Patent Publication Number: US-8978775-B2

Title: Downhole valve assembly and methods of using the same

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED 
     Not applicable. 
     RESEARCH OR DEVELOPMENT 
     Not applicable. 
     REFERENCE TO A MICROFICHE APPENDIX 
     Not applicable. 
     BACKGROUND 
     Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, during which a servicing fluid such as a fracturing fluid or a perforating fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Such a subterranean formation stimulation treatment may increase hydrocarbon production from the well. 
     A work string (e.g., tool string, coiled tubing string, and/or segmented tool string) is often used to communicate fluid to and from the subterranean formation, for example, during a wellbore stimulation (e.g., a hydraulic fracturing) operation. For example, jointed tubing may be used to form at least a portion of the work string. Additionally or alternatively, coiled tubing may also be used to form at least a portion of the work string. 
     Sometimes, during the performance of a wellbore servicing operation, it may be desirable to fluidicly isolate two or more sections of the work string (e.g. between a coiled tubing string and a jointed tubing string), for example, so as to close off fluid communication through the work string flowbore in at least one direction. For example, closing off fluid communication through a work string flowbore may allow, as an example, for the isolation of well pressure within the work string flowbore during run-in and/or run-out of a work string (e.g., facilitating connection and/or disconnection of one or more work string sections, such as a jointed tubing section and a coiled tubing section, two or more sections of jointed tubing, or combinations thereof). As such, there is a need for apparatuses, system, and methods of selectively allowing and/or preventing fluid communication through the flowbore of a workstring during the performance of a wellbore servicing operation. 
     SUMMARY 
     Disclosed herein is a wellbore servicing system comprising a work string, and an actuatable valve tool defining an axial flowbore and incorporated within the work string, wherein the actuatable valve tool is transitionable from a first mode to a second mode, from the second mode to a third mode, and from the third mode to a fourth mode, wherein the actuatable valve tool is configured to transition from the first mode to the second mode upon an application of pressure to the axial flowbore of at least a threshold pressure, wherein the actuatable valve tool is configured to transition from the second mode to the third mode upon a dissipation of pressure from the axial flowbore to not more than the threshold pressure, wherein, in the first mode, the actuatable valve tool is configured to allow fluid communication via the axial flowbore in a first direction and to disallow fluid communication via the axial flowbore in a second direction, and wherein, in the second, and third modes, the actuatable valve tool is configured to allow fluid communication via the axial flowbore in both the first direction and the second direction. 
     Also disclosed herein is a wellbore servicing method comprising disposing a wellbore servicing system comprising an actuatable valve tool in a wellbore, the actuatable valve tool generally defining an axial flowbore, wherein the actuatable valve tool is configured in a first mode, wherein in the first mode, the actuatable valve tool allows downward fluid communication via the axial flowbore and disallows upward fluid communication via the axial flowbore, making a first application of fluid pressure of at least a pressure threshold to the axial flowbore, wherein the first application of fluid pressure transitions the actuatable valve tool to a second mode in which the actuatable valve tool allows both upward and downward fluid communication, allowing a first dissipation of fluid pressure applied to the axial flowbore to less than the pressure threshold, wherein allowing the first dissipation of fluid pressure transitions the actuatable valve tool to a third mode in which the actuatable valve tool allows both upward and downward fluid communication, making a second application of fluid pressure of at least the pressure threshold to the axial flowbore, wherein the second application of fluid pressure transitions the actuatable valve tool to a fourth mode in which the actuatable valve tool allows both upward and downward fluid communication, allowing a second dissipation of fluid pressure applied to the axial flowbore to less than the pressure threshold, wherein allowing the fluid pressure applied to the axial flowbore to dissipate transitions the actuatable valve tool to the first mode. 
     Further disclosed herein is a wellbore servicing method comprising disposing a wellbore servicing system in a wellbore, the wellbore servicing system comprising a actuatable valve tool generally defining an axial flowbore, wherein during disposing the wellbore servicing system within the wellbore, the actuatable valve tool is configured so as to allow downward fluid communication via the axial flowbore and to disallow upward fluid communication via the axial flowbore, reconfiguring the actuatable valve tool so as to allow downward and upward fluid communication via the axial flowbore, wherein reconfiguring the actuatable valve tool comprises applying a fluid pressure of at least a pressure threshold to the axial flowbore, allowing a fluid pressure applied to the axial flowbore to dissipate to less than the pressure threshold, or combinations thereof, reconfiguring the actuatable valve tool so as to allow downward fluid communication via the axial flowbore and to disallow upward fluid communication via the axial flowbore, wherein reconfiguring the actuatable valve tool comprises applying a fluid pressure of at least a pressure threshold to the axial flowbore, allowing a fluid pressure applied to the axial flowbore to dissipate to less than the pressure threshold, or combinations thereof, and repositioning the wellbore servicing system. 
     Further disclosed herein is an actuatable valve tool comprising a housing defining the axial flowbore, a flapper valve, wherein, when the flapper valve is in an activated state, the flapper valve is free to move between a closed position in which the flapper valve blocks the axial flowbore and an open position in which the flapper valve does not block the axial flowbore, and wherein, when the flapper valve is in an inactivated state, the flapper valve is retained in the open position, a sliding sleeve, wherein, in a first position, the sliding sleeve does not interact with the flapper valve, and wherein, in a second position and a third position, the sliding sleeve retains the flapper valve in the open position, and a transition system configured to control the longitudinal movement of the sliding sleeve, wherein the transition system comprises a j-slot, and a lug, wherein the lug is disposed within a least a portion of the j-slot. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description: 
         FIG. 1  is a partial cutaway view of an embodiment of an operating environment associated with an actuatable valve tool; 
         FIG. 2A  is a cutaway view an embodiment of an actuatable valve tool in a first mode or configuration; 
         FIG. 2B  is a cutaway view an embodiment of an actuatable valve tool in a second mode or configuration; 
         FIG. 2C  is a cutaway view an embodiment of an actuatable valve tool in a third mode or configuration; 
         FIG. 2D  is a cutaway view an embodiment of an actuatable valve tool in a fourth mode or configuration; and 
         FIG. 3  is a side view of an embodiment of a sleeve having a J-slot associated therewith. 
     
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
     In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. In addition, similar reference numerals may refer to similar components in different embodiments disclosed herein. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is not intended to limit the invention to the embodiments illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results. 
     Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. 
     Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “up-hole,” “upstream,” or other like terms shall be construed as generally from the formation toward the surface or toward the surface of a body of water; likewise, use of “down,” “lower,” “downward,” “down-hole,” “downstream,” or other like terms shall be construed as generally into the formation away from the surface or away from the surface of a body of water, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. 
     Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water. 
     Disclosed herein are embodiments of wellbore servicing apparatuses, systems and methods of using the same. Particularly disclosed herein are one or more embodiments of an actuatable valve tool (AVT), systems, and methods utilizing the same. In one or more of the embodiments as will be disclosed herein, the AVT may be generally configured to transition through one or more configurations and/or phases so as to selectively allow and/or disallow fluid communication through a tubular string (e.g., a work string) in one or both directions, for example, during the performance of a wellbore servicing operation (e.g., a subterranean formation stimulation operation). 
