Patent Publication Number: US-11377930-B2

Title: Actuatable deflector for a completion sleeve in multilateral wells

Description:
BACKGROUND 
     Multilateral well technology allows an operator to drill a parent wellbore, and subsequently drill one or more lateral wellbores that extend from the parent wellbore at desired depths and angular orientations. For many well completions, such as offshore deepwater wells, multiple lateral wellbores are drilled from a single parent wellbore in an effort to optimize hydrocarbon production while minimizing overall drilling and well completion costs. 
     Briefly, drilling a multilateral well first requires that the parent wellbore be drilled and at least partially completed by lining the parent wellbore with a string of casing or other type of wellbore liner and subsequently securing the casing to the wellbore with cement. The casing serves to strengthen the parent wellbore and facilitate isolation of certain areas of the surrounding subterranean formations for the eventual production of hydrocarbons. A casing exits (alternately referred to as a “window”) is then created in the casing at a predetermined location to initiate the formation of a lateral well bore. The casing exit is formed by running a whipstock assembly into the parent wellbore and securing the whipstock assembly at the predetermined location. The whipstock assembly is then used to deflect one or more mills laterally to penetrate (i.e., cut through) the casing and form the casing exit. Once the casing exit is formed, a drill bit can then be inserted through the casing exit to drill the lateral wellbore to a desired depth, and the lateral wellbore can then be completed as desired. 
     Drilling and completing multilateral wellbores can be a costly and time-consuming process that requires multiple “trips” into the parent \wellbore to complete various completion tasks. Moreover, entering a drilled and completed lateral wellbore for post completion downhole operations can also require multiple trips into the parent wellbore. Accordingly, well operators are always looking for ways to reduce the number of downhole trips and thereby save time and expense. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present disclosure 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, without departing from the scope of this disclosure. 
         FIG. 1  is a cross-sectional side view of an exemplary well system that may incorporate the principles of the present disclosure. 
         FIG. 2  is an isometric view of an example embodiment of the completion sleeve of  FIG. 1 . 
         FIGS. 3A and 3B  are cross-sectional side views of the completion sleeve of  FIG. 1 . 
         FIGS. 4A and 4B  are enlarged cross-sectional side views of the example deflector assembly of the completion sleeve of  FIGS. 3A-3B   
         FIG. 5  is an enlarged cross-sectional side view of another embodiment of the deflector assembly and the completion sleeve of  FIGS. 3A-3B . 
         FIGS. 6A and 6B  are enlarged cross-sectional side views of another embodiment of the deflector assembly and the completion sleeve of  FIGS. 3A-3B . 
         FIGS. 7A and 7B  are enlarged cross-sectional side views of another embodiment of the deflector assembly and the completion sleeve of  FIGS. 3A-3B . 
         FIGS. 8A and 8B  are enlarged cross-sectional side views of another embodiment of the deflector assembly and the completion sleeve of  FIGS. 3A-3B . 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure is related to multilateral wellbore operations and, more particularly, to completion sleeves that incorporate a deflector that is remotely, wirelessly, or mechanically actuatable between a stowed position and a deployed position. 
     Embodiments described herein reduce the number of required intervention trips into a multilateral well to perform maintenance on a lateral wellbore extending from a parent wellbore. The example completion sleeve embodiments described herein each incorporate and otherwise include a deflector assembly that is remotely, wirelessly, or mechanically actuatable to move an associated deflector from a stowed position to a deployed position for deflecting downhole tools through a window defined in the completion sleeve. In its stowed position, the deflector is positioned in the sidewall of the completion sleeve to enable full-bore access through the interior of the completion sleeve. When in the deployed position, the deflector receives and deflects downhole tools out of the completion sleeve via the window. When desired, the deflector assembly may again be remotely, wirelessly, or mechanically actuated to move the deflector back to the stowed position. Including the deflector assembly in the completion sleeve advantageously eliminates at least two downhole runs that would otherwise be required in conventional completion sleeve applications to nm and install a deflector and subsequently retrieve the deflector. 
       FIG. 1  is a cross-sectional side view of an exemplary well system  100  that may incorporate the principles of the present disclosure, according to one or more embodiments. As illustrated, the well system  100  may include a parent well bore  102  and a lateral wellbore  104  that extends at an angle from the parent wellbore  102 . The parent wellbore  102  can alternately be referred to as a primary wellbore, and the lateral wellbore  104  can be referred to as a secondary wellbore. While only one lateral wellbore  104  is depicted in  FIG. 1 , it will be appreciated that the well system  100  may include multiple lateral (secondary) well bores  104  extending from the parent well bore  102  at various desired locations. In addition, the well system  100  may include one or more tertiary wellbores extending from one or more secondary wellbores  104 , without departing from the scope of the disclosure. Accordingly, the well system  100  may be characterized and otherwise referred to as a “multilateral” wellbore system. 
     The parent and lateral wellbores  102 ,  104  may be drilled and completed using conventional well drilling techniques. A liner or casing  106  may line each of the parent and lateral well bores  102 ,  104  and cement  108  may be used to secure the casing  106  therein. In some embodiments, however, the casing  106  may be omitted from the lateral wellbore  104 , without departing from the scope of the disclosure. The parent and lateral wellbores  102 ,  104 , may be drilled and completed using conventional well drilling techniques. A casing exits  110  may be milled, drilled, or otherwise defined along the casing  106  at the junction between the parent and lateral wellbores  102 ,  104 . The casing exit  110  generally provides access for downhole tools to enter the lateral well bore  104  from the parent wellbore  102 . 
     In the illustrated embodiment, the well system  100  has been completed by installing a reentry window assembly  112  in the parent wellbore  102 . The reentry window assembly  112  includes a completion sleeve  114  and, in some embodiments, may further include an isolation sleeve  116  movably positioned within the interior of the completion sleeve  114 . As illustrated, the completion sleeve  114  is positioned within the parent wellbore  102  and provides a generally cylindrical body  118  that axially spans the casing exit  110 . A window  120  is defined in the completion sleeve  114 , and the completion sleeve  114  may be arranged within the parent wellbore  102  such that the window  120  azimuthally and angularly aligns with the casing exit  110  and thereby provides access into the lateral wellbore  104  from the parent wellbore  102 . 
