EP2751377B1 - Système et procédé de régulation de fluide pour fond de puits à réaction dynamique aux conditions de puits locales - Google Patents

Système et procédé de régulation de fluide pour fond de puits à réaction dynamique aux conditions de puits locales Download PDF

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Publication number
EP2751377B1
EP2751377B1 EP11871579.6A EP11871579A EP2751377B1 EP 2751377 B1 EP2751377 B1 EP 2751377B1 EP 11871579 A EP11871579 A EP 11871579A EP 2751377 B1 EP2751377 B1 EP 2751377B1
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EP
European Patent Office
Prior art keywords
zone
flow control
fluid flow
fcd
control device
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EP11871579.6A
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German (de)
English (en)
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EP2751377A4 (fr
EP2751377A1 (fr
Inventor
John Charles GANO
Luke William Holderman
Michael Linley Fripp
Jason D. Dykstra
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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    • 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
    • E21B43/14—Obtaining from a multiple-zone well
    • 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
    • E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids
    • 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
    • E21B34/08—Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
    • 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
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells

Definitions

  • This disclosure relates, in general, to equipment utilized in conjunction with operations performed in subterranean wells and, in particular, to a downhole fluid flow control system and method having dynamic response to local well conditions to control the inflow of formation fluids and the outflow of injection fluids.
  • production tubing and various completion equipment are installed in the well to enable safe and efficient production of the formation fluids.
  • the flow control devices may include one or more flow control components such as flow tubes, nozzles, labyrinths or the like.
  • the production flowrate through these flow control devices is fixed prior to installation by the number and design of the flow control components.
  • US 2006/162935 A1 discloses a snorkel device for flow control.
  • US 2006/124310 A1 discloses a system for completing multiple well intervals.
  • the disclosure herein comprises a downhole fluid flow control system and method having dynamic response to local well conditions to control the inflow of formation fluids and the outflow of injection fluids.
  • the downhole fluid flow control system and method of the present disclosure are operable to independently control the inflow of production fluids into multiple production intervals without the requirement for well intervention as formation pressure or the composition of the fluids produced into specific intervals changes over time.
  • the downhole fluid flow control system includes a tubing string operably positionable in a wellbore. Annular barriers are positioned between the tubing string and the wellbore to isolate first and second zones. A fluid flow control device is positioned within each zone. A flow tube operably associated with the fluid flow control device of the first zone operable to establish fluid communication between the second zone and the fluid flow control device in the first zone such that a differential pressure between the first zone and the second zone is operable to actuate the fluid flow control device of the first zone from a first operating configuration to a second operating configuration.
  • the first operating configuration is an open position and the second operating configuration is a closed position. In another embodiment, the first operating configuration is a closed position and the second operating configuration is an open position. In a further embodiment, the first operating configuration is an open position and the second operating configuration is a restricted position.
  • the flow tube extends through at least one of the annular barriers. In some embodiments, a flow tube operably associated with the fluid flow control device of the second zone extends through at least one of the annular barriers to establish fluid communication between the first zone and the fluid flow control device in the second zone such that a differential pressure between the first zone and the second zone is operable to actuate the fluid flow control device of the second zone from a first operating configuration to a second operating configuration.
  • the method includes isolating first and second zones in a wellbore, each zone having a fluid flow control device positioned therein, establishing fluid communication between the first zone and the fluid flow control device in the second zone, flowing fluid through the fluid flow control device of the first zone, generating a differential pressure between the first zone and the second zone and actuating the fluid flow control device of the second zone from a first operating configuration to a second operating configuration responsive to the differential pressure.
  • the method may also include installing annular barriers between the tubing string and the wellbore, extending a flow tube through at least one of the annular barriers, injecting a fluid from an interior of the tubing string into the formation through the first zone, performing an acid stimulation of the first zone, performing a fracture operation in the formation, changing the viscosity of the fluid or actuating the fluid flow control device of the second zone from a closed position to an open position.