     Referring to  FIG. 1 , an embodiment of an operating environment in which such an AVT and/or a wellbore servicing system comprising such an AVT may be employed is illustrated. As depicted in  FIG. 1 , the operating environment generally comprises a wellbore  114  that penetrates a subterranean formation  102  for the purpose of recovering hydrocarbons, storing hydrocarbons, disposing of carbon dioxide, or the like. The wellbore  114  may be drilled into the subterranean formation  102  using any suitable drilling technique. In an embodiment, a drilling or servicing rig  106  disposed at the surface  104  comprises a derrick  108  with a rig floor  110  through which a work string (e.g., a drill string, a tool string, a segmented tubing string, a jointed tubing string, or any other suitable conveyance, or combinations thereof) generally defining an axial flow bore  126  may be positioned within or partially within wellbore  114 . In an embodiment, such a work string may comprise two or more concentrically positioned strings of pipe or tubing (e.g., a first work string may be positioned within a second work string). The drilling or servicing rig may be conventional and may comprise a motor driven winch and other associated equipment for lowering the work string into wellbore  114 . Alternatively, a mobile workover rig, a wellbore servicing unit (e.g., coiled tubing units), or the like may be used to lower the work string into the wellbore  114 . In such an embodiment, the work string may be utilized in drilling, stimulating, completing, or otherwise servicing the wellbore, or combinations thereof. 
     The wellbore  114  may extend substantially vertically away from the earth&#39;s surface over a vertical wellbore portion, or may deviate at any angle from the earth&#39;s surface  104  over a deviated or horizontal wellbore portion  118 . In alternative operating environments, portions or substantially all of wellbore  114  may be vertical, deviated, horizontal, and/or curved and such wellbore may be cased, uncased, or combinations thereof. In some instances, at least a portion of the wellbore  114  may be lined with a casing  120  that is secured into position against the formation  102  in a conventional manner using cement  122 . In this embodiment, the deviated wellbore portion  118  includes casing  120 . However, in alternative operating environments, the wellbore  114  may be partially cased and cemented thereby resulting in a portion of the wellbore  114  being uncased. In an embodiment, a portion of wellbore  114  may remain uncemented, but may employ one or more packers (e.g., mechanical and/or swellable packers, such as Swellpackers™, commercially available from Halliburton Energy Services, Inc.) to isolate two or more adjacent portions or zones within wellbore  114 . It is noted that although some of the figures may exemplify a horizontal or vertical wellbore, the principles of the apparatuses, systems, and methods disclosed may be similarly applicable to horizontal wellbore configurations, conventional vertical wellbore configurations, and combinations thereof. Therefore, the horizontal or vertical nature of any figure is not to be construed as limiting the wellbore to any particular configuration. 
     Referring to  FIG. 1 , a wellbore servicing system  100  is illustrated. In the embodiment of  FIG. 1 , the wellbore servicing system  100  comprises an AVT  200  incorporated within a work string  112  and positioned within the wellbore  114 . Additionally, in an embodiment the wellbore servicing system  100  may further comprise a wellbore servicing tool  150 . In such an embodiment, the wellbore servicing tool  150  may be incorporated within the work string  112 , for example, at a position relatively downhole from the AVT  200 . Also, in such an embodiment, the work string  112  may be positioned within the wellbore  114  such that the wellbore servicing tool  150  is positioned proximate and/or substantially adjacent to one or more zones of the subterranean formation  102 . 
     The wellbore servicing tool  150  may be generally configured to deliver a wellbore servicing fluid to the wellbore  114 , the subterranean formation  102  and/or one or more zones thereof, for example, for the performance of one or more servicing operations. For example, the wellbore servicing tool  150  may generally comprise a stimulation tool (such as a fracturing, perforating tool, and/or acidizing tool), a drilling tool (such as a drill bit), a wellbore cleanout tool, or combinations thereof. While this disclosure may refer to a wellbore servicing tool  150  configured for a stimulation operation (e.g., a perforating and/or fracturing tool), as disclosed herein, a wellbore servicing tool incorporated with the wellbore servicing system may be configured for various additional or alternative operations and, as such, this disclosure should not be construed as limited to utilization in any particular wellbore servicing context unless so-designated. In an embodiment, the wellbore servicing tool  150  may be selectively actuatable, for example, being configured to provide or not provide a route of fluid communication from the wellbore servicing tool  150  to the wellbore  114 , the subterranean formation  102 , and/or a zone thereof. In such an embodiment, the wellbore servicing tool  150  may be configured for actuation via the application of fluid pressure to the wellbore servicing tool  150 , via the operation of a ball or dart, via the operation of a shifting tool (e.g., a wireline tool), or combinations thereof, as will be appreciated by one of skill in the art upon viewing this application. Although the embodiment of  FIG. 1  illustrates a single wellbore servicing tool  150  (e.g., being positioned substantially proximate or adjacent to a formation), one of skill in the art viewing this disclosure will appreciate that any suitable number of wellbore servicing tools may be similarly incorporated within a work string  112 , for example, 2, 3, 4, 5, 6, 7, 8, 9, 10, etc. wellbore servicing tools. 
     In the embodiment of  FIG. 1 , the work string  112  comprises at least one segment of jointed tubing  20  (e.g., a “joint”). For example, in the embodiment of  FIG. 1 , the jointed tubing  20  may be coupled to the AVT  200  and may comprise a portion of the work string  112  relatively downhole from the AVT  200 . Not intending to be bound by theory, the jointed tubing  20  may provide a relatively strong, reliable work string flowbore  126  at the location of the stimulation operation. For example, the wellbore servicing tool  150  may be incorporated within the jointed tubing  20  portion of the work string  112 . Additionally, in an embodiment, the wellbore servicing system  100  may further comprise at least one segment of coiled tubing  80 . For example, in the embodiment of  FIG. 1 , the coiled tubing  80  may be coupled to the AVT  200  and may comprise a portion of the work string  112  relatively uphole from the valve tool  200 . Not intending to be bound by theory, the coiled tubing  80  may allow for the work string  112  to be quickly and easily moved uphole or downhole within the wellbore  114  (e.g., to be quickly and easily “run-in” or “run-out” of the wellbore  114 ). While in the embodiment of  FIG. 1 , jointed tubing  20  is coupled to and located downhole from the AVT  200  and coiled tubing  80  is coupled to and located uphole from the valve tool  200 , in other embodiments, various suitable additional or alternative configurations may be similarly employed. For example, in alternative embodiments, jointed tubing  20  may be located uphole from the AVT  200  and/or coiled tubing  80  may be located downhole from the valve tool  200 . Furthermore, in yet another embodiment, the jointed tubing  20  or coiled tubing  80  may be located both uphole and downhole from the AVT  200  (e.g., comprising substantially all of the work string  112 ). 
