EP4259899B1 - Régulation de l'écoulement de fluide à travers un élément tubulaire de puits de forage - Google Patents

Régulation de l'écoulement de fluide à travers un élément tubulaire de puits de forage Download PDF

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Publication number
EP4259899B1
EP4259899B1 EP22704233.0A EP22704233A EP4259899B1 EP 4259899 B1 EP4259899 B1 EP 4259899B1 EP 22704233 A EP22704233 A EP 22704233A EP 4259899 B1 EP4259899 B1 EP 4259899B1
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EP
European Patent Office
Prior art keywords
aicvs
wellbore
tubular member
production tubular
subterranean formation
Prior art date
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Active
Application number
EP22704233.0A
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German (de)
English (en)
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EP4259899A1 (fr
Inventor
Nawaf I. Sayedakram
Bilal H. Altoukhi
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.)
Saudi Arabian Oil Co
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Saudi Arabian Oil Co
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Publication date
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Publication of EP4259899A1 publication Critical patent/EP4259899A1/fr
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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
    • E21B34/08—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
    • E21B43/02—Subsoil filtering
    • E21B43/08—Screens or liners
    • 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
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/128—Packers; Plugs with a member expanded radially by axial pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/12—Valve arrangements for boreholes or wells in wells operated by movement of casings or tubings

Definitions

  • the present disclosure describes apparatus, systems, and methods for controlling fluid flow through a wellbore tubular.
  • Inflow control devices are often used in hydrocarbon production operations.
  • inflow control devices can be positioned within a wellbore and operated to open and close to, for instance, limit an amount of water from a subterranean formation (along with one or more hydrocarbons) that is produced to the surface.
  • US 2013/0180727 describes apparatus and methods for controlling the flow of fluid, such as formation fluid, through an oilfield tubular positioned in a wellbore extending through a subterranean formation. Fluid flow is autonomously controlled in response to change in a fluid flow characteristic, such as density or viscosity.
  • a fluid diverter is movable between an open and closed position in response to fluid density change and operable to restrict fluid flow through a valve assembly inlet.
  • the diverter can be pivotable, rotatable or otherwise movable in response to the fluid density change.
  • US 2004/0035578 describes a fluid flow control device for use in a wellbore to control the inflow of production fluids and that comprises a sand control screen having a base pipe with a first set of openings that allows the production fluids to flow therethrough and a sleeve coaxially disposed adjacent to the base pipe.
  • the sleeve has a second set of openings that allows the production fluids to flow therethrough.
  • the sleeve is selectively positionable relative to the base pipe such that a pressure drop in the production fluids is selectively controllable by adjusting an alignment of the first set of openings relative to the second set of openings.
  • US 10,711,569 describes a downhole fluid flow control system that includes a fluid control module having an upstream side, a downstream side and a main fluid pathway in parallel with a secondary fluid pathway each extending between the upstream and downstream sides.
  • a valve element disposed within the main fluid pathway has open and closed positions.
  • a viscosity discriminator including a viscosity sensitive channel forms at least a portion of the secondary fluid pathway.
  • a differential pressure switch operable to open and close the valve element includes a first pressure signal from the upstream side, a second pressure signal from the downstream side and a third pressure signal from the secondary fluid pathway.
  • a wellbore flow control system includes a production tubular member configured to run into a wellbore formed from a terranean surface and into a subterranean formation; a plurality of autonomous inflow control valves (AICVs) positioned on the production tubular member, each of the plurality of AICVs controllable based at least in part on at least one of a density or a viscosity of a formation fluid; and a plurality of sliding sleeves mounted in the production tubular member, each of the plurality of sliding sleeves mounted near a set of AICVs of the plurality of AICVs, each of the plurality of sliding sleeves controllable based on a wellbore drawdown pressure to fluidly couple or fluidly decouple an inner volume of the production tubular member with the subterranean formation through the particular set of AICVs.
  • AICVs autonomous inflow control valves
  • the set of AICVs includes a single AICV or a pair of AICVs.
  • each of the plurality of sliding sleeves is controllable based on the wellbore drawdown pressure to fluidly couple or fluidly decouple the inner volume of the production tubular member with the subterranean formation through one AICV of the pair of AICVs in the particular set of AICVs.
  • the production tubular member includes a plurality of compartments, each compartment including a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves.
