Patent Publication Number: US-9850742-B2

Title: Reclosable sleeve assembly and methods for isolating hydrocarbon production

Description:
BACKGROUND 
     The present invention relates to equipment utilized in subterranean well operations and, more particularly, to a reclosable sleeve assembly and methods for isolating hydrocarbon production within a well. 
     Hydrocarbon-producing wells are often stimulated by one or more hydraulic fracturing operations which generally include injecting a fracturing fluid into a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. One of the purposes of the fracturing process is to increase formation conductivity so that the greatest possible quantity of hydrocarbons from the formation can be extracted/produced into the penetrating wellbore. 
     In some wells, it may be desirable to selectively create multiple fractures along a wellbore at predetermined distances apart from each other, thereby creating multiple “pay zones” from which hydrocarbons can be intelligently produced. A series of actuatable sleeve assemblies may be arranged within the downhole completion assembly in order to separate the pay zones for intelligent production. These sleeve assemblies have devices movably arranged therein generally known as sliding sleeves or sliding side doors due to the ability of the devices to shift an inner sleeve from a first position to a second position. Shifting these inner sleeves allow the operator at the surface to initiate hydrocarbon production, cease hydrocarbon production, or generally regulate hydrocarbon production through the sleeve assembly at that particular location. 
     Actuating a sleeve downward within the sleeve assembly serves to reveal one or more flow ports that, once exposed, allow the influx of fluids into the production tubing. In conventional actuated sleeve assemblies, the sleeve is not designed to retract into the closed position in order to close the flow ports and thereby cease hydrocarbon production at that location. Instead, a tool, such as a side door choke, is typically run into the sleeve assembly to occlude the flow ports and provide a permanent installation within the production tubing. While effective in sealing the flow ports and ceasing hydrocarbon production at that location, the side door choke adversely reduces the inner diameter of the production tubing at that location which, in turn, reduces the potential flow rate through the production tubing. A reduced inner diameter of the production tubing also adversely affects the size of the downhole tools that can be extended past the sleeve assembly, which are thereafter required to be of smaller diameters. Thus, there is a need for a reclosable sleeve assembly that does not disadvantageously reduce the inner diameter of the production tubing but nonetheless is effective in ceasing hydrocarbon production through the one or more flow ports. 
     SUMMARY OF THE INVENTION 
     The present invention relates to equipment utilized in subterranean well operations and, more particularly, to a reclosable sleeve assembly and methods for isolating hydrocarbon production within a well. 
     In some aspects of the disclosure, a sleeve assembly is disclosed. The sleeve assembly may include a housing having an uphole end and a downhole end and defining one or more flow ports that provide fluid communication between a wellbore annulus and an interior of the housing, the housing being coupled to a top sub at the uphole end and to a bottom sub at the downhole end, an outer sleeve arranged within the housing and movable between a closed position, where the outer sleeve occludes the one or more flow ports, and an open position, where the one or more flow ports are exposed, and an inner sleeve concentrically arranged within the outer sleeve and defining a plurality of flow slots, the inner sleeve being movable between an open position and a closed position where, when in the open position, the plurality of flow slots are axially aligned with the one or more flow ports. 
     In other aspects of the disclosure, a method of actuating a sleeve assembly installed in production tubing is disclosed. The method may include introducing a first shifting tool into the sleeve assembly, the sleeve assembly including a housing defining one or more flow ports, an outer sleeve arranged within the housing such that the one or more flow ports are exposed, and an inner sleeve concentrically arranged within the outer sleeve and defining a plurality of flow slots, wherein the plurality of flow slots are axially aligned with the one or more flow ports, thereby providing fluid communication between a wellbore annulus and an interior of the sleeve assembly, engaging the first shifting tool on a first radial shoulder defined on the inner sleeve, and axially moving the inner sleeve with the first shifting tool such that the plurality of flow slots are moved out of axial alignment with the one or more flow ports. 