     Additionally, although the embodiment of  FIG. 1  illustrates a wellbore servicing system  100  comprising the AVT  200  incorporated within a work string  112 , a similar wellbore servicing system may be similarly incorporated within any other suitable type of string (e.g., a drill string, a tool string, a segmented tubing string, a jointed tubing string, a casing string, a coiled-tubing string, or any other suitable conveyance, or combinations thereof), working environment, or configuration, as may be appropriate for a given servicing operation. Also, although the embodiment of  FIG. 1  illustrates a single AVT  200 , one of skill in the art viewing this disclosure will appreciate that any suitable number of AVTs, as will be disclosed herein, may be similarly incorporated within a work string  112 , for example, 2, 3, 4, 5, etc. AVTs. 
     In one or more of the embodiments disclosed herein, one or more AVTs  200  may be configured to be activated while disposed within a wellbore like wellbore  114 . In an embodiment, a valve tool  200  may be transitionable from a “first” mode or configuration to a “second” mode or configuration, from the “second” mode or configuration to a “third” mode or configuration, and from the “third” mode or configuration to a “fourth” mode or configuration. Further, in an embodiment, the AVT  200  may be configured so as to be transitionable from the “fourth mode or configuration back to the “first” mode or configuration. Further still, in an embodiment, the AVT  200  may be transitionable through such a sequence (e.g., first, second, third, then fourth mode) an unlimited number of iterations/cycles, as will be disclosed herein. 
     Referring to  FIG. 2A , an embodiment of an AVT  200  is illustrated in the first mode or configuration. In an embodiment, when the AVT  200  is in the first mode, also referred to as a run-in or installation mode, the AVT  200  may be configured so as to allow for fluid communication therethrough in a first direction (e.g., downward fluid communication) and to not allow fluid communication therethrough in a second direction (e.g., upward fluid communication), as will be described herein. In an embodiment, as will be disclosed herein, the AVT  200  may be configured to transition from the first mode to the second mode upon the application of a pressure of at least a threshold pressure to the AVT  200 . For example, the AVT  200  may be configured to transition from the first mode to the second mode upon experiencing a threshold pressure. In such an embodiment, the threshold pressure may be at least about 500 psi, alternatively, about 750 psi, alternatively, about 1,000 psi, alternatively, about 1,500 psi, alternatively, about 2,000 psi, alternatively, about 2,500 psi, alternatively, about 3,000 psi, alternatively, about 4,000 psi, alternatively, about 5,000 psi, alternatively, about 6,000 psi, alternatively, about 7,000 psi, alternatively, about 8,000 psi, alternatively, about 10,000 psi, alternatively, alternatively, about 12,000 psi, alternatively, about 14,000 psi, alternatively, about 16,000 psi, alternatively, about 18,000 psi, alternatively, about 20,000 psi, alternatively, any suitable pressure. As will be appreciated by one of skill in the art upon viewing this disclosure, the threshold pressure may depend upon various factors, for example, including, but not limited to, the type of wellbore servicing operation being implemented. In an additional or alternative embodiment, the AVT  200  may be configured to transition from the first mode to the second mode upon a fluid being communicated through the AVT  200  in a suitable direction and/or at a suitable rate. For example, the AVT  200  may be configured to transition from the first mode to the second mode upon the communication therethrough of a fluid, in a given direction, at a rate of at least a threshold fluid flow. In such an embodiment, the threshold fluid flow rate may be at least about 2 barrels per minute (BPM), alternatively, about 5 BPM, alternatively, about 10 BPM, alternatively, about 15 BPM, alternatively, about 20 BPM, alternatively, about 25 BPM, alternatively, about 30 BPM, alternatively, about 45 BPM, alternatively, about 60 BPM, alternatively, about 75 BPM, alternatively, about 90 BPM, alternatively, about 105 BPM, alternatively, about 120 BPM, alternatively, about 135 BPM, alternatively about 150 BPM, alternatively, any suitable flow rate. As will be appreciated by one of skill in the art upon viewing this disclosure the threshold flow rate may depend upon various factors including, but not limited to, the type of wellbore servicing operation being implemented. 
     Referring to  FIG. 2B , an embodiment of the AVT  200  is illustrated in the second mode or configuration. In an embodiment, when the AVT  200  is in the second mode, also referred to as the fully stroked mode, the AVT  200  may be configured so as to allow for fluid communication therethrough in the first direction (e.g., downward fluid communication), as will be described herein. In an embodiment, the AVT  200  may be configured so as to remain in the second mode for so long as a suitable pressure (e.g., a pressure of at least the threshold pressure) is applied to the AVT  200  and/or for so long as a suitable flow rate is maintained (e.g., a fluid flow rate of at least the threshold flow rate) through the AVT  200 . In an embodiment, as will also be disclosed herein, the AVT  200  may be configured to transition from the second mode to the third mode upon the dissipation of the pressure applied thereto to less than threshold pressure and/or upon the cessation of fluid communication therethrough at a rate of at least the threshold flow rate. For example, the AVT  200  may be configured to transition from the second mode to the third mode by reducing the pressure applied to the AVT  200  (e.g., to less than the threshold pressure) and/or by reducing the fluid flow rate through the AVT  200  (e.g., to a rate less than the threshold flow rate). 
     Referring to  FIG. 2C , an embodiment of the AVT  200  is illustrated in third mode or configuration. In an embodiment, when the AVT  200  is in the third mode, also referred to as the reverse circulation mode, the AVT  200  may be configured so as to allow for fluid communication therethrough in both the first direction (e.g., downward fluid communication) and in the second direction (e.g., upward fluid communication), as will be described herein. In an embodiment, the AVT  200  may be configured to remain in the third mode for so long as the pressure applied thereto is less than threshold pressure and/or for so long as the flow rate of fluid communication therethrough is less than the threshold flow rate. In an embodiment as will also be disclosed herein, the AVT  200  may be configured to transition from the third position to the fourth position upon the application of a pressure of at least the threshold pressure to the AVT  200  and/or upon a fluid being communicated through the AVT  200  in a given direction at a rate of at least the threshold fluid flow, for example, as similarly disclosed herein with reference to transitioning the AVT  200  from the first mode to the second mode. 
     Referring to  FIG. 2D , an embodiment of the AVT  200  is illustrated in the fourth mode or configuration. In an embodiment, the AVT  200  may be configured so as to allow for fluid communication therethrough in the first direction (e.g., downward fluid communication), as will be described herein. In an embodiment, the AVT  200  may be configured to remain in the fourth mode for so long as a suitable pressure (e.g., a pressure of at least the threshold pressure) is applied to the AVT  200  and/or for so long as a suitable flow rate is maintained (e.g., a fluid flow rate of at least the threshold flow rate) through the AVT  200 . Additionally, in an embodiment, as will be disclosed herein, the AVT  200  may be configured to transition from the fourth mode back to the first mode upon the dissipation of the pressure applied thereto to less than threshold pressure and/or upon the cessation of fluid communication therethrough at a rate of at least the threshold flow rate, for example, as disclosed herein with reference to transitioning the AVT from the second mode to the third mode. 