  • a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs.
  • the wellbore drawdown pressure includes a difference between the reservoir pressure and a flowing bottomhole pressure of the wellbore.
  • Another aspect combinable with any one of the previous aspects further includes one or more packers positioned on the production tubular member.
  • adjacent compartments of the plurality of compartments are fluidly separated by at least one packer of the plurality of packers.
  • Another aspect combinable with any one of the previous aspects further includes a plurality of screens, each screen mounted across one or more AICVs of the plurality of AICVs.
  • a wellbore fluid flow control method includes operating a production tubular member run into a wellbore formed from a terranean surface and into a subterranean formation, the production tubular member including a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves, at least one of the plurality of sliding sleeves in a closed position to fluidly decouple a first set of AICVs of the plurality of AICVs from the subterranean formation; determining a composition of a wellbore fluid flowing from the subterranean formation into the production tubular member through a second set of AICVs of the plurality of AICVs; based on the determined composition, autonomously modulating a second set of AICVs of the plurality of AICVs toward a closed position; determining a flowing bottomhole pressure; and based on the determined flowing bottomhole pressure being less than a desired value, adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards an open position
  • autonomously modulating the first set of AICVs of the plurality of AICVs toward the open position includes autonomously modulating one or two AICVs of the plurality of AICVs toward the open position.
  • the production tubular member includes a plurality of compartments, each compartment including a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves.
  • the first set of AICVS comprises a pair of AICVs.
  • adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through the first set of AICVs includes adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through one AICV of the pair of AICVs of the first set of AICVs.
  • the first set of AICVs is positioned in a first compartment and the second set of AICVs positioned in a second compartment.
  • a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs.
  • Another aspect combinable with any one of the previous aspects further includes fluidly isolating the first compartment from the second compartment within an annulus between the production tubular member and the subterranean formation by at least one packer positioned on the production tubular member.
  • Another aspect combinable with any one of the previous aspects further includes hydraulically actuating the at least one packer positioned on the production tubular member to fluidly isolate the first compartment from the second compartment.
  • Another aspect combinable with any one of the previous aspects further includes re-determining the flowing bottomhole pressure; and based on the re-determined flowing bottomhole pressure being less than a desired value, adjusting at least another sliding sleeve of the plurality of sliding sleeves toward the open position to fluidly couple the production tubular member to the subterranean formation through a third set of AICVs of the plurality of AICVs.
  • Another aspect combinable with any one of the previous aspects further includes screening the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs with a plurality of screens, each screen mounted across one or more AICVs of the second set of AICVs.
  • Another aspect combinable with any one of the previous aspects further includes running the production tubular member into the wellbore; and maintaining the at least one sliding sleeve in the closed position during the running.
  • Another aspect combinable with any one of the previous aspects further includes determining the flowing bottomhole pressure with a pressure sensor positioned at or near an entry of the wellbore; and measuring a flow rate of the wellbore fluid with a flowmeter positioned at or near the entry of the wellbore.
  • determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs includes determining the composition of the wellbore fluid based on at least one of the viscosity or density.
  • determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs includes determining the composition of the wellbore fluid at the second set of AICVs.
  • Implementations of a tubular flow control system according to the present disclosure may include one or more of the following features.
  • a tubular flow control system according to the present disclosure can prolong a life of a hydrocarbon well.
  • a tubular flow control system according to the present disclosure can maximize dry oil and/or gas production.
  • a tubular flow control system according to the present disclosure can reduce costs by enhancing well performance without requiring rig intervention.
  • the present disclosure describes example implementations of a downhole flow control system that includes autonomous inflow control valves (AICVs) and sliding sleeves that operate in combination to control a flow of a wellbore fluid from a subterranean formation (also called a reservoir) into a production tubular for production at a terranean surface.
  • AICVs autonomous inflow control valves
  • the downhole flow control system includes a tubular member or section that may be part of or coupled to a wellbore tubular, such as a production tubing or casing.
  • the tubular member includes, in some aspects, one or more AICVs and at least one sliding sleeve in a particular compartment of the tubular member.
  • the tubular member can include multiple compartments.
  • FIG. 1 is a schematic diagram of an example implementation of a downhole flow control system 100 according to the present disclosure.
