Patent Publication Number: US-2022235635-A1

Title: Stopping fluid flow through a stuck open inflow control valve

Description:
TECHNICAL FIELD 
     This disclosure relates to stopping flow through stuck open valves. 
     BACKGROUND OF THE DISCLOSURE 
     In oil and gas production operations, fluids and gases containing hydrocarbons, along with water and other chemicals, flow from formations of the earth into a wellbore drilled from a surface of the earth to the formations beneath the surface of the earth. The fluids and gases flow uphole from the formations through the wellbore to the surface of the earth. A completion is the equipment placed in a wellbore after the wellbore has been drilled in the earth by a drilling rig. The completion is used to extract naturally occurring hydrocarbon deposits from the earth and move the hydrocarbons and water to the surface of the earth. Completion equipment may be placed in an open wellbore or in a cased wellbore. An open wellbore is a wellbore that is in direct contact with the earth and various subsurface formations of the earth. A cased wellbore is a wellbore that has been sealed from the earth and various subsurface formations of the earth. A wellbore can be fully cased or have portions that are open. Completing a wellbore is the process of disposing or placing the completion equipment within the wellbore. One type of completion equipment positioned in wellbores are inflow control valves. 
     SUMMARY 
     A wellbore is drilled from the surface of the earth to geologic formations of the earth containing liquids and gases, in the form of hydrocarbons, chemicals, and water. An inflow control valve can be positioned in a flow path of the wellbore from a single geologic formation to the wellbore to control the flow of the liquids and gases from that single geologic formation into the wellbore. Multiple inflow control valves can be installed in a single wellbore to control different fluid and gas flows from different geologic formations through which the wellbore passes. Inflow control valves can become stuck open allowing fluid flow into the wellbore. The present disclosure relates to stopping flow through a stuck open inflow control valve. 
     An inflow control valve of the present disclosure has a valve body with an inlet. The inflow control valve has an inner sleeve that is coupled to an inner surface of the valve body. The inner sleeve moves from a closed position to an open position to provide a fluid flow path from an annulus of a wellbore through the valve body. The inner sleeve also moves from the open position to the closed position to restrict the fluid flow through the valve body. The inflow control valve has an outer sleeve coupled to an outer surface of the valve body to stop the fluid flow through the inlet. The outer sleeve moves from a normal operating position offset from the inlet of the inflow control valve body to a locked position limiting fluid flow to the inlet of the inflow control valve to stop the fluid flow through the inflow control valve. The inflow control valve has a first actuation mechanism coupled to the outer sleeve. The first actuation mechanism operates to move the outer sleeve from the normal operating position offset from the inlet of the inflow control valve body to the locked position to stop the fluid flow through the inflow control valve body. The inner sleeve can become stuck open, allowing fluid flow through the inlet. When the inner sleeve becomes stuck open, the outer sleeve can be shut by actuating the first actuation mechanism to stop fluid flow through the inlet. 
     Implementations of the present disclosure include an assembly and a method for stopping fluid flow through a stuck open inflow control valve. A wellbore inflow control valve includes an inflow control valve body, an inner sleeve, an outer sleeve, and a first actuation mechanism. The inflow control valve body includes an inlet. The inner sleeve is coupled to an inner surface of the inflow control valve body. 
     The inner sleeve is movable from a closed position to an open position to provide a fluid flow path from an annulus of a wellbore through the inflow control valve body and moveable from the open position to the closed position to restrict the fluid flow through the inflow control valve body. Where the inflow control valve further includes inner sleeve coupled to the inner surface of the inflow control valve body, the inner sleeve can slide relative to the inner surface of the inflow control valve body stopping a fluid flow through the inflow control valve. 
     The outer sleeve is coupled to an outer surface of the inflow control valve body to stop the fluid flow through the inlet. The outer sleeve is movable from a normal operating position offset from the inlet of the inflow control valve body to a locked position limiting fluid flow to the inlet of the inflow control valve to stop the fluid flow through the inflow control valve. The outer sleeve can further include a sleeve sliding cap coupled to the outer sleeve. The outer sleeve can further include a latch to maintain the outer sleeve in the locked position. 
     The first actuation mechanism is coupled to the outer sleeve. The actuation mechanism is operable to move the outer sleeve from the normal operating position offset from the inlet of the inflow control valve body to the locked position limiting fluid flow to the inlet of the inflow control valve body to stop the fluid flow through the inflow control valve body. The first actuation mechanism can include a nitrogen pressure vessel. 
     In some implementations, the wellbore inflow control valve further includes a second actuation mechanism coupled to the inner sleeve. The second actuation mechanism is operable to reversibly move the inner sleeve between the closed position and the open position to control fluid flow through the inflow control valve body. 