     In yet other aspects of the disclosure, another sleeve assembly is disclosed. The sleeve assembly may include a housing defining one or more flow ports that provide fluid communication between a wellbore annulus and an interior of the housing, the housing being configured to be coupled at each end to production tubing, an outer sleeve arranged within the housing and movable between a closed position, where the outer sleeve occludes the one or more flow ports, and an open position, where the one or more flow ports are exposed, an inner sleeve concentrically arranged within the outer sleeve and defining a plurality of flow slots, the inner sleeve being movable between an open position and a closed position where, when in the open position, the plurality of flow slots are axially aligned with the one or more flow ports, a piston movably arranged within a piston bore defined in the housing, a spring arranged within the piston bore and configured to bias an uphole end of the piston, and an upper locking device arranged within a first cavity defined in the piston and movable therewith, the upper locking device being engageable with an outer radial surface of the outer sleeve such that as the spring biases against and axially moves the piston within the piston bore, the upper locking device engages and simultaneously moves the outer sleeve into its open position. 
     The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure. 
         FIG. 1  illustrates a well system employing one or more exemplary sleeve assemblies, according to one or more embodiments. 
         FIGS. 2A and 2B  illustrate a partial cross-sectional view of an exemplary sleeve assembly, according to one or more embodiments. 
         FIG. 3  illustrates a partial cross-sectional view of the sleeve assembly of  FIGS. 2A and 2B  as a piston is forced to axially translate within a piston bore, according to one or more embodiments. 
         FIG. 4  illustrates a partial cross-sectional view of the sleeve assembly of  FIGS. 2A and 2B  as an outer sleeve is moved into its open position, according to one or more embodiments. 
         FIGS. 5A and 5B  illustrate partial cross-sectional views of the sleeve assembly of  FIGS. 2A and 2B  as an inner sleeve is moved from its open position into its closed position, according to one or more embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention relates to equipment utilized in subterranean well operations and, more particularly, to a reclosable sleeve assembly and methods for isolating hydrocarbon production within a well. 
     One advantage provided by the disclosed exemplary sleeve assembly is that, opposed to the bulky side door choke typically used to occlude the flow ports, the exemplary sleeve assembly includes an inner sleeve that is able to cover its flow ports without adversely reducing the inner diameter of the production tubing. As a result, the flow rate through the production tubing is largely unaffected and downhole tools that must traverse the sleeve assembly are therefore not required to exhibit a reduced diameter. An additional advantage of the exemplary sleeve assembly is the ability to close and reopen the sleeve assembly. For instance, in some applications, for various reasons it may be advantageous to close the sleeve assembly and thereby cease production at that location for a predetermined period of time and then reopen the sleeve assembly at a later time in order to recommence production. 
     Referring to  FIG. 1 , illustrated is a well system  100  that may employ one or more exemplary sleeve assemblies  102  as disclosed herein, according to one or more embodiments. As depicted, the system  100  may include a drilling or servicing rig  104  that is positioned on the Earth&#39;s surface  106  and extends over and around a wellbore  108  that penetrates a subterranean formation  110  for the purpose of recovering hydrocarbons. The wellbore  108  may be drilled into the subterranean formation  110  using any suitable drilling technique known to those skilled in the art. In an embodiment, the drilling or servicing rig  104  includes a derrick  112  with a rig floor  114 . A casing string  116  may extend from the surface  106  and be cemented into an upper portion of the wellbore  108 . In some embodiments, lower portions of the wellbore  108  may be cemented or un-cemented, without departing from the scope of the disclosure. While the rig  104  is depicted in  FIG. 1  as a land-based facility, it may equally be located at any geographical location. Accordingly, the drilling or servicing rig  104  may be, for example, an offshore rig or drilling platform, without departing from the scope of the disclosure. 
