US20150034324A1 - Valve assembly - Google Patents

Valve assembly Download PDF

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Publication number
US20150034324A1
US20150034324A1 US13/957,925 US201313957925A US2015034324A1 US 20150034324 A1 US20150034324 A1 US 20150034324A1 US 201313957925 A US201313957925 A US 201313957925A US 2015034324 A1 US2015034324 A1 US 2015034324A1
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US
United States
Prior art keywords
sleeve
valve assembly
string
valve assemblies
valve
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US13/957,925
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English (en)
Inventor
William Mark NORRID
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Technology Corp
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Schlumberger Technology Corp
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 Schlumberger Technology Corp filed Critical Schlumberger Technology Corp
Priority to US13/957,925 priority Critical patent/US20150034324A1/en
Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: NORRID, William Mark
Priority to PCT/US2014/048450 priority patent/WO2015017337A1/fr
Priority to CA2918326A priority patent/CA2918326A1/fr
Publication of US20150034324A1 publication Critical patent/US20150034324A1/en
Abandoned legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • 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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
    • 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
    • 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 OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/16—Control means therefor being outside the borehole
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/06—Sleeve valves

Definitions

  • At least one perforating gun may be deployed into the well via a conveyance mechanism, such as a wireline, a slickline or a coiled tubing string.
  • the shaped charges of the perforating gun(s) are fired when the gun(s) are appropriately positioned to perforate a casing of the well and form perforating tunnels into the surrounding formation.
  • Additional operations may be performed in the well to increase the well's permeability, such as well stimulation operations and operations that involve hydraulic fracturing.
  • the above-described perforating and stimulation operations may be performed in multiple stages of the well.
  • the above-described operations may be performed by actuating one or more downhole tools (perforating guns, sleeve valves, and so forth).
  • a given downhole tool may be actuated using a wide variety of techniques, such dropping a ball into the well sized for a seat of the tool; running another tool into the well on a conveyance mechanism to mechanically shift or inductively communicate with the tool to be actuated; pressurizing a control line; and so forth.
  • a system that is usable with a well includes a string and valve assemblies that are disposed on the string.
  • the valve assembly includes at least one control port and at least one radial fluid communication port.
  • the valve assembly is adapted to serially receive an untethered object deployed in the string such that receipt of the object by a valve assembly of the plurality of valve assemblies creates a fluid obstruction to cause the valve assembly to expose the control port(s) of the valve assembly; serially release the untethered object; and jointly respond to pressurization of the string to open the radial fluid communication port(s).
  • the housing includes at least one radial communication port and at least one control port.
  • the apparatus includes a first sleeve that is slidably attached to the housing to control fluid communication through the radial communication port(s) in response to pressure being exerted on the control port(s) and a second sleeve that is slidably attached to the housing and adapted to be shifted to expose the control port(s).
  • the seat is attached to the second sleeve; and the seat is adapted to receive an untethered object, cause the second sleeve to shift in response to a fluid obstruction created by the seat receiving the untethered object, and release the received object in response to the shifting of the second sleeve.
  • FIG. 1 is a schematic diagram of a well according to an example implementation.
  • FIG. 2 is a schematic cross-sectional view of a valve assembly of FIG. 1 in a run-in-hole state according to an example implementation.
  • FIG. 3 is a schematic cross-sectional view of the valve assembly illustrating landing of an actuation ball in the assembly according to an example implementation.