     In some implementations, the wellbore inflow control valve of claim  1  includes a sensor and a controller. The sensor senses a wellbore condition of the wellbore and generate a signal representing the wellbore condition. The sensor can be at least one of a pressure sensor, a conductivity sensor, or a flow rate sensor. The controller receives the signal representing the wellbore condition, and responsive to receiving the signal representing the wellbore condition, to operate the first actuation mechanism to move the outer sleeve to the locked position to stop the fluid flow through the inflow control valve body. 
     Further implementations of the present disclosure include a valve assembly. The valve assembly includes a sliding element and first actuation mechanism. The sliding element includes an outer sleeve. The outer sleeve is positioned external to a valve body defining an inlet. The outer sleeve is movable from a normal operating position offset from the inlet of the valve body to a locked position limiting fluid flow to the inlet of the valve body to stop the fluid flow through the valve body. The sliding element can further include a sleeve sliding cap. The sliding element can also further include a latch to maintain the outer sleeve in the locked position. 
     The first actuation mechanism is coupled to the outer sleeve. The first actuation mechanism is operable to move the outer sleeve from the normal operating position offset from the inlet of the valve body to the locked position limiting fluid flow to the inlet of the valve body to stop the fluid flow through the valve body. The first actuation mechanism can include a nitrogen pressure vessel. 
     In some implementations, the valve assembly includes a sensor and a controller. The sensor senses a condition and generate a signal representing the condition. The sensor can include at least one of a pressure sensor, a conductivity sensor, a flow rate sensor, or a valve position sensor. The controller receives the signal representing the condition, and responsive to receiving the signal representing the condition, positions the actuation mechanism to position the outer sleeve to stop the fluid flow through the valve body. 
     In some implementations, the valve assembly further includes an inner sleeve coupled to an inner surface of the valve body. The inner sleeve is movable from a closed position to an open position to provide a fluid flow path through the valve body and moveable from the open position to the closed to restrict the fluid flow path through the valve body. 
     In some implementations, the valve assembly further includes a second actuation mechanism coupled to the inner sleeve. The second actuation mechanism is operable to reversibly move the inner sleeve between the closed position and the open position to control fluid flow through the valve body. 
     Further implementations of the present disclosure include a method of stopping a fluid flow of a wellbore. The wellbore includes a wellbore inflow control valve to control the fluid flow through the wellbore. The wellbore inflow control valve includes an inflow control valve body, an inner sleeve, an outer sleeve, and a first actuation mechanism. The inflow control valve body includes an inlet. The inner sleeve is coupled to an inner surface of the inflow control valve body. The inner sleeve is movable from a closed position to an open position to provide a fluid flow path from an annulus of a wellbore through the inflow control valve body and moveable from the open position to the closed position to restrict the fluid flow through the inflow control valve body. The outer sleeve is coupled to an outer surface of the inflow control valve body to stop the fluid flow through the inlet. The outer sleeve is movable from a normal operating position offset from the inlet of the inflow control valve body to a locked position limiting fluid flow to the inlet of the inflow control valve to stop the fluid flow through the inflow control valve. The first actuation mechanism is coupled to the outer sleeve. The first actuation mechanism is operable to move the outer sleeve from the normal operating position offset from the inlet of the inflow control valve body to the locked position limiting fluid flow to the inlet of the inflow control valve body to stop the fluid flow through the inflow control valve body. 
     The method of stopping a fluid flow of a wellbore includes actuating the first actuation mechanism. Where the wellbore inflow control valve further includes a sensor to sense a wellbore condition of the wellbore and generate a signal representing the wellbore condition and a controller to receive the signal representing the wellbore condition, and responsive to receiving the signal representing the wellbore condition, to operate the first actuation mechanism to move the outer sleeve from the normal operating position to the locked position to limit fluid flow through the inflow control valve, actuating the first actuation mechanism can further include sensing the wellbore condition. Where wellbore condition indicates the inner sleeve failed to shut, allowing fluid flow through the inlet, the sensor can generate a signal representing the wellbore condition indicating the inner sleeve failed to shut and transmit the signal representing the wellbore condition indicating the inner sleeve failed to shut to the controller. The signal representing the wellbore condition indicating the inner sleeve failed to shut can be received at the controller. Responsive to receiving the signal representing the wellbore condition indicating the inner sleeve failed to shut, by the controller, the first actuation mechanism can be actuated. 
