WO2009132462A1 - Raccord double femelle de fond de puits avec soupape à manchon actionnable de façon hydraulique - Google Patents

Raccord double femelle de fond de puits avec soupape à manchon actionnable de façon hydraulique Download PDF

Info

Publication number
WO2009132462A1
WO2009132462A1 PCT/CA2009/000599 CA2009000599W WO2009132462A1 WO 2009132462 A1 WO2009132462 A1 WO 2009132462A1 CA 2009000599 W CA2009000599 W CA 2009000599W WO 2009132462 A1 WO2009132462 A1 WO 2009132462A1
Authority
WO
WIPO (PCT)
Prior art keywords
sleeve
pressure
valve
port
tubing string
Prior art date
Application number
PCT/CA2009/000599
Other languages
English (en)
Inventor
Daniel Jon Themig
Kevin O. Trahan
Christopher Denis Desranleau
Original Assignee
Packers Plus 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 Packers Plus Energy Services Inc. filed Critical Packers Plus Energy Services Inc.
Priority to EP09737604.0A priority Critical patent/EP2294279A4/fr
Priority to AU2009242942A priority patent/AU2009242942B2/en
Priority to CA2719561A priority patent/CA2719561A1/fr
Publication of WO2009132462A1 publication Critical patent/WO2009132462A1/fr
Priority to US12/830,412 priority patent/US8167047B2/en
Priority to US12/914,731 priority patent/US8757273B2/en
Priority to US14/273,989 priority patent/US10030474B2/en
Priority to US16/014,926 priority patent/US10704362B2/en
Priority to US16/029,506 priority patent/US20180320478A1/en

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
    • E21B34/102—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for locking the closing element in open or closed position
    • E21B34/103—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for locking the closing element in open or closed position with a shear pin
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/004—Indexing systems for guiding relative movement between telescoping parts of downhole tools
    • E21B23/006—"J-slot" systems, i.e. lug and slot indexing mechanisms
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/06—Sleeve valves