  • a wellbore 104 is formed (for example, drilled or otherwise) from a terranean surface 102 and into and through a subterranean formation 118.
  • the terranean surface 102 is illustrated as a land surface, terranean surface 102 may be a sub-sea or other underwater surface, such as a lake or an ocean floor or other surface under a body of water.
  • the wellbore 104 may be formed under a body of water from a drilling location on or proximate the body of water.
  • the illustrated wellbore 104 is a directional wellbore.
  • the wellbore 104 includes a substantially vertical portion 106 coupled to a radiussed or curved portion 108, which in turn is coupled to a substantially horizontal portion 110.
  • substantially in the context of a wellbore orientation, refers to wellbores that may not be exactly vertical (for example, exactly perpendicular to the terranean surface 102) or exactly horizontal (for example, exactly parallel to the terranean surface 102).
  • the substantially horizontal portion 110 may be a slant wellbore or other directional wellbore that is oriented between exactly vertical and exactly horizontal. Further, the substantially horizontal portion 110, in some aspects, may be a slant wellbore or other directional well bore that is oriented to follow the slant of the formation 118. As illustrated in this example, the three portions of the wellbore 104 - the vertical portion 106, the radiussed portion 108, and the horizontal portion 110 - form a continuous wellbore 104 that extends into the Earth.
  • the illustrated wellbore 104 has a surface casing 120 positioned and set around the wellbore 104 from the terranean surface 102 into a particular depth in the Earth.
  • the surface casing 120 may be a relatively large-diameter tubular member (or string of members) set (for example, cemented) around the wellbore 104 in a shallow formation.
  • tubular may refer to a member that has a circular cross-section, elliptical cross-section, or other shaped cross-section.
  • a production casing 122 is positioned and set within the wellbore 104 downhole of the surface casing 120.
  • the casing 122 may include any casing installed in the wellbore 104 that subject to hydrocarbon production operations, such as, for example, perforating operations, hydraulic fracturing operations, or production operations (or a combination thereof).
  • the casing 122 refers to and includes any form of tubular member that is set (for example, cemented) in the wellbore 104 downhole of the surface casing 120.
  • the production casing 122 may begin at an end of the radiussed portion 108 and extend throughout the substantially horizontal portion 110. The casing 122 could also extend into the radiussed portion 108 and into the vertical portion 106.
  • cement 130 is positioned (for example, pumped) around the casings 120 and 122 in an annulus between the casings 120 and 122 and the wellbore 104.
  • the cement 130 may secure the casings 120 and 122 (and any other casings or liners of the wellbore 104) through the subterranean formations (including subterranean formation 118) under the terranean surface 102.
  • the cement 130 may be installed along the entire length of the casings (for example, casings 120 and 122 and any other casings), or the cement 130 could be used along certain portions of the casings if adequate for a particular wellbore 104.
  • the wellbore 104 and associated casings 120 and 122 may be formed with various example dimensions and at various example depths (for example, true vertical depth, or TVD).
  • a conductor casing (not shown) may extend down to about 120 feet TVD, with a diameter of between about 28 in. and 60 in.
  • the surface casing 120 may extend down to about 2500 feet TVD, with a diameter of between about 22 in. and 48 in.
  • An intermediate casing (not shown) between the surface casing 120 and production casing 122 may extend down to about 8000 feet TVD, with a diameter of between about 16 in. and 36 in.
  • the production casing 122 may extend substantially horizontally (for example, to case the substantially horizontal portion 110) with a diameter of between about 11 in. and 22 in.
  • diameters and TVDs may depend on the particular geological composition of one or more of multiple subterranean formations (including formation 118), particular drilling techniques, or particular secondary operation techniques (for example, perforating, fracturing, acid jobs, fluid injection from other wellbores, and otherwise).
  • the downhole flow control system 100 includes a wellbore tubular 124, for example, a production tubing or otherwise, that extends into the wellbore 104 from the terranean surface 102.
  • a production tubular member (or section) 125 is Coupled to or part of the wellbore tubular 124.
  • the production tubular member 125 is a single-piece downhole tool (tubular) that includes one or more AICVs, one or more sliding sleeves, and one or more wellbore seals (for example, packers) as described herein and can be coupled (for example, threadingly or otherwise) to the wellbore tubular 124.