     Where the first actuation mechanism includes a nitrogen pressure vessel, actuating the first actuation mechanism can further include by the controller, flowing a pressurized nitrogen gas from the nitrogen pressure vessel to the outer sleeve. Responsive to flowing the pressurized nitrogen gas from the nitrogen pressure vessel to the outer sleeve, the outer sleeve can be moved from the normal operating position to the locked position, stopping the fluid flow. 
     The method of stopping a fluid flow of a wellbore includes, responsive to actuating the first actuation mechanism, moving the outer sleeve from the normal operating position to the locked position. 
     The method of stopping a fluid flow of a wellbore includes, responsive to moving the outer sleeve from the normal operating position to the locked position, stopping the fluid flow. 
     In some implementations, where the wellbore inflow control valve further includes a latch, the method of stopping a fluid flow of a wellbore can include latching the outer sleeve in the locked position. Responsive to latching the outer sleeve in the locked position, the fluid flow is maintained stopped. 
     In some implementations, when the outer sleeve is in the locked position, the method can include unlatching the outer sleeve. The method can include releasing, by the controller, the pressurized nitrogen gas from the outer sleeve. Responsive to releasing the pressurized nitrogen gas from the outer sleeve, moving the outer sleeve from the locked position to the normal operating position. Responsive to moving the outer sleeve from the locked position to the normal operating position, allowing the fluid flow. 
     Implementations of the present disclosure can realize one or more of the following advantages. Sealing a wellbore tubular flow from a stuck open valve can be simplified and accomplished quickly. In some cases, a single lateral of a multiple lateral wellbore containing a stuck open inflow control valve can be isolated, while maintaining the other producing lateral wellbores open to flow, without isolating the entire wellbore. This can avoid unnecessary producing well downtime by sustaining production from other producing formations and zones. In some instances, if an inflow control valve is stuck open, use of a workover rig is required to stop the flow through the wellbore. This can be a time intensive and costly operation. By implementing techniques described in this specification, such complex removal and replacement operations can be avoided. Additionally, a high water volume producing formation adjacent to a stuck open inflow control valve can be isolated. This can extend the run-life of a well by increasing the overall value of the produced liquids and gases, keeping a wellbore economically viable to produce. 
     Other aspects and advantages of this disclosure will be apparent from the following description made with reference to the accompanying drawings and the claims. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1A  is a schematic view of a wellbore with multiple inflow control valves positioned in the wellbore. 
         FIG. 1B  is a schematic view of a portion of the wellbore of  FIG. 1A . 
         FIG. 2A  is a schematic view of an inflow control valve with the outer sleeve in an normal operating position. 
         FIG. 2B  is a schematic view of the inflow control valve of  FIG. 2B  with the outer sleeve in a locked position. 
         FIG. 3  is a flow chart of an example method of stopping a fluid flow from a stuck open inflow control device. 
         FIG. 4  is a schematic view of a stand-alone outer sleeve sealing assembly. 
     
    
    
     Like reference numbers and designations in the various drawings indicate like elements. 
     DETAILED DESCRIPTION 
     The present disclosure relates to an assembly and a method for stopping fluid flow through a stuck open inflow control valve of wellbore. Multiple inflow control valves can be installed in a wellbore drilled from the surface of the earth to geologic formations of the earth containing liquids and gases, in the form of hydrocarbons, chemicals, and water. Completion equipment can be placed in the wellbore to conduct and control the flow of the liquids and gases through the wellbore from the geologic formations to the surface of the earth. An inflow control valve is one type of completion equipment that can be positioned in a flow path from a single geologic formation to the wellbore to control the flow of the liquids and gases from that single geologic formation into the wellbore. Multiple inflow control valves can be installed in a single wellbore to control different fluid and gas flows from different geologic formations or selected zones from the same formation through which the wellbore passes. The different geologic formations or zones can be isolated from the others by isolation devices such as packers. 
     Inflow control valves can become stuck open. For example, geologic debris such as rocks or sand from the associated geologic formation can mechanically block the inflow control valve from shutting. Additionally or alternatively, chemicals from the geologic formation can corrode the inflow control valve, rendering the inflow control valve inoperable, preventing the inflow control valve from shutting. In such instances, fluid and gas flow from the formation continues into the wellbore. 
     An inflow control valve including a valve body, an inner sleeve, an outer sleeve, and a first actuation mechanism can be installed in a wellbore to stop fluid flow through a stuck open inner sleeve of the inflow control valve by shutting the outer sleeve. The valve body includes an inlet. The inner sleeve is coupled to an inner surface of the valve body. The inner sleeve is movable from a closed position to an open position to provide a fluid flow path from an annulus of a wellbore through the valve body and moveable from the open position to the closed position to restrict the fluid flow through the valve body. The outer sleeve is coupled to an outer surface of the valve body to stop the fluid flow through the inlet. The outer sleeve is movable from a normal operating position offset from the inlet of the valve body to a locked position limiting fluid flow to the inlet of the valve body to stop the fluid flow through the inflow control valve. The first actuation mechanism is coupled to the outer sleeve. The actuation mechanism is operable to move the outer sleeve from the normal operating position offset from the inlet of the valve body to the locked position limiting fluid flow to the inlet of the valve body to stop the fluid flow through the valve body. 