     The isolation sleeve  116  may be positioned within the body  118  of the completion sleeve  114  and may comprise a generally tubular or cylindrical structure that is axially movable within the completion sleeve  114  between a first or “closed” position and a second or “open” position.  FIG. 1  depicts the isolation sleeve  116  in the first position, where the isolation sleeve  116  occludes (covers) the window  120  and thereby prevents access into the lateral wellbore  104  from the parent wellbore  102 . When in the second position, the isolation sleeve  116  is moved axially within the body  118  to expose the window  120  and thereby allow downhole tools to access the lateral wellbore  104  via the window  120 . Moreover, when the isolation sleeve  116  is in the second position, production fluids (oil, gas, water, etc.) can flow through into the completion sleeve  114  via the window  120  and to production tubing coupled to the reentry window assembly  112  in the parent wellbore  102 . It should also be noted that this system can also be used for injecting fluids into the parent or lateral wellbores  102 ,  104 . 
     In some embodiments, as in the example of  FIG. 1 , a set of upper seals  122   a  and a set of lower seals  122   b  seal between the completion sleeve  114  and the isolation sleeve  116 . In some applications, the upper seals  122   a  and the lower seals  122   b  are carried on the isolation sleeve  116 . In such applications, the upper seals  122   a  may sealingly engage an upper seal bore  124   a  provided on the inner surface of the body  118 , and the lower seals  122   b  may sealingly engage a lower seal bore  124   b  provided on the inner surface of the body  118 . Alternatively, the upper and lower seals  122   a,b  may be carried on the inner diameter of the completion sleeve  114 . As illustrated, the upper and lower seal bores  124   a,b  are located adjacent opposing axial ends of the window  120 . Accordingly, when in the first position, the isolation sleeve  116  may provide fluid isolation between the parent and lateral wellbores  102 ,  104  and, more specifically, between the lateral wellbore  104  and the production tubing (or an intermediate completion tubing string) coupled to the reentry window assembly  112 . 
     The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well. 
       FIG. 2  is an isometric view of an example embodiment of the completion sleeve  114  of  FIG. 1 . As illustrated, the completion sleeve  114  includes or otherwise comprises the generally cylindrical body  118 , which has a first or “uphole” end  202   a  and a second or “downhole” end  202   b  opposite the first end  202   a . The first end  202   a  may provide a location to couple the completion sleeve  114  to a running tool or work string (not shown) that enables a well operator to run the completion sleeve  114  downhole and into the parent wellbore  102  ( FIG. 1 ). In other embodiments, an intermediate tubing or sub (not shown) is coupled to the first end  202   a , which is coupled to other portions of the re-entry window assembly  112  to be run into the parent wellbore  102  on the running tool or the work string. At the second end  202   b , in some embodiments, the completion sleeve  114  may be coupled to a latch assembly (not shown) that axially and azimuthally aligns the window  120  relative to the casing exit  110  ( FIG. 1 ). 
     With conventional completion sleeves, when it is desired to convey a downhole tool (not shown) into the lateral wellbore  104  ( FIG. 1 ), a tubing exit whipstock (TEW) assembly (alternately referred to as a “whipstock assembly” or a “deflector assembly”) is first nm into the parent wellbore  102  ( FIG. 1 ), through the production tubing string and eventually to the reentry window assembly and its completion sleeve. The TE\V is secured within or relative to the completion sleeve and includes a deflector that is aligned with the window  120  such that downhole tools subsequently conveyed into the completion sleeve engage the deflector and are deflected laterally out of the completion sleeve via the window  120 . Once the desired downhole operations are completed in the lateral well bore  104 , the downhole tool is then retracted back to the well surface. The TEW must then be removed from the parent well bore  102  in a separate downhole run. 
     According to the embodiments of the present disclosure, the presently described completion sleeve  114  incorporates and otherwise includes a deflector assembly that is remotely, wirelessly, or mechanically actuatable to move an associated deflector from a stowed position to a deployed position for deflecting downhole tools through the window  120 . In some embodiments, the deflector does not obstruct the interior of the completion sleeve  114  when in the stowed position, but instead allows full-bore access through the interior of the completion sleeve  114 . When in the deployed position, the deflector receives and deflects downhole tools out of the completion sleeve  114  via the window  120 . When desired, the deflector assembly may again be remotely, wirelessly, or mechanically actuated to move the deflector back to the stowed position. The deflector assembly included in the completion sleeve  114  may advantageously eliminate two downhole runs required to install a TEW and later retrieve the TEW. This may also eliminate the need to de-complete a well prior to a workover operation (e.g., re-stimulation, running production logging tools, etc.). 
       FIGS. 3A and 3B  are cross-sectional side views of the completion sleeve  114 , according to one or more embodiments. As illustrated, the body  118  forms a generally elongated tubular structure that defines an interior or inner passage  302 . As used herein, the term “elongated” refers to having a length that is greater than a width. The body  118  includes or otherwise comprises a sidewall  304  that at least partially defines the inner passage  302 . Moreover, the window  120  is defined in or through the sidewall  304  and thereby provides a lateral exit from the inner passage  302  for downhole tools entering the completion sleeve  114 . 
     A deflector assembly  306  is included in the completion sleeve  114  and includes a deflector  308  and an actuator  310  used to move the deflector  308  between a stowed (retracted) position, as shown in  FIG. 3A , and a deployed (extended) position, as shown in  FIG. 3B . The deflector assembly  306  is housed within the inner passage  302  of the completion sleeve  114 . More particularly, the deflector  308  and the actuator  310  may each be housed within the sidewall  304  within the inner passage  302 . The deflector  308 , for example, may be pivotably secured within a recess or pocket  312  defined in the sidewall  304  within the inner passage  302 . In some embodiments, the pocket  312  may be large enough to receive the deflector  308  in the stowed position such that the deflector  308  does not extend into or obstruct the inner passage  302 . Accordingly, in its stowed position, the deflector  308  may allow full-bore access through the inner passage  302  for downhole tools required to pass through the completion sleeve  114 . In other embodiments, however, the deflector  308  may extend partially into the inner passage  302  in the stowed position, without departing from the scope of the disclosure. 