     The wellbore  108  may extend substantially vertically away from the surface  106  over a vertical wellbore portion, or may deviate at any angle from the surface  106  over a deviated or horizontal wellbore portion. In other well systems  100 , portions or substantially all of the wellbore  108  may be vertical, deviated, horizontal, and/or curved. It is noted that although  FIG. 1  depicts horizontal and vertical portions of the wellbore  108 , the principles of the systems and methods disclosed herein are applicable to any type of wellbore  108  configuration. Accordingly, the horizontal or vertical nature of any figure is not to be construed as limiting the wellbore  108 , or the use of a sleeve assembly  102  therein, to any particular configuration. 
     Production tubing  118  may extend from the rig floor  114  and into the wellbore  108  and casing string  116 . The production tubing  118  provides a conduit for formation fluids to travel from the formation  110  to the surface  106 . As illustrated, in one or more embodiments, the exemplary sleeve assembly  102  may be incorporated within the production tubing  118  at some part thereof. While only one sleeve assembly  102  is shown in  FIG. 1 , it will be appreciated that more than one sleeve assembly  102  may be employed in any given well system  100 , without departing from the scope of the disclosure. In some embodiments, the well system  100  may further include one or more packers  120  configured to provide fluid seals between the production tubing  118  and the wellbore  108 , thereby defining various production intervals or pay zones. The well system  100  may also include one or more manipulatable servicing tools  122  and a float shoe  124 . A wellbore annulus  126  is defined between the production tubing  118  and the wellbore  108 , and in operation formation fluids, or other fluids disposed in the formation  110 , escape into the wellbore annulus  126  and are extracted therefrom via the one or more sleeve assemblies  102 , as will be described in more detail below. 
     The drilling or servicing rig  104  may be conventional and may comprise a motor driven winch and other associated equipment for lowering the production tubing  118  into the wellbore  108 , thereby positioning the sleeve assembly  102  and other wellbore servicing equipment at the desired depth. While the well system  100  depicted in  FIG. 1  refers to a stationary drilling or servicing rig  104  for lowering and setting the production tubing  118  within a land-based wellbore  108 , one of ordinary skill in the art will readily appreciate that mobile workover rigs, offshore rigs and platforms, wellbore servicing units (e.g., coiled tubing units), and the like may be used to lower the production tubing  118 , and accompanying sleeve assembly  102 , into the wellbore  108 . Accordingly, it should be understood that the various disclosed embodiments of the sleeve assembly  102  may equally be used in other operational environments, such as within an offshore wellbore operational environment. 
     Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward or uphole direction being toward the left of the corresponding figure and the downward or downhole direction being toward the right of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe or bottom of the well. 
     Referring now to  FIGS. 2A and 2B , with continued reference to  FIG. 1 , illustrated is a partial cross-sectional view of an exemplary sleeve assembly  200 , according to one or more embodiments. Specifically,  FIG. 2A  illustrates an upper portion of the sleeve assembly  200  and  FIG. 2B  illustrates a connected lower portion thereof, with some of the features or components of the sleeve assembly  200  overlapping in each figure. The sleeve assembly  200  may be similar to the sleeve assembly  102  of  FIG. 1 , and therefore may be deployed in a wellbore  108  drilled into the subterranean formation  110  for the extraction of hydrocarbons from the wellbore annulus  126  defined between the wellbore  108  and the sleeve assembly  200 . As illustrated, the sleeve assembly  200  is depicted as being arranged in an open hole section of the wellbore  108 , but those skilled in the art will readily appreciate that the sleeve assembly  200  may equally be deployed in a cased section of the wellbore  108 , without departing from the scope of the disclosure. 