  • the production tubular member 125 comprises multiple tubular sections coupled together (for example, threadingly).
  • Each tubular section of the tubular member 125 may comprise one or more AICVs, one or more sliding sleeves, and one or more wellbore seals (for example, packers) as described herein.
  • the tubular member 125 includes or is separated into multiple compartments 138a-138c as shown in FIG. 1 .
  • Each compartment 138a-138c may include one or more AICVs and at least one sliding sleeve.
  • each compartment 138a-138c is fluidly isolated (for example, within an annulus volume between the tubular member 125 and the casing 122) from other compartments 138a-138c by at least one wellbore seal 132, such as a packer 132 (for example, hydraulically or mechanically actuated packer).
  • a packer 132 for example, hydraulically or mechanically actuated packer
  • the compartment 138a includes (two) AICVs 134a and the sliding sleeve 136a; the compartment 138b includes (two) AICVs 134b and the sliding sleeve 136b; and the compartment 138c includes (two) AICVs 134c and the sliding sleeve 136c.
  • Other example implementations of the tubular member 125 can include more or fewer compartments; further, other example implementations of each compartment 138a-138c can include more or fewer AICVs.
  • the tubular member 125 can control wellbore water production from the subterranean formation 118 into the wellbore tubular 124, as well as wellbore drawdown, by operating (in combination) the illustrated AICVs with the illustrated sliding sleeves (for example, on a compartment-by-compartment basis).
  • each of the AICVs 134a-134c can be controlled (for example, to open, to close, or to be positioned between 100% open and 100% closed) autonomously.
  • the AICVs 134a-134c can operate to autonomously (for example, without direction or control external to the valves), distinguish between hydrocarbons and undesired fluids (for example, water) within a produced flow into the AICVs 134a-134c.
  • the AICVs 134a-134c autonomously operate at 100% open.
  • the AICVs 134a-134c are autonomously operated to close or partially close based on a particular percentage of undesired fluid/gas passing through the AICVs 134a-134c.
  • the tubular member 125 allows selective activation of each AICV (or set of AICVs in a compartment) based on watercut without a need for rig intervention.
  • watercut is determined by a density, a viscosity, or both, of the wellbore fluid.
  • wellbore drawdown is a pressure difference in a reservoir pressure (for example, pressure of the subterranean formation 118) and a flowing bottomhole pressure (for example, a pressure within and at a downhole end of the wellbore 104 during production of the wellbore fluid).
  • a reservoir pressure for example, pressure of the subterranean formation 118
  • a flowing bottomhole pressure for example, a pressure within and at a downhole end of the wellbore 104 during production of the wellbore fluid.
  • the example tubular member 125 can activate one or more of the sliding sleeves 136a-136c (for example, based on measurements from one or more sensors in a sensor system 146) to increase wellbore fluid production into the wellbore tubular 124 as the flowing bottomhole pressure decreases below a particular threshold.
  • well productivity can increase and wellbore drawdown can decrease in a rigless operation (in other words, rigless intervention) with the tubular member 125.
  • FIG. 2 is a schematic diagram of an example implementation of a downhole flow control tubular 200 according to the present disclosure.
  • the flow control tubular 200 can be used as or in place of the tubular member 125 shown in FIG. 1 .
  • the flow control tubular 200 is positioned in a portion of a wellbore 201 that is formed in a reservoir 203.
  • the flow control tubular 200 a tubing 202 with an interior volume 206.
  • An annulus 204 is formed between the wellbore 201 and the tubing 202.
  • the flow control tubular 200 includes or is separated into multiple compartments 208a-208c.
  • Each compartment 208a-208c may include one or more AICVs and at least one sliding sleeve.
  • each compartment 208a-208c is fluidly isolated (for example, within the annulus 204 between the tubing 202 and the wellbore 201) from other compartments 208a-208c by at least one packer 211 (for example, a hydraulically or mechanically actuated packer).
  • each compartment 208a-208c includes two AICVs 210a and a sliding sleeve 212.
  • Other example implementations of the flow control tubular 200 can include more or fewer compartments; further, other example implementations of each compartment 208a-208c can include more or fewer AICVs 210 or more sliding sleeves 212.
  • each compartment 208a-208c include a screen 214 that circumscribes the tubing 202 around each AICV 210.