     The actuator  310  may be operatively coupled (either directly or indirectly) to the deflector  308  and actuatable to move the deflector  308  between the stowed and deployed positions. In some embodiments, however, the actuator  310  may not be configured or otherwise required to move the deflector  308  back to the stowed position. In such embodiments, the deflector  308  may return to the stowed position by natural forces (e.g., gravity), spring force, or through the intervention of a downhole tool extended through the inner passage  302 , for example. The actuator  310  may comprise any type of actuation device including, but not limited to, a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, or any combination thereof. 
     In some embodiments, the actuator  310  may be remotely actuated to move the deflector  308  between the stowed and deployed positions. More specifically, a communications line  314  may be extended from a well surface location and communicably coupled to the actuator  310 . Operation (actuation) of the actuator  310  may be triggered upon receipt of a control (command) signal provided via the communications line  314 . The control signal may be sent by a well operator at the well surface location when desired, or the control signal may alternatively comprise an automated signal sent from a computer system located at the well surface location at a predetermined or designed time. In other embodiments, the control signal may be sent by a well operator located remote from the well surface location but in communication with the well surface location either wired or wirelessly. Accordingly, as used herein, “at the well surface location” refers to being physically located at a well site or otherwise in communication with the well site via a communication means (wired or wireless means). 
     The communications line  314  may comprise one or more control lines, such as hydraulic, fiber optic, and electrical lines. Accordingly, control signals provided to the actuator  310  may comprise electrical signals, hydraulic signals, optical signals, digital signals, analog signals, pulse-width modulation signals, or any combination thereof In at least one embodiment, the communications line  314  may comprise a plurality (e.g., twelve) of individual control lines provided in either single- or multiple-flat pack configurations. Moreover, the communications line  314  may provide bi-directional communication to enable the actuator  310  to communicate with the well surface location. Accordingly, and as described in more detail below, the actuator  310  may include a control module configured to receive downhole signals from the well surface location and transmit uphole signals to be received and considered at the well surface location. This may prove advantageous in providing a well operator with real-time status reports on the operational conditions of the deflector assembly  306 , such as a position of the deflector  308 . Various sensors could also be included in the completion sleeve  114  and communicably coupled to the control module to provide real-time reporting of the wellbore conditions, such as the fluids inside and outside of the completion sleeve  114 . 
     Accordingly, operation of the deflector  308  can be controlled at the surface location by communicating with the actuator  310  via the communications line  314 . In some embodiments, a first control signal may be communicated to the actuator  310  to move the deflector  308  to the deployed position, as shown in  FIG. 3B  With the deflector  308  in the deployed position, a downhole tool introduced into the inner passage  302  may engage the deflector  308 , which deflects the downhole tool laterally out of the completion sleeve  114  via the window  120 . A second control signal may subsequently be communicated to the actuator  310  via the communications line  314  to move the deflector  308  back to the stowed position, as shown in  FIG. 3A . 
       FIGS. 4A and 4B  are enlarged cross-sectional side views of the example deflector assembly  306  of the completion sleeve  114  of  FIGS. 3A-3B .  FIG. 4A  depicts the deflector  308  in the stowed position, and  FIG. 4B  depicts the deflector  308  in the deployed position. As illustrated, the actuator  308  may include a control module  402  communicably coupled to the communications line  314  and configured to communicate with a well surface location and operate the actuator  308 , which moves the deflector  308  between the stowed and deployed positions. In some embodiments, as illustrated, the sidewall  304  of the completion sleeve  114  may be thick enough to house the control module  402  and its various components. 
     The control module  402  may include, for example, computer hardware and/or software used to operate the actuator  310 . The computer hardware may include a processor configured to execute one or more sequences of instructions, programming stances, or code stored on a non-transitory, computer-readable medium and can include, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, or any like suitable device. In some embodiments, the control module  402  may further include a power source that provides electrical power to the actuator  310  for its operation and may also provide a source of electrical power to other downhole devices. The power source may comprise, but is not limited to, one or more batteries, a fuel cell, a nuclear-based generator, a flow induced vibration power harvester, or any combination thereof. The sidewall  304  may be thick enough to store such batteries and power supplies as required. In other embodiments, however, the power source may be omitted, and electrical power required to operate the actuator  310  may be obtained via the communications line  314 . Alternatively, receiving electrical power via the communications line  314  may act as a backup for a downhole power source. 
     The control module  402  may also include a communications module that enables transfer of data or control signals to/from the control module  402  and a well surface location during operation. The communications module may include one or more transmitters and receivers, for example, to facilitate bi-directional communication with the surface location. As a result, a well operator at the well surface location may be applied of the real-time operational conditions of the deflector assembly  306  and may be able to send command signals to the actuator  310  to adjust the position of the deflector  308  as desired. 
     In the illustrated embodiment, the actuator  310  comprises a hydraulic actuator that includes a piston  404  operatively coupled to the deflector  308  and movably positioned within a piston chamber  406 . While the actuator  310  is described and depicted herein as a hydraulic-type actuator, it is again noted that the actuator  310  may alternatively comprise any of the actuation devices mentioned herein, or any combination thereof, without departing from the scope of the disclosure. Accordingly, it is contemplated herein to move the deflector  308  between the stowed and deployed configurations using an actuator based on any electrical, hydraulic, magnetic, and/or mechanical means. Discussion of the actuator  310  as a hydraulic-type actuator, therefore, should not be considered limiting on the scope of the disclosure. 
     The piston  404  includes a first end  408   a , a second end  408   b  opposite the first end  408   a , and a piston rod  408  that extends between the first and second ends  408   a,b . The piston  404  is operatively coupled to the deflector  308  at the first end  408   a . More particularly, the piston  404  may include a pin  410  or another coupling mechanism secured to the piston  404  at the first end  408   a  and extendable through a slot  412  defined in the deflector  308 . As illustrated, the slot  412  may comprise and otherwise define a straight portion  414   a  that transitions into an angled portion  414   b . The straight portion  414   a  may extend longitudinally and generally parallel to a deflector surface  416  of the deflector  308 . In contrast, the angled portion  414   b  may extend at an angle offset from parallel to the deflector surface  416 . The angled portion  414   b  may provide leverage for the pin  410  that helps move the deflector  308  from the stowed to deployed positions during operation. 