     The sleeve assembly  200  may include a housing  202  coupled or otherwise attached to a top sub  204   a  at an uphole end and coupled or otherwise attached to a bottom sub  204   b  at a downhole end. In at least one embodiment, the sleeve assembly  200  may also include a mid sub  204   c  that generally interposes the bottom sub  204   b  and the housing  202 . In some embodiments, the mid sub  204   c  may be considered part of the bottom sub  204   b . Accordingly, in at least one embodiment, the bottom sub  204   b  is coupled to the downhole end of the housing  202  via interconnection with the mid sub  204   c . The top and bottom subs  204   a,b  may form part of or otherwise be considered an integral portion of the production tubing  118 , and therefore may help facilitate the production of hydrocarbons from the formation  110  to the surface  106  ( FIG. 1 ). 
     The housing  202  may define one or more flow ports  206  (two shown) which provide fluid communication between the wellbore annulus  126  and the interior of the housing  202  when the sleeve assembly  200  is in an open configuration, as will be discussed in greater detail below. The sleeve assembly  200  may further include an inner sleeve  208   a  and an outer sleeve  208   b . The inner sleeve  208   a  may be movably arranged or otherwise extend within each of the housing  202  and the top and bottom subs  204   a,b . At or near an uphole end, the inner sleeve  208   a  may define a plurality of flow slots  210  about its circumference. The flow slots  210  may be equidistantly or randomly spaced from each other about the circumference of the inner sleeve  208   a . While depicted in  FIG. 2A  as elongate perforations in the inner sleeve  208   a , it will be appreciated by those skilled in the art that the flow slots  210  can be defined in any geometric shape, without departing from the scope of the disclosure. The inner sleeve  208   a  may be movable between an open position and a closed position where, when in the open position, the flow slots  210  may be axially aligned, at least generally, with the flow ports  206  defined in the housing  202 . Accordingly, as depicted in  FIGS. 2A and 2B , the inner sleeve  208   a  is shown in its open position. 
     At or near a downhole end, the inner sleeve  208   a  may provide or otherwise define a locking collet  212  configured to lock or otherwise secure the inner sleeve  208   a  in either its open or closed positions. In some embodiments, the locking collet  212  may define one or more locking keys  214  that extend radially from the locking collet  212 . The locking keys  214  may be configured to locate and extend into corresponding grooves defined on the inner radial surface of the bottom sub  204   b , thereby securing the inner sleeve  208   a  against axial movement in either its open or closed positions. Specifically, the bottom sub  204   b  may define a first or lower groove  216   a  and a second or upper groove  216   b . The lower groove  216   a  may be configured to receive the one or more locking keys  214  in order to lock the inner sleeve  208   a  in its open position (as depicted in  FIGS. 2A and 2B ). The upper groove  216   b , however, may be axially offset from the lower groove  216   a  and configured to receive the one or more locking keys  214  in order to lock the inner sleeve  208   a  in its closed position (as depicted in  FIGS. 5A and 5B ). 
     While the upper groove  216   b  is shown as being axially offset from the lower groove  216   a  in the uphole direction, embodiments are also contemplated herein where the relative position of the grooves  216   a,b  and their respective functions are reversed. Moreover, additional embodiments are contemplated where the upper and lower grooves  216   a,b  are defined on the top sub  204   a  instead of the bottom sub  204   b , and the locking collet  212  is otherwise configured to engage or otherwise interact with the grooves  216   a,b  as defined on the top sub  204   a . For example, in at least one embodiment, the inner sleeve  208   a  may be configured to translate axially in the downhole direction and engage the upper groove  216   b  in order to secure the inner sleeve  208   a  in the closed position. Those skilled in the art will readily recognize several variations of the embodiments disclosed herein that will provide equally similar results. 
     In at least one embodiment, the locking collet  212  may define one or more longitudinal perforations  218  therein. The longitudinal perforations  218  may be configured to allow the locking collet  212  to flex such that the locking keys  214  are able to move or bend in and out of the corresponding lower and upper grooves  218   a,b  in response to an appropriate amount of axial force applied to the inner sleeve  208   a.    