Definitions

  • hydraulic pressure may be used to actuate various components.
  • packers may be pressure set
  • sleeve valves may be provided that are hydraulically moveable to open ports.
  • hydraulically actuable components are useful, difficulties can arise when there is more than one hydraulically actuable component to be separately actuated. In a system including pressure set packers and sleeve valves for tubular ports, difficulties have occurred when attempting to open the sleeve valves after the packers have been set.
  • a hydraulically actuable sleeve valve comprising: a tubular segment including a wall defining therein an inner bore; a port through the wall of the tubular segment; a sleeve supported by the tubular segment and installed to be axially moveable relative to the tubular segment from a first position covering the port to a second position and to a third position away from a covering position over the port, the sleeve including a first piston face open to tubing pressure and a second piston face open to annular pressure, such that a pressure differential can be set up between the first piston face and the second piston face to drive the sleeve toward a low pressure side from the first position into the second position with the sleeve continuing to cover the port; and a driver to move the sleeve from the second position into the third position, the driver being unable to move the sleeve until the pressure differential is substantially dissipated.
  • a method for opening a port through the wall of a ported sub comprising: providing a sub with a port through its tubular side wall; providing a hydraulically actuable valve to cover the port, the valve being actuable to move away from a position covering the port to thereby open the port; increasing pressure within the sub to create a pressure differential across the valve to move the valve toward the low pressure side, while the port remains closed by the valve; thereafter, reducing pressure within the sub to reduce the pressure differential; and driving the valve to move it away from a position covering the port.
  • a wellbore tubing string assembly comprising: a tubing string; and a first plurality of sleeve valves carried along the tubing string, each of the first plurality of sleeve valves capable of holding pressure when a tubing pressure within the tubing string is greater than an annular pressure about the tubing string and the first plurality of sleeve valves being driven to open at substantially the same time as the tubing pressure is substantially equalized with the annular pressure.
  • a method of accessing a hydrocarbon laden formation comprising: providing a plurality of fluid flow regulating mechanisms; constructing a tubing string wherein the plurality of fluid flow regulating
  • WSUgal ⁇ 045023 ⁇ 00057 ⁇ 5238704v2 mechanisms are grouped into a plurality of areas including a first area including one or more of the plurality of fluid flow regulating mechanisms and a second area including one or more of the plurality of fluid flow regulating mechanisms; placing the tubing string into a wellbore passing into the hydrocarbon laden formation; actuating substantially simultaneously all of the fluid flow regulating mechanisms comprising the first area to access the hydrocarbon laden formation along the first area; and actuating substantially simultaneously all of the fluid flow regulating mechanisms comprising the second area to access the hydrocarbon laden formation along the second area.
  • Figures IA, IB and 1C are axial sectional views of a sleeve valve in first, second and final positions, respectively, according to one aspect of the present invention
  • Figure 2 is a sectional view through another sleeve valve tool useful in the present invention.
  • Figure 3 is schematic sectional view through a wellbore with a tubing string installed therein;
  • Figure 4 is a diagrammatical illustration of a tubing string incorporating the present invention installed in a hydrocarbon well prior to activation of the packers thereof;
  • Figure 5 is a view similar to Figure 4 illustrating the tubing string following actuation of the packers
  • Figure 6 is a view similar to Figure 4 illustrating actuation of and tracing through the fracing ports comprising the first area of the tubing string;
  • Figure 7 is a view similar to Figure 4 illustrating actuation of and fracing through the fracing ports comprising the second area of the tubing string;
  • Figure 8 is an illustration similar to Figure 4 illustrating the actuation of and fracing through the fracing ports comprising the eighth area of the tubing string;
  • Figure 9 is a view similar to Figure 4 illustrating completion of the actuation of the fracing ports
  • Figure 10 is a sectional view illustrating the run-in configuration of a downhole tool useful in the practice of the invention.
  • Figure 11 is a view similar to Figure 10 illustrating another position of the tool of Figure 10;
  • Figure 12 is a view similar to Figure 10 illustrating the frac position of the tool
  • Figure 13 is a perspective view of the tool of Figure 10;
  • Figure 14 is an illustration of the configuration of the tool of Figure 10 for the second area fracing mechanism as illustrated in Figures 4-9;
  • Figure 15 is an illustration of the configuration of the tool of Figure 10 for the third area fracing mechanism as illustrated in Figures 4-9;
  • Figure 16 is an illustration of the configuration of the tool of Figure 10 for the fourth area fracing mechanism as illustrated in Figures 4-9;
  • Figure 17 is an illustration of the configuration of the tool of Figure 10 for the fifth area fracing mechanism as illustrated in Figures 4-9;
  • Figure 18 is an axial sectional view of another sleeve valve according to another aspect of the present invention.
  • Sleeve valve 10 may include a tubular segment 12, a sleeve 14 supported by the tubular segment and a driver, shown generally at reference number 16, to drive the sleeve to move.
  • Sleeve valve 10 may be intended for use in wellbore tool applications.
  • the sleeve valve may be employed in wellbore treatment applications.
  • Tubular segment 12 may be a wellbore tubular such as of pipe, liner casing, etc. and may be a portion of a tubing string.
  • Tubular segment 12 may include a bore 12a in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids may be communicated from surface therethrough, such as for wellbore treatment.
  • Tubular segment 12 may be formed in various ways to be incorporated in a tubular string.
  • the tubular segment may be formed integral or connected by various means, such as threading, welding etc., with another portion of the tubular string.
  • ends 12b, 12c of the tubular segment may be formed for engagement in sequence with adjacent tubulars in a string.
  • ends 12b, 12c may be formed as threaded pins or boxes to allow threaded engagement with adjacent tubulars.
  • Sleeve 14 may be installed to act as a piston in the tubular segment, in other words to be axially moveable relative to the tubular segment at least some movement of which is driven by fluid pressure.
  • Sleeve 14 may be axially moveable through a plurality of positions. For example, as presently illustrated, sleeve 14 may be moveable through a first position (Figure IA), a second position (Figure IB) and a final or third position ( Figure 1C).
  • the installation site for the sleeve in the tubular segment is formed to allow for such movement.
  • Sleeve 14 may include a first piston face 18 in communication, for example through ports 19, with the inner bore 12a of the tubular segment such that first piston face 18 is open to tubing pressure.
  • Sleeve 14 may further include a second piston face 20 in communication with the outer surface 12d of the tubular segment.
  • one or more ports 22 may be formed from outer surface 12d of the tubular segment such that second piston face 20 is open to annulus, hydrostatic pressure about the tubular segment.
  • First piston face 18 and second piston face 20 are positioned to act oppositely on the sleeve.
  • first piston face is open to tubing pressure and the second piston face is open to annulus pressure
  • a pressure differential can be set up between the first piston face and the second piston face to move the sleeve by offsetting or adjusting one or the other of the tubing or annulus pressure.
  • hydrostatic pressure may generally be equalized between the tubing inner bore and the annulus, by increasing tubing pressure, as by increasing pressure in bore 12a from surface, pressure acting against first piston face 18 may be greater than the pressure acting against second piston face 20, which may cause sleeve 14 to move toward the low pressure side, which is the side open to face 20, into a selected second position ( Figure IB).
  • Seals 18a such as o-rings, may be provided to act against leakage of fluid from the bore to the annulus about the tubular segment such that fluid from inner bore 12a is communicated only to face 18 and not to face 20.
  • One or more releasable setting devices 24 may be provided to releasably hold the sleeve in the first position.
  • Releasable setting devices 24, such as one or more of a shear pin (a plurality of shear pins are shown), a collet, a c-ring, etc. provide that the sleeve may be held in place against inadvertent movement out of any selected position, but may be released to move only when it is desirable to do so.
  • releasable setting devices 24 may be installed to maintain the sleeve in its first position but can be released, as shown sheared in Figures IB and 1C, by differential pressure between faces 18 and 20 to allow movement of the sleeve.
  • a releasable setting device such as shear pins to be overcome by a pressure differential
  • the differential pressure required to shear out the sleeve is affected by the hydrostatic pressure and the rating and number of shear pins.
  • Driver 16 may be provided to move the sleeve into the final position.
  • the driver may be selected to be unable to move the sleeve until releasable setting device 24 is released. Since driver 16 is
  • driver 16 can only move the sleeve once the releasable setting devices are released. Since driver 16 cannot overcome the holding pressure of releasable setting devices 24 but the differential pressure can overcome the holding force of devices 24, it will be appreciated then that driver 16 may apply a driving force less than the force exerted by the differential pressure such that driver 16 may also be unable to overcome or act against a differential pressure sufficient to overcome devices 24. Driver 16 may take various forms.
  • driver 16 may include a spring 25 ( Figure 2) and/or a gas pressure chamber 26 ( Figure 1) to apply a push or pull force to the sleeve or to simply allow the sleeve to move in response to an applied force such as an inherent or applied pressure differential or gravity.
  • driver 16 employs hydrostatic pressure through piston face 20 that acts against trapped gas chamber 26 defined between tubular segment 12 and sleeve 14.
  • Chamber 26 is sealed by seals 18a, 28a, such as o- rings, such that any gas therein is trapped.
  • Chamber 26 includes gas trapped at atmospheric or some other low pressure.
  • chamber 26 includes air at surface atmospheric pressure, as may be present simply by assembly of the parts at surface.
  • the pressure in chamber 26 is somewhat less than the hydrostatic pressure downhole. As such, when sleeve 14 is free to move, a pressure imbalance occurs across the sleeve at piston face 20 causing the sleeve to move toward the low pressure side, as provided by chamber 26, if no greater forces are acting against such movement.
  • sleeve 14 moves axially in a first direction when moving from the first position to the second position and reverses to move axially in a direction opposite to the first direction when it moves from the second position to the third position.
  • sleeve 14 passes through the first position on its way to the third position.
  • the illustrated sleeve configuration and sequence of movement allows the sleeve to continue to hold pressure in the first position and the second position.
  • the sleeve moves from one overlapping, sealing position over port 28 into a further overlapping, port closed position and not towards opening of the port.
  • the second position may be considered a closed but activated or passive position, wherein the sleeve has been acted upon, but the valve remains closed.
  • the pressure differential between faces 18 and 20 caused by pressuring up in bore 12c does not move the sleeve into or even toward a port open position. Pressuring up the tubing string only releases the sleeve for later opening. Only when tubing pressure is dissipated to reduce or remove the pressure differential, can sleeve 14 move into the third, port open position.
  • the first direction when moving from the first position to the second position, may be towards surface and the reverse direction may be downhole.
  • Sleeve 14 may be installed in various ways on or in the tubular segment and may take various forms, while being axially moveable along a length of the tubular segment.
  • sleeve 14 may be installed in an annular opening 27 defined between an inner wall 29a and an outer wall 29b of the tubular segment.
  • piston face 18 is positioned at an end of the sleeve in annular opening 27, with pressure communication through ports 19 passing through inner wall 29a.
  • chamber 26 is defined between sleeve 14 and inner wall 29a. Also shown in this embodiment but again variable as desired, an opposite end of sleeve 14 extends out from annular opening 27 to have a surface in direct communication with inner bore 12a.
  • Sleeve 14 may include one or more stepped portions 31 to adjust its inner diameter and thickness.
  • Stepped portions 31, if desired, may alternately be selected to provide for piston face sizing and force selection.