  • the method includes isolating first and second zones in a wellbore, each zone having a fluid flow control device positioned therein, establishing fluid communication between the second zone and the fluid flow control device in the first zone, flowing fluid through the fluid flow control devices of the first zone and the second zone, generating a differential pressure between the first zone and the second zone and actuating the fluid flow control device of the first zone from a first operating configuration to a second operating configuration responsive to the differential pressure.
  • the method may also include installing annular barriers between the tubing string and the wellbore, extending a flow tube through at least one of the annular barriers, producing fluid from the formation into an interior of the tubing string through the first zone and the second zone, transitioning from production of a desired fluid to production of an undesired fluid in the first zone, increasing the flowrate of the fluid produced through the first zone, changing the viscosity of the fluid produced through the first zone, actuating the fluid flow control device of the first zone from an open position to a restricted position or actuating the fluid flow control device of the first zone from an open position to a closed position.
  • the method includes isolating first and second zones in a wellbore, each zone having a fluid flow control device positioned therein, establishing fluid communication between the second zone and the fluid flow control device in the first zone, establishing fluid communication between the first zone and the fluid flow control device in the second zone, injecting fluid from a tubing string through the fluid flow control device of the first zone into a formation, generating a differential pressure between the first zone and the second zone and responsive to the differential pressure, opening the fluid flow control device in the second zone and closing the fluid flow control device in the first zone.
  • a well system including a downhole fluid flow control system embodying principles of the present invention that is schematically illustrated and generally designated 10.
  • a wellbore 12 extends through the various earth strata.
  • Wellbore 12 has a substantially vertical section 14, the upper portion of which has cemented therein a casing string 16.
  • Wellbore 12 also has a substantially horizontal section 18 that extends through a hydrocarbon bearing subterranean formation 20. As illustrated, substantially horizontal section 18 of wellbore 12 is open hole.
  • Tubing string 22 Positioned within wellbore 12 and extending from the surface is a tubing string 22.
  • Tubing string 22 provides a conduit for formation fluids to travel from formation 20 to the surface and for injection fluids to travel from the surface to formation 20.
  • tubing string 22 is coupled to a completions string 24 that has been installed in wellbore 12 and divides the completion interval into various production intervals identified as zone 1, zone 2, zone 3 ... zone N-1 and zone N.
  • Completion string 24 includes a plurality of flow control devices identified as FCD 1, FCD 2, FCD 3, FCD N-1 and FCD N, wherein FCD 1 corresponds with zone 1, FCD 2 corresponds to zone 2 and so forth.
  • annular barrier may refer to any suitable pressure barrier known to those skilled in the art including, but not limited to, production packers, inflatable packer, swellable packer or the like as well as materials such as gravel packs or other wellbore filler materials that are operable to provide a pressure differential thereacross, thereby isolating zones in the wellbore.
  • the annular barriers may or may not provide a complete seal between the tubing string and the wellbore.
  • the flow control devices may serve numerous functions.
  • the flow control devices may function as filter media such as a wire wrap screen, a woven wire mesh screen, a prepacked screen or the like, with or without an outer shroud positioned therearound, designed to allow fluids to flow therethrough but prevent particulate matter of a predetermined size from flowing therethrough.
  • the flow control devices may function as inflow control devices to regulate the flow of a production fluid stream during the production phase of well operations or as outflow control devices to control the flow of an injection fluid stream during a treatment phase of well operations or both.
  • the inflow and outflow control may be accomplished using the same or different components within the flow control devices such that the desired flowrates are achieved.
  • the flow control devices are also operable to dynamically respond to local well conditions to control the inflow of formation fluids or the outflow of injection fluids through the various zones of the wellbore. It is noted that the function of inflow or outflow control during production or injection operations and the function of dynamic response to wellbore conditions may be performed by the same or different components within the flow control devices.
  • inflow or outflow control during production or injection operations may be achieved using fluid flow resistors such as nozzles, flow tubes, labyrinths or other tortuous path flow resistors, as well as vortex chambers or other fluidic diodes, matrix chambers containing fluid flow resisting filler material such as bead or fluid selector materials that swell when in contact with hydrocarbons, water or other stimulants such as pH, ionic concentration or the like.
  • the function of dynamic response to wellbore conditions may be achieved using valves such as sliding sleeves, piston operated valves, velocity valves or the like.
  • both inflow or outflow control during production or injection operations and dynamic response to wellbore conditions could be performed by the same component such as a choke or other infinitely variable valving assembly.
  • each of the flow control devices is in communication with one or more adjacent zones, for example, fluid communication, fluid pressure communication or the like.
  • FCD 1 is operably associated with a flow tube 28 proving upstream communication with zone 2 through one of the annular barriers 26.
  • the term flow tube shall mean any medium capable of providing a communication path, such as a fluid or pressure communication path, between a flow control device and another zone.