     A piston head  418  is provided at the second end  408   b  and includes one or more sealing elements  420  (two shown as O-rings) configured to sealingly engage the inner surface of the piston chamber  406 . A seal ring  422  may also be positioned within the piston chamber  406  to guide the piston rod  409  during its stroke length. The seal ring  422  may include one or more sealing elements  424  (two shown as O-rings) configured to sealingly engage the outer surface of the piston rod  409 . 
     Exemplary operation of the deflector assembly  306  of  FIGS. 4A-4B  is now provided. The deflector  308  is shown in  FIG. 4A  in the stowed position, where the deflector  308  is received within the pocket  312  defined in the sidewall  304  such that full-bore access through the inner passage  302  is allowed for downhole tools required to pass through the completion sleeve  114 . When it is desired to move the deflector  308  to the deployed position, as shown in  FIG. 4B , a control (command) signal is provided to the actuator  310  via the communications line  314 . In some embodiments, the control signal may comprise an electrical signal received by the control module  402 , which triggers actuation of the actuator  310 . In such embodiments, the actuator  310  may pump a hydraulic fluid from a fluid source (not shown) into the piston chamber  406  to act on the piston head  418  and thereby move the piston  404 . In other embodiments, however, the control signal may comprise hydraulic fluid provided directly to the actuator  310  via the communications line  314  and conveyed into the piston chamber  406  to act on the piston head  418 . 
     The hydraulic fluid impinging on the piston head  418  urges the piston  408  to move within piston chamber  406 . As the piston  408  moves, the deflector  308  is forced to pivot out of the pocket  312  and into the deployed position. More specifically, as the pin  410  traverses the slot  412 , the pin  410  will eventually engage the angled portion  414   b , which urges the deflector  308  to pivot about a pivot hinge  426  that pivotably couples the deflector  308  to the completion sleeve  114 . To prevent hydraulic lock between the piston head  418  and the seal ring  422  within the piston chamber  406 , a vent  428  may be defined in the sidewall  304  and extend between the piston chamber  406  and an exterior of the completion sleeve  114 . Any fluid interposing the piston head  418  and the seal ring  422  with the piston chamber  406  can escape the piston chamber  406  via the vent  428  as the piston head  418  advances toward the seal ring  422 . The vent  428  may also prove useful when the piston head  418  advances away from the seal ring  422  and a fluid may be drawn into the piston chamber  406  via the vent  428  to also prevent or mitigate hydraulic lock. This might be accomplished through the use of one or more of a check valve, a return control line, an accumulator, or any combination thereof positioned within or in fluid communication with the vent  428 . 
     With the deflector  308  in the deployed position, downhole tools introduced into the completion sleeve  114  may be deflected laterally out of the completion sleeve  114  through the window  120  by engaging the deflector surface  416 . The deflector surface  416  may have any suitable dimensions to achieve a particular deflected distance or angle. If desired, the deflector  308  may be configured to assist in retaining a downhole tool in position relative to the deflector assembly  306  when it is engaged with the deflector surface  416 . For example, the deflector surface  416  may be trough-shaped, concave, or curved to assist in preventing the downhole tool from rolling off the deflector assembly  306 . 
     In some embodiments, as depicted in  FIG. 4B , when the deflector  308  is in the deployed position, the deflector surface  416  may extend generally parallel to a ramp surface  430  defined by the window  120 . Consequently, downhole tools engaging and riding up the ramp surface  430  may transition to the ramp surface  430  to exit the window  120 . In other embodiments, however, the deflector  308  may be positioned at other locations within the completion sleeve  114  and not necessarily at the downhole end of the window  120 . Rather, the deflector  308  may be positioned at any location between the uphole and downhole ends of the window  120  as long as the deflector  308  is able to suitably deflect downhole tools out of the window  120 . In such embodiments, the actuator  310  may be positioned adjacent the deflector  308  or at a location away from the deflector  308 . 
     When it is desired to move the deflector  308  back to the stowed position, a second control signal may be communicated to the actuator  310  via the communications line  314 . In at least one embodiment, the hydraulic fluid used to move the piston  404  may be drawn out of the piston chamber  406  via the communications line  314  to urge the piston  404  back toward the actuator  310 , and correspondingly move the deflector  308  to the stowed position as the pin  410  traverses the slot  412 . h1 other embodiments, the communications line  314  may include two hydraulic lines, one hydraulic line to actuate the deflector  308  to the deployed position and a second hydraulic line (e.g., coupled to the vent  428 ) to move the deflector  308  back to the stowed position. 
     The deflector assembly  306  may further include one or more sensors used to monitor the position of the deflector  308  during operation and report the same to the control module  402 . In some embodiments, for example, the deflector assembly  306  may include a first position sensor  432   a  and a second position sensor  432   b  that may cooperatively track the position of the piston  404  within the piston chamber  306 , and thereby determine the position of the deflector  308 . The position sensors  432   a,b  may be positioned at or near the start and end of the stroke length of the piston  404 , for example, and configured to detect the proximity of the piston head  418 . In such embodiments, the position sensors  432   a,b  may comprise magnetic sensors, or any other type of proximity sensor able to detect the presence or non-presence of the piston head  418 . When the first position sensor  432   a  detects proximity of the piston head  418 , that may be an indication that the piston  404  is un-stroked and the deflector  308  is, therefore, in the stowed position. However, when the second position sensor  432   b  detects proximity of the piston head  418 , that may be an indication that the piston  404  is fully stroked and the deflector  308  is, therefore, in the deployed position. 
     In another embodiment, a third position sensor  432   c  may be arranged in or adjacent the pocket  312  and configured to monitor the proximity of the deflector  308 . When the third position sensor  432   c  detects proximity of the deflector  308 , that may be indicative that the deflector  308  is in the stowed position. h1 contrast, when the third position sensor  432   c  fails to detect proximity of the deflector  308 , that may be indicative that the deflector  308  is in the deployed position. 