  • stepped portion 31 provides another piston face on the sleeve in communication with inner bore 12a, and therefore tubing pressure, through ports 33.
  • the piston face of portion 31 acts with face 20 to counteract forces generated at piston face 18.
  • ports 33 also act to avoid a pressure lock condition at stepped portion 31.
  • the face area provided by stepped portion 31 may be considered when calculating the total piston face area of the sleeve and the overall pressure effect thereon.
  • faces 18, 20 and 31 must all be considered with respect to pressure differentials acting across the sleeve and the effect of applied or inherent pressure conditions, such as applied tubing pressure, hydrostatic pressure acting as driver 16. Faces 18, 20 and 31 may all be considered to obtain a sleeve across which pressure differentials can be readily achieved.
  • sleeve 14 may be axially moved relative to tubular segment 12 between the three positions.
  • the sleeve valve may initially be in the first position with releasable setting devices 24 holding the sleeve in that position.
  • pressure may be increased in bore 12a, which pressure is not communicated to the annulus, such that a pressure differential is created between face 18 and face 20 across the sleeve. This tends to force the sleeve toward the low pressure side, which is the side at face 20.
  • Such force releases devices 24, for example shears the shear pins, such that sleeve 14 can move toward the end defining face 20 until it arrives at the second position ( Figure IB). Thereafter, pressure in bore 12a can be allowed to relax such that the pressure differential is reduced or eliminated between faces 18 and 20. At this point, since the sleeve is free from the holding force of devices 24, once the pressure differential is sufficiently reduced, the force in driver 16 may be sufficient to move the sleeve into the third position ( Figure 1C).
  • the hydrostatic pressure may act on face 20 and, relative to low pressure chamber 26, a pressure imbalance is established that may tend to drive sleeve 14 to the third, and in the illustrated embodiment of Figure 1C, final position.
  • a pressure increase within the tubular segment causes a pressure differential that releases the sleeve and renders the sleeve into a condition such that it can be acted upon by a driving force to move the sleeve to a further position.
  • Pressuring up is only required to release the sleeve and not to move the sleeve into a port open position.
  • any pressure differential where the tubing pressure is greater than the annular pressure holds the sleeve in a port-closed, pressure holding position, the sleeve can only be acted upon by the driving force once the tubing pressure generated differential is dissipated.
  • the sleeve may, therefore, be actuated by pressure cycling wherein a pressure increase within the tubular segment causes a pressure differential that releases the sleeve and renders the sleeve in a condition such that it can be acted upon by a driver, such as existing hydrostatic pressure, to move the sleeve to a further position.
  • a driver such as existing hydrostatic pressure
  • the sleeve valve of the present invention may be useful in various applications where it is desired to move a sleeve through a plurality of positions, where it is desired to actuate a sleeve to open after increasing tubing pressure, where it is desired to open a port in a tubing string
  • WSLegal ⁇ 045023 ⁇ 00057 ⁇ 5238704v2 hydraulically but where the fluid pressure must be held in the tubing string for other purposes prior to opening the ports to equalize pressure and/or where it is desired to open a plurality of sleeve valves in the tubing string hydraulically at substantially the same time without a risk of certain of the valves failing to open due to pressure equalization through certain others of the valves that opened first.
  • sleeve 14 in both the first and second positions is positioned to cover port 28 and seal it against fluid flow therethrough. However, in the third position, sleeve 14 has moved away from port and leaves it open, at least to some degree, for fluid flow therethrough.
  • Seals 30 may be provided to assist with the sealing properties of sleeve 14 relative to port 28.
  • Such port 28 may open to an annular string component, such as a packer to be inflated, or may open bore 12a to the annular area about the tubular segment, such as may be required for wellbore treatment or production.
  • the sleeve may be moved to open port 28 through the tubular segment such that fluids from the annulus, such as produced fluids can pass into bore 12a.
  • the port may be intended to allow fluids from bore 12a to pass into the annulus.
  • a plurality of ports 28 pass through the wall of tubular segment 12 for passage of fluids between bore 12a and outer surface 12d and, in particular, the annulus about the string.
  • ports 28 each include a nozzle insert 35 for jetting fluids radially outwardly therethrough.
  • Nozzle insert 35 may include a convergent type orifice, having a fluid opening that narrows from a wide diameter to a smaller diameter in the direction of the flow, which is outwardly from bore 12a to outer surface 12d.
  • nozzle insert 35 may be useful to generate a fluid jet with a high exit velocity passing through the port in which the insert is positioned.
  • ports 28 may have installed therein a choking device for regulating the rate or volume of flow therethrough, such as may be useful in limited entry systems.
  • Port configurations may be selected and employed, as desired.
  • the ports may operate with or include screening devices.
  • the ports may communicate with inflow control device (ICD) channels such as those acting to create a pressure drop for incoming production fluids.
  • ICD inflow control device
  • valve 10 may include one or more locks, as desired.
  • a lock may be provided to resist sleeve 14 of the valve from moving from the first position directly to the third position and/or a lock may be provided to resist the sleeve from moving from the third position back to the second position.
  • an inwardly biased c- ring 32 is installed to act between a shoulder 34 on tubular member 12 and a shoulder 36 on sleeve 14. By acting between the shoulders, they cannot approach each other and, therefore, sleeve 14 cannot move from the first position directly toward the third position, even when shear pins 24 are no longer holding the sleeve.
  • C-ring 32 does not resist movement of the sleeve from the first position to the second position.
  • the c-ring may be held by another shoulder 38 on tubular member 12 against movement with the sleeve, such that when sleeve 14 moves from the first position to the second position the sleeve moves past the c-ring.
  • Sleeve 14 includes a gland 40 that is positioned to pass under the c-ring as the sleeve moves and, when this occurs, c- ring 32, being biased inwardly, can drop into the gland.
  • Gland 40 may be sized to accommodate the c-ring no more than flush with the outer diameter of the sleeve such that after dropping into gland 40, c-ring 32 may be carried with the sleeve without catching again on parts beyond the gland. As such, after c-ring 32 drops into the gland, it does not inhibit further movement of the sleeve.
  • the lock may be provided, for example, in the illustrated embodiment to resist movement of the sleeve from the third position back to the second position.
  • the lock may also employ a device such as a c-ring 42 with a biasing force to expand from a gland 44 in sleeve 14 to land against a shoulder 46 on tubular member 12, when the sleeve carries the c-ring to a position where it can expand.
  • the gland for c-ring 42 and the shoulder may be positioned such that they align when the sleeve moves substantially into the third position. When c-ring 42 expands, it acts between one side of gland 44 and shoulder 46 to prevent the sleeve from moving from the third position back toward the second position.
  • the tool may be formed in various ways. As will be appreciated, it is common to form wellbore components in tubular, cylindrical form and oftentimes, of threadedly or weldedly connected subcomponents.
  • tubular segment in the illustrated embodiment is formed of a plurality of parts connected at threaded intervals. The threaded intervals may be selected to hold pressure, to form useful shoulders, etc., as desired.
  • WSLegal ⁇ 045023 ⁇ 00057 ⁇ 5238704v2 It may be desirable in some applications to provide the sleeve valve with a port-recloseable function. For example, in some applications it may be useful to open ports 28 to permit fluid flow therethrough and then later close the ports to shut in the well. This reclosure may be useful for wellbore treatment (i.e. soaking), for back flow or production control, etc. As such sleeve 14 may be moveable from the third position to a position overlying and blocking flow through ports.
  • another downhole tool may be provided with a sleeve valve including a sleeve 48 in a tubular segment 49, the sleeve being moveable from a position initially overlying and closing ports 50 to a position away from the ports (as shown), wherein ports 50 become opened for fluid flow therethrough.
  • tubular segment 49 may include a second sleeve 51 that is positioned adjacent ports 50 and moveable from a position away from the ports to a position overlying and closing them.
  • Second sleeve 51 may be positioned on a side of the ports opposite sleeve 48 and can be moved into place when and if it is desired to close the ports.
  • Sleeve 51 may include seals 52 to seal between the tubular segment and the sleeve, if desired.
  • Sleeve 51 may be capable of moving in any of various ways.
  • sleeve 51 may include a shifting catch groove 53 allowing it to be engaged and moved by a shifting tool conveyed and manipulated from surface.
  • sleeve 51 may include seat to catch a drop plug so that it can be moved into a sealing position over the ports.
  • Sleeve 51 may include a releasable setting device such as a shear pin, a collet or a spring that holds the sleeve in place until the holding force of the releasable setting device is overcome.
  • Sleeve 51 may be reopenable, if desired, by engaging the sleeve again and moving it away from ports 50.
  • a downhole tool including a valve according to the present invention can be used in a wellbore string 58 where it is desired to activate multiple sleeves on demand and at substantially the same time.
  • a tubular string carrying a plurality of ICD or screen devices 60 sleeve valves, such as one of those described herein above or similar, can be used to control fluid flow through the ports of devices 60.
  • Such sleeve valves may also or alternately be useful where the tubing string carries packers 62 that must first be pressure set before the sleeves can be opened.
  • the pressure up condition required to set the packers may move the sleeves into the second position, where they continue to cover ports and hold pressure, and a subsequent pressure relaxation may then allow the sleeves to be driven to open the ports in devices 60 to permit fluid flow therethrough.
  • WSLegal ⁇ 045023 ⁇ 00057 ⁇ 5238704v2 course, even if the tubing string does not include packers, there may be a desire to install a tubing string with its flow control devices 60 in a closed (non-fluid conveying) condition and to open the devices all at once and without physical manipulation thereof and without a concern of certain devices becoming opened to fluid flow while others fail to open because of early pressure equalization caused by one sleeve valve opening before the others (i.e. although the sleeve valves are released hydraulically to be capable of opening, even if one sleeve opens its port first, the others are not adversely affected by such opening).
  • the sleeve valves described herein may be useful installed in, on or adjacent devices 60 to control fluid flow therethrough.
  • One or more sleeve valve may be installed to control flow through each device 60.
  • An indexing J keyway may be installed between the sleeve and the tubular segment to hold the sleeve against opening the ports until a selected number of pressure cycles have been applied to the tubing string, after which the keyway releases the sleeve such that the driver can act to drive the sleeve to the third, port open position.
  • An indexing J keyway may be employed to allow some selected sleeves to open while others remain closed and only to be opened after a selected number of further pressure cycles. The selected sleeves may be positioned together in the well or may be spaced apart.
  • an apparatus 120 for placing in a wellbore through a formation to effect fluid handling therethrough there is shown an apparatus 120 for placing in a wellbore through a formation to effect fluid handling therethrough.
  • the apparatus is described for fluid handling is for the purpose of wellbore stimulation, and in particular tracing.
  • the fluid handling could also be for the purposes of handling produced fluids.
  • the illustrated apparatus 120 comprises the plurality of tracing mechanisms 121, 122 each of which includes at least one port 142 through which fluid flow may occur.
  • a plurality of packers 124 are positioned with one or more tracing mechanisms 121, 122 therebetween along at least a portion of the length of the apparatus 120. In some cases, only one tracing mechanism is positioned between adjacent packers, such as in Area I, while in other cases there may be more than one tracing mechanism between each set of adjacent packers, as shown in Area VIII.
  • the packers 124 are genetically illustrated in Figures 4-9, the packers 124 may, for example, comprise Rockseal® packers of the type manufactured and sold by Packers Plus