  • the screen 214 in some aspects, can filter fluid particulates in the wellbore fluid 215 from entering the interior volume 206 of the tubing 202 through the AICVs 210.
  • each sliding sleeve 212 is moveable (for example, by coiled tubing) to fluidly decouple the annulus 204 from the interior volume 206 through one or both AICVs 210 of each compartment 208a-208c to prevent (or substantially prevent) a wellbore fluid (or production flow) 215 from entering the tubing 202 from one or more perforations or fractures in the reservoir 203 (and casing, not shown).
  • each sliding sleeve 212 is moveable (to fully or partially cover or uncover one or more AICVs within a particular compartment), for example by coiled tubing.
  • each AICV 210 is autonomously controllable to adjust to a fully open position, a fully closed position, or a partially open position.
  • the flow control tubular 200 can be installed initially with one or more of the sliding sleeves 212 in a closed position (fluidly decoupling one or more AICVs 210 from the reservoir 203).
  • production flow 215 is passing through the other AICVs (for fluidly decoupled) only.
  • the undesirable fluid/gas percentage passed through the AICVs 210 that are not fluidly decoupled by a sliding sleeve 112 can increase, resulting in autonomous closure (for example, partial or full) the open AICVs 210.
  • the flowing bottomhole pressure is thus lowered, thereby increasing drawdown due to less flow area into the flow control tubular 200.
  • This decrease in flowing bottomhole pressure can ultimately result in lowering the flowrate of the production fluid 215 into the flow control tubular 200.
  • one or more of the sliding sleeves 112 can be mechanically opened (for example, riglessly using a coiled tubing unit). This intervention by opening one or more of the previously closed sliding sleeves 112 can therefore fluidly couple two or more AICVs 210 to the reservoir 203 to restore well productivity by increasing the flow area (leading to higher flowing bottomhole pressure and lower drawdown).
  • FIG. 3 is a flowchart of an example method 300 performed with or by an example implementation of a downhole flow control system according to the present disclosure.
  • method 300 may be executed with or by the downhole flow control system 100 (including the tubular member 125 or the flow control tubular 200).
  • Method 300 can begin at step 302, which includes operating a production tubular member (within a wellbore) that includes a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves. At least one of the sliding sleeves is positioned to fluidly decouple a first set (one or more) of AICVs of the plurality of AICVs from a reservoir.
  • AICVs autonomous inflow control valves
  • a downhole tool for example, tubular member 125 or flow control tubular 200
  • a wellbore tubular such as a production tubular.
  • the wellbore can include a casing that has previously been perforated and, in some cases, fractured.
  • the wellbore may be an open hole completion.
  • the production tubular member can be defined by or include multiple compartments, where each of the compartments includes one or more (such as a set of) AICVs and a sliding sleeve (for example, mechanically operated).
  • one or more packers are included with or coupled to the production tubular member and actuated to fluidly separate the compartments in an annulus between the production tubular member and the subterranean formation (or casing).
  • each of the AICVs can be open and one or more of the sliding sleeves is in a closed position.
  • the number of AICVs, the number of compartments, or the number of AICVs per compartment may be determined and designed into the production tubular member based on, for instance, an expected or measure reservoir pressure, an expected or desired inflow rate of the wellbore fluid, or a combination thereof.
  • Method 300 can continue at step 304, which includes flowing a wellbore fluid from the reservoir through a second set of AICVs and into the production tubular.
  • the second set of AICVs therefore, is fluidly coupled to the reservoir without being closed by one or more of the sliding sleeves.
  • the AICVs in the second set (or sets other than the first set, with each set of AICVS positioned in a particular compartment of the production tubular member) are open (for example, 100% open) to allow a wellbore fluid (for example, a mixture of hydrocarbon fluids and water) to flow from the reservoir, into the annulus, through the set of open AICVs, and into an interior volume of the production tubular member.
  • a wellbore fluid for example, a mixture of hydrocarbon fluids and water
  • the sliding sleeves can be positioned so as to allow fluid flow through the second set of AICVs without impedance.
  • a screen may be positioned in each compartment of the production tubular member to catch or filter particulates from the wellbore fluid as it enters the interior volume.
  • Method 300 can continue at step 306, which includes determining a composition of the wellbore fluid.
  • one or more sensors can operate to determine one or more properties of the wellbore fluid to determine the composition.