  • FIG. 4 is a schematic cross-sectional view of the valve assembly in a state in which a bypass sleeve of the assembly has been shifted to expose pressure control ports for operating a main sleeve of the assembly according to an example implementation.
  • FIG. 5 is a schematic cross-sectional view of the valve assembly in a state in which the main sliding sleeve valve of the assembly has been shifted to open radial fluid communication ports of the assembly according to an example implementation.
  • FIG. 6 is a flow diagram depicting a technique to perform a stimulation operation in a stage of a well according to an example implementation.
  • valve assemblies that are disposed on a tubing string (a production tubing string or casing string, as examples).
  • the tubing string is run into the well with the valve assemblies being initially configured to be in their closed states.
  • the valve assembly isolates its radial fluid communication ports (fracture ports, for example) from the central passageway of the tubing string to prevent fluid communication through these ports.
  • an “untethered object” refers to an object that is communicated downhole through the passageway of the string along at least part of its path without the use of a conveyance line (a slickline, a wireline, a coiled tubing string, and so forth).
  • the untethered object may be a ball (or sphere), a dart or a bar.
  • the untethered object is an actuation ball that is deployed into the tubing string from the Earth surface of the well; and each valve assembly contains a bypass sleeve and the above-mentioned main sleeve. Similar to the main sleeve, the bypass sleeve is also “closed” when the valve assembly is initially run into the well, and in its closed stated, the bypass sleeve isolates pressure control port(s) of the assembly, which may be otherwise used to communicate pressurized fluid to a piston of the assembly to force the main sleeve open.
  • the deployed ball serially propagates through the valve assemblies for purposes of engaging each assembly one at a time to open each valve assembly's bypass sleeve.
  • the opened bypass sleeve exposes the pressure control ports of the valve assembly to configure the assembly to respond to the subsequent pressurization of the string.
  • the valve assembly in its run-in-hole state, has a seat that is constructed to receive the actuation ball to form a corresponding fluid barrier, or obstruction, in the central passageway of the tubing string. Because of this fluid obstruction, the central passageway of the string above the obstruction may be pressurized to shift the bypass sleeve of the valve assembly to expose the pressure control ports of the assembly and simultaneously cause the seat to release the ball, thereby allowing the ball to descend further into the well to land in the seat of the next valve assembly.
  • the above-described process may be repeated from one valve assembly to the next (i.e., from the valve assembly at the uphole end of the stage to the bottom valve assembly at the downhole end of the stage), until the ball reaches a final seat where the ball forms a corresponding final, or end, fluid obstruction in the string at the downhole end of the stage.
  • the central passageway of the tubing string may then be pressurized to exert sufficient pressure on the pressure control ports of all of the valve assemblies of the stage to simultaneously or near simultaneously shift the main sleeves of the valve assemblies open to expose the assemblies' fracturing ports.
  • more fluid may be pumped into the string to communicate fracturing fluid into the surrounding formation for purposes of performing a stimulation operation (a fracturing operation, for example) in the stage.
  • well 10 in accordance with example implementations, includes a wellbore 15 that traverses one or more hydrocarbon-bearing formations.
  • a tubing string 26 (a coiled tubing string or a jointed tubing string, as examples) extends downhole inside the wellbore 15 and is secured to the surrounding formation(s) by packers, such as example upper 60 and lower 64 packers.
  • packers such as example upper 60 and lower 64 packers.
  • the tubing string 26 is deployed in an open hole wellbore, which is uncased.
  • tubing string 26 may be deployed inside another string (a “casing”) that lines, or supports, the wellbore 15 and which may be cemented to the wellbore 15 (such wellbores are typically referred to as “cased hole” wellbores).
  • the wellbore 15 may extend through multiple stages.