     In some embodiments, the sleeve assembly  200  may also include one or more seals  220   a  and  220   b  configured to prevent unwanted fluid communication between the inner sleeve  208   a  and portions of the housing  202  or mid sub  204   c . Specifically, a first seal  220   a  may be arranged between the inner sleeve  208   a  and the housing  202  at or near an uphole end of the sleeve assembly  200  and a second seal  220   b  may be arranged between the inner sleeve  208   a  and the mid sub  204   c  (or alternatively the bottom sub  204   b , in other embodiments) at or near a downhole end of the sleeve assembly  200 . The seals  220   a,b  may be useful in preventing unwanted fluid migration when the inner sleeve  208   a  is in either its open or closed positions, or during the transition between the open and closed positions. In some embodiments, the seals  220   a,b  may be v-packing seals (e.g., hydraulic seals). In other embodiments, the seals  220   a,b  may be any other type of seal known to those skilled in the art as suitable in the prevention of fluid migration in downhole environments. 
     The outer sleeve  208   b  may be radially offset from the inner sleeve  208   a  in a generally concentric or nested relationship, such that the inner sleeve  208   a  may translate axially within the outer sleeve  208   b . The outer sleeve  208   b  may be otherwise movably arranged within the housing  202  and axially translatable between an open position and a closed position. In embodiments where the sleeve assembly  200  includes the mid sub  204   c , the outer sleeve  208   b  may also be movably arranged within at least a portion of the mid sub  204   c . In its closed position, as depicted in  FIGS. 2A and 2B , the outer sleeve  208   b  may be configured to substantially occlude or otherwise cover the one or more flow ports  206  defined in the housing  202 , thereby preventing fluid communication between the wellbore annulus  126  and the interior of the housing  202 . Moreover, in its closed position, the uphole end of the outer sleeve  208   b  may be configured to engage or otherwise bias against a nipple shoulder  209  defined in the interior of the housing  202 . The nipple shoulder  209  may prevent the outer sleeve  208   b  from axially translating uphole (i.e., to the left). 
     The sleeve assembly  200  may further include a piston  222  movably arranged within a piston bore  224  defined in the housing  202 . In some embodiments, the piston bore  224  may be cooperatively defined by both the housing  202  and the outer sleeve  208   b . The piston  222  may be configured to axially translate within the piston bore  224  and a spring  226  may be arranged within the piston bore  224  and configured to engage the piston  222  at its uphole end and thereby bias the piston  222  to the right. 
     A piston chamber  228  may be defined between the piston  222  and the outer sleeve  208   b . In some embodiments, the piston chamber  228  may be cooperatively defined by both the piston  222  and the outer sleeve  208   b . In at least one embodiment, the piston  222  may be coupled or otherwise attached to the outer sleeve  208   b  using one or more shear pins  230  (one shown). The shear pins  230  may extend at least partially through each of the piston  222  and the outer sleeve  208   b . In order to move the outer sleeve  208   b  from its closed position to its open position (as depicted in  FIGS. 4, 5A and 5B ), the shear pins  230  may be sheared with a predetermined amount of force applied to the piston  222 . 
     In at least one embodiment, the force required to shear the shear pins  230  may be obtained by pressurizing the production tubing  118 . For example, as the pressure within the production tubing  118  increases, it eventually surpasses the pressure of the wellbore annulus  126  and the pressure within the piston chamber  228 , thereby generating a pressure differential across the piston  222 . Further increasing the pressure within the production tubing  118  will force the piston  222  to move left (i.e., upward) with respect to the outer sleeve  208   b  (which is biased against the nipple shoulder  209 ), thereby shearing the shear pins  230  and simultaneously axially collapsing the piston chamber  228 . 