       FIG. 1A  is a schematic view of a wellbore with multiple inflow control valves positioned in the wellbore. A wellbore fluid control system  100  is shown in  FIG. 1A . The wellbore fluid control system  100  includes a wellbore  102  extending from a surface  104  of the earth down through multiple geologic formations of the earth. Some geologic formations, for example a first formation  106   a , can contain hydrocarbons, water, and chemicals in the form of liquids and gases. The first formation  106   a  is bounded by a second formation  106   b  and a third formation  106   c . The second formation  106   b  and the third formation  106   c  can also contain hydrocarbons, water, and chemicals in the form of liquids and gases. When the second formation  106   b  and a third formation  106   c  contain hydrocarbons, water, and chemicals in the form of liquids and gases, the second formation  106   b  and a third formation  106   c  can include completion devices such as the inflow control devices described in this specification. 
     In some cases, multiple branches of wellbores can be drilled from the wellbore  102 . Each branch can also be referred to as a lateral. The entire wellbore can be referred to as a multi-lateral well. The wellbore  102  has three branches, a first branch  108   a , a second branch  108   b , and a third branch  108   c , to conduct fluids from different locations in the first formation  106   a  into the wellbore and up to the surface  104  of the earth. In some cases, where the second formation  106   b  and the third formation  106   c  contain hydrocarbons, water, and chemicals in the form of liquids and gases, the second branch  108   b  can be positioned in the second formation  106   b , and the third branch  108   c  can be positioned in the third formation  106   c . In some cases, the wellbore  102  can include few or more than three branches. In some cases, multiple branches can be drilled in a single formation. 
     A first inflow control device  110   a  is installed in the wellbore  102  to control the fluid flow from the first branch  108   a . A second inflow control device  110   b  is installed in the wellbore  102  to control the fluid flow from the second branch  108   b . A third inflow control device  110   c  is installed in the wellbore  102  to control the fluid flow from the third branch  108   c.    
     The wellbore fluid control system  100  includes a control panel  112  to operate the first inflow control device  110   a , the second inflow control device  110   b , and the third inflow control device  110   c . The control panel  112  can be at or near the wellhead  114  or can be remotely controlled by remote operations center (not shown). 
       FIG. 1B  is a schematic view of a portion of the wellbore of  FIG. 1A .  FIG. 1B  shows a detailed view of the first inflow control device  110   a , the second inflow control device  110   b , and the third inflow control device  110   c  positioned into the first branch  108   a , the second branch  108   b , and the third branch  108   c , respectively, of the wellbore  102 . The first inflow control device  110   a , the second inflow control device  110   b , and the third inflow control device  110   c  are coupled to a tubular  116  positioned in the wellbore  102 . The tubular  116  conducts the liquids and gases from the first branch  108   a , the second branch  108   b , and the third branch  108   c  to the surface  104 . The tubular  116  can be a production tubular. The tubular  116  can be made of a metal, for example, steel. 
     A first packer  118   a  surrounds the tubular  116  and is engaged to an inner surface  120  of the wellbore  102  to fluidically seal the fluid in the first branch  108   a  from a wellbore annulus  122 . The fluid flow path follows first flow path  124  into the first inflow control device  110   a  into the tubular  116  and then up the surface  104  of the earth (shown in  FIG. 1A ). The first branch  108   a  is fluidically isolated from the second branch  108   b  by a second packer  118   b . The second packer  118   b  surrounds the tubular  116  and is engaged to an inner surface  120  of the wellbore  102  to fluidically seal the fluid in the second branch  108   b  from the first branch  108   a . The fluid flow path follows a second flow path  126  into the second inflow control device  110   b  into the tubular  116  and then up the surface  104  of the earth (shown in  FIG. 1A ). The third branch  108   c  is fluidically isolated from the second branch  108   b  by a third packer  118   c . The third packer  118   c  surrounds the tubular  116  and is engaged to an inner surface  120  of the wellbore  102  to fluidically seal the fluid in the third branch  108   c  from the second branch  108   b . The fluid flow path follows a third flow path  128  into the third inflow control device  110   c  into the tubular  116  and then up the surface  104  of the earth (shown in  FIG. 1A ). 