  • the wellbore 15 extends through an example stage 50 .
  • the tubing string 26 extends into the stage 50 , and the upper 60 and lower 64 packers of the tubing string 26 form corresponding uphole and downhole boundaries for the isolated stage 50 .
  • each packer 60 , 64 forms an annular barrier between the outer surface of the tubing string 26 and the wellbore wall.
  • the packer 60 , 64 may be a mechanically-set packer, a weight-set packer, a hydraulically-set packer, an inflatable bladder-type packer, a swellable packer, and so forth, depending upon the particular implementation.
  • FIG. 1 depicts the isolated stage 50 as being disposed in a lateral wellbore
  • the techniques and systems that are disclosed herein may likewise be applied to vertical wellbores.
  • the well may contain multiple wellbores, which contain tubing strings that are similar to the illustrated tubing string 26 of FIG. 1 .
  • the well 10 may be a subsea well or may be a terrestrial well, depending on the particular implementation. Additionally, the well 10 may be an injection well or may be a production well. Thus, many implementations are contemplated, which are within the scope of the intended claims.
  • valve assemblies that, when open, are used to communicate fluid from the central passageway of the string 26 into the surrounding formation(s) of the stage 50 .
  • these valve assemblies may include, in general, two types of valve assemblies: valve assemblies 70 that share a common design and are irregularly or regularly distributed along the stage 50 (depending on the particular implementation); and a terminating valve assembly 80 that is located downhole of the valve assemblies 70 and at or near the downhole end of the stage 50 .
  • each valve assembly 70 has a central passageway that forms part of the central passageway of the tubing string 26 and contains radial fluid communication ports 72 (or “fracture ports” for some applications), which are openings in the wall of the tubing string 26 and when permitted by an open state of the valve assembly 70 , may be used to communicate fluid between the central passageway of the tubing string 26 and the region outside of the tubing string 26 (the region extending into the surrounding formation(s), for example).
  • the valve assembly 80 also has a central passageway that forms part of the central passageway of the tubing string 26 and contains radial fluid communication ports 82 (or “fracture ports ” for some applications), which, when permitted by an open state of the valve assembly 80 , may be used to communicate fluid between the central passageway of the tubing string 26 and the region outside of the tubing string 26 (the region extending into the surrounding formation(s), for example).
  • the valve assembly 80 is constructed to catch an untethered object (such as an actuation ball) and unlike the valve assembly 70 (as described herein) retain the object as fluid pressure in the central passageway of the tubing string 26 is increased.
  • valve assemblies 70 are run downhole on the tubing string 26 , main sleeves of the assemblies 70 are in positions to close off fluid communication through the fluid communication ports 72 (i.e., the valve assemblies 70 are closed).
  • an untethered object such as an actuation ball, may be deployed from the Earth surface through the central passageway of the tubing string 26 for purposes of serially propagating through the valve assemblies 70 to configure the assemblies 70 , one at a time, to be subsequently responsive to the pressurization of the string 26 for purposes of translating, or shifting, the main sleeves of the assemblies 70 .
  • the tubing string 26 may be pressurized for purposes of causing all of the valve assemblies 70 to shift their main sleeves open so that a stimulation operation (a fracturing operation, for example) may be performed in the stage 50 using the now opened fluid communication ports 72 .
  • a stimulation operation a fracturing operation, for example
  • the serial propagation of the actuation ball through the valve assemblies 70 occurs from a heel end of the wellbore to the toe end of the wellbore (i.e., from left to right in FIG. 1 ), in accordance with an example implementation. In further implementations, however, propagation may be performed in a reverse direction, from the toe end to the heel end of the wellbore 15 . Thus, may variations are contemplated, which are within the scope of the intended claims.
  • FIG. 2 depicts a schematic cross-sectional view of the valve assembly 70 in accordance with an example implementation.
