995-06-20 Bestline Liner Systems Well completion tool and process
US5758726A (en) * 1996-10-17 1998-06-02 Halliburton Energy Services Ball drop head with rotating rings
US5810088A (en) * 1997-03-26 1998-09-22 Baker Hughes, Inc. Electrically actuated disconnect apparatus and method
US5960881A (en) * 1997-04-22 1999-10-05 Jerry P. Allamon Downhole surge pressure reduction system and method of use
AU4499400A (en) * 1999-04-30 2000-11-17 Frank's International, Inc. Method and multi-purpose apparatus for control of fluid in wellbore casing
US6390200B1 (en) * 2000-02-04 2002-05-21 Allamon Interest Drop ball sub and system of use
US6776228B2 (en) * 2002-02-21 2004-08-17 Weatherford/Lamb, Inc. Ball dropping assembly
US7036611B2 (en) * 2002-07-30 2006-05-02 Baker Hughes Incorporated Expandable reamer apparatus for enlarging boreholes while drilling and methods of use
US7100700B2 (en) * 2002-09-24 2006-09-05 Baker Hughes Incorporated Downhole ball dropping apparatus
WO2005090740A1 (fr) * 2004-03-19 2005-09-29 Tesco Corporation Dispositif anti-jaillissement de type a lance
US7770652B2 (en) * 2007-03-13 2010-08-10 Bbj Tools Inc. Ball release procedure and release tool
US8091628B2 (en) * 2007-05-30 2012-01-10 Smith International, Inc. Apparatus and method for providing fluid and projectiles to downhole tubulars
US7624810B2 (en) * 2007-12-21 2009-12-01 Schlumberger Technology Corporation Ball dropping assembly and technique for use in a well
CA2719752A1 (fr) * 2008-03-31 2009-10-08 Halliburton Energy Services, Inc. Systeme et procede pour operations d'agrandissement de trou en une seule passe
US8307913B2 (en) * 2008-05-01 2012-11-13 Schlumberger Technology Corporation Drilling system with drill string valves
US9085974B2 (en) * 2009-08-07 2015-07-21 Halliburton Energy Services, Inc. Stimulating subterranean zones
CN201560744U (zh) * 2009-12-21 2010-08-25 新疆石油管理局采油工艺研究院 管内投球器
US8678098B2 (en) * 2010-11-12 2014-03-25 Baker Hughes Incorporated Magnetically coupled actuation apparatus and method
GB2526826B (en) * 2014-06-03 2016-05-18 Nov Downhole Eurasia Ltd Downhole actuation apparatus and associated methods

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1132565A2 (fr) * 2000-03-09 2001-09-12 Halliburton Energy Services, Inc. Méthode et Dispositif pour lancer de billes dans des puits de forage
US20030155115A1 (en) * 2002-02-21 2003-08-21 Weatherford/Lamb, Inc. Ball dropping assembly
US20130062055A1 (en) * 2010-05-26 2013-03-14 Randy C. Tolman Assembly and method for multi-zone fracture stimulation of a reservoir using autonomous tubular units
US20120085548A1 (en) * 2010-10-06 2012-04-12 Colorado School Of Mines Downhole Tools and Methods for Selectively Accessing a Tubular Annulus of a Wellbore
US8596359B2 (en) * 2010-10-19 2013-12-03 Halliburton Energy Services, Inc. Remotely controllable fluid flow control assembly

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9708894B2 (en) 2014-08-27 2017-07-18 Baker Hughes Incorporated Inertial occlusion release device
US9745847B2 (en) 2014-08-27 2017-08-29 Baker Hughes Incorporated Conditional occlusion release device
US10100601B2 (en) 2014-12-16 2018-10-16 Baker Hughes, A Ge Company, Llc Downhole assembly having isolation tool and method
US10428623B2 (en) 2016-11-01 2019-10-01 Baker Hughes, A Ge Company, Llc Ball dropping system and method

Also Published As

Publication number Publication date
US20160222764A1 (en) 2016-08-04
AU2013406811A1 (en) 2016-04-28
CA2928139A1 (fr) 2015-06-11
AU2013406811B2 (en) 2016-09-22
NO20160663A1 (en) 2016-04-21
CN105793516A (zh) 2016-07-20
CA2928139C (fr) 2019-06-04
GB2538386A (en) 2016-11-16

Similar Documents

Publication Publication Date Title
AU2013406811B2 (en) Ball drop tool and methods of use
US9453380B2 (en) Remote hydraulic control of downhole tools
US8464812B2 (en) Remotely controlled apparatus for downhole applications and related methods
US9284816B2 (en) Actuation assemblies, hydraulically actuated tools for use in subterranean boreholes including actuation assemblies and related methods
US8936099B2 (en) Cam mechanism for downhole rotary valve actuation and a method for drilling
US20150014061A1 (en) Hydraulic actuation of a downhole tool assembly
US10487602B2 (en) Hydraulic control of downhole tools
US20130292175A1 (en) Drilling assemblies including expandable reamers and expandable stabilizers, and related methods
US9038748B2 (en) Tools for use in subterranean boreholes having expandable members and related methods
US9719305B2 (en) Expandable reamers and methods of using expandable reamers
EP2483510A2 (fr) Appareil telecommande pour applications de fond de puits et procedes d'exploitation
US20150144401A1 (en) Hydraulically actuated tool with electrical throughbore
US10794178B2 (en) Assemblies for communicating a status of a portion of a downhole assembly and related systems and methods
US10597976B2 (en) Ball drop tool and methods of use
US20240141739A1 (en) Indexing Control System

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 13898779

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 2928139

Country of ref document: CA

ENP Entry into the national phase

Ref document number: 201606954

Country of ref document: GB

Kind code of ref document: A

Free format text: PCT FILING DATE = 20131204

ENP Entry into the national phase

Ref document number: 2013406811

Country of ref document: AU

Date of ref document: 20131204

Kind code of ref document: A

REG Reference to national code

Ref country code: BR

Ref legal event code: B01A

Ref document number: 112016008725

Country of ref document: BR

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 13898779

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 112016008725

Country of ref document: BR

Kind code of ref document: A2

Effective date: 20160419