     The fluids and gases from the third branch  108   c  flow into the third inflow control valve  110   c  and into the tubular  116  in the direction shown by arrows  128 . The fluids and gases from the second branch  108   b  flow into the second inflow control device  110   b . The fluids and gases from the third branch  108   c  and the second branch  108   b  mix and combine in the tubular  116  at location  130  and continue flowing towards the surface  104  (which can also be referred to as an uphole direction). The fluids and gases from the first branch  108   a  mix and combine with the fluids and gases from the third branch  108   c  and the second branch  108   b  in the tubular  116  at location  132  and continue flowing towards the surface  104 . 
     The first wellbore inflow control device  110   a  includes a first control unit  134   a  to actuate a first inflow control valve  136   a , both described with respect to  FIGS. 2A-2B . The control panel  112  (shown in  FIG. 1A ) controls the flow of hydraulic fluid in a first hydraulic supply conduit  138   a  to the first control unit  134   a . A common hydraulic return conduit  140  flows the hydraulic fluid back to the control panel  112 . Flowing the hydraulic fluid to the first control unit  134   a  actuates the first control unit  134   a  to operate the first inflow control valve  136   a.    
     The second wellbore inflow control device  110   b  includes a second control unit  134   b  to actuate a second inflow control valve  136   b . The control panel  112  (shown in  FIG. 1A ) controls the flow of hydraulic fluid in a second hydraulic supply conduit  138   b  to the second control unit  134   b . The common hydraulic return conduit  140  flows the hydraulic fluid back to the control panel  112 . Flowing the hydraulic fluid to the second control unit  134   b  actuates the second control unit  134   b  to operate the second inflow control valve  136   b.    
     The third wellbore inflow control device  110   c  includes a third control unit  134   c  to actuate a third inflow control valve  136   c . The control panel  112  (shown in  FIG. 1A ) controls the flow of hydraulic fluid in a third hydraulic supply conduit  138   c  to the third control unit  134   c . The common hydraulic return conduit  140  flows the hydraulic fluid back to the control panel  112 . Flowing the hydraulic fluid to the third control unit  134   c  actuates the third control unit  134   c  to operate the third inflow control valve  136   c.    
     The first wellbore inflow control device  110   a  includes a first outer sleeve assembly  146   a  and a first outer sleeve actuation mechanism  148   a . The first outer sleeve assembly  146   a  moves laterally over the first control unit  134   a  and the first inflow control valve  136   a  to seal the first inflow control valve  136   a . The first outer sleeve assembly  146   a  seals a fluid flow in to or out of the first inflow control valve  136   a . The first outer sleeve actuation mechanism  148   a  actuates the first outer sleeve  146   a . The first outer sleeve actuation mechanism  148   a  includes a first hydraulic control conduit  150   a  coupled to the control panel  112 . The control panel  112  controls a supply of hydraulic fluid to the first outer sleeve actuation mechanism  148   a  to actuate the first outer sleeve actuation mechanism  148   a , moving the first outer sleeve assembly  146   a  to stop fluid flow through the first inflow control valve  136   a . The first hydraulic control conduit  150   a  can include a hydraulic return line (not shown). The first outer sleeve assembly  146   a  and the first outer sleeve actuation mechanism  148   a  are described in more detail referring to  FIGS. 2A and 2B . 
     The second wellbore inflow control device  110   b  includes a second outer sleeve assembly  146   b  and a second outer sleeve actuation mechanism  148   b . The second outer sleeve assembly  146   b  moves laterally over the second control unit  134   b  and the second inflow control valve  136   b  to seal the second inflow control valve  136   b . The second outer sleeve assembly  146   b  seals a fluid flow in to or out of the second inflow control valve  136   b . The second outer sleeve actuation mechanism  148   b  actuates the second outer sleeve assembly  146   b . The second outer sleeve actuation mechanism  148   b  includes a second hydraulic control conduit  150   b  coupled to the control panel  112 . The control panel  112  controls a supply of hydraulic fluid to the second outer sleeve actuation mechanism  148   b  to actuate the second outer sleeve actuation mechanism  148   b , moving the second outer sleeve assembly  146   b  to stop fluid flow through the second inflow control valve  136   b . The second hydraulic control conduit  150   b  can include a hydraulic return line (not shown). The second outer sleeve assembly  146   b  and the second outer sleeve actuation mechanism  148   b  are described in more detail referring to  FIGS. 2A and 2B . 