  • such properties such as viscosity, density, or both, can determine a composition, and therefore, a watercut of the wellbore fluid.
  • Method 300 can continue at step 308, which includes a determination of whether the composition of the wellbore fluid indicates a high watercut.
  • this step is performed autonomously by the AICVs on a valve-by-valve basis. For example, if the watercut (as determined by the composition) is low (below a threshold value), then step 308 may continue back to step 304 for normal operation (for example, with the second set of AICVs fully open).
  • the property (and watercut) can be determined on a compartment-by-compartment basis. If the watercut is above a desired value (according to the composition) in one or more of the compartments, then the method can continue to step 310.
  • Step 310 includes modulating the second set of AICVs of the plurality of AICVs toward a closed position.
  • this step is performed autonomously by the second set of AICVs, for example, on a valve-by-valve basis.
  • the second set (one or more) of AICVs in the production tubular member may be autonomously adjusted toward a closed position.
  • only the set of AICVs within the particular compartment in which the watercut was determined to be too high is autonomously modulated toward or to the closed position.
  • Method 300 can continue at step 312, which includes flowing a wellbore fluid from a reservoir through the modulated second set of AICVs and into the production tubular. For example, once the second set of AICVs is adjusted in step 310, operation of the production tubular member to receive the wellbore fluid can continue. Wellbore fluid received into the production tubular through open AICVs (all or partially) can be circulated to the terranean surface.
  • Method 300 can continue at step 314, which includes determining a Flowing bottomhole pressure.
  • one or more pressure sensors can determine a differential between the reservoir pressure and the bottomhole pressure in the wellbore (for example, during step 312).
  • a percentage of undesired fluid can increase in some of the compartments of the production tubular member.
  • some restriction or full closure of the second set of AICVs (as in step 310) can occur, which can minimize production from these compartments in which one or more AICVs were closed.
  • step 310 can result in creating a higher wellbore drawdown across the other compartments to meet a target wellbore fluid flowrate into the production tubular member.
  • the flowing bottom hole pressure can reach a minimum operating limit and the target rate will not be achieved.
  • method 300 can continue at step 316, which includes a determination of whether the Flowing bottomhole pressure is less than a threshold value. For example, if the determination is no and the flowing bottomhole pressure is greater than the threshold value (thereby signifying an acceptable production rate of the wellbore fluid), then method 300 can revert back to step 312.
  • step 316 can continue at step 318, which includes adjusting the sliding sleeve toward an open position to fluidly couple the production tubular member from the subterranean formation through the first set of AICVs.
  • step 318 includes adjusting the sliding sleeve toward an open position to fluidly couple the production tubular member from the subterranean formation through the first set of AICVs.
  • the sliding sleeve can be adjusted to increase or start flow of the wellbore fluid into that compartment by uncovering the set (one or more) of the AICVs in that compartment (in other words, fluidly coupling that compartment to the reservoir).
  • step 318 includes adjusting the sliding sleeve toward the open position to fluidly couple the production tubular member from the subterranean formation through a number of AICVs less than the full set of AICVs in the first set of AICVs.
  • the first set of AICVs can include a pair of AICVs.
  • Step 318 can include, therefore, adjusting the sliding sleeve to fluidly couple the first AICV to the subterranean formation, thereby facilitating flow of fluid through both the first and second AICVs of the first set of AICVs.
  • Method 300 can continue at step 320, which includes flowing the wellbore fluid from the reservoir through the first set of AICVs (now uncovered by the adjusted sliding sleeve) and into the production tubular. For example, after adjusting the sliding sleeve in one or more compartments, operation of flowing the wellbore fluid into the production tubular member (at an increased flowing bottomhole pressure) can continue.
  • example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.

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Claims (17)

  1. Système de régulation d'écoulement de puits de forage, comportant :
    un élément tubulaire (125, 200) de production configuré pour entrer dans un puits (104, 201) de forage formé à partir d'une surface terrestre (102) et jusque dans une formation souterraine (118) ;
    une pluralité de vannes autonomes de régulation d'écoulement entrant, AICV, (134) positionnées sur l'élément tubulaire de production, chacune de la pluralité d'AICV pouvant être commandée en fonction d'une densité et/ou d'une viscosité d'un fluide (215) de formation ; et
    une pluralité de manchons coulissants (136, 212) montés dans l'élément tubulaire de production, chacun de la pluralité de manchons coulissants étant monté près d'un ensemble d'AICV de la pluralité d'AICV, chacun de la pluralité de manchons coulissants pouvant être commandé en fonction d'une pression de soutirage du puits de forage pour coupler fluidiquement ou découpler fluidiquement un volume intérieur (206) de l'élément tubulaire de production avec la formation souterraine à travers au moins une AICV de l'ensemble d'AICV considéré.