     Once the AVT  200  has been returned to the first mode, in an embodiment, as will be disclosed herein, the AVT  200  may be configured so as to again be transitioned (cycled) from the first mode to the fourth mode as disclosed herein. 
     Referring to  FIGS. 2A-2D , in an embodiment the AVT  200  generally comprises a housing  51 , a sleeve  55 , one or more valves (e.g., a first and second valves,  53   a  and  53   b , respectively; cumulatively and non-specifically, valves  53 ), a biasing member  57 , and a transition system  50 . The AVT  200  may be characterized as having a longitudinal axis  49 . Additionally, the AVT  200  may also be characterized as a continuation of the flowbore  126 . 
     While an embodiment of the AVT  200  is disclosed with respect to  FIGS. 2A-2D  and  3 , one of skill in the art upon viewing this disclosure, will recognize suitable alternative configurations. As such, while embodiments of an AVT may be disclosed with reference to a given configuration (e.g., AVT  200  as will be disclosed with respect to  FIGS. 2A-2D  and  3 ), this disclosure should not be construed as limited to such embodiments. 
     In an embodiment, the housing  51  may be characterized as a generally tubular body having a first terminal end  51   a  (e.g., an uphole end) and a second terminal end  51   b  (e.g., a downhole end). The housing  51  may also be characterized as generally defining a longitudinal, axial flowbore  52 . In an embodiment, the housing  51  may be configured for connection to and/or incorporation within a string, such as the work string  112 . For example, the housing  51  may comprise a suitable means of connection to the work string  112  (such as the jointed tubing  20  and/or the coiled tubing  80  as illustrated in  FIGS. 2A-2D ). For instance, in the embodiments illustrated in  FIGS. 2A-2D , the first terminal end  51   a  of the housing  51  may comprise internally and/or externally threaded surfaces  70  as may be suitably employed in making a threaded connection to the work string  112  (e.g., to a coiled tubing segment, such as coiled tubing segment  80 , for example, via a coiled tubing adapter  81 ). Also, in the embodiments illustrated in  FIGS. 2A-2D , the second terminal end  51   b  of the housing  51  may also comprise internally or externally threaded surfaces  70  as may be suitably employed in making a threaded connection to the work string  112  (e.g., to a segment of jointed tubing  20 ). Alternatively, an AVT like AVT  200  may be incorporated within a work string like work string  112  by any suitable connection, such as, for example, via one or more quick-connector type connections. Suitable connections to a work string member will be known to those of skill in the art viewing this disclosure. In an embodiment, the AVT  200  may be integrated and/or incorporated with the work string  112  such that the axial flowbore  52  may be in fluid communication with the axial flowbore  126  defined by work string  112 , for example, such that a fluid communicated via the axial flowbore  126  of the work string  112  will flow into and through the axial flowbore  52  of the AVT  200 . 
     In an embodiment, the one or more valves  53  may be generally configured, when activated, as will be disclosed herein, to close and/or seal the longitudinal bore  52  through the AVT  200  to fluid communication therethrough in at least one direction and to allow fluid communication in the opposite direction. In an embodiment, the one or more valves  53  may be characterized as one-way or unidirectional valve, that is, configured to allow fluid communication therethrough in only a single direction (e.g., when activated). For example, in an embodiment, the one or more valves  53  may comprise flapper valves. In such an embodiment, each of the activatable flapper valves may comprise a flap or disk movably (e.g., rotatably) secured within the housing  51  (e.g., directly or indirectly) via a hinge. For example, the flapper may be hinged to the housing  51 , alternatively, to a body which may be disposed within the housing  51 . In an embodiment, the flapper may be rotatable about the hinge from a first, closed position in which the flapper extends into the longitudinal bore  52  to a second, open position in which the flapper does not extend into the longitudinal bore  52 . In an embodiment, the flapper may be biased, for example, biased toward the first, closed position via the operation of any suitable biasing means or member, such as a spring-loaded hinge. In an embodiment, when the flapper is in the second position, the flapper may be retained within a recess within the longitudinal bore of the housing  51 , such as a depression (alternatively, a groove, cut-out, chamber, hollow, or the like). Also, when the flapper is in the first position, the flapper may protrude into the longitudinal bore  52 , for example, so as to sealingly engage or rest against a portion of the housing  51  (alternatively, so as to engage a shoulder, a mating seat, the like, or combinations thereof). The flapper may be round, elliptical, or any other suitable shape. 
     In an embodiment, as will be disclosed herein, the one or more valves  53  may be activated and/or inactivated through an interaction with the movement of the sleeve  55 . As used herein, reference to the one or more valves  53  as being in an “activated” state may mean that the one or more valves  53  are free to move between the first, closed position and the second, open position. Also, as used herein, reference to the one or more valves  53  as being in an “inactivated” state may mean that the one or more valves  53  are not free to move between the first, closed position and the second, open position. For example, in an embodiment as will be disclosed herein, 
     While the embodiments of  FIGS. 2A-2D  illustrate an AVT  200  comprising two valves, in alternative embodiments, an AVT may similarly comprise only a single valve, alternatively, three valves, alternatively, four valves, alternatively, any suitable number of valves. In an embodiment, the one or more valves, particularly, a first valve  53   a  and a second valve  53   b , each comprise flapper valves. 
     In an embodiment, the sleeve  55  generally comprises a cylindrical or tubular structure. In an embodiment, for example, in the embodiment of  FIGS. 2A-2D , the sleeve may be slidably located/positioned within the housing  51 . For example, the sleeve  55  may be slidably movable between various longitudinal positions with reference to the housing  51 . For example, in the embodiments shown in  FIGS. 2A-2D , the sleeve  55  that is slidably disposed within the housing  51  and movable between a first (e.g., upper) position, a second (e.g., lower) position, and third (e.g., intermediate) position. For example, the sleeve  55  is shown in its first position in  FIG. 2A ; in its second position in  FIGS. 2B and 2D ; and in its third position in  FIG. 2C . For example, when the sleeve  55  is in the first position, the AVT  200  may be configured in the first mode; when the sleeve  55  is in the second position (after having most-recently departed the first position), the AVT  200  may be configured in the second mode; when the sleeve  55  is in the third position, the AVT  200  may be configured in the third mode; and when the sleeve  55  is in the second position (after having most-recently departed the third position), the AVT may be configured in the fourth mode. In an embodiment, as will be disclosed herein, AVT  200  may be configured such that the sleeve  55  may be movable from the first position to the second; thereafter, from the second position to the third position; thereafter, from the third position to the second position (e.g., a second time); and, thereafter, from the second position to the first position. 