     The third wellbore inflow control device  110   c  includes a third outer sleeve assembly  146   c  and a third outer sleeve actuation mechanism  148   c . The third outer sleeve assembly  146   c  moves laterally over the third control unit  134   c  and the third inflow control valve  136   c  to seal the third inflow control valve  136   c . The third outer sleeve assembly  146   c  seals a fluid flow in to or out of the third inflow control valve  136   c . The third outer sleeve actuation mechanism  148   c  actuates the third outer sleeve assembly  146   c . The third outer sleeve actuation mechanism  148   c  includes a third hydraulic control conduit  150   c  coupled to the control panel  112 . The control panel  112  controls a supply of hydraulic fluid to the third outer sleeve actuation mechanism  148   c  to actuate the third outer sleeve actuation mechanism  148   c , moving the third outer sleeve assembly  146   c  to stop fluid flow through the third inflow control valve  136   c . The third hydraulic control conduit  150   c  can include a hydraulic return line (not shown). The third outer sleeve assembly  146   c  and the third outer sleeve actuation mechanism  148   c  are described in more detail referring to  FIGS. 2A and 2B . 
       FIG. 2A  is a schematic view of a wellbore inflow control valve with the outer sleeve in a normal operating position offset from the inlet of the inflow control valve body allowing the fluid flow through the inflow control valve. The first inflow control valve  136   a  includes a valve body  202 . The valve body  202  is a hollow cylindrical body which includes an inlet  204 . The inlet  204  can be a single inlet or multiple inlets. Fluids and gases from the first branch  108   a  of the wellbore  102  flow into the valve body  202  through the inlet  204 . The valve body  202  can be made of a metal, for example, steel or aluminum. 
     The first inflow control valve  136   a  includes an inner sleeve  206 . The inner sleeve  206  is positioned within the valve body  202 . The inner sleeve  206  is coupled to an inner surface  208  of the valve body  202 . The inner sleeve  206  moves from a closed position  210  to an open position  212  (as shown in  FIG. 2A ) to provide a fluid flow path from the wellbore annulus  122  (shown in  FIG. 1B ) through the valve body  202 . The inner sleeve  206  also moves from the open position  212  to the closed position  210  to restrict the fluid flow through the valve body  202 . The inner sleeve  206  can be made from a metal, for example, steel or aluminum. 
     The first inflow control valve  136   a  includes an inner sleeve actuation mechanism  214  coupled to the inner sleeve  206 . The inner sleeve actuation mechanism  214  operates to reversibly move the inner sleeve  206  between the closed position  210  and the open position  212  to control fluid flow through the valve body  202 . The inner sleeve actuation mechanism  214  can be a hydraulic control valve. The inner sleeve actuation mechanism  214  is operated by the control panel  112  to supply hydraulic fluid through the first hydraulic supply conduit  138   a  and the common hydraulic return conduit  140  as previously described in reference to  FIG. 1B , to move the inner sleeve  206  between the closed position  210  and the open position  212 . 
       FIG. 2B  is a schematic view of the inflow control valve of  FIG. 1A  with the outer sleeve in a locked position sealing the inlet of the inflow control valve to stop the fluid flow through the inflow control valve. The outer sleeve  216  is coupled to an outer surface  218  of the valve body  202  to stop the fluid flow through the inlet  204 , the outer sleeve  216  moves from a normal operating position  220  offset from the inlet  204  of the valve body  202  to a locked position  222 , shown in  FIG. 2B , stopping fluid flow to the inlet  204  of the inflow control valve body  202 . The outer sleeve  216  is a metal, for example, steel or aluminum. 
     The first hydraulic control conduit  150   a  supplies hydraulic fluid to the first outer sleeve actuation mechanism  148   a  to move the outer sleeve  216  from the normal operating position  220  offset from the inlet  204  of the valve body  202  to the locked position  222  stopping fluid flow to the inlet  204 . The first outer sleeve actuation mechanism  148   a  is coupled to the outer sleeve  216 . The first outer sleeve actuation mechanism  148   a  operates to move the outer sleeve  216  from the normal operating position  220  offset from the inlet  204  of the valve body  202  allowing fluid flow, to the locked position  222  limiting fluid flow to the inlet  204  of the valve body  202  stopping the fluid flow through the valve body  202 . 
     As shown in  FIG. 2A , the first outer sleeve actuation mechanism  148   a  includes a pressure vessel  226 . The pressure vessel  226  contains a pressurized gas, such as nitrogen, to provide a motive force to the outer sleeve  216  to move the outer sleeve  216  from the normal operating position  220  to the locked position  222 . The pressure vessel  226  includes a piston  228  to further force the pressurized nitrogen to move the outer sleeve  216 . Additionally or alternatively, the piston  228  maintains the nitrogen pressurized within the pressure vessel  226 . The piston  228 , when actuated by the hydraulic fluid in the first hydraulic supply conduit  150   a , forces a sliding sleeve cap  230  coupled to the outer sleeve  216  to move the outer sleeve  216  from the normal operating position  220  to the locked position  222 . 