  2. Système de régulation d'écoulement de puits de forage selon la revendication 1, l'ensemble d'AICV comportant une seule AICV ou une paire d'AICV, et chacun de la pluralité de manchons coulissants (136, 212) pouvant optionnellement être commandé en fonction de la pression de soutirage du puits de forage pour coupler fluidiquement ou découpler fluidiquement le volume intérieur de l'élément tubulaire de production avec la formation souterraine à travers une AICV de la paire d'AICV dans l'ensemble d'AICV considéré.
  3. Système de régulation d'écoulement de puits de forage selon la revendication 1, l'élément tubulaire de production comportant une pluralité de compartiments (208), chaque compartiment comportant un ensemble particulier d'AICV et au moins un manchon coulissant de la pluralité de manchons coulissants.
  4. Système de régulation d'écoulement de puits de forage selon la revendication 3, un nombre de la pluralité de compartiments étant basé au moins en partie sur une pression de réservoir de la formation souterraine et un débit visé du fluide de formation à travers la pluralité d'AICV, et
    la pression de soutirage du puits de forage comportant optionnellement une différence entre la pression de réservoir et une pression de fond en débit du puits de forage.
  5. Système de régulation d'écoulement de puits de forage selon la revendication 3, comportant en outre une ou plusieurs garnitures (132, 211) positionnées sur l'élément tubulaire de production, et
    des compartiments adjacents de la pluralité de compartiments étant optionnellement séparés fluidiquement par au moins une garniture de la pluralité de garnitures.
  6. Système de régulation d'écoulement de puits de forage selon la revendication 1, comportant en outre une pluralité de tamis (214), chaque tamis étant monté en travers d'une ou de plusieurs AICV de la pluralité d'AICV.
  7. Procédé de régulation d'écoulement de fluide de puits de forage, comportant les étapes consistant à :
    exploiter (302) un élément tubulaire (125, 200) de production introduit dans un puits (104, 201) de forage, le puits (104) de forage étant formé à partir d'une surface terrestre (102) et jusque dans une formation souterraine (118), l'élément tubulaire de production comportant une pluralité de vannes autonomes de régulation d'écoulement entrant, AICV, et une pluralité de manchons coulissants (136, 212), au moins un de la pluralité de manchons coulissants (136, 212) étant dans une position fermée pour découpler fluidiquement un premier ensemble d'AICV de la pluralité d'AICV de la formation souterraine ;
    déterminer (306) une composition d'un fluide de puits de forage s'écoulant de la formation souterraine dans l'élément tubulaire de production à travers un deuxième ensemble d'AICV de la pluralité d'AICV ;
    en fonction de la composition déterminée, moduler (310) de manière autonome un deuxième ensemble d'AICV de la pluralité d'AICV vers une position fermée ;
    déterminer (314) une pression de fond en débit ; et
    sur la base du fait que la pression de fond en débit déterminée soit inférieure à une valeur souhaitée, régler (328) le ou les manchons coulissants de la pluralité de manchons coulissants vers une position ouverte pour coupler fluidiquement l'élément tubulaire de production à la formation souterraine à travers au moins une AICV du premier ensemble d'AICV.
  8. Procédé selon la revendication 7, la modulation autonome du premier ensemble d'AICV de la pluralité d'AICV vers la position ouverte comportant la modulation autonome d'une ou deux AICV de la pluralité d'AICV vers la position ouverte.
  9. Procédé selon la revendication 7, l'élément tubulaire de production comportant une pluralité de compartiments (208), chaque compartiment comportant un ensemble particulier d'AICV et au moins un manchon coulissant de la pluralité de manchons coulissants, le premier ensemble d'AICV étant positionné dans un premier compartiment et le deuxième ensemble d'AICV étant positionné dans un deuxième compartiment.