  • the apparatus 120 in the illustration is divided into eight areas designated as Areas I- VIII (Areas III through VII are omitted in the drawings for clarity).
  • each area comprises four tracing mechanisms 121 or 122 which are designated in Figures 4-9, inclusive, by the letters A, B, C and D.
  • the apparatus 120 comprises thirty- two fracing mechanisms 121, 122.
  • the apparatus 120 may comprise as many fracing mechanisms as may be required for particular applications of the invention, the fracing mechanisms can be arranged in one or more areas as may be required for particular applications of the invention, and each area may comprise one or more fracing mechanisms depending upon the requirements of particular applications of the invention.
  • the amount of fracing fluid that can exit each of the ports of the fracing mechanisms, when they are open, may be controlled by the sizing of the individual frac port nozzles.
  • the ports may be selected to provide limited entry along an Area.
  • Limited entry technology relies on selection of the number, size and placement of fluid ports 142 along a selected length of a tubing string such that critical or choked flow occurs across the selected ports. Such technology ensures that fluid can be passed through the ports in a selected way along the selected length.
  • a limited entry approach may be used by selection of the rating of choking inserts in ports 142 to ensure that, under critical flow conditions, an amount of fluid passes through each port at a substantially even rate to ensure that a substantially uniform treatment occurs along the entirety of the wellbore spanned by Area VIII of the apparatus.
  • the apparatus 120 is initially positioned in a hydrocarbon well with each of the packers 124 being in its non-actuated state.
  • the distal end of the tubing string comprising the apparatus 120 may be initially open to facilitate the flow of fluid through the tubing string and then back through at least a portion of the well annulus toward surface to condition the well.
  • a ball 126 is passed through the tubing string until it engages a ball receiving mechanism 128, such as a seat, thereby closing the distal end of the tubing string. After the ball 126 has been seated, the tubing string is
  • Figure 5 illustrates the apparatus 120 after the packers 124 have been actuated.
  • tracing mechanisms 121 A, B, C and D that reside in Area I all open at the same time which occurs after pressurization takes place after ball 126 seats.
  • the tracing mechanisms 122 A, B, C and D, etc. of Areas II, III, etc. remain closed during the opening of tracing mechanisms 121 of Area I and possibly even during any tracing therethrough.
  • This ball provides two functions; first, it seats and seals off the open tracing mechanisms 121 in Area I; and second, it allows pressure to be applied to the tracing mechanisms 122 that are located above Area I. This next pressurization opens all of the tracing ports in Area II (which is located adjacent to and up-hole from Area I in the string). At the same time, the tracing mechanisms in Area III and higher remain closed. After completing a frac in Area II, another ball is dropped that seats above the tracing mechanisms in Area II and below the tracing mechanisms in Area III, the string is pressured up to open the mechanisms of Area III, and so on.
  • the tracing mechanisms 121 of Area I may be as described above in Figures 1 or 2, such that they may be opened all at once by a single pressure pulse. For example, the mechanisms may be released to open by an increase in tubing pressure as effected after ball 126 seats and when packers are being set and may be driven to open as tubing pressure is released. However, the tracing mechanisms 122 of the remaining areas remain closed during the initial pressure cycle and only open after a second or further pressure up condition in the string.
  • Figures 10-17 illustrate the construction and operation of a possible tracing mechanism 122 of the apparatus 120.
  • Fracing mechanism 122 comprises a tubular body including an upper housing 136 and a lower housing 138, which is secured to the upper housing 136.
  • a sleeve-type piston 140 is slidably supported within the upper housing 136 and the lower housing 138.
  • Piston 140 includes a face 149 acted upon by tubing pressure, while the opposite end of the piston is open to annular pressure.
  • the upper housing 136 is provided with a plurality of frac ports 142. The number, diameter and construction of the frac ports 142 may vary along the length of the tubing string, depending upon the characteristics of various zones and desired treatments to be effected within
  • the frac ports are normally closed by the piston 140 and are opened when apertures 144 formed in the piston 140 are positioned in alignment with the frac ports 142.
  • the fracing mechanism includes a driver such as an atmosphere trap 143, a spring, etc.
  • Figure 10 illustrates the fracing mechanism 122 with the piston 140 in its lower most position.
  • Figure 11 illustrates the fracing mechanism 122 with the piston 140 located somewhere above its location as illustrated in Figure 10, as driven by pressure applied against face 149 which is greater than annular pressure.
  • Figure 12 illustrates the frac port 122 with the piston 140 in its uppermost position wherein the apertures 144 align with the frac ports 142.
  • each fracing mechanism 122 is provided with a slot 146 which engages, and rides over a J-pin 148 as shown in Figures 10-12.
  • the J-pin 148 is installed, as by sealable engagement with the upper housing 136.
  • Figure 14 illustrates, as an example, the profile of the slot 146a formed in the exterior wall of the piston 140 for use in all Area II mechanisms.
  • the J-pin 148 initially resides in position 1 in the slot 146a.
  • the piston moves as by pressure applied against face 149, so that the J-pin 148 resides in position 2.
  • the piston is driven, as by hydrostatic pressure creating a differential relative to chamber 143, so that the J-pin 148 resides in position 3, and when the apparatus 120 is pressurized the second time, the piston moves so that the J-pin 148 resides in position 4.
  • the piston Upon release of the second pressurization within the apparatus 120, the piston is biased by the driver so that the J-pin 148 resides in position 11 whereupon the apertures 144 in the piston 140 align with the frac ports 142 formed through the upper housing 136 of the fracing mechanism 122 thereby opening the ports at Area II and, if desired, facilitating fracing of the portion of the hydrocarbon well located at Area II.
  • the fracing ports located in Area II are simultaneously opened upon the second pressurization and release thereof.
  • Figure 15 illustrates the profile of a slot 146b for all Area III tools.
  • the profile illustrated in Figure 15 operates identically to the profile illustrated in Figure 14 as described herein in conjunction therewith above except that an additional pressurization and release cycle is required
  • Figure 16 illustrates the profile of the slot 146c for all Area IV tools.
  • the configuration of slot 146c shown in Figure 16 operates identically to that of the slot 146b shown in Figure 15 except that an additional pressurization and release is necessary in order to bring the J-pin riding in slot 146c into position 11, thereby aligning the apertures 144 of the piston 140 with the fracing ports 142.
  • Figure 17 illustrates the profile of the slot 146d as used in all of the Area V tools.
  • the operation of the slot 146d of the Area V tools is substantially identical to that of the Area IV tools except that an additional pressurization and release is necessary in order to bring the J-pin riding in that slot to position 11 wherein the apertures 144 of the piston 140 are aligned with the fracing ports 142 to effect fracing of the Area V location of the well.
  • the pattern of the slots can be continued by wrapping the slot around the extension of the piston to the extent necessary to open all of the facing ports 142 comprising particular applications of the invention.
  • valve is designed to allow for a single pressure cycle to move the valve from a first, closed position (as shown), to a second closed and activated position and thereafter it cycles from the closed activated position to a third, open position.
  • the valve may be moved from the closed position to the closed and activated position by differential pressure from tubing to annulus and may include a driver to bias the sleeve from the closed but activated position to the open position.
  • the valve driver may include a spring, a pressure chamber containing nitrogen or
  • the valve of Figure 18 comprises an outer tube, also termed a housing 202 that has threaded ends 201 such that it is attachable to the tubing or casing string in the well.
  • the outer tube in this embodiment includes an upper housing 202a and a lower housing 202b that are threaded together to form the final housing.
  • the outer housing has a port 204 through its side wall that is closed off by an inner tube 213 that serves both as a sealing sleeve and as a piston.
  • a spring 206 is placed to act between the inner tube and the housing. It shoulders against an upset 205 in the outer housing.
  • the inner tube is installed with seals 209 and 203 that form a seal between the housing and the inner tube, and that seal above and below ports 204 in the outer housing.
  • Seals 203, 209 are positioned to create a chamber 212 in communication with the outer surface of the housing through ports.
  • a piston face 210 is formed on the inner tube that can be effected by pressure differentials between the inner diameter of the housing and the annulus.
  • the inner tube 213 When the inner tube 213 is installed, it traps the spring 206 between a shoulder 207 on the inner tube and upset shoulder 205 on the housing and radially between itself and the housing. As the inner tube is pushed into place, it compresses the spring 206. The spring is compressed and the inner tube is pushed into the outer tube until a slot in the piston becomes lined up with the shear screw holes in the outer housing. Once this alignment is achieved, shear screws 208 are installed locking the inner tube in position.
  • a gap 215 remains between the top of the inner tube and any shoulder 214 forming the upper end of the annular groove. This gap is required to allow movement of the inner tube within the housing.
  • pressure applied internally will act against piston face 210 and force the inner tube to move upward (away from the end on which piston face 210 is formed). This upward movement will load into the shear pins. Once the force from the internal pressure is increased to a predetermined amount, it will shear the pins 208 allowing the inner tube to move upward until the upper end of the inner tube contacts the
  • the valve will remain in the activated and closed position as long as the internal pressure is sufficient to keep the spring compressed.
  • the pressure differential across face 210 prevents the sleeve from moving down.
  • the tubing pressure can be maintained for an indefinite period of time. Once the pressure differential between the tubing inner diameter and the chamber 212 (which is annular pressure) is dissipated such that the force of spring can overcome the holding force across face 210, the inner tube will be driven down to open the ports.
  • the spring As the spring expands, it pushes against the shoulders 205 and 207 and moves the inner tube down so that the upper seals 203 move below the port 204 in the outer housing.
  • the valve is then fully open, and fluids from inside the tubing string can be pumped into the annulus, or can be produced from the annulus into the tubing.
  • the valve can also contain a locking device to keep it in the open position or it can contain the ability to close the piston by forcing it back into the closed position. It may also contain a separate closing sleeve to allow a sleeve to move across the port 204, if required.
  • tubing or casing pressure operations can be conducted, if desired, such as setting hydraulically actuated packers, such as hydraulically compressible or inflatable packers. Once pressure operations are conducted and completed, the pressure between the tubing and annulus can be adjusted towards equalization, which will allow the driver to open the ports closed by the inner tube.
  • valves can be run in a tubing string, and can be moved to the activated but closed and the open positions substantially simultaneously.
  • the pressures on either side of piston face 210 can be adjusted toward equalization by releasing pressure on the tubing at surface, or by opening a hydraulic opened sleeve or pump-out plug downhole. For example, once a single valve is opened, allowing the pressure to equalize inside and outside of the tubing, all the valves in the tubing string that have been activated will be moved to the open position by the driver, which in this case is spring 206.
  • the driver which in this case is spring 206.
  • a plurality of sleeves as shown in Figure 18 can be employed that become activated but closed at about 2500 to 3500 psi and additionally a hydraulically openable port could be employed that moves directly from a closed to an open position at a pressure above 3500 psi, for example at about 4000 psi, to provide for pressure equalization on demand.
  • tubing pressure to at least 2500 psi would cause the inner tubes of the valves of Figure 18 to be activated but held closed and, while the inner tubes are held in a closed position, tubing pressure could be further increased to above 3500 psi to open the port to cause equalization, thereby dissipating the pressure differential to allow the inner tubes to move away from ports 204, as driven by spring 206.
  • a suitable hydraulically openable sleeve is available as a FracPORTTM product from Packers Plus Energy Services Inc.