     The sliding sleeve cap  230  is movably coupled to a sliding element  232   a . The sliding element  232   a  is coupled to the outer sleeve  216  to align and move the outer sleeve  216  to seal the inlet  204 . The sliding element  232   a  provides a pathway for the sliding cap to ride in or on as it moves the outer sleeve  216 . The sliding element  232   a  can be a channel, a portion of a rack and pinion gear, or a metallic sliding element/path guide. The first outer sleeve assembly  146   a  can include multiple sliding elements. For example, as shown in  FIGS. 2A and 2B , the outer sleeve  216  can include a second sliding element  232   b  substantially similar to the first sliding element  232   a  described previously. In some cases, the sliding element  232   a  can be an assembly of a tube and a spring with a guide rod. 
     The outer sleeve  216  can include a mechanism to lock the outer sleeve  216  in its closed position. For example, the outer sleeve  216  can include a latch mechanism  234 . The latch mechanism includes a lever  236  and a latch  238 . The latch  238  is mechanically coupled to the outer sleeve  216 . As the outer sleeve  216  moves to seal the inlet  204 , the latch  238  slides over the lever  236  and catches on the lever  236 , locking the outer sleeve  216  in place at the locked position  222 , sealing the inlet  204 . The latch mechanism  234 , when the latch  238  is engaged to the lever  236 , keeps outer sleeve  216  fixed at the locked position  222  eliminating reverse movement of the outer sleeve  216  after sealing the inlet  204  with the outer sleeve  216 . 
     Referring to  FIG. 1B , the first wellbore inflow control device  110   a  includes a first sensor  142   a . The first sensor  142   a  senses a wellbore condition of the wellbore  102  and generates a signal representing the wellbore condition. The first sensor  142   a  transmits the signal representing the wellbore condition to a first controller  144   a . The first controller  144   a  receives the signal representing the wellbore condition and compares the signal representing the wellbore condition to an expected value. When the result of the comparison indicates that the inflow control valve  136   a  is stuck open, the first controller  144   a  operates the first control unit  134   a  to move the outer sleeve  216  to the locked position  222  to stop the fluid flow through the inlet  204 . Some examples of wellbore conditions which can be sensed include pressure, conductivity, flow rate, or inner sleeve position. The sensor  142   a  can be a pressure sensor, a conductivity sensor, a flow rate sensor, or a position sensor. Alternatively or in addition, when the result of the comparison indicates that the inflow control valve  136   a  is stuck open, the first controller  144   a  can send a signal to the control panel  112  to alert an operator to a stuck open inflow control valve  136   a  condition. The operator can use the data collected from the first sensor  142   a  data to actuate the system manually. 
     The controller  144   a  can have one or more set of programmed instructions stored in a memory or other non-transitory computer-readable media that stores data (e.g., connected with the printed circuit board), which can be accessed and processed by a microprocessor. The programmed instructions can include, for example, instructions for sending or receiving signals and commands to operate the first control unit  134   a  and instructions for collecting and storing data from the first sensor  142   a . The data also can be transmitted to the surface panel  112  to be used to verify the condition of the valve. 
     The second wellbore inflow control device  110   b  includes the second control unit  134   b , substantially similar to the first control unit  134   a  previously described. The second wellbore inflow control valve  110   b  can include a second sensor  142   b  and a second controller  144   b  substantially similar to the first sensor  142   a  and the first controller  144   a  previously described. 
     The third wellbore inflow control device  110   c  includes the third control unit  134   c , substantially similar to the first control unit  134   a  previously described. The third wellbore inflow control device  110   c  can include a third sensor  142   c  and a third controller  144   c  substantially similar to the first sensor  142   a  and the first controller  144   a  previously described. 
       FIG. 3  is a flow chart of an example method  300  of stopping a fluid flow from a stuck open inflow control device. At  302 , in a wellbore including a wellbore inflow control valve to control the fluid flow through the wellbore with a sensor and a controller, a wellbore condition is sensed. The wellbore inflow control valve includes an inflow control valve body, an inner sleeve, and outer sleeve, and a first actuation mechanism. The inflow control valve body includes an inlet. The inner sleeve is coupled to an inner surface of the inflow control valve body. The inner sleeve is movable from a closed position to an open position to provide a fluid flow path from an annulus of a wellbore through the inflow control valve body and moveable from the open position to the closed position to restrict the fluid flow through the inflow control valve body. The outer sleeve is coupled to an outer surface of the inflow control valve body to stop the fluid flow through the inlet. The outer sleeve is movable from a normal operating position offset from the inlet of the inflow control valve body to a locked position limiting fluid flow to the inlet of the inflow control valve to stop the fluid flow through the inflow control valve. The first actuation mechanism is coupled to the outer sleeve. The first actuation mechanism is operable to move the outer sleeve from the normal operating position offset from the inlet of the inflow control valve body to the locked position limiting fluid flow to the inlet of the inflow control valve body to stop the fluid flow through the inflow control valve body. 