  10. Procédé selon la revendication 9, le premier ensemble d'AICV comportant une paire d'AICV, et le réglage du ou des manchons coulissants de la pluralité de manchons coulissants vers la position ouverte pour coupler fluidiquement l'élément tubulaire de production à la formation souterraine à travers le premier ensemble d'AICV comportant le réglage du ou des manchons coulissants de la pluralité de manchons coulissants vers la position ouverte pour coupler fluidiquement l'élément tubulaire de production à la formation souterraine à travers une AICV de la paire d'AICV du premier ensemble d'AICV.
  11. Procédé selon la revendication 9, un nombre de la pluralité de compartiments étant basé au moins en partie sur une pression de réservoir de la formation souterraine et un débit visé du fluide de formation à travers la pluralité d'AICV.
  12. Procédé selon la revendication 9, comportant en outre le fait d'isoler fluidiquement le premier compartiment du deuxième compartiment à l'intérieur d'un espace annulaire entre l'élément tubulaire de production et la formation souterraine par au moins une garniture positionnée sur l'élément tubulaire de production, et le procédé comportant en outre optionnellement l'actionnement hydraulique de la ou des garnitures positionnées sur l'élément tubulaire de production pour isoler fluidiquement le premier compartiment du deuxième compartiment.
  13. Procédé selon la revendication 7, comportant en outre les étapes consistant à :
    déterminer à nouveau la pression de fond en débit ; et
    sur la base du fait que la pression de fond en débit à nouveau déterminée soit inférieure à une valeur souhaitée, régler au moins un autre manchon coulissant de la pluralité de manchons coulissants vers la position ouverte pour coupler fluidiquement l'élément tubulaire de production à la formation souterraine à travers un troisième ensemble d'AICV de la pluralité d'AICV.
  14. Procédé selon la revendication 7, comportant en outre le fait de tamiser le fluide de puits de forage s'écoulant de la formation souterraine dans l'élément tubulaire de production à travers le deuxième ensemble d'AICV avec une pluralité de tamis (214), chaque tamis étant monté en travers d'une ou de plusieurs AICV du deuxième ensemble d'AICV.
  15. Procédé selon la revendication 7, comportant en outre :
    l'introduction de l'élément tubulaire de production dans le puits de forage ; et
    le maintien du ou des manchons coulissants dans la position fermée pendant l'introduction.
  16. Procédé selon la revendication 7, comportant en outre :
    la détermination de la pression de fond en débit à l'aide d'un capteur de pression positionné au niveau ou près d'une entrée du puits de forage ; et
    la mesure d'un débit du fluide de puits de forage à l'aide d'un débitmètre positionné au niveau ou près de l'entrée du puits de forage.
  17. Procédé selon la revendication 7, la détermination de la composition du fluide de puits de forage s'écoulant de la formation souterraine dans l'élément tubulaire de production à travers le deuxième ensemble d'AICV comportant la détermination de la composition du fluide de puits de forage d'après la viscosité et/ou la densité,
    et
    la détermination de la composition du fluide de puits de forage s'écoulant de la formation souterraine dans l'élément tubulaire de production à travers le deuxième ensemble d'AICV comportant optionnellement la détermination de la composition du fluide de puits de forage au niveau du deuxième ensemble d'AICV.
EP22704233.0A 2021-01-28 2022-01-28 Régulation de l'écoulement de fluide à travers un élément tubulaire de puits de forage Active EP4259899B1 (fr)

Applications Claiming Priority (2)

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US17/160,568 US20220235628A1 (en) 2021-01-28 2021-01-28 Controlling fluid flow through a wellbore tubular
PCT/US2022/014282 WO2022165155A1 (fr) 2021-01-28 2022-01-28 Régulation de l'écoulement de fluide à travers un élément tubulaire de puits de forage

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US20250264020A1 (en) * 2024-02-20 2025-08-21 Schlumberger Technology Corporation Downhole estimation of multiphase flows in production systems

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EP2090742A1 (fr) * 2008-02-14 2009-08-19 ExxonMobil Upstream Research Company Procédés et systèmes pour évaluer les évènements d'un puits de forage
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US20220235628A1 (en) 2022-07-28
EP4259899A1 (fr) 2023-10-18
CA3206882A1 (fr) 2022-08-04

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