  • the valve assembly 70 contains a tubular housing 200 that is concentric with a longitudinal axis 290 and is generally coaxial with the tubing string 26 .
  • the tubular housing 200 has concentric upper tubular 200 A, intermediate 200 B and lower 200 C sections, in accordance with example implementations; and the tubular housing 200 has an uphole end 280 and a downhole end 282 .
  • the valve assembly 70 further includes tubular main 220 and bypass 219 sleeves, which are concentric with the longitudinal axis 290 , contained within the housing 200 , and are slidably mounted to the housing 200 .
  • the main sleeve 220 controls fluid communication through the radial fluid communication ports 72 , which radially extend through the housing 200 B and are isolated by the main sleeve 220 in the state of the assembly 70 shown in FIG. 2 .
  • the bypass sleeve 219 controls fluid communication with pressure control ports 217 , which are formed in the upper tubular housing section 200 A and may be used to shift the main sleeve 220 to open fluid communication through the fluid communication ports 72 , as further described herein.
  • the valve assembly 70 is in its run-in-hole state.
  • the main sleeve 220 of the valve assembly 70 covers, or isolates, the fluid communication ports 72 .
  • seals o-rings, for example
  • the main sleeve 220 may be initially secured in place to the housing 200 in the assembly's run-in-hole state by one or more shear devices 221 (shear screws or pins, as examples).
  • the bypass sleeve 219 circumscribes an inner sleeve 204 , which contains a seat 206 at an upper end of the sleeve 204 .
  • the inner sleeve 204 is initially secured to the bypass sleeve 219 via one or more shear devices 223 (shear screws, or pins, for as examples) and is used to operate the sleeve 219 via the use of a deployed untethered object, as further described herein.
  • the seat 206 of the inner sleeve 204 is configured to receive an untethered object, such as an actuation ball.
  • the seat 206 has an inner diameter that is appropriately sized to catch an actuation ball having a given minimum outer diameter, in accordance with example implementations.
  • bypass sleeve 219 in the run-in-hole state of the valve assembly 70 , isolates the pressure control ports 217 of the valve assembly 70 from fluid inside the tubing string's central passageway.
  • the outer surface of the bypass sleeve 219 in conjunction with fluid seals (o-rings, for example) between the sleeve 219 and an inner surface of the upper tubular housing section 200 A, isolate the pressure control ports 217 from the central passageway of the tubing string 26 .
  • the pressure control ports 217 are in fluid communication with a piston surface of the main sleeve 220 . Therefore, with the bypass sleeve 219 in the position that is depicted in FIG. 2 , the pressure control ports 217 are covered, or isolated, so that fluid pressurization of the tubing string's central passageway does not exert a shifting force on the piston of the main sleeve 220 .
  • FIG. 3 depicts the landing of an actuation ball 300 in the seat 206 of the valve assembly 70 .
  • the actuation ball 300 may be deployed from the Earth surface of the well 10 (see FIG. 1 ) into the central passageway of the tubing string 26 and travel through the central passageway until the ball 300 lands in the seat 206 .
  • the landing of the actuation ball 300 in the seat 206 creates a fluid barrier, or obstruction, in the tubing string 26 uphole of the ball 300 .
  • Pressurization of the string 26 above the ball 300 may be subsequently used to shift the bypass sleeve 219 to expose the pressure control ports 217 so that the pressure control ports 217 may be subsequently used to respond to pressure to shift the main sleeve 220 .
  • the shifted bypass sleeve 219 is secured in the open position due to a split ring 211 on the sleeve 219 engaging an interior annular groove 213 in the upper housing section 200 A.
  • Forces resulting from the pressurization of the tubing string 26 may also be used to, after the bypass sleeve 219 is locked into its open position, exert a downward shifting force on the inner sleeve 204 to shear the shear device(s) 223 that initially secure the sleeve 204 to the sleeve 219 , thereby allowing the sleeve 204 to be shifted, or translated, in a downhole direction to a lower position that is depicted in FIG. 4 .
  • the inner sleeve 204 is radially expandable and contractable and is held in a radially contracted state when the sleeve 204 is in inside the bypass sleeve 219 (see FIG. 3 ).
  • the sleeve 204 has a tendency, or bias, to radially expand.