Abstract

L'invention porte sur un procédé pour ouvrir un orifice à travers la paroi d'un raccord double femelle porté, comprenant les opérations consistant à : procurer un raccord double femelle avec un orifice à travers sa paroi latérale tubulaire ; procurer une soupape actionnable de façon hydraulique pour recouvrir l'orifice, la soupape étant actionnable pour s'éloigner d'une position recouvrant l'orifice pour ainsi ouvrir l'orifice ; augmenter la pression à l'intérieur du raccord double femelle pour créer un différentiel de pression à travers la soupape pour déplacer la soupape vers le côté basse pression, tandis que l'orifice reste fermé par la soupape ; ensuite, réduire la pression à l'intérieur du raccord double femelle pour réduire le différentiel de pression ; et entraîner la soupape pour l'éloigner d'une position recouvrant l'orifice.
PCT/CA2009/000599 2002-08-21 2009-04-29 Raccord double femelle de fond de puits avec soupape à manchon actionnable de façon hydraulique WO2009132462A1 (fr)

Priority Applications (8)

Application Number Priority Date Filing Date Title
EP09737604.0A EP2294279A4 (fr) 2008-04-29 2009-04-29 Raccord double femelle de fond de puits avec soupape à manchon actionnable de façon hydraulique
AU2009242942A AU2009242942B2 (en) 2008-04-29 2009-04-29 Downhole sub with hydraulically actuable sleeve valve
CA2719561A CA2719561A1 (fr) 2008-04-29 2009-04-29 Raccord double femelle de fond de puits avec soupape a manchon actionnable de facon hydraulique
US12/830,412 US8167047B2 (en) 2002-08-21 2010-07-05 Method and apparatus for wellbore fluid treatment
US12/914,731 US8757273B2 (en) 2008-04-29 2010-10-28 Downhole sub with hydraulically actuable sleeve valve
US14/273,989 US10030474B2 (en) 2008-04-29 2014-05-09 Downhole sub with hydraulically actuable sleeve valve
US16/014,926 US10704362B2 (en) 2008-04-29 2018-06-21 Downhole sub with hydraulically actuable sleeve valve
US16/029,506 US20180320478A1 (en) 2002-08-21 2018-07-06 Method and apparatus for wellbore fluid treatment

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US4879708P 2008-04-29 2008-04-29
US61/048,797 2008-04-29
US40518509A 2009-03-16 2009-03-16
US12/405,185 2009-03-16

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
US40518509A Continuation-In-Part 2002-08-21 2009-03-16

Related Child Applications (3)

Application Number Title Priority Date Filing Date
US10/604,807 Continuation-In-Part US7108067B2 (en) 2002-08-21 2003-08-19 Method and apparatus for wellbore fluid treatment
US12/830,412 Continuation-In-Part US8167047B2 (en) 2002-08-21 2010-07-05 Method and apparatus for wellbore fluid treatment
US12/914,731 Continuation-In-Part US8757273B2 (en) 2008-04-29 2010-10-28 Downhole sub with hydraulically actuable sleeve valve

Publications (1)

Publication Number Publication Date
WO2009132462A1 true WO2009132462A1 (fr) 2009-11-05

Family

ID=41254752

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/CA2009/000599 WO2009132462A1 (fr) 2002-08-21 2009-04-29 Raccord double femelle de fond de puits avec soupape à manchon actionnable de façon hydraulique

Country Status (4)

Country Link
EP (1) EP2294279A4 (fr)
AU (1) AU2009242942B2 (fr)
CA (1) CA2719561A1 (fr)
WO (1) WO2009132462A1 (fr)