     The sensor senses a wellbore condition of the wellbore and generate a signal representing the wellbore condition. The controller receives the signal representing the wellbore condition, and responsive to receiving the signal representing the wellbore condition, to operate the first actuation mechanism to move the outer sleeve from the normal operating position to the locked position to limit fluid flow through the inflow control valve. 
     Sensing the wellbore condition indicating the inner sleeve failed to shut can include generating a signal representing the wellbore condition indicating the inner sleeve failed to shut. The signal representing the wellbore condition indicating the inner sleeve failed to shut is transmitted to the controller by the sensor. The signal representing the wellbore condition indicating the inner sleeve failed to shut is received at the controller. 
     At  304 , responsive to receiving the signal representing the wellbore condition indicating the inner sleeve failed to shut, by the controller, the first actuation mechanism is actuated. 
     At  306 , when the first actuation mechanism includes a nitrogen pressure vessel, by the controller, a pressurized nitrogen gas is flowed from the nitrogen pressure vessel to the outer sleeve. 
     At  308 , responsive to flowing the pressurized nitrogen gas from the nitrogen pressure vessel to the outer sleeve, the outer sleeve is moved from the normal operating position to the locked position, stopping the fluid flow. Where the wellbore inflow control valve includes a latch, the outer sleeve is latched in the locked position. Responsive to latching the outer sleeve in the locked position, the fluid flow is maintained stopped. The method can include unlatching the outer sleeve. The method can include releasing, by the controller, the pressurized nitrogen gas from the outer sleeve. The method can include responsive to releasing the pressurized nitrogen gas from the outer sleeve, moving the outer sleeve from the locked position to the normal operating position. The method can include responsive to moving the outer sleeve from the locked position to the normal operating position, allowing the fluid flow. 
       FIG. 4  is a schematic view of a stand-alone outer sleeve sealing assembly  400 . The stand-alone outer sleeve sealing assembly can be positioned in a wellbore around a portion of an inflow control valve (not shown) to move to seal the inflow control valve when the inflow control valve is stuck open, allowing flow from the wellbore into the inflow control valve. 
     Referring to  FIG. 4 , the stand-alone outer sleeve sealing assembly  400  includes an outer sleeve assembly  402 . The outer sleeve assembly  402  is in a normal operating position. When coupled to the inflow control valve, the outer sleeve assembly  402  is in the normal operating position allowing flow through an inlet of the inflow control valve. The outer sleeve assembly  402  can move to a locked position sealing the inlet of the inflow control valve to stop the fluid flow through the inflow control valve. The outer sleeve assembly  402  is a metal, for example, steel or aluminum. 
     As shown in  FIG. 4 , the stand-alone outer sleeve sealing assembly  400  includes an actuation mechanism  404  operably coupled to the outer sleeve assembly  402 . The actuation mechanism  404  includes a pressure vessel  406 . The pressure vessel  406  contains a pressurized gas, such as nitrogen, to provide a motive force to the outer sleeve assembly  402  the normal operating position to the locked position. The pressure vessel  406  can include a piston (not shown) to further force the pressurized nitrogen to move the outer sleeve assembly  402 . Additionally or alternatively, the piston maintains the nitrogen pressurized within the pressure vessel  406 . The piston, is actuated by a hydraulic fluid from a hydraulic supply conduit  408  coupled to the pressure vessel  406 . The piston forces a sliding sleeve cap (not shown), substantially similar to the sliding sleeve cap described earlier, coupled to the outer sleeve assembly  402  to move the outer sleeve assembly  402  from the normal operating position to the locked position. 
     The sliding sleeve cap is movably coupled to a sliding element (not shown), substantially similar to the sliding element described earlier. The sliding element can coupled to the inflow control valve to align and move the outer sleeve assembly  402  to seal inflow control valve inlet. 
     The stand-alone outer sleeve sealing assembly  400  can include a latch mechanism (not shown) to lock the outer sleeve assembly  402  in its closed position. The latch mechanism is substantially similar to the latch mechanism described earlier. 
     While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.