     The position sensors  432   a - c  may each be communicably coupled (either wired or wirelessly) to the control module  402  to enable transfer of data to/from the control module  402 . The control module  402  may then either store the data or transmit the real-time position of the deflector  308  to the surface location via the communications line  314 . While only three position sensors  432   a - c  are depicted in  FIGS. 4A-4B  in specific arrangements (positions), it should be noted that the position sensors  432   a - c  might be positioned at any location in the deflector assembly  306  suitable to monitor the position of the deflector  308 , without departing from the scope of the disclosure. Moreover, the position feedback obtained by the position sensors  432   a - c  may be electrical, hydraulic, optical, digital, analog, pulse-width modulation, electro-magnetic, sonic, or any combination thereof. 
       FIG. 5  is an enlarged cross-sectional side view of another embodiment of the deflector assembly  306  and the completion sleeve  114 , according to one or more additional embodiments. During use of the deflector assembly  306  and/or over extended periods of time, the deflector  308  may become stuck or otherwise fixed in the deployed position. This may result from several causes, such as failure of the actuator  310  and/or the communications line  314 , debris  502  accumulating in the pocket  312  and thereby preventing the deflector  308  from returning to the stowed position, or a combination of both. To ensure that the deflector  308  can be properly returned to the stowed position when desired, the completion sleeve  114  and/or the deflector assembly  306  may further include and otherwise incorporate one or more fail-safe methods or mechanisms. 
     In the event the deflector  308  becomes stuck or fixed in the deployed position, for whatever reason, a downhole tool  504  may be conveyed to the completion sleeve  114  to help move the deflector  308  back to the stowed position. In some embodiments, the downhole tool  504  may be run downhole on wireline or slickline and include jarring tool (not shown). Upon engaging the deflector  308  and, more particularly, the deflector surface  416 , the jarring tool may be actuated and thereby apply axial impulse loads against the deflector surface  416  in the downhole direction (i.e., to the right in  FIG. 5 ). In other embodiments, the downhole tool  504  may be conveyed downhole on coiled tubing, production tubing, or another rigid or semi-rigid conveyance. Upon engaging the deflector  308 , an axial load may be applied to the deflector  308  from the surface location via the downhole tool. The axial loading assumed by the deflector  308  in either embodiment will be transferred to the piston  404 , which forces the piston  404  toward the actuator  310  and correspondingly moves the deflector  308  back into the pocket  312  and to the stowed position. 
     In embodiments where the actuator  310  is a hydraulic actuator, as described above, the deflector assembly  306  may further include a pressure relief valve  506  positioned within the sidewall  304  and fluidly coupled to a pressure relief conduit  508  that extends between the piston chamber  406  and an exterior of the completion sleeve  114 . As the piston  404  is forced back toward the actuator  310 , as described above, hydraulic fluid present in the piston chamber  406  will act on the pressure relief valve  506 . Upon assuming a predetermined hydraulic loading, the pressure relief valve  506  will fail and the trapped hydraulic fluid may escape out of the piston chamber  406  via the pressure relief conduit  508 , which allows the piston  404  to move back to its un-stroked position and correspondingly move the deflector  308  back to the stowed position. In some embodiments, the pressure relief valve  506  will reset automatically for subsequent use, if needed. 
     In some applications, debris  502  accumulated in the pocket  312  may prevent the deflector  308  from moving to the stowed position. In such applications, the downhole tool  504  may include a bullnose  510  that provides one or more jetting ports  512  (one shown) used to eject a fluid  514  at a high pressure. As the bullnose  510  approaches the deflector  308 , the fluid  514  may be discharged from the jetting port(s)  512  to flush the pocket  312  and thereby remove the debris  502  so that the deflector  308  may be seated again within the pocket  312 . 
       FIGS. 6A and 6B  are enlarged cross-sectional side views of another embodiment of the deflector assembly  306  and the completion sleeve  114 , according to one or more additional embodiments. In some embodiments, the deflector assembly  306  may further include one or more devices or mechanisms that aid in moving the deflector  308  either to the deployed position, as shown in  FIG. 6B , or to the stowed position, as shown in  FIG. 6A . More specifically, the deflector assembly  306  may include a first biasing device  602   a  positioned within the piston chamber  406  and interposing the piston  404  and the actuator  310 . The first biasing device  602   a  may comprise a spring, for example, but could alternatively comprise any other type of biasing mechanism. In some embodiments, the first biasing device  602   a  may comprise a compression spring. In such embodiments, the first biasing device  602   a  may be configured to help move the deflector  308  to the deployed position as it acts on the piston  404 . In other embodiments, however, the first biasing device  602   a  may comprise a coil spring configured to help move the deflector  308  to the stowed position as it pulls on the piston  404  back toward the actuator  310 . 
     Alternatively, or in addition to the first biasing device  602   a , the deflector assembly  306  may include a second biasing device  602   b  positioned within the pocket  312  and generally interposing the deflector  308  and the inner wall of the pocket  312 . As illustrated, the second biasing device  602   b  may be received within a cavity  604  defined in the inner wall of the pocket  312  when fully compressed. Similar to the first biasing device  602   a , the second biasing device  602   b  may comprise a spring, such as a compression spring. In such embodiments, the second biasing device  602   b  may be configured to help move the deflector  308  to the deployed position as it acts on the underside of the deflector  308 . In other embodiments, however, the second biasing device  602   b  may comprise a coil spring that helps pull the deflector  308  back into the pocket  312  and to the stowed position. 
     In some embodiments, the deflector assembly  306  may further include one or more locking mechanisms  606  (one shown) configured to help permanently or temporarily lock the deflector  308  in the deployed position. In the illustrated embodiment, the locking mechanism  606  comprises a ball  608  and detent  610  mechanism, where the detent  610  is spring-loaded. In such embodiments, as the piston  404  strokes past the locking mechanism  606 , the piston head  418  will engage and force the ball  608  into the detent  610 , which allows the piston head  418  to bypass the locking mechanism  606 . Once past the locking mechanism  606 , the spring-loaded detent  610  will force the bail  608  outward again and out of the detent  610 . With the ball  608  extending at least partially out of the detent  610 , the piston head  418  will be prevented from moving back toward the actuator  310 , thereby temporarily locking the piston  404  in place and correspondingly holding the deflector  308  in the deployed position. The piston  404  may again bypass the locking mechanism  606  upon actuation of the actuator  310  to move the deflector  308  back to the stowed position. 