Cited By (48)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2011072367A1 (fr) * 2009-12-16 2011-06-23 Packers Plus Energy Services Inc . Raccord double femelle de fond de trou comportant une soupape à manchon actionnable hydrauliquement
WO2011058325A3 (fr) * 2009-11-12 2011-10-06 Halliburton Energy Services, Inc. Outil actionné par mise sous pression progressive en fond de trou et son procédé d'utilisation
WO2012037646A1 (fr) * 2010-09-22 2012-03-29 Packers Plus Energy Services Inc. Fermeture d'orifice tubulaire de puits de forage à ouverture retardée
US8167047B2 (en) 2002-08-21 2012-05-01 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
WO2012115749A2 (fr) * 2011-02-21 2012-08-30 Halliburton Energy Services, Inc. Soupape de production commandée à distance et procédé
US8276675B2 (en) 2009-08-11 2012-10-02 Halliburton Energy Services Inc. System and method for servicing a wellbore
GB2495502A (en) * 2011-10-11 2013-04-17 Red Spider Technology Ltd Valve actuating apparatus
WO2013096100A1 (fr) * 2011-12-21 2013-06-27 Baker Hughes Incorporated Manchon coulissant de fracturation entraîné de façon hydrostatique
CN103261577A (zh) * 2010-12-17 2013-08-21 韦尔泰克有限公司 完井装置
US8596368B2 (en) 2011-02-04 2013-12-03 Halliburton Energy Services, Inc. Resettable pressure cycle-operated production valve and method
US8662178B2 (en) 2011-09-29 2014-03-04 Halliburton Energy Services, Inc. Responsively activated wellbore stimulation assemblies and methods of using the same
US8668012B2 (en) 2011-02-10 2014-03-11 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US8668016B2 (en) 2009-08-11 2014-03-11 Halliburton Energy Services, Inc. System and method for servicing a wellbore
WO2013028385A3 (fr) * 2011-08-23 2014-04-10 Halliburton Energy Services, Inc. Système et procédé d'entretien d'un puits de forage
US8695710B2 (en) 2011-02-10 2014-04-15 Halliburton Energy Services, Inc. Method for individually servicing a plurality of zones of a subterranean formation
US8757273B2 (en) 2008-04-29 2014-06-24 Packers Plus Energy Services Inc. Downhole sub with hydraulically actuable sleeve valve
WO2014094137A1 (fr) * 2012-12-21 2014-06-26 Resource Well Completion Technologies Inc. Isolation et fracturation de puits à étages multiples
WO2014138019A1 (fr) * 2013-03-04 2014-09-12 Baker Hughes Incorporated Ensembles d'actionnement, outils actionnés hydrauliquement pour l'utilisation dans des trous de forage souterrains comprenant des ensembles d'actionnement et procédés associés
US8893811B2 (en) 2011-06-08 2014-11-25 Halliburton Energy Services, Inc. Responsively activated wellbore stimulation assemblies and methods of using the same
US20140374096A1 (en) * 2013-06-24 2014-12-25 Team Oil Tools, Lp Method and apparatus for smooth bore toe valve
US8991509B2 (en) 2012-04-30 2015-03-31 Halliburton Energy Services, Inc. Delayed activation activatable stimulation assembly
EP2737167A4 (fr) * 2011-05-30 2015-07-22 Packers Plus Energy Serv Inc Outil de cimentation de trou de forage à écoulement à sens unique
US9097079B2 (en) 2011-06-21 2015-08-04 Packers Plus Energy Services Inc. Fracturing port locator and isolation tool
US9121255B2 (en) 2009-11-13 2015-09-01 Packers Plus Energy Services Inc. Stage tool for wellbore cementing
EP2428639A3 (fr) * 2010-09-08 2015-09-16 Weatherford Technology Holdings, LLC Agencement d'une gaine d'isolation et de gaines regroupées dotées de chambres de pression
US9140097B2 (en) 2010-01-04 2015-09-22 Packers Plus Energy Services Inc. Wellbore treatment apparatus and method
US9187994B2 (en) 2010-09-22 2015-11-17 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
WO2016041091A1 (fr) 2014-09-18 2016-03-24 Steelhaus Technologies Inc. Robinet de réglage de débit
US9303501B2 (en) 2001-11-19 2016-04-05 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US9316088B2 (en) 2011-10-11 2016-04-19 Halliburton Manufacturing & Services Limited Downhole contingency apparatus
US9341027B2 (en) 2013-03-04 2016-05-17 Baker Hughes Incorporated Expandable reamer assemblies, bottom-hole assemblies, and related methods
US9366109B2 (en) 2010-11-19 2016-06-14 Packers Plus Energy Services Inc. Kobe sub, wellbore tubing string apparatus and method
US9376889B2 (en) 2011-10-11 2016-06-28 Halliburton Manufacturing & Services Limited Downhole valve assembly
WO2016106447A1 (fr) * 2014-12-30 2016-07-07 Resource Completion Systems, Inc. Manchon de fracturation obturable
US9394761B2 (en) 2013-10-03 2016-07-19 Saudi Arabian Oil Company Flexible zone inflow control device
US9482074B2 (en) 2011-10-11 2016-11-01 Halliburton Manufacturing & Services Limited Valve actuating apparatus
WO2017066877A1 (fr) * 2015-10-20 2017-04-27 Modern Wellbore Solutions Ltd. Appareil et procédés de cimentation de puits de forage
US9784070B2 (en) 2012-06-29 2017-10-10 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US9797221B2 (en) 2010-09-23 2017-10-24 Packers Plus Energy Services Inc. Apparatus and method for fluid treatment of a well
US9856715B2 (en) 2012-03-22 2018-01-02 Daniel Jon Themig Stage tool for wellbore cementing
WO2018049533A1 (fr) 2016-09-16 2018-03-22 Ncs Multistage Inc. Appareil de commande d'écoulement de puits de forage avec régulation de solides
WO2018052589A1 (fr) * 2016-09-13 2018-03-22 Baker Hughes, A Ge Company, Llc Vanne actionnée hydrauliquement, verrouillable et déverrouillable mécaniquement, système et procédé de trou de forage
CN107869326A (zh) * 2016-09-23 2018-04-03 中石化石油工程技术服务有限公司 开关滑套
US10174560B2 (en) 2015-08-14 2019-01-08 Baker Hughes Incorporated Modular earth-boring tools, modules for such tools and related methods
WO2019143409A1 (fr) * 2018-01-17 2019-07-25 Baker Hughes, A Ge Company, Llc Agencement et procédé de dépôt de substance et de prévention de reflux
WO2020152478A1 (fr) * 2019-01-25 2020-07-30 Pragma Well Technology Limited Outil de fond de puits actionné par pression
US10890047B2 (en) 2016-05-27 2021-01-12 Packers Plus Energy Services Inc. Wellbore stage tool with redundant closing sleeves
CN115788383A (zh) * 2023-02-03 2023-03-14 陕西万普隆油气技术服务有限公司 一种气井抽吸泡排一体化排液装置

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9291034B2 (en) 2009-04-27 2016-03-22 Logan Completion Systems Inc. Selective fracturing tool
US20120006562A1 (en) 2010-07-12 2012-01-12 Tracy Speer Method and apparatus for a well employing the use of an activation ball
CN102094596B (zh) * 2010-12-30 2013-08-21 中国海洋石油总公司 一种智能井井下滑套锁紧装置及其操作方法

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5609178A (en) * 1995-09-28 1997-03-11 Baker Hughes Incorporated Pressure-actuated valve and method
US6109354A (en) * 1996-04-18 2000-08-29 Halliburton Energy Services, Inc. Circulating valve responsive to fluid flow rate therethrough and associated methods of servicing a well
US6220357B1 (en) * 1997-07-17 2001-04-24 Specialised Petroleum Services Ltd. Downhole flow control tool
US7152678B2 (en) * 1998-08-21 2006-12-26 Bj Services Company, U.S.A. System and method for downhole operation using pressure activated valve and sliding sleeve
WO2007017353A1 (fr) * 2005-08-09 2007-02-15 Shell Internationale Research Maatschappij B.V. Systeme d'injection et de production cycliques a partir d'un puits