  • the flow tubes may be control lines or other tubing in the annulus between the tubing string and the wellbore that extend through one or more annular barriers.
  • the flow tubes could be concentric tubulars around the tubing string that extend through and are preferably positioned interiorly of one or more annular barriers.
  • the flow tubes may provide an unencumbered communication path between a flow control device and another zone or the flow tubes may include valving, pistons or other flow control or pressure operated devices.
  • FCD 2 is operably associated with a flow tube 30 proving downstream communication with zone 1 through one of the annular barriers 26.
  • FCD 2 is operably associated with a flow tube 32 proving upstream communication with zone 3 through one of the annular barriers 26.
  • FCD 3 is operably associated with a flow tube 34 proving downstream communication with zone 2 through one of the annular barriers 26.
  • FCD 3 is operably associated with a flow tube 36 proving upstream communication through one of the annular barriers 26.
  • FCD N-1 is operably associated with a flow tube 38 proving downstream communication through one of the annular barriers 26. Also, FCD N-1 is operably associated with a flow tube 40 proving upstream communication with zone N through one of the annular barriers 26. FCD N is operably associated with a flow tube 42 proving downstream communication with zone N-1 through one of the annular barriers 26. Even though figure 1 depicts each flow control device in communication with one or more adjacent zones via the flow tubes, it is to be understood by those skilled in the art that the flow control devices in the present invention could alternatively or additionally be in communication with one or more remote zones that are not adjacent to the zone in which that flow control device operates.
  • figure 1 depicts the flow control system of the present invention in an open hole environment, it should be understood by those skilled in the art that the present invention is equally well suited for use in cased wells. Also, even though figure 1 depicts one flow control device in each production interval, it should be understood by those skilled in the art that any number of flow control devices may be deployed within a production interval without departing from the principles of the present invention. In addition, even though figure 1 depicts the flow control system of the present invention in a horizontal section of the wellbore, it should be understood by those skilled in the art that the present invention is equally well suited for use in wells having other directional configurations including vertical wells, deviated wells, slanted wells, multilateral wells and the like.
  • FIG. 1 a tubing string depicted as completion string 24 has been located in wellbore 12.
  • a plurality of annular barriers 26 has been deployed which isolate a plurality of zones; namely, zone 1 - zone N.
  • Each zone includes a fluid flow control device FCD 1 - FCD N that is in fluid communication with one or more other zones via flow tubes 28-42.
  • Figure 1 depicts a first stage of a treatment operation wherein FCD 1 is in the open position and FCD 2 - FCD N are all in the closed position such that the treatment fluid, indicated by the arrows, is directed out of completions string 24 into formation 20 through FCD 1 and zone 1.
  • the treatment operation depicted may be an acid treatment, a hydraulic fracturing operation or other operation that requires pumping fluid down the tubing string into a production zone or the formation.
  • the pressure P1 in zone 1 will change as local well conditions change. For example, during an acid treatment, the pressure P1 in zone 1 will initially be at a high pressure that is above reservoir pressure as the filter cake or other wellbore damage will create resistance to the flow of the treatment fluid into the formation at the surface of the wellbore. As the acid treatment removes the filter cake in zone 1, the pressure P1 will decrease as the resistance to flow into the formation decreases. As another example, during certain fracture operations, the pressure P1 in zone 1 will initially be at a high pressure that is above reservoir pressure as a large volume of treatment fluid is pumped into the formation to create and prop open the hydraulic fractures.
  • the pressure P1 When the fractures cease to propagate or a sand out occurs, the pressure P1 will increase. Similarly, in other fracture operations, the pressure P1 in zone 1 will initially be at a high pressure that is above reservoir pressure as a large volume of treatment fluid is pumped into the formation to create and prop open the hydraulic fractures. As the composition of the treatment fluid changes from a high viscosity gel to a lower viscosity fluid, for example, the pressure P1 will decrease as the resistance to flow into the formation decreases. In each of these treatment scenarios, the pressure P1 changes over time and has an expected pressure signature.
  • these pressure changes in zone 1 are seen by FCD 2 in zone 2 due to fluid communication through annular barrier 26 via flow tube 30.
  • the fluid pressure P1 can be routed to the appropriate side of a piston, sliding sleeve or other operation mechanism within FCD 2.
  • the other side of the piston, sliding sleeve or other operation mechanism within FCD 2 may see the pressure P2 from zone 2, which is initially reservoir pressure.
  • the differential pressure between P1 and P2 thus provides an energy source to operate FCD 2 from a first operating configuration to a second operating configuration.
  • FCD 2 is shifted from the closed to the open position, as best seen in figure 2 .
  • FCD 1 can remain open or preferably, FCD 1 can be closed.
  • the pressure P2 in zone 2 is seen by FCD 1 in zone 1 due to fluid communication through annular barrier 26 via flow tube 28.