     In an embodiment, the relative longitudinal position of the sleeve  55  may determine if the one or more valves are in an activated state or an inactivated state. For example, when the sleeve  55  is located in the first position, the one or more valves may be in the activated state; alternatively, when the sleeve is located in the second and third positions, the one or more valves may be in the inactivated state. For example, as shown in  FIG. 2A , when the sleeve is in the first position (e.g., when the AVT  200  is in the first mode), the sleeve  55  does not interfere with the movement of the one or more valves  53  and, as such, allows the biased flappers of the one or more valves  53  to move into the first, closed position and the second, open position. Alternatively, as shown in  FIGS. 2B ,  2 C, and  2 D, when the sleeve is in the second and third positions (e.g., when the AVT  200  is in the second, third, and fourth modes), the sleeve  55  will retain the flappers of the one or more valves  53  in the second, open position. The housing may comprise sufficient space, longitudinally, to allow for the sleeve  55  to move between the first, second, and third positions. 
     In an embodiment, the sleeve  55  may be longitudinally biased. For example, the sleeve  55  may be generally upwardly biased, for example, such that the sleeve  55  will experience a force sufficient to move the sleeve  55  in the upward direction (e.g., toward the first terminal end  51   a ) if otherwise uninhibited from such movement. For example, the sleeve  55  may be upwardly, longitudinally biased by the biasing member  57 . 
     In an embodiment, the biasing member  57  generally comprises a suitable structure or combination of structures configured to apply a directional force and/or pressure to sleeve  55  with respect to the housing  51 . Examples of suitable biasing members include a spring, a compressible fluid or gas contained within a suitable chamber, an elastomeric composition, a hydraulic piston, or the like. For example, in the embodiment of  FIGS. 2A-2D , the biasing member  57  comprises a spring (e.g., a coiled, compression spring). 
     The biasing member  57  may be configured to apply an axial force to sleeve  55  with respect to the housing  51 . For example, in the embodiment of  FIGS. 2A-2D , the biasing member  57  is configured to apply an upward force to the sleeve  55  relative to the housing  51 , via an upper shoulder  55   c  of the sleeve  55  throughout at least a portion of the length of the movement of the sleeve  55 . Engagement between the biasing member  57  and the shoulder  55   c  of the sleeve  55  biases the sleeve  55  axially upward toward the first terminal end  51   a  of the housing  51 , such that, if otherwise uninhibited, the sleeve  55  will move longitudinally/axially upward. 
     In such an embodiment, the biasing member  57  may be generally disposed within an annular cavity  60  which may be cooperatively defined by the housing  51  and the sleeve  55 . For example, in the embodiment of  FIGS. 2A-2D , the annular cavity  60  is substantially defined by the upper shoulder  55   c  and a first outer cylindrical surface  54   a  of the sleeve  55 , and by a first inner cylindrical surface  61   a , a lower shoulder  51   c , an intermediate shoulder  51   d , and a recessed bore surface  60   a  within the housing  51 . 
     In an embodiment, sleeve  55  may be configured so as to be selectively moved downwardly, for example, against the biasing force applied by the biasing member  57 . For example, in an embodiment, the sleeve  55  may be configured such that the application of a fluid and/or hydraulic pressure (e.g., a hydraulic pressure exceeding a threshold pressure) to the axial flowbore  52  thereof will cause sleeve  55  to move in the downward direction (e.g., toward the second terminal end  51   b ). For example, in such an embodiment, sleeve  55  may be configured such that the application of fluid pressure of at least the threshold pressure to axial flowbore  52  (e.g., via, the flowbore  126 ) results in a net hydraulic force applied to sleeve  55  in the axially downward direction (e.g., in the direction towards the second terminal end  51   b ). In such an embodiment, the force applied to sleeve  55  as a result of the application of such a fluid/hydraulic pressure to the AVT  200  may be greater in the axial direction toward the second terminal end  51   b  (e.g., downward forces) than the sum of any forces applied in the opposite axial direction, for example, in the axial direction toward the first terminal end  51   a  (e.g., upward forces). 
     For example, in an embodiment, the sleeve  55  may be configured so as to have a differential in the surface area of the downward-facing and upward-facing surfaces of the sleeve  55  which are exposed to the axial flowbore  52 , for example, so as to result in a differential between the axially upward and axially downward forces upon the application of fluid/hydraulic pressure to the axial flowbore. For example, in an embodiment, one or more of the interfaces between the housing  51  and the sleeve  55  may be sealed, for example, so as to provide such a differential in the surface area of the downward-facing and upward-facing surfaces of the sleeve  55  which are exposed to the axial flowbore  52 . In the embodiment of  FIGS. 2A-2D , the annular cavity  60  is sealed from the axial flowbore  52  by one or more upper seals  58  (each disposed in an upper seal groove  58   a  within the sleeve  55 ) and a lower seal  59  (disposed in a lower seal groove  59   a  within the housing  51 ) located at the interfaces between the sleeve  55  and the housing  51 . Particularly, in the embodiment of  FIGS. 2A-2D , the upper seal  58  is located at the interface between the second outer cylindrical surface  54   b  of the sleeve  55  and the first inner cylindrical surface  61   a  of the housing  51 . Also, in the embodiment of  FIGS. 2A-2D , the lower seal  59  is located at the interface between first outer cylindrical surface  54   a  of the sleeve  55  and the second inner cylindrical surface  61   b  of the housing  51 . Suitable seals include but are not limited to a T-seal, an O-ring, a gasket, or combinations thereof. In an additional embodiment metal, graphite, rod seals, piston seals, symmetrical seals, or combinations thereof. These seals serve to isolate annular cavity  60  between the sleeve  55  and the housing  51 , preventing fluid flow across the seal in order to define a pressure sealed annular space  60 . For example, the upper seal  58  and the lower seal  59  isolate the upper shoulder  55   c  (e.g., a downward-facing surface, not intending to be bound by theory, which would have the effect of applying an upward force to the sleeve upon the application of a fluid/hydraulic force thereto) of the sleeve  55  from the axial flowbore  52 . One of ordinary skill in the art, upon viewing this disclosure, will appreciate the various suitable, alternative configurations by which seals may seal the annular cavity  60  from the bore  52  as the sleeve  55  moves between the various positions, as disclosed herein. In an embodiment, the differential between the upward and downward forces applied to the sleeve  55 , upon the application a fluid/hydraulic pressure to the axial flowbore  52  of at least the threshold pressure (e.g., resulting in a net, downward force), may be sufficient to overcome the force applied by biasing member  57  (e.g., in the upward direction). 
     In an additional or alternative embodiment, the sleeve  55  may be configured such that the movement of fluid through the axial flowbore  52  (e.g., downward movement of fluid exceeding a threshold flow rate) will cause sleeve  55  to move in the downward direction (e.g., toward the second terminal end  51   b ). For example, in such an embodiment, the sleeve  55  may be configured such that fluid movement through the sleeve  55  in a given direction (e.g., downwardly) will apply a force to the sleeve  55  in the direction of the movement. For example, not intending to be bound by theory, the sleeve  55  may experience a force as a result of the fluid movement therethrough resulting from the frictional interaction between the moving fluid and the sleeve  55 . For example, in such an embodiment, the sleeve  55  may comprise at least one surface configured so as exhibit a relatively increased coefficient of fluid movement as to fluid moving therethrough; for example, the sleeve  55  (e.g., portions of the sleeve exposed to fluid flow) may be configured to exhibit a drag coefficient sufficient to cause the movement of fluid through the AVT  200  (e.g., through the sleeve  55 ) to exert a force against the sleeve  55  in generally the same direction as the fluid movement (e.g., in a downward direction). In such an embodiment, the sleeve  55  may comprise one or more features (e.g., physical features) configured to alter the drag coefficient as to a fluid moving therethrough, for example, a roughened surface, various, lips, shoulders, grooves, or other profiles, or combinations thereof. In an embodiment, the force exerted against the sleeve  55 , upon the movement of a fluid therethrough at a flow rate of at least threshold flow rate (e.g., resulting in a net, downward force), may be sufficient to overcome the force applied by biasing member  57  (e.g., in the upward direction). 