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5609178A (en) * 1995-09-28 1997-03-11 Baker Hughes Incorporated Pressure-actuated valve and method
US6109354A (en) * 1996-04-18 2000-08-29 Halliburton Energy Services, Inc. Circulating valve responsive to fluid flow rate therethrough and associated methods of servicing a well
US6220357B1 (en) * 1997-07-17 2001-04-24 Specialised Petroleum Services Ltd. Downhole flow control tool
US7152678B2 (en) * 1998-08-21 2006-12-26 Bj Services Company, U.S.A. System and method for downhole operation using pressure activated valve and sliding sleeve
WO2007017353A1 (fr) * 2005-08-09 2007-02-15 Shell Internationale Research Maatschappij B.V. Systeme d'injection et de production cycliques a partir d'un puits

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
See also references of EP2294279A4 *

Cited By (98)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10087734B2 (en) 2001-11-19 2018-10-02 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US9963962B2 (en) 2001-11-19 2018-05-08 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US9366123B2 (en) 2001-11-19 2016-06-14 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US10822936B2 (en) 2001-11-19 2020-11-03 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US9303501B2 (en) 2001-11-19 2016-04-05 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US10487624B2 (en) 2002-08-21 2019-11-26 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US10053957B2 (en) 2002-08-21 2018-08-21 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US9074451B2 (en) 2002-08-21 2015-07-07 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US8167047B2 (en) 2002-08-21 2012-05-01 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US8657009B2 (en) 2002-08-21 2014-02-25 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US10704362B2 (en) 2008-04-29 2020-07-07 Packers Plus Energy Services Inc. Downhole sub with hydraulically actuable sleeve valve
US10030474B2 (en) 2008-04-29 2018-07-24 Packers Plus Energy Services Inc. Downhole sub with hydraulically actuable sleeve valve
US8757273B2 (en) 2008-04-29 2014-06-24 Packers Plus Energy Services Inc. Downhole sub with hydraulically actuable sleeve valve
US8276675B2 (en) 2009-08-11 2012-10-02 Halliburton Energy Services Inc. System and method for servicing a wellbore
US8668016B2 (en) 2009-08-11 2014-03-11 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US8272443B2 (en) 2009-11-12 2012-09-25 Halliburton Energy Services Inc. Downhole progressive pressurization actuated tool and method of using the same
CN102686826A (zh) * 2009-11-12 2012-09-19 哈里伯顿能源服务公司 井下钻进渐进加压致动工具以及使用其的方法
WO2011058325A3 (fr) * 2009-11-12 2011-10-06 Halliburton Energy Services, Inc. Outil actionné par mise sous pression progressive en fond de trou et son procédé d'utilisation
US9650868B2 (en) 2009-11-13 2017-05-16 Packers Plus Energy Services Inc. Stage tool for wellbore cementing
US10273781B2 (en) 2009-11-13 2019-04-30 Packers Plus Energy Services Inc. Stage tool for wellbore cementing
US9121255B2 (en) 2009-11-13 2015-09-01 Packers Plus Energy Services Inc. Stage tool for wellbore cementing
WO2011072367A1 (fr) * 2009-12-16 2011-06-23 Packers Plus Energy Services Inc . Raccord double femelle de fond de trou comportant une soupape à manchon actionnable hydrauliquement
AU2010333653B2 (en) * 2009-12-16 2013-12-19 Packers Plus Energy Services Inc. Downhole sub with hydraulically actuable sleeve valve
US9140097B2 (en) 2010-01-04 2015-09-22 Packers Plus Energy Services Inc. Wellbore treatment apparatus and method
US9970274B2 (en) 2010-01-04 2018-05-15 Packers Plus Energy Services Inc. Wellbore treatment apparatus and method
EP2428639A3 (fr) * 2010-09-08 2015-09-16 Weatherford Technology Holdings, LLC Agencement d'une gaine d'isolation et de gaines regroupées dotées de chambres de pression
EP2619403A4 (fr) * 2010-09-22 2017-05-31 Packers Plus Energy Services Inc. Fermeture d'orifice tubulaire de puits de forage à ouverture retardée
US9909392B2 (en) 2010-09-22 2018-03-06 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
US8931565B2 (en) 2010-09-22 2015-01-13 Packers Plus Energy Services Inc. Delayed opening wellbore tubular port closure
US9187994B2 (en) 2010-09-22 2015-11-17 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
WO2012037646A1 (fr) * 2010-09-22 2012-03-29 Packers Plus Energy Services Inc. Fermeture d'orifice tubulaire de puits de forage à ouverture retardée
US9797221B2 (en) 2010-09-23 2017-10-24 Packers Plus Energy Services Inc. Apparatus and method for fluid treatment of a well
US9366109B2 (en) 2010-11-19 2016-06-14 Packers Plus Energy Services Inc. Kobe sub, wellbore tubing string apparatus and method
CN103261577B (zh) * 2010-12-17 2017-02-08 韦尔泰克有限公司 完井装置
CN103261577A (zh) * 2010-12-17 2013-08-21 韦尔泰克有限公司 完井装置
CN106968646A (zh) * 2010-12-17 2017-07-21 韦尔泰克有限公司 完井装置
CN106968646B (zh) * 2010-12-17 2020-10-16 韦尔泰克油田解决方案股份公司 完井装置
US8596368B2 (en) 2011-02-04 2013-12-03 Halliburton Energy Services, Inc. Resettable pressure cycle-operated production valve and method
US8596365B2 (en) 2011-02-04 2013-12-03 Halliburton Energy Services, Inc. Resettable pressure cycle-operated production valve and method
US9428976B2 (en) 2011-02-10 2016-08-30 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US9458697B2 (en) 2011-02-10 2016-10-04 Halliburton Energy Services, Inc. Method for individually servicing a plurality of zones of a subterranean formation
US8668012B2 (en) 2011-02-10 2014-03-11 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US8695710B2 (en) 2011-02-10 2014-04-15 Halliburton Energy Services, Inc. Method for individually servicing a plurality of zones of a subterranean formation
US8662179B2 (en) 2011-02-21 2014-03-04 Halliburton Energy Services, Inc. Remotely operated production valve and method
WO2012115749A2 (fr) * 2011-02-21 2012-08-30 Halliburton Energy Services, Inc. Soupape de production commandée à distance et procédé
WO2012115749A3 (fr) * 2011-02-21 2012-10-18 Halliburton Energy Services, Inc. Soupape de production commandée à distance et procédé
US9650864B2 (en) 2011-02-21 2017-05-16 Halliburton Energy Services, Inc. Remotely operated production valve and method
US10138708B2 (en) 2011-02-21 2018-11-27 Halliburton Energy Services, Inc. Remotely operated production valve
EP2737167A4 (fr) * 2011-05-30 2015-07-22 Packers Plus Energy Serv Inc Outil de cimentation de trou de forage à écoulement à sens unique
US8893811B2 (en) 2011-06-08 2014-11-25 Halliburton Energy Services, Inc. Responsively activated wellbore stimulation assemblies and methods of using the same
US9097079B2 (en) 2011-06-21 2015-08-04 Packers Plus Energy Services Inc. Fracturing port locator and isolation tool
WO2013028385A3 (fr) * 2011-08-23 2014-04-10 Halliburton Energy Services, Inc. Système et procédé d'entretien d'un puits de forage
US8899334B2 (en) 2011-08-23 2014-12-02 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US8662178B2 (en) 2011-09-29 2014-03-04 Halliburton Energy Services, Inc. Responsively activated wellbore stimulation assemblies and methods of using the same
GB2495502A (en) * 2011-10-11 2013-04-17 Red Spider Technology Ltd Valve actuating apparatus
US9376891B2 (en) 2011-10-11 2016-06-28 Halliburton Manufacturing & Services Limited Valve actuating apparatus
US9482074B2 (en) 2011-10-11 2016-11-01 Halliburton Manufacturing & Services Limited Valve actuating apparatus
EP2581550A3 (fr) * 2011-10-11 2017-07-05 Halliburton Manufacturing & Services Limited Ensemble soupape de fond de trou
GB2495502B (en) * 2011-10-11 2017-09-27 Halliburton Mfg & Services Ltd Valve actuating apparatus
US9376889B2 (en) 2011-10-11 2016-06-28 Halliburton Manufacturing & Services Limited Downhole valve assembly
US9316088B2 (en) 2011-10-11 2016-04-19 Halliburton Manufacturing & Services Limited Downhole contingency apparatus
WO2013096100A1 (fr) * 2011-12-21 2013-06-27 Baker Hughes Incorporated Manchon coulissant de fracturation entraîné de façon hydrostatique
US9856715B2 (en) 2012-03-22 2018-01-02 Daniel Jon Themig Stage tool for wellbore cementing
US8991509B2 (en) 2012-04-30 2015-03-31 Halliburton Energy Services, Inc. Delayed activation activatable stimulation assembly
US9784070B2 (en) 2012-06-29 2017-10-10 Halliburton Energy Services, Inc. System and method for servicing a wellbore
WO2014094137A1 (fr) * 2012-12-21 2014-06-26 Resource Well Completion Technologies Inc. Isolation et fracturation de puits à étages multiples
CN104968888A (zh) * 2012-12-21 2015-10-07 资源成套设备公司 多级井隔离和断裂
US10018014B2 (en) 2013-03-04 2018-07-10 Baker Hughes Incorporated Actuation assemblies, hydraulically actuated tools for use in subterranean boreholes including actuation assemblies and related methods
NO342141B1 (en) * 2013-03-04 2018-03-26 Baker Hughes Inc Actuation assembly for use with a downhole tool in a subterranean borehole, expandable apparatus for use in a subterranean borehole and method for actuating a downhole tool
WO2014138019A1 (fr) * 2013-03-04 2014-09-12 Baker Hughes Incorporated Ensembles d'actionnement, outils actionnés hydrauliquement pour l'utilisation dans des trous de forage souterrains comprenant des ensembles d'actionnement et procédés associés
GB2526993A (en) * 2013-03-04 2015-12-09 Baker Hughes Inc Actuation assemblies, hydraulically actuated tools for use in subterranean boreholes including actuation assemblies and related methods
GB2526993B (en) * 2013-03-04 2020-05-06 Baker Hughes A Ge Co Llc Actuation assemblies, hydraulically actuated tools for use in subterranean boreholes including actuation assemblies and related methods
US9284816B2 (en) 2013-03-04 2016-03-15 Baker Hughes Incorporated Actuation assemblies, hydraulically actuated tools for use in subterranean boreholes including actuation assemblies and related methods
US10036206B2 (en) 2013-03-04 2018-07-31 Baker Hughes Incorporated Expandable reamer assemblies, bottom hole assemblies, and related methods
US10480251B2 (en) 2013-03-04 2019-11-19 Baker Hughes, A Ge Company, Llc Expandable downhole tool assemblies, bottom-hole assemblies, and related methods
US9341027B2 (en) 2013-03-04 2016-05-17 Baker Hughes Incorporated Expandable reamer assemblies, bottom-hole assemblies, and related methods
US20140374096A1 (en) * 2013-06-24 2014-12-25 Team Oil Tools, Lp Method and apparatus for smooth bore toe valve
US9476282B2 (en) * 2013-06-24 2016-10-25 Team Oil Tools, Lp Method and apparatus for smooth bore toe valve
US9394761B2 (en) 2013-10-03 2016-07-19 Saudi Arabian Oil Company Flexible zone inflow control device
US10364647B2 (en) 2014-09-18 2019-07-30 Torsch Inc. Method and apparatus for controlling fluid flow through a down hole tool
EP3194709A4 (fr) * 2014-09-18 2018-05-16 Steelhaus Technologies Inc. Robinet de réglage de débit
WO2016041091A1 (fr) 2014-09-18 2016-03-24 Steelhaus Technologies Inc. Robinet de réglage de débit
WO2016106447A1 (fr) * 2014-12-30 2016-07-07 Resource Completion Systems, Inc. Manchon de fracturation obturable
US10829998B2 (en) 2015-08-14 2020-11-10 Baker Hughes, A Ge Company, Llc Modular earth-boring tools, modules for such tools and related methods
US10174560B2 (en) 2015-08-14 2019-01-08 Baker Hughes Incorporated Modular earth-boring tools, modules for such tools and related methods
WO2017066877A1 (fr) * 2015-10-20 2017-04-27 Modern Wellbore Solutions Ltd. Appareil et procédés de cimentation de puits de forage
US10890047B2 (en) 2016-05-27 2021-01-12 Packers Plus Energy Services Inc. Wellbore stage tool with redundant closing sleeves
WO2018052589A1 (fr) * 2016-09-13 2018-03-22 Baker Hughes, A Ge Company, Llc Vanne actionnée hydrauliquement, verrouillable et déverrouillable mécaniquement, système et procédé de trou de forage
EP3513031A4 (fr) * 2016-09-16 2020-04-29 NCS Multistage Inc. Appareil de commande d'écoulement de puits de forage avec régulation de solides
WO2018049533A1 (fr) 2016-09-16 2018-03-22 Ncs Multistage Inc. Appareil de commande d'écoulement de puits de forage avec régulation de solides
CN107869326A (zh) * 2016-09-23 2018-04-03 中石化石油工程技术服务有限公司 开关滑套
WO2019143409A1 (fr) * 2018-01-17 2019-07-25 Baker Hughes, A Ge Company, Llc Agencement et procédé de dépôt de substance et de prévention de reflux
US11035202B2 (en) 2018-01-17 2021-06-15 Baker Hughes, A Ge Company, Llc Substance deposition and backflow preventing arrangement and method
WO2020152478A1 (fr) * 2019-01-25 2020-07-30 Pragma Well Technology Limited Outil de fond de puits actionné par pression
GB2580906A (en) * 2019-01-25 2020-08-05 Pragma Well Tech Limited Pressure actuated downhole device
GB2580906B (en) * 2019-01-25 2022-12-07 Pragma Well Tech Limited Pressure actuated downhole device
US11891879B2 (en) 2019-01-25 2024-02-06 Pragma Well Technology Limited Pressure actuated downhole device
CN115788383A (zh) * 2023-02-03 2023-03-14 陕西万普隆油气技术服务有限公司 一种气井抽吸泡排一体化排液装置