  • the fluid pressure P2 can be routed to an appropriate side of the operation mechanism within FCD 1, the other side of which preferably sees the pressure P1 from zone 1.
  • the differential pressure between P1 and P2 thus provides an energy source to operate FCD 1 from a first operating configuration to a second operating configuration which in this case is shifting FCD 1 from the open to the closed position, as best seen in figure 2 .
  • FCD 2 is opened prior to closing FCD 1.
  • FCD 1 may be mechanically biased or locked in the closed position using springs, collets or other locking assemblies or it may be biased in the closed position by pressure in the system, such as tubing pressure.
  • the treatment operation then continues in zone 2 with the pressure P2 changing over time with an expected pressure signature that depends on the treatment operation being performed.
  • These pressure changes in zone 2 are seen by FCD 3 in zone 3 due to fluid communication through annular barrier 26 via flow tube 34.
  • the fluid pressure P2 can be routed to the appropriate side of the operation mechanism within FCD 3 with the other side preferably seeing the pressure P3 from zone 3, which is initially reservoir pressure.
  • the differential pressure between P2 and P3 thus provides an energy source to operate FCD 3 from its closed position to its open position, as best seen in figure 3 .
  • FCD 2 can remain open or preferably, FCD 2 can be closed.
  • the pressure P3 in zone 3 is seen by FCD 2 in zone 2 due to fluid communication through annular barrier 26 via flow tube 32.
  • the fluid pressure P3 can be routed to an appropriate side of the operation mechanism within FCD 2, the other side of which preferably sees the pressure P2 from zone 2.
  • the differential pressure between P2 and P3 thus provides an energy source to operate FCD 2 from its open to its closed position, as best seen in figure 3 .
  • FCD 3 is opened prior to closing FCD 2 and FCD 2 is secured in the closed position.
  • This process may proceed uphole in a stepwise fashion to accomplish the desired treatment goals until the last zone of wellbore 12 is treated, as best seen in figure 4 , wherein FCD N is open to allow treatment fluid to enter zone N as indicated by the arrows and all other flow control devices are closed.
  • each of the previously closed flow control devices may be operated to the open position based upon sequential differential pressure changes in the zones. For example, as fluid is produced into zone N, the pressure PN falls below reservoir pressure. This pressure change in zone N is seen by FCD N-1 in zone N-1 due to fluid communication through annular barrier 26 via flow tube 40.
  • the fluid pressure PN can be routed to the appropriate side of the operation mechanism within FCD N-1, the other side of which preferably sees the pressure PN-1 from zone N-1, which is initially reservoir pressure.
  • the differential pressure between PN and PN-1 can be use as an energy source to operate FCD N-1 from its closed position to its open position. This process may proceed downhole in a stepwise fashion until all zones are open to production.
  • FIG. 5 a tubing string depicted as completion string 24 has been located in wellbore 12.
  • a plurality of annular barriers 26 has been deployed which isolate a plurality of zones; namely, zone 1 - zone N.
  • Each zone includes a fluid flow control device FCD 1 - FCD N that is in fluid communication with one or more other zones via flow tubes 28-42.
  • Figure 5 depicts a production operation wherein each of the flow control devices is in the open position such that the production fluid, indicated by the arrows, flows into completion string 24 through each of the flow control devices and each of the zones.
  • the inflow control components within FCD 1 - FCD N will attempt to regulate and balance production rates through each zone. Under certain conditions, however, the inflow control components may be unable to regulate and balance production rates or it may be desirable to shut-in or highly restrict production from one or more zones due to changes in flowrate through a zone or changes in the composition of a fluid being produced into a zone. For example, if the desired fluid to be produced in the well system is oil and one or more zones begin to produce an undesired fluid such as gas or water, the fluid flow control system of the present invention can dynamically respond to this local well condition.
  • the pressure in that zone is greater than the pressure in a zone producing oil.
  • the pressure in that zone is greater than the pressure in a zone producing oil through a normal permeability region of the formation. In each of these production scenarios, the pressure difference in various zones can be used to control production.
  • FCD 2 in zone 2 due to fluid communication through annular barrier 26 via flow tubes 30, 32.
  • the fluid pressure P1 or P3 can be routed to the appropriate side of a piston, sliding sleeve or other operation mechanism within FCD 2 with the other side of the piston, sliding sleeve or other operation mechanism within FCD 2 seeing the pressure P2 from zone 2.
  • the differential pressure between P1 and P2 or P3 and P2 thus provides an energy source to operate FCD 2 from a first operating configuration to a second operating configuration.
  • FCD 2 when the differential pressure reaches a predetermined level, FCD 2 could be operated from its open position to a choked position or FCD 2 could be operation from its open position to a closed position, as best seen in figure 6 . Preferably, FCD 2 is then secured in the closed position.
  • the process will continue interventionlessly throughout the wellbore system as production fluid flowrates or compositions change in the various zones, with differential pressures providing the energy for the closure of the desired flow control devices. It should be noted that the required differential pressure needed to operate the various flow control devices may be different in different zones and may be preselected or predetermined.