     While the detent  610  is depicted in  FIGS. 6A-6B  as being defined in the sidewall  304  of the completion sleeve  114 , the detent  610  could alternatively be provided on the piston  404 , without departing from the scope of the disclosure. In other embodiments, two or more detents  610  may be provided either in the sidewall  304  of the completion sleeve  114  or on the piston  404  to provide a temporary lock at a corresponding two or more positions. 
     While the locking mechanism  606  is shown in  FIGS. 6A-6B  as a bail  608  and detent  610  mechanism, the locking mechanism  606  may alternatively comprise a variety of other devices located in a variety of other locations, without departing from the scope of the disclosure. In other embodiments, for instance, the locking mechanism  606  may comprise a snap ring with beveled uphole and downhole edges, where the snap ring is forced to radially contract upon engagement with the piston head  418 . Alternatively, the locking mechanism  606  may be positioned at other locations within the completion sleeve  114  and still serve to permanently or temporarily lock the deflector  308  in the deployed position. 
       FIGS. 7A and 7B  are enlarged cross-sectional side views of another embodiment of the deflector assembly  306  and the completion sleeve  114 , according to one or more additional embodiments. In some embodiments, operation of the actuator  310  may be triggered upon receipt of a wireless signal. In the illustrated embodiment, for example, a downhole tool  702  is conveyed to the completion sleeve  114  and used to transmit a wireless signal that actuates the actuator  310  and thereby moves the deflector  308  from the stowed position, as shown in  FIG. 7A , to the deployed position, as shown in  FIG. 7B . 
     A bullnose  704  may be positioned at the distal end of the downhole tool  702  and a wireless transmitter  706  be installed in the bullnose  704 . The wireless transmitter  706  may be configured to emit a wireless signal  708  receivable by the control module  402  and, more particularly, by one or more receivers (not shown) included in the control module  402 . The receiver(s) may be configured to sense the wireless signal  708  as the downhole tool  702  approaches the deflector  308 , which triggers actuation of the actuator  310  and deployment of the deflector  308  to the deployed position. As shown in  FIG. 7B , the downhole tool  702  may advance out of the completion sleeve  114  via the window  120  with the deflector  308  in the deployed position. Upon retracting the downhole tool  702  following completion of the desired downhole operations, the wireless transmitter  706  may again emit the wireless signal  708  to be received by the control module  402 , which triggers actuation of the actuator  310  to return the deflector  308  to the stowed position. 
     In some embodiments, the receiver(s) included in the control module  402  may comprise radio frequency (RF) sensors and the wireless transmitter  706  may comprise a radio frequency identification (RFID) tag that emits an RFID wireless signal  708 . In at least one embodiment, the receiver(s) may comprise micro-electromechanical systems (MEMS) or devices capable of sensing radio frequencies. In such cases, the MEMS sensors may include or otherwise encompass an RF coil and thereby be used as the receiver(s). The receiver(s) may alternatively comprise a near field communication (NFC) sensor capable of establishing radio communication with a corresponding dummy tag arranged on the bullnose  704 . Each NFC sensor may operate in either passive mode, where the initiator device provides a carrier field and the target device answers by modulating the existing field, or in active mode, where both initiator and target devices communicate by alternately generating their own fields. When the dummy tags come into proximity of the receiver(s), the receiver(s) may register the presence of the downhole tool  702 . In yet other embodiments, other signal methods may be used, such as magnetics or mechanical sensor(s), without departing from the scope of the disclosure. It will be appreciated that the receiver(s) included in the control module  402  and the transmitter  706  of the bullnose  704  may each comprise transceivers capable of both transmission and reception of signals, without departing from the scope of the disclosure. 
     The above described embodiments of remotely actuating the actuator  310  or wirelessly actuating the actuator  310  using the downhole tool  702  may prove advantageous in multilateral wells having more than one lateral wellbore (e.g., the lateral wellbore  104  of  FIG. 1 ). In such multilateral wells, separate and independent completion assemblies  114  may be installed at each lateral wellbore and a downhole tool may be run into each lateral wellbore without requiring installation and removal of a separate tubing exit whipstock (TEW) at each junction. Rather, the deflector  308  at the upper lateral wellbore may be moved to the deployed position to allow the downhole tool to enter the upper lateral wellbore. After work in the upper lateral wellbore has been completed, the downhole tool can be pulled back into the parent wellbore (e.g., the parent wellbore  102  of  FIG. 1 ) above the upper completion assembly and the deflector  308  may then be moved back to the stowed position. The downhole tool may then be advanced downhole through the upper completion sleeve and to the lower completion sleeve where the deflector  308  of the lower completion sleeve is actuated to the deployed position to allow the downhole tool to enter the lower lateral wellbore. Following operations in the lower lateral wellbore, the downhole tool may be retracted back into the parent wellbore, and the deflector may be actuated to the stowed position to allow the downhole tool to advance even further downhole within the parent wellbore, if desired, to perform additional operations on other branches or lateral wellbores. 
     In some embodiments, the deflector  308  of any of the completion sleeves  114  described herein may be actuated mechanically as opposed to a remote actuation or a wireless signal actuation propagated through the communications line  314 .  FIGS. 8A and 8B , for example, are cross-sectional side views of upper and lower portions of the completion sleeve  114 , according to one or more additional embodiments. To enable viewing of the component parts of the embodiment, the cross-sectional view of  FIGS. 8A and 8B  is 90° offset from the cross-sectional views of  FIGS. 3A-3B, 4A-4B, 5, 6A-6B, and 7A-7B  Accordingly, the deflector assembly  306 , including the deflector  308  and the actuator  310 , is shown in plan view. 