Also Published As

Publication number Publication date
AU2009242942B2 (en) 2014-07-31
EP2294279A1 (fr) 2011-03-16
AU2009242942A1 (en) 2009-11-05
EP2294279A4 (fr) 2015-11-18
CA2719561A1 (fr) 2009-11-05

Similar Documents

Publication Publication Date Title
US10704362B2 (en) Downhole sub with hydraulically actuable sleeve valve
AU2009242942B2 (en) Downhole sub with hydraulically actuable sleeve valve
AU2010333653B2 (en) Downhole sub with hydraulically actuable sleeve valve
CA2810423C (fr) Fermeture d'orifice tubulaire de puits de forage a ouverture retardee
US9909392B2 (en) Wellbore frac tool with inflow control
US9874067B2 (en) Sliding sleeve sub and method and apparatus for wellbore fluid treatment
DK2673462T3 (en) Method for individually inspecting a plurality of zones in an underground formation
AU2012264470B2 (en) System and method for servicing a wellbore
EP2673463B1 (fr) Système et procédé pour l'entretien d'un puits de forage
AU2012258489B2 (en) Downhole sub with hydraulically actuable sleeve valve
AU2012261578B2 (en) Downhole sub with hydraulically actuable sleeve valve

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: 09737604

Country of ref document: EP

Kind code of ref document: A1

WWE Wipo information: entry into national phase

Ref document number: 2719561

Country of ref document: CA

WWE Wipo information: entry into national phase

Ref document number: 2009242942

Country of ref document: AU

NENP Non-entry into the national phase

Ref country code: DE

REEP Request for entry into the european phase

Ref document number: 2009737604

Country of ref document: EP

WWE Wipo information: entry into national phase

Ref document number: 2009737604

Country of ref document: EP

ENP Entry into the national phase

Ref document number: 2009242942

Country of ref document: AU

Date of ref document: 20090429

Kind code of ref document: A