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Claims (6)

  1. Procédé de commande d'écoulement de fluide en fond de forage, comprenant les étapes consistant à :
    isoler une première, une seconde et une troisième zone dans un puits de forage (14), chaque zone ayant un dispositif de commande d'écoulement de fluide (FCD) positionné à l'intérieur ;
    établir une communication fluidique entre la seconde zone et le dispositif de commande d'écoulement de fluide (FCD 1) dans la première zone ;
    établir une communication fluidique entre la première zone et le dispositif de commande d'écoulement de fluide (FCD 2) dans la seconde zone ;
    établir une communication fluidique entre la troisième zone et le dispositif de commande d'écoulement de fluide (FCD 2) dans la seconde zone ;
    établir une communication fluidique entre la seconde zone et le dispositif de commande d'écoulement de fluide (FCD3) dans la troisième zone ;
    injecter un fluide de traitement depuis un train de tubes (22) via le dispositif de commande d'écoulement de fluide (FCD 1) de la première zone jusque dans une formation alors que les dispositifs de commande d'écoulement de fluide de la seconde et de la troisième zone sont dans la position fermée ;
    générer une première pression différentielle entre la première zone et la seconde zone ;
    en réponse à la première pression différentielle, ouvrir le dispositif de commande d'écoulement de fluide (FCD 2) dans la seconde zone et fermer le dispositif de commande d'écoulement de fluide (FCD 1) dans la première zone ;
    injecter le fluide de traitement depuis le train de tubes (22) via le dispositif de commande d'écoulement de fluide (FCD 2) de la seconde zone alors que les dispositifs de commande d'écoulement de fluide de la première et de la troisième zone sont dans la position fermée ;
    générer une seconde pression différentielle entre la seconde zone et la troisième zone ;
    en réponse à la seconde pression différentielle, ouvrir le dispositif de commande d'écoulement de fluide (FCD 3) dans la troisième zone et fermer le dispositif de commande d'écoulement de fluide (FCD 2) dans la seconde zone ; et
    injecter le fluide de traitement depuis le train de tubes (22) via le dispositif de commande d'écoulement de fluide (FCD 3) de la troisième zone alors que les dispositifs de commande d'écoulement de fluide de la première et de la seconde zone sont dans la position fermée.
  2. Procédé de commande d'écoulement de fluide en fond de forage selon la revendication 1, dans lequel l'isolation de la première, de la seconde et de la troisième zone dans le puits de forage (12) comprend également l'installation de barrières annulaires (26) entre un train de tubes (22) et le puits de forage (12) ; et/ou
    dans lequel l'injection du fluide depuis le train de tubes via le dispositif de commande d'écoulement de fluide (FCD 1) de la première zone jusque dans la formation comprend en outre d'exécuter une stimulation acide de la première zone ; et/ou
    dans lequel l'injection du fluide depuis le train de tubes (22) via le dispositif de commande d'écoulement de fluide (FCD) de la première zone jusque dans la formation comprend en outre d'exécuter une opération de fracture dans la formation.
  3. Système de commande d'écoulement de fluide en fond de forage comprenant :
    un train de tubes (22) capable d'être positionné fonctionnellement dans un puits de forage (12) ;
    une pluralité de barrières annulaires (26) susceptibles d'être positionnées entre le train de tubes (22) et le puits de forage (12) pour isoler une première, une seconde et une troisième zone ;
    un dispositif de commande d'écoulement de fluide (FCD) positionné dans chaque zone ;
    un premier tube d'écoulement (28) fonctionnellement associé au dispositif de commande d'écoulement de fluide (FCD 1) de la première zone, le premier tube d'écoulement établissant une communication entre la seconde zone et le dispositif de commande d'écoulement de fluide (FCD 1) dans la première zone de telle façon qu'une pression différentielle entre la première zone et la seconde zone a pour fonction d'actionner le dispositif de commande d'écoulement de fluide (FCD) de la première zone depuis une première configuration fonctionnelle vers une seconde configuration fonctionnelle,
    un second tube d'écoulement (32) fonctionnellement associé au dispositif de commande d'écoulement de fluide (FCD 2) de la seconde zone, le second tube d'écoulement établissant une communication entre la troisième zone et le dispositif de commande d'écoulement de fluide dans la seconde zone de telle façon qu'une pression différentielle entre la seconde zone et la troisième zone a pour fonction d'actionner le dispositif de commande d'écoulement de fluide (FCD 2) de la seconde zone depuis une première configuration fonctionnelle vers une seconde configuration fonctionnelle ;
    un troisième tube d'écoulement (30) fonctionnellement associé au dispositif de commande d'écoulement de fluide (FCD 2) de la seconde zone, le troisième tube d'écoulement établissant une communication entre la première zone et le dispositif de commande d'écoulement de fluide (FCD 2) dans la seconde zone ; et
    un quatrième tube d'écoulement (34) fonctionnellement associé au dispositif de commande d'écoulement de fluide (FCD 3) de la troisième zone, le quatrième tube d'écoulement établissant une communication entre la seconde zone et le dispositif de commande d'écoulement de fluide (FCD 3) dans la troisième zone.
  4. Système de contrôle d'écoulement de fluide en fond de forage selon la revendication 3, dans lequel au moins un tube d'écoulement s'étend à travers l'une au moins des barrières annulaires (26).
  5. Système de contrôle d'écoulement de fluide en fond de forage selon la revendication 3, dans lequel la première configuration fonctionnelle est une position ouverte et la seconde configuration fonctionnelle est une position fermée ; ou
    dans lequel la première configuration fonctionnelle est une position fermée et la seconde configuration fonctionnelle est une position ouverte.
  6. Système de contrôle d'écoulement de fluide en fond de forage selon la revendication 3, dans lequel la première configuration fonctionnelle est une position ouverte et la seconde configuration fonctionnelle est une position restreinte.
EP11871579.6A 2011-08-29 2011-08-29 Système et procédé de régulation de fluide pour fond de puits à réaction dynamique aux conditions de puits locales Active EP2751377B1 (fr)