     While one or more of the embodiments disclosed herein may refer to sleeve movement as a result of the application of a given fluid pressure and/or the communication of a fluid at a given rate, it is contemplated that a given AVT may be configured for movement via either of these, or by any other suitable method, apparatus, or system. 
     In an embodiment, the transition system  50  may be configured to guide the axial and/or rotational movement of the sleeve  55  relative to the housing  51 . In an embodiment, the transition system  50  generally comprises a recess or slot  63  and one or more lugs  64 , for example, a “J-slot,” a control groove, an indexing slot, or combinations thereof. In an embodiment, through the interaction between the slot  63  and the one or more lugs  64 , the transition system  50  may be configured to guide the rotational and axial movement of sleeve  55 , as will be disclosed herein. In an embodiment, recess or slot  63  may be disposed on the second outer cylindrical surface  54   b  of the sleeve  55  and, the lug  64  may extend inwardly from the first inner cylindrical surface  61   a  of the housing  51  (e.g., a pin disposed within a bore within the housing  51 ). In an alternative embodiment, a slot like slot  63  may be similarly disposed within the housing and may interact with a lug like lug  64  extending outwardly from the sleeve. In an embodiment, the slot  63  may be characterized as a continuous slot. For example, the slot  63  may comprise a continuous J-slot. As used herein, a continuous slot refers to a slot, such as a groove or depression having a depth beneath the outer surface  54  of the sleeve  55  and extending entirely about (i.e., 360 degrees) the circumference of sleeve  55 , though not necessarily in a single straight path. For example, as will be discussed herein, a continuous J-slot refers to a design configured to receive one or more protrusions or lugs (e.g. lug  64 ) coupled to and/or integrated within a component (e.g., housing  51 ), so as to guide the axial and/or rotational movement of that component through the J-slot, for example due to the physical interaction between the lug and the upper and lower shoulders of the slot. 
     Referring to  FIG. 3 , an embodiment of the slot  63  (e.g., a J-slot) is illustrated disposed on the outer surface of the sleeve  55 . In the embodiment of  FIG. 3 , the slot  63  is disposed on the second outer cylindrical surface  54   b  of the sleeve  55 . The slot  63  extends beneath (e.g., a groove or slot depth) the second outer cylindrical surface  54   b , partially through the sleeve  55  (e.g., radially inward) and is generally defined by an axially upper shoulder  63   b  (e.g., which forms the upper bound of the slot  63 ), an axially lower shoulder  63   c  (e.g., which forms the lower bound of the slot  63 ) and an inner surface  63   a  extending between upper shoulder  63   b  and lower shoulder  63   c . Inner surface  63   a  and upper shoulder  63   b  generally define one or more upper notches  63   d  extending axially upward (i.e., to the left in the Figures) toward first sleeve terminal end  55   a . The upper shoulder  63   b  may comprise a profile having one or more upper sloped edges  63   g  extending between each upper notch  63   d . Also, inner surface  63   a  and lower shoulder  63   c  generally define one or more first or short lower notches  63   e  and one or more second or long lower notches  63   f  extending axially downward (i.e., to the right in the Figures) toward second sleeve terminal end  55   b . Long lower notches  63   f  extend farther axially in the direction of second sleeve terminal end  55   b  than short lower notches  63   e . Moving radially around the circumference of inner surface  63   a , each long lower notch  63   f  is followed by a short lower notch  63   e , for example, thereby forming an alternating pattern of long lower notches  63   f  and short lower notches  63   e  (e.g., long lower notch  63   f -short lower notch  63   e -long lower notch  63   f -short lower notch  63   e , etc.). The lower shoulder  63   c  may comprise a profile having one or more lower sloped edges  63   h  extending between each long lower shoulder  63   f  and short lower shoulder  63   e , partially defining lower shoulder  63   c . One of ordinary skill in the art, upon viewing this disclosure, would appreciate various additional and/or alternatively configurations of a slot, such as slot  63 . 
     In an embodiment, the slot  63  and lug  64  may be configured so as to interact to guide the sleeve  55 , upon the application of various forces sufficient to move the sleeve  55  longitudinally being applied thereto (e.g., alternating downward and upward forces, as disclosed herein), from the first position to second position, from the second position to the third position, from the third position again to the second position, from the second position again to the first position, and then to repeat the cycle. For example, in an embodiment, the slot  63  and lug  64  may interact such that when the sleeve  55  is in the first position, the lug  64  may be generally disposed in one of the long lower notches  63   f . In an embodiment, the slot  63  and lug  64  may also interact such that, upon the application of a downward force to the sleeve  55  sufficient to overcome upward forces applied to the sleeve  55 , the lug  64  will move through the slot  63  from the long lower notch  63   f  to one of the upper notches  63   d , for example, causing the sleeve  55  to move radially along with the downward movement thereof and, thereby, causing the sleeve  55  to arrive in the second position. Thereafter, upon relieving the downward force applied to the sleeve  55  such that the upward forces applied to the sleeve  55  overcome the downward forces applied thereto, the lug  64  will move through the slot  63  from the upper notch  63   d  to one of the short lower notches  63   e , for example, causing the sleeve  55  to move radially along with the upward movement thereof and, thereby, causing the sleeve  55  to arrive in the third position. Thereafter, upon another application of a downward force to the sleeve  55  sufficient to overcome upward forces applied to the sleeve  55 , the lug  64  will move through the slot  63  from the short lower notch  63   e  to another of the upper notches  63   d , for example, causing the sleeve  55  to move radially along with the downward movement thereof and, thereby, causing the sleeve  55  to return to the second position. Thereafter, upon again relieving the downward force applied to the sleeve  55  such that the upward forces applied to the sleeve  55  overcome the downward forces applied thereto, the lug  64  will move through the slot  63  from the upper notch  63   d  to another of the long lower notches  63   f , for example, causing the sleeve  55  to move radially along with the upward movement thereof and, thereby, causing the sleeve  55  to return to the first position. It is understood that the sleeve  55  is free to rotate within the housing  51 , for example, so as to allow the lug  64  to cycle (e.g., move both radially and longitudinally) with respect to the slot  63 . 