     In the illustrated embodiment, the completion sleeve  114  may further include a shifting sleeve  802  movably positioned within the cylindrical body  118  ( FIGS. 3A-3B ) or, alternatively, within a top sub  804  coupled to the body  118 . In either case, the shifting sleeve  802  will be movably positioned within or otherwise in communication with the inner passage  302  ( FIGS. 3A-3B ) of the completion sleeve  114 . The shifting sleeve  802  includes a first or upper profile  806   a  and a second or lower profile  806   b , and the first and second profiles  806   a,b  are configured to receive and otherwise mate with a corresponding shifting tool profile  808  provided on a shifting tool  810  (shown in dashed lines). The shifting tool profile  808  may comprise, for example, one or more spring loaded keys, lugs, or dogs that exhibit a unique shape or design configured to locate and mate with the first and second profiles  804   a,b . The shifting tool profile  808  may be configured to mate with the first (upper) profile  806   a  when moving in the downhole direction (i.e., to the right in  FIG. 8 ), and configured to mate with the second (lower) profile  804   b  when moving in the uphole direction (i.e., to the left in  FIG. 8 ). Alternatively, the shifting tool profile  808  may be configured to mate with the second (lower) profile  806   b  when moving in the downhole direction mate with the first (upper) profile  804   a  when moving in the downhole direction, without departing from the scope of the disclosure. 
     In  FIG. 8A , the shifting tool  810  may be conveyed downhole to mechanically actuate the deflector  308  from the stowed to deployed positions. More specifically, as the shifting tool  810  is conveyed downhole, the shifting tool profile  808  will locate and mate with the first profile  806   a . Once the shifting tool profile  808  mates with the first profile  806   a , an axial load may be applied to the shifting tool  810  in the downhole direction to correspondingly move the shifting sleeve  802  in the same direction from a first position, as shown in  FIG. 8A , to a second position, as shown in  FIG. 8B . 
     In some embodiments, the shifting sleeve  802  may include a first or upper releasable coupling  811   a  and a second or lower releasable coupling  811   b . In the illustrated embodiment, the first and second releasable couplings  811   a,b  are depicted as collet assemblies configured to mate with corresponding collet profiles  813   a,b  defined on the inner radial surface of the upper sub  804 . In other embodiments, however, the first and second releasable couplings  811   a,b  may comprise other devices or mechanisms configured to releasably secure the shifting sleeve  802  within the upper sub  804  in the first and second positions. The axial load applied to the shifting tool  810  in the downhole direction may be sufficient to overcome the coupling engagement of the first releasable coupling  811   a  and thereby release the shifting sleeve  802  from the upper sub  804 . 
     As the shifting sleeve  802  is moved to the second position and the second releasable coupling  811   b . engages the lower collet profile  813   b , hydraulic fluid within a first hydraulic chamber  812   a  defined in the upper sub  804  (or alternatively the body  118  of  FIGS. 3A-3B ) will be forced into a first control line  814   a  communicably coupled to the actuator  310 . Additional hydraulic fluid will be conveyed into a second hydraulic chamber  812   b  defined in the upper sub  804  (or alternatively the body  118 ) via a second control line  814   b  to prevent hydraulic lock of the shifting sleeve  802 . As illustrated, the second control line  814   b  may be communicably coupled to the piston chamber  406  between the hydraulic seal ring  422  and the piston head  418 . Moreover, the first and second hydraulic chambers  812   a,b  are isolated from one another. 
     In some embodiments, the hydraulic fluid conveyed to the actuator  310  via the first control line  814   a  is used to act on the piston head  418  of the piston  408  and thereby urge the piston  408  to move within piston chamber  406  and force the deflector  308  to pivot out of the pocket  312  to the deployed position, as generally described above. In other embodiments, however, the hydraulic fluid conveyed to the actuator  310  via the first control line  814   a  may constitute a signal used to activate electrical actuation of the actuator  310  and thereby similarly deploy the deflector  308 . In such embodiments, the actuator  310  may comprise an electro-hydraulic valve used to actuate the deflector  308 . 
     Once the deflector  308  is deployed, continued axial load on the shifting tool  810  in the downhole direction will allow the shifting tool profile  808  to snap out of engagement with the first profile  806   a , thereby freeing the shifting tool  810  from the shifting sleeve  802 . Once free from the shifting sleeve  802 , the shifting tool  810  may advance downhole to be deflected into the lateral wellbore  104  ( FIG. 1 ) via the deployed deflector  308  and the window  120  ( FIGS. 3A-3B ) Various wellbore operations may then be undertaken in the lateral wellbore  104  before retracting the shifting tool  810  back into the parent well bore  102  ( FIG. 1 ) to re-engage the shifting sleeve  802  and mechanically actuate the deflector  308  from the deployed position back to the stowed position. 
     In  FIG. 8B , the shifting sleeve  802  is shown in the second or downhole position, the deflector  308  is shown in the deployed position, and the shifting tool  810  is shown engaged with the shifting sleeve  802  at the second (lower) profile  806   b . As the shifting tool  810  is retracted back into the parent wellbore  102  ( FIG. 1 ), the shifting tool profile  808  will eventually locate and mate with the second profile  806   b . Once the shifting tool profile  808  mates with the second profile  806   b , an axial load may be applied to the shifting tool  810  in the uphole direction (i.e., to the left in  FIG. 8B ) to correspondingly move the shifting sleeve  802  in the same direction back to the first position. The axial load applied to the shifting tool  810  in the uphole direction may be sufficient to overcome the coupling engagement of the second releasable coupling  811   b  and thereby release the shifting sleeve  802  from the upper sub  804 . 
     As the shifting sleeve  802  is moved back to the first position, the hydraulic fluid within the second hydraulic chamber  812   b  will be forced into the piston chamber  406  via the second control line  814   b  and correspondingly act on the piston head  418  to urge the piston  408  to move back to its initial position and thereby pivot the deflector  308  back to the stowed position. In other embodiments, however, the hydraulic fluid may be conveyed to the actuator  310  via the second control line  814   a  and constitute a signal used to activate electrical actuation of the actuator  310  and thereby similarly deploy the deflector  308 . 
     Once the shifting sleeve  802  is moved back to the first position and the deflector  308  is stowed, continued axial load on the shifting tool  810  in the uphole direction will allow the shifting tool profile  808  to snap out of engagement with the second profile  806   b , thereby freeing the shifting tool  810  from the shifting sleeve  802 . Once free from the shifting sleeve  802 , the shifting tool  810  may be returned to the surface location. 
     Shifting tools having a profile that does not match the first or second profiles  806   a,b  will bypass or “snap through” the shifting sleeve  802  without actuating the deflector In such cases, the shifting tool may advance further downhole to interact, for example, with another reentry window assembly. 