  • the sleeve 204 may be a C-ring or a collet.
  • the inner sleeve 204 in its initial position that is depicted in FIG. 3 , the inner sleeve 204 is in a radially restricted region 202 of the valve assembly 70 .
  • the relatively reduced inner diameter of the bypass sleeve 219 radially constricts the inner sleeve 204 so that the seat 206 of the sleeve 204 has a sufficiently small inner diameter to “catch,” or land, the actuation ball 300 .
  • the inner sleeve 204 and attached seat 206 shift downwardly to the position that is depicted in FIG.
  • the inner sleeve 204 enters a radially expanded section 203 of the valve assembly 70 , which allows the seat 206 to radially expand. Due to the radial expansion of the seat 206 , the inner diameter of the seat 206 is no longer sufficiently small enough to retain the actuation ball 300 . As a result, the seat 206 releases the actuation ball 300 , thereby allowing the ball 300 to travel to the next valve assembly 70 downhole of the valve assembly 70 from which the ball 300 was released (i.e., the ball 300 is not shown in FIG. 4 , as the ball 300 has been released from the valve assembly 70 ).
  • the actuation ball 300 lands in a seat of the valve assembly 80 , where, in accordance with example implementations, the ball 300 remains to form a fluid obstruction at the bottom end of the stage 50 for purposes of allowing the string's central passageway uphole of the valve assembly 80 to be adequately pressurized for the subsequent shifting open all of the main sleeves 220 to open the fluid communication ports 72 of all of the valve assemblies 70 of the stage 50 .
  • a subsequent stimulation operation (a fracturing operation, for example) that relies on the open valve assemblies 70 may then be performed.
  • the central passageway of the tubing string 26 may be pressurized using the fluid obstruction that is created by the ball 300 landing in the valve 80 (located at the bottom of the stage 50 , as depicted in FIG. 1 ).
  • the resulting fluid pressure concurrently exerts downward forces on the pistons of the main sleeves 220 to shear the shear device(s) constraining the sleeves 220 and cause the sleeves 220 to translate downwardly, to expose the radial fluid communication ports 72 .
  • the main sleeves 220 of the stage 50 are concurrently, are jointly, opened, in accordance with example implementations.
  • the main sleeve 220 is secured in its open position due to a split ring 209 on a downhole end of the sleeve 220 engaging an interior annular groove 227 that is formed in the intermediate housing section 200 B. Therefore, when the valve assembly 70 is in the state that is depicted in FIG. 5 , fluid communication is allowed through the fluid communication ports 72 so that for a string containing multiple valve assemblies 70 that extend in a given stage 50 of a well, a simulation fluid may be communicated through the ports 72 of the valve assemblies 70 (a fracturing fluid may be communicated into the stage 50 to perform a fracturing operation, for example).
  • the ball 300 may be removed from the valve assembly 80 (see FIG. 1 ) to allow work below the valve assembly 80 .
  • the ball 300 may be milled out, forced through an expandable seat of the valve assembly 80 by increasing pressure, dissolved, and so forth, as can be appreciated by the skilled artisan.
  • Stimulation operations may be performed in one or more stages through which the tubing string 26 extends using additional valve assemblies 70 and 80 of the string 26 , as can be appreciated by the skilled artisan.
  • a technique 600 includes deploying an untethered object in a string that contains valve assemblies, pursuant to block 602 and serially propagating (block 604 ) the object through valve assemblies to shift bypass sleeves of the assemblies to expose pressure control ports of the assemblies.
  • the string is pressurized (block 606 ) to shift main sleeves of the assemblies open to expose radial fluid ports of the assemblies.
  • the technique 600 includes using the opened valve assemblies to perform simulation operation, pursuant to block 608 .
  • the string may be further pressurized to perform a fracturing operation.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Check Valves (AREA)
US13/957,925 2013-08-02 2013-08-02 Valve assembly Abandoned US20150034324A1 (en)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US13/957,925 US20150034324A1 (en) 2013-08-02 2013-08-02 Valve assembly
PCT/US2014/048450 WO2015017337A1 (fr) 2013-08-02 2014-07-28 Ensemble soupape
CA2918326A CA2918326A1 (fr) 2013-08-02 2014-07-28 Ensemble soupape