     As such, in an embodiment, AVT  200  may be configured to transition from the first mode to the second mode, from the second mode to the third mode, from the third mode to the fourth mode, and from the fourth mode back to the first mode (e.g., by alternatingly applying pressure to the AVT  200  and allowing the pressure applied to the AVT  200  to dissipate). In an embodiment, for example, where the slot  63  is a continuous slot, the AVT  200  may be cycled, as disclosed herein, an unlimited number of cycles. 
     One or more of embodiments of an AVT (e.g., such as AVT  200 ) and/or a wellbore servicing system (e.g., such as wellbore servicing system  100 ) comprising such an AVT  200  having been disclosed, one or more embodiments of a wellbore servicing method employing such a wellbore servicing system  100  and/or such an AVT  200  are also disclosed herein. In an embodiment, a wellbore servicing method may generally comprise the steps of positioning a work string (e.g., such as work string  112 ) having an AVT  200  incorporated therein within a wellbore (such as wellbore  114 ), communicating a fluid through the work string  112 , and repositioning the work string  112 . As will be disclosed herein, the AVT  200  may control fluid movement through the work string  112  during the wellbore servicing method. For example, as will be disclosed herein, during the step of positioning the work string  112  within the wellbore  114  and/or the step of repositioning the work string  112 , the AVT  200  may be configured to prohibit fluid communication out of the wellbore  114  through the work string  112  (e.g., upward fluid communication through the work string  112 ). Also, for example, during the step of communicating the fluid through the work string  112 , the AVT  200  may be configured to allow fluid communication through the work string  112  in both directions (e.g., upward and downward fluid communication) as will disclosed herein. 
     In an embodiment, the wellbore servicing method may further comprise re-positioning the work string  112  and, a second time, communicating a fluid through the work string  112 , as will be disclosed herein. 
     In an embodiment, positioning the work string  112  comprising the AVT  200  may comprise forming and/or assembling the components of the work string  112 , for example, as the work string  112  is run into the wellbore  114 . For example, referring to the embodiment of  FIG. 1  where the work string  112  comprises a jointed tubing string  80  located downhole from the AVT  200 , the jointed tubing segments may be assembled as the jointed tubing is run-in. In some embodiments as disclosed herein, a wellbore servicing tool (such as wellbore servicing tool  150 ) may be incorporated within the jointed tubing string, for example, downhole relative to the AVT  200 . In the embodiment of  FIG. 1 , the AVT  200  is incorporated within the work string  112  atop the jointed tubing string  80 . Referring again to the embodiment of  FIG. 1 , the coiled tubing may be attached atop the AVT  200 , for example, via a suitable coiled tubing adaptor such as coiled tubing adapter  81 . Alternatively, as disclosed herein, one or more AVTs  200  may be incorporated/integrated within the work string  112  at any suitable location. 
     In an embodiment, the work string  112  may be run into the wellbore  114  with the AVT  200  configured in the first mode, for example, with the sleeve  55  in the first position as disclosed herein and as illustrated in the embodiment of  FIG. 2A . In such an embodiment, with the AVT  200  configured in the first mode, the AVT  200  will not allow upward fluid communication therethrough (and, as such, will not allow upward fluid communication through the work string  112 ) but will allow downward fluid communication therethrough (and, as such, will allow downward fluid communication through the work string  112 ). For example, as shown in the embodiment of  FIG. 2A , when the AVT  200  is configured in the first mode (e.g., when the sleeve  55  is in the first position), the one or more flapper valve  53  may be activated, that is, free to move into the first, closed position. 
     In an embodiment, the work string  112  may be run into the wellbore  114  to a desired depth. For example, the work string  112  may be run in such that the wellbore servicing tool  150  is positioned proximate to one or more desired subterranean formation zones to be treated (e.g., a first formation zone). 
     In an embodiment, communicating a fluid through the work string  112  may comprise communicating a fluid from the surface  104  (e.g., from a wellbore servicing equipment component located at the surface  104 ) through the work string  112  into the formation  102  (for example, forward circulating a fluid through the work string  112  and the AVT  200 ). In an embodiment, the fluid may be communicated (e.g., pumped, for example, via the operation of one or more wellbore servicing equipment components, such as one or more high-pressure pumps). In an embodiment, the fluid communicated (e.g., forward-circulated) through the work string  112  (e.g., and the AVT  200 ) may comprise a wellbore servicing fluid. Nonlimiting examples of a suitable wellbore servicing fluid include but are not limited to a fracturing fluid (such as a proppant-laden fluid, a foamed fluid, or the like), a perforating or hydrajetting fluid, an acidizing fluid, the like, or combinations thereof. The wellbore servicing fluid may be communicated at a suitable rate and pressure for a suitable duration. For example, the wellbore servicing fluid may be communicated at a rate and/or pressure sufficient to initiate or extend a fluid pathway (e.g., a perforation or fracture) within the subterranean formation  102  and/or a zone thereof. Additionally, in an embodiment, a second fluid (e.g., a component fluid) may be communicated into the wellbore  114  via a second flow path substantially contemporaneously with the communication of fluid through the work string  112 . For example, the second flow path may comprise an annular space surrounding the work string  112 . The contemporaneous communication via multiple flow paths is disclosed in U.S. application Ser. No. 13/442,411 to East, et al., which is disclosed herein by reference in its entirety. 
     In an embodiment, communicating a fluid through the work string  112 , for example, forward circulating a fluid through the work string  112 , may comprise transitioning the AVT  200  from the first, run-in mode to the second, fully-stroked mode. For example, in an embodiment forward-circulating the fluid (e.g., the wellbore servicing fluid) though the work string  112  (e.g., at a pressure and/or flow rate about a predetermined threshold) may apply a downward force to the sleeve  55  sufficient to overcome the upward forces applied thereto and cause the sleeve to transition from the first position (e.g., as shown in  FIG. 2A ) to the second position (e.g., as shown in  FIG. 2B ). 
     For example, in an embodiment where the AVT  200  is activated by the communication of fluid therethrough (e.g., by pressure and/or flow rate), for example, in the embodiment of  FIGS. 2A-2D , communicating the fluid (e.g., pumping the wellbore servicing fluid) downwardly via the flowbore  126  of the work string  112  may increase the fluid pressure within work string  112  (e.g., within flowbore  126  or the work string  112  and the axial flow bore  52  of the AVT  200 ) and, as such, may increase the downward force applied to the sleeve  55 . For example, the AVT  200  may be configured such that the pressures attained within the axial flow bore  52  during the servicing operation (e.g., during pumping the wellbore servicing fluid) may be greater than the pressure threshold associated with AVT  200 . As previously discussed, the biasing member  57  applies an upward force to sleeve  55 . When the downward force applied to the sleeve  55  exceeds the force in the axially upward direction provided by biasing member  57  (and, any upward forces due to the application of fluid pressure), the sleeve  55  shifts downward, moving rotationally and axially as the lug  64  follows the profile of slot  63 . The sleeve  55  may slide downward until it reaches its maximum downward position (e.g., the second position). In an embodiment, the maximum downward position may be defined by the engagement between the lug  64  and one of the upper notches  63   d  of the slot  63 , as shown in  FIG. 3 . Specifically, as the sleeve  55  moves downward, the lug  64  may be displaced from one of the lower notches  63   f  to the upper notch  63   d . For example, as the sleeve moves downwards, the upper shoulder  63   b  (e.g., the upper sloped edges  63   g ) may guide the lug  64  towards the upper notch  63   d . As lugs  64  enter upper notches  63   d  and engages the upper shoulder  63   b , the sleeve  55  comes to rest in the second position, corresponding to the second, fully-stroke mode of wellbore servicing tool  200 . In an embodiment, the maximum downward position may additionally or alternatively be defined by the engagement between the sleeve  55  (e.g., the second sleeve terminal end  55   b ) and a shoulder  56  of the housing  51 , as shown in  FIG. 2B . 