     As will be appreciated, the embodiment shown in  FIGS. 8A-8B  may be used independently or in conjunction with any of the embodiments described herein, such as a system that can be operated and/or powered from the surface. In such embodiments, one system can act as a backup to the second system or provide the well operator the option of having two ways (means) to actuate the deflector  308  between the stowed and deployed position. In at least one embodiment, the embodiment shown in  FIGS. 8A-8B  may also include RFID) and/or wireless means, as described herein, to enable a third actuation option. In such embodiments, the deflector  308  could alternatively be activated by a transceiver mounted in the nose of the shifting tool  810 . 
     While two control lines  814   a,b  are shown in  FIGS. 8A-8B , more or less control lines may be used without departing from the scope of the disclosure. Moreover, other types of control lines may be included in the embodiment to transmit power, control signals, data, etc. to the completion sleeve  114 , the actuator  310 , tools in the lateral wellbore  104  ( FIG. 1 ), and tools positioned downhole from the completion sleeve  114 . 
     Embodiments disclosed herein include: 
     A. A completion sleeve that includes a body that defines an inner passage and a window that provides a lateral exit from the inner passage, a deflector positioned within the inner passage and pivotable between a stowed position, where the deflector is received within a pocket defined in a sidewall of the body, and a deployed position to deflect downhole tools laterally through the window, and an actuator positioned within the sidewall and operatively coupled to the deflector, the actuator being actuatable to move the deflector between the stowed and deployed positions. 
     B. A well system that includes a parent wellbore lined with casing that defines a casing exit, a lateral wellbore extending from the casing exit, a completion sleeve installed within the parent wellbore and defining an inner passage and a window that provides a lateral exit from the inner passage, and a deflector assembly positioned within the inner passage and including a deflector pivotable between a stowed position, where the deflector is received within a pocket defined in a sidewall of the completion sleeve, and a deployed position to deflect a downhole tool laterally through the window, and an actuator positioned within the sidewall and operatively coupled to the deflector, the actuator being actuatable to move the deflector between the stowed and deployed positions. 
     C. A method that includes advancing a downhole tool into a parent wellbore lined with casing that defines a casing exit and has a lateral wellbore extending from the casing exit, extending the downhole tool into a completion sleeve installed within the parent wellbore and defining an inner passage and a window aligned with the casing exit, actuating an actuator operatively coupled to a deflector and thereby moving the deflector from a stowed position, where the deflector is received within a pocket defined in a sidewall of the completion sleeve, and to a deployed position, and deflecting the downhole tool into the lateral wellbore with the deflector. 
     Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element J: wherein the deflector in the stowed position allows full-bore access through the inner passage. Element 2: wherein the actuator comprises an actuation device selected from the group consisting of a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, and any combination thereof. Element 3: wherein the actuator is a hydraulic actuator including a piston operatively coupled to the deflector, and wherein actuating the actuator moves the piston within a piston chamber and correspondingly moves the deflector between the stowed and deployed positions. Element 4: wherein the piston includes a pin received within a slot defined in the deflector and moving the piston within the piston chamber correspondingly moves the pin within the slot to pivot the deflector between the stowed and deployed positions. Element 5: further comprising a biasing device positioned in the piston chamber and interposing the piston and the actuator. Element 6: further comprising one or more sensors coupled to the body to detect a position of the deflector. Element 7: further comprising a biasing device positioned within the pocket and coupled to an underside of the deflector. Element 8: further comprising a locking mechanism secured to the body to lock the deflector in the deployed position. 
     Element 9: wherein the actuator comprises an actuation device selected from the group consisting of a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, and any combination thereof. Element 10: further comprising a communications line extended from a well surface location and communicably coupled to the actuator to remotely actuate the actuator. Element 11: wherein the communications line is communicably coupled to a control module of the actuator and the deflector assembly further includes one or more sensors coupled to the body and communicably coupled to the control module, the one or more sensors being configured to detect a position of the deflector. Element 12: wherein the downhole tool includes a wireless transmitter that emits a wireless signal receivable by the actuator to actuate the actuator. Element 13: further comprising a shifting sleeve movably positioned within the inner passage and providing first profile and a second profile, and a shifting tool conveyable into the completion sleeve and providing a shifting tool profile matable with the first and second profiles, wherein mating the shifting tool profile with the first profile and providing an axial load in a first direction results in a first hydraulic signal that actuates the actuator to move the deflector to the deployed position, and wherein mating the shifting tool profile with the second profile and providing an axial load in a second direction opposite the first direction results in a second hydraulic signal that actuates the actuator to move the deflector to the stowed position. 
     Element 14: wherein actuating the actuator comprises transmitting a control signal to the actuator via a communications line extended from a well surface location and communicably coupled to the actuator Element 15. wherein actuating the actuator comprises emitting a wireless signal from a wireless transmitter included in the downhole tool and receiving the wireless signal with the actuator to actuate the actuator. Element 16: further comprising applying an axial load to the deflector with the downhole tool to move the deflector back to the stowed position. Element 17: further comprising ejecting a fluid out of the downhole tool to clear debris accumulated in the pocket. Element 18: further comprising actuating the actuator to move the actuator back to the stowed position. Element 19: wherein the downhole tool comprises a shifting tool that provides a shifting tool profile, wherein advancing the downhole tool into the parent wellbore further comprises locating and mating the shifting tool profile on a first profile of a shifting sleeve movably positioned within the inner passage, applying an axial load on the shifting sleeve in a first direction via the shifting tool and thereby providing a first hydraulic signal that actuates the actuator to move the deflector to the deployed position, locating and mating the shifting tool profile on a second profile of the shifting sleeve, and applying an axial load on the shifting sleeve in a second direction opposite the first direction via the shifting tool and thereby providing a second hydraulic signal that actuates the actuator to move the deflector to the stowed position. 
     By way of non-limiting example, exemplary combinations applicable to A, B, and C include: Element 3 with Element 4; Element 3 with Element 5; and Element 10 with Element 11. 
     Therefore, the disclosed systems and methods are 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 teachings of the present disclosure 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 of the present disclosure. The systems and methods illustratively disclosed herein may suitably 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. AU 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 elements 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. 
     As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By, way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.