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2011/049527 WO2013032433A1 (fr) 2011-08-29 2011-08-29 Système et procédé de régulation de fluide pour fond de puits à réaction dynamique aux conditions de puits locales

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EP2751377A1 EP2751377A1 (fr) 2014-07-09
EP2751377A4 EP2751377A4 (fr) 2016-04-13
EP2751377B1 true EP2751377B1 (fr) 2017-10-18

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EP (1) EP2751377B1 (fr)
CN (1) CN103688013A (fr)
AU (1) AU2011375763B2 (fr)
BR (1) BR112013032877B1 (fr)
CA (1) CA2838164C (fr)
SG (1) SG194941A1 (fr)
WO (1) WO2013032433A1 (fr)

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US9638000B2 (en) 2014-07-10 2017-05-02 Inflow Systems Inc. Method and apparatus for controlling the flow of fluids into wellbore tubulars
US20240102355A1 (en) * 2020-12-03 2024-03-28 Baker Hughes Oilfield Operations Llc Wellbore having opposing action valvular conduits
CN113503143B (zh) * 2021-08-05 2022-03-04 大庆凯思石油技术开发有限公司 一种电路与压差控制开启的井下滑阀开关

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Also Published As

Publication number Publication date
EP2751377A4 (fr) 2016-04-13
AU2011375763B2 (en) 2015-06-25
AU2011375763A1 (en) 2013-11-28
BR112013032877A2 (pt) 2017-01-24
SG194941A1 (en) 2013-12-30
CN103688013A (zh) 2014-03-26
BR112013032877B1 (pt) 2020-10-27
EP2751377A1 (fr) 2014-07-09
CA2838164A1 (fr) 2013-03-07
WO2013032433A1 (fr) 2013-03-07
CA2838164C (fr) 2017-03-28

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