     Referring now to  FIG. 3 , with continued reference to  FIGS. 2A and 2B , illustrated is a partial cross-sectional view of the sleeve assembly  200  as the piston  222  is forced to axially translate within the piston bore  224 , according to one or more embodiments. Specifically,  FIG. 3  illustrates the piston  222  as it has been forced to move axially from a first position within the piston bore  224 , as shown in  FIG. 2A , to the left (i.e., upward) and to a second position, as shown in  FIG. 3 . As the piston  222  moves axially to the left (i.e., upward) within the piston bore  224 , the piston chamber  228  ( FIG. 2A ) collapses until the piston engages a shoulder  302  defined on the outer sleeve  208   b . Moreover, as the piston  222  moves axially to the left (i.e., upward) within the piston bore  224 , the piston  222  also engages the spring  226  and overcomes its spring force and the pressure of the annulus  126 , thereby axially compressing the spring  226  within the piston bore  224  in the same direction. 
     The sleeve assembly  200  may further include a first or upper locking device  304   a  and a second or lower locking device  304   b . The upper locking device  304   a  may be arranged within the piston bore  224  and otherwise configured to interact with the piston  222  and the outer radial surface of the outer sleeve  208   b . The lower locking device  304   b  may also be arranged within the piston bore  224 , but otherwise configured to interact with the mid sub  204   c  and the outer radial surface of the outer sleeve  208   b . In some embodiments, the upper locking device  304   a  may be arranged or otherwise captured within a cavity defined in the piston  222  and the lower locking device  304   b  may be arranged or otherwise captured within a cavity defined within the mid sub  204   c  (e.g., considered part of the bottom sub  204   b ). 
     In at least one embodiment, the upper and lower locking devices  304   a,b  may be beveled c-rings configured to extend about at least a portion of the circumference of the outer sleeve  208   b . In some embodiments, each of the locking devices  304   a,b  may define a plurality of teeth  306  on their underside (i.e., their respective inner radial surfaces). The teeth  306  may be configured to interact with corresponding teeth  308  defined on the outer radial surface of the outer sleeve  208   b . For example, as the piston  222  moves axially to the left (i.e., upward) within the piston bore  224 , the upper locking device  304   a  moves concurrently therewith since it is captured within the cavity defined in the piston  222 . As the upper locking device  304   a  moves axially to the left, its teeth  306  may be configured to move or otherwise bounce over the teeth  308  of the outer sleeve  208   b  or otherwise not cause a binding engagement therewith. On the other hand, if moving in the opposite direction (i.e., axially to the right or downward within the piston bore  224 ), the teeth  306  of the upper locking device  304   a  may further be configured to engage or otherwise bind against the teeth  308  of the outer sleeve  208   b.    
     Referring now to  FIG. 4 , with continued reference to  FIGS. 2A-B  and  3 , illustrated is a partial cross-sectional view of the sleeve assembly  200  as the outer sleeve  208   b  is moved into its open position, according to one or more embodiments. Specifically, in at least one embodiment, the outer sleeve  208   b  may be moved to the open position by decreasing the fluid pressure within the production tubing  118 . Decreasing the pressure in the production tubing  118  removes the pressure differential previously generated across the piston  222 , thereby allowing the spring  226  to expand and axially force the piston  222  back to the right (i.e., downward) within the piston bore  224 . The piston  222  is also forced to the right by the fluid pressure derived from the annulus  126 . The spring  226  may force the piston  222  axially to the right within the piston bore  224  until the downhole end of the piston  222  engages a pin nose  314  defined on the mid sub  204   c  and thereby stops its axial movement. 
     As the piston  222  moves axially to the right (i.e., downward), as briefly stated above, the teeth  306  of the upper locking device  304   a  may be configured to engage or otherwise bind against the teeth  308  of the outer sleeve  208   b , thereby forcing the outer sleeve  208   b  also to translate axially to the right (i.e., downward) and into its open position. In the open position, the outer sleeve  208   b  may be configured to uncover the flow ports  206  defined in the housing  202 , thereby exposing the flow ports  206  to the flow slots  210  defined in the inner sleeve  208   a  and allowing fluid communication between the wellbore annulus  126  and the production tubing  118 . 