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Application Number Priority Date Filing Date Title
US13/957,925 US20150034324A1 (en) 2013-08-02 2013-08-02 Valve assembly

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US20150034324A1 true US20150034324A1 (en) 2015-02-05

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US13/957,925 Abandoned US20150034324A1 (en) 2013-08-02 2013-08-02 Valve assembly

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US (1) US20150034324A1 (fr)
CA (1) CA2918326A1 (fr)
WO (1) WO2015017337A1 (fr)

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20130168099A1 (en) * 2010-09-22 2013-07-04 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
WO2019067012A1 (fr) * 2017-09-29 2019-04-04 Comitt Well Solutions Us Holding Inc. Procédés et systèmes pour déplacer un manchon coulissant sur la base d'une pression interne
WO2019226509A1 (fr) * 2018-05-21 2019-11-28 Thru Tubing Solutions, Inc. Vanne de fracturation
US11142989B2 (en) * 2016-01-20 2021-10-12 China Petroleum & Chemical Corporation Tool for jet packing and fracturing and tubular column comprising same

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Publication number Priority date Publication date Assignee Title
US2872983A (en) * 1955-10-20 1959-02-10 Larkin And Company Inc Hydraulic cement retaining shoe
US20110036592A1 (en) * 2009-08-13 2011-02-17 Baker Hughes Incorporated Tubular valving system and method
US20120205120A1 (en) * 2011-02-10 2012-08-16 Halliburton Energy Services, Inc. Method for individually servicing a plurality of zones of a subterranean formation
US20130048298A1 (en) * 2011-08-23 2013-02-28 Halliburton Energy Services, Inc. System and method for servicing a wellbore

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US8695716B2 (en) * 2009-07-27 2014-04-15 Baker Hughes Incorporated Multi-zone fracturing completion
US8739864B2 (en) * 2010-06-29 2014-06-03 Baker Hughes Incorporated Downhole multiple cycle tool
WO2012048144A2 (fr) * 2010-10-06 2012-04-12 Colorado School Of Mines Outils de fond de puits et procédés pour accéder de manière sélective à un anneau tubulaire d'un trou de forage
US9080420B2 (en) * 2011-08-19 2015-07-14 Weatherford Technology Holdings, Llc Multiple shift sliding sleeve
US8267178B1 (en) * 2011-09-01 2012-09-18 Team Oil Tools, Lp Valve for hydraulic fracturing through cement outside casing

Patent Citations (4)

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Publication number Priority date Publication date Assignee Title
US2872983A (en) * 1955-10-20 1959-02-10 Larkin And Company Inc Hydraulic cement retaining shoe
US20110036592A1 (en) * 2009-08-13 2011-02-17 Baker Hughes Incorporated Tubular valving system and method
US20120205120A1 (en) * 2011-02-10 2012-08-16 Halliburton Energy Services, Inc. Method for individually servicing a plurality of zones of a subterranean formation
US20130048298A1 (en) * 2011-08-23 2013-02-28 Halliburton Energy Services, Inc. System and method for servicing a wellbore

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20130168099A1 (en) * 2010-09-22 2013-07-04 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
US9187994B2 (en) * 2010-09-22 2015-11-17 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
US9909392B2 (en) 2010-09-22 2018-03-06 Packers Plus Energy Services Inc. Wellbore frac tool with inflow control
US11142989B2 (en) * 2016-01-20 2021-10-12 China Petroleum & Chemical Corporation Tool for jet packing and fracturing and tubular column comprising same
WO2019067012A1 (fr) * 2017-09-29 2019-04-04 Comitt Well Solutions Us Holding Inc. Procédés et systèmes pour déplacer un manchon coulissant sur la base d'une pression interne
WO2019226509A1 (fr) * 2018-05-21 2019-11-28 Thru Tubing Solutions, Inc. Vanne de fracturation
US11125052B2 (en) 2018-05-21 2021-09-21 Thru Tubing Solutions, Inc. Frac valve

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WO2015017337A1 (fr) 2015-02-05
CA2918326A1 (fr) 2015-02-05

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