     In one or more embodiments, the lower locking device  304   b  may be configured to lock the outer sleeve  208   b  in the open position. For instance, as the outer sleeve  208   b  moves axially to the right, the teeth  306  of the lower locking device  304   b  may be configured to move or otherwise bounce over the teeth  308  of the outer sleeve  208   b  or otherwise not cause a binding engagement therewith. The teeth  306  of the lower locking device  304   b , however, may further be configured to engage or otherwise bind against the teeth  308  of the outer sleeve  208   b  in the event the outer sleeve is forced in the opposite direction (i.e., axially to the left within the piston bore  224 ). As a result, the lower locking device  304   b  secures the outer sleeve  208   b  in the open position such that it will not inadvertently close again. 
     The sleeve assembly  200  is depicted in  FIG. 4  in its open configuration. In the open configuration, production operations can be undertaken in order to extract the hydrocarbons present in the surrounding subterranean formation  110 . As briefly mentioned above, however, at least one of the advantages of the exemplary sleeve assembly  200  is the incorporation of the inner sleeve  208   a  which may be useful in reclosing the sleeve assembly  200  if desired. In some applications, an operator may want to reclose the sleeve assembly  200  in order to cease production from that particular location, or to allow pressure testing to be undertaken in the production tubing  118 . In other applications, the operator may want to reclose the sleeve assembly  200  in order to isolate certain sections of the production tubing  118  where it would otherwise be disadvantageous to do so while having fluid communication through open flow ports  206  in the sleeve assembly  200 . 
     To reclose the sleeve assembly  200 , or otherwise place the sleeve assembly  200  in a closed configuration, the inner sleeve  208   a  may be configured to be moved from its open position, as shown in  FIGS. 2A-B ,  3 , and  4 , and into its closed position, as shown in  FIGS. 5A and 5B . In some embodiments, this may be accomplished by introducing a shifting tool  316  (shown in phantom in  FIG. 4 ) into the production tubing  118  and run to the sleeve assembly  200 . In some embodiments, the shifting tool  316  is run in hole via wireline (not shown), or any other suitable conveyance. In at least one embodiment, the shifting tool  316  may have one or more radial keys or arms  318  configured to extend radially from the shifting tool  316  and locate or otherwise engage a radial shoulder  320  defined on the inner sleeve  208   a . In some embodiments, the radial arms  318  may be spring loaded. In other embodiments, however, the radial arms  318  may be mechanically, electromechanically, or hydraulically actuated. While the shifting tool  316  has been described herein as having a particular configuration, those skilled in the art will readily recognize that many variations of the shifting tool  316  may be used to engage and shift the inner sleeve  208   a , without departing from the scope of the disclosure. 
     Once the shifting tool  316  is properly engaged with the radial shoulder  320  of the inner sleeve  208   a , the shifting tool  316  may then be “jarred” upwards, i.e., towards the left in  FIG. 4  or otherwise towards the surface  106  ( FIG. 1 ). As known by those skilled in the art, jarring upwards refers to an upward impulse of force that is applied to an element, such as in this case the shifting tool  316 . Jarring upwards on the shifting tool  316  as engaged with the radial shoulder  320  may force the inner sleeve  208   a  to also move axially to the left within the production tubing  118 , thereby shifting the inner sleeve  208   a  from its open position into its closed position. 
     Referring now to  FIGS. 5A and 5B , with continued reference to  FIGS. 2A-B ,  3 , and  4 , illustrated are partial cross-sectional views of the sleeve assembly  200  as the inner sleeve  208   a  is moved from its open position into its closed position, according to one or more embodiments. Specifically,  FIG. 5A  illustrates the upper portion of the sleeve assembly  200  and  FIG. 2B  illustrates a connected lower portion thereof, with some of the features of the sleeve assembly  200  overlapping in each figure. 
     In order to axially move the inner sleeve  208   a  to the left within the production tubing  118 , and therefore into its closed position, the jarring of the shifting tool  316  may be configured to overcome the locking engagement between the locking collet  212  and the lower groove  216   a . In particular, the shifting tool  316  may be jarred sufficiently such that the locking keys  214  flex inwards and out of engagement with the lower groove  216   a . Once out of engagement with the lower groove  216   a , the locking keys  214  may be able to slide along the inner radial surface of the bottom sub  204   b  as the inner sleeve  208   a  moves axially to the left and towards its closed position. Upon locating or otherwise engaging the upper groove  216   b , the locking keys  214  may be configured to once again flex outwards and into engagement with the upper groove  216   b , thereby securing the inner sleeve  208   a  in the closed position. 
     With the inner sleeve  208   a  in its closed position, the flow slots  210  are no longer exposed to the flow ports  206 . Instead, the flow ports  206  are generally occluded by the wall of the inner sleeve  208   a , thereby preventing fluid communication between the wellbore annulus  126  and the production tubing  118 , and effectively ceasing fluid production at the location of the sleeve assembly  200 . Accordingly,  FIGS. 5A and 5B  depict the sleeve assembly  200  in a closed configuration. 
     One of the advantages of the exemplary sleeve assembly  200  is that the locking engagement between the upper groove  216   b  and the locking keys  214  may prevent the inner sleeve  208   a  from inadvertently moving back into its open position. In some applications, however, an operator may want to recommence production at the sleeve assembly  200  at a later time, thereby requiring the inner sleeve  208   a  to move back into its open position and the sleeve assembly  200  back into its open configuration. To accomplish this, in some embodiments, a shifting tool  502  (shown in phantom in  FIG. 5B ) may be introduced into the production tubing  118  and run to the sleeve assembly  200  via wireline  504  or other suitable conveyance means. In some embodiments, the shifting tool  502  may be similar to or the same as the shifting tool  316  shown in  FIGS. 4 and 5A . In other embodiments, however, the shifting tool  502  may be any suitable shifting tool known to those skilled in the art. 
     In at least one embodiment, the shifting tool  502  may have one or more radial keys or arms  506  configured to extend radially from the shifting tool  502  and locate or otherwise engage a radial shoulder  508  defined on the inner sleeve  208   a . In one embodiment, the radial shoulder  508  may be defined on the inner radial surface of the locking collet  212  of the inner sleeve  208   a . Once the shifting tool  502  is properly engaged with the radial shoulder  508 , the shifting tool  502  may then be jarred downwards, i.e., towards the right in  FIG. 5B  or otherwise towards the toe of the well. As known by those skilled in the art, jarring downwards refers to a downward impulse of force that is applied to an element, such as in this case the shifting tool  502 . Jarring downwards on the shifting tool  502  as engaged with the radial shoulder  508  may force the inner sleeve  208   a  to move axially to the right within the production tubing  118 , and thereby back towards its open position. 
     In order to axially move the inner sleeve  208   a  to the right within the production tubing  118 , however, the jarring of the shifting tool  502  must overcome the locking engagement between the locking collet  212  and the upper groove  216   b . In particular, the shifting tool  502  may be jarred sufficiently such that the locking keys  214  flex inwards and out of engagement with the upper groove  216   b . Once out of engagement with the upper groove  216   b , the locking keys  214  may be able to slide along the inner radial surface of the bottom sub  204   b  as the inner sleeve  208   a  moves axially to the right and back towards its open position. Upon locating or otherwise engaging the lower groove  216   a , the locking keys  214  may be configured to once again flex outwards and into engagement with the lower groove  216   a , thereby securing the inner sleeve  208   a  in the closed position. 
     Accordingly, it will be appreciated by those skilled in the art that the sleeve assembly  200  may be opened and closed multiple times. This provides a distinct and valuable advantage over prior art sleeve assemblies which oftentimes provide a permanent fixation in either the open or closed configurations. 
     Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.