     In an embodiment, the fluid communicated through the work string  112  (e.g., through the AVT  200 ) may be characterized abrasive, corrosive, and/or erosive (for example, containing particulate material, such as sand). For example, in an embodiment as disclosed herein, the fluid may comprise a wellbore servicing fluid, for example a fracturing fluid comprising a proppant such as sand. In an embodiment, movement of the sleeve  55  to the second position, as disclosed herein, may protect and/or substantially protect one or more components of the AVT  200  from experiencing the potentially abrasive, corrosive, and/or erosive fluids communicated therethrough. For example, in the embodiment of  FIG. 2B , movement of the sleeve  55  to the second positions obscures and/or blocks the one or more valve  53 , for example, such that the one or more valves  53  do not experience (e.g., are generally unexposed) to the fluid communicated through the AVT  200 . 
     In an embodiment, when a desired amount of the servicing fluid has been communicated, for example, sufficient to create a perforation or fracture of a desired number or character, an operator may cease the communication of fluid (e.g., cease the downward communication of a wellbore servicing fluid), for example, by ceasing to pump the servicing fluid into work string  112 . 
     In an embodiment, ceasing the communication of fluid (alternatively, decreasing the pressure at which the fluid is communicated, decreasing the rate at which the fluid is communicated, or combinations thereof) may comprise transitioning the AVT  200  from the second, fully-stroked mode to the third, reverse circulation mode. For example, in an embodiment ceasing the communication of fluid (alternatively, decreasing the pressure at which the fluid is communicated, decreasing the rate at which the fluid is communicated, or combinations thereof) may decrease the downward forces applied to the sleeve  55  such that the upward forces applied thereto (e.g., by the biasing member) overcome any such downward forces and cause the sleeve to transition from the second position (e.g., as shown in  FIG. 2B ) to the third position (e.g., as shown in  FIG. 2C ). 
     For example, in an embodiment where the AVT  200  is activated by the communication of fluid therethrough (e.g., by pressure and/or flow rate), for example, in the embodiment of  FIGS. 2A-2D , decreasing the pressure within work string  112  (e.g., within flowbore  126  or the work string  112  and the axial flow bore  52  of the AVT  200 ) may decrease the downward force applied to the sleeve  55 . For example, as the pressure is decreased within work string  112  (for example, to less than the pressure threshold), the upward axial force applied to sleeve  55  (e.g., applied by biasing member  57 ) may overcome the axially downward forces applied to sleeve  55 , and produces a net force in the upward axial direction. The resulting net upward force may shift the sleeve  55  axially upward into the third configuration as the lug  64  follows the profile of the slot  63 . As the sleeve moves upward, the lug  64  may be displaced from the upper notch  63   d  into one of the short lower notches  63   e . For example, as the lugs  64  enter the short lower notches  63   e , the sleeve  55  comes to rest in the third position, as shown in  FIG. 2C . Similar to the first, run-in or installation mode, in the third, reverse-circulation mode, the sleeve may be held upward by a net force in the upward axial direction provided by the biasing member  57 . As disclosed herein, in the third, reverse circulation mode, the interaction between the lug  64  and the short lower notches  63   e  cause the sleeve  55  to continue to retain the valve(s)  53   a  and  53   b  in the inactivated state (e.g., open), and further to protect and shield the valves  53  from wear/degradation associated with further fluid flow (e.g., reverse-circulation of fluid from the formation toward the surface). 
     Additionally or alternatively, communicating a fluid through the work string may comprise communicating a fluid through the work string  112  from the formation  102  and or the wellbore  114  through the work string  112  toward the surface  104  (for example, reverse-circulating a fluid through the work string). In an embodiment, for example, following the performance of a servicing operation with respect to a given zone of the subterranean formation, fluid (e.g., a wellbore servicing fluid, a formation fluid, such as water and/or hydrocarbons, or combinations thereof) may be reverse-circulated through the work string  112 . In an embodiment, upon transitioning the AVT  200  to the third, reverse-circulation mode, a fluid may be reverse-circulated (communicated upward) through the work string  112  and/or the AVT  200 . For example, when the AVT  200  is configured in the third mode, fluid may be communicated therethrough in either direction, for example, because the one or more valves  53  are retained in the inactivated (e.g., open) state, as disclosed herein. 
     Additionally, although the third circulation mode is called the reverse circulation mode, in an embodiment, fluid may be also communicated downward through the AVT  200  while the AVT  200  is maintained in the third mode (e.g., so long as such fluid is communicated at a pressure below the threshold fluid pressure and/or flow rate. 
     In an embodiment, repositioning the work string  112  may comprising positioning the work string  112  such that the wellbore servicing tool is positioned proximate to another formation zone (e.g., a second formation zone). In such embodiments, repositioning the work string may allow for such additional formation zones to be serviced. For example, the work string  112  may be run-in (e.g., deeper within the wellbore  114 ); alternatively, the work string  112  may be run out (e.g., shallower within the wellbore  114 ). In an alternative embodiment, repositioning the work string  112  may comprise removing the work string  112  from the wellbore  114 . 
     In an embodiment, repositioning the work string  112  may comprise transitioning the AVT  200  from the third mode to the fourth mode and transitioning the AVT  200  from the fourth mode to the first mode, again. 
     For example, in an embodiment where the AVT  200  is activated by the communication of fluid therethrough (e.g., by pressure and/or flow rate), for example, in the embodiment of  FIGS. 2A-2D , transitioning AVT  200  to the fourth, re-indexing mode, as shown in  FIG. 2D , may comprise communicating (e.g., pumping) a fluid through the work string  112  via the flowbore  126  of the work string  112  so as to increase the fluid pressure within work string  112  (e.g., within flowbore  126 ) to the threshold pressure and/or flow rate. As previously discussed, when the downward force applied to the sleeve  55  (e.g., as a result of the application of a fluid force to the AVT  200 ) exceeds the force in the axially upward direction provided by biasing member  57 , the sleeve  55  shifts downward, moving rotationally and axially as the lug  64  follows the profile of slot  63 . The sleeve  55  may slide downward until it reaches its maximum downward position (e.g., the second position). As previously disclosed herein, in an embodiment, the maximum downward position may be defined by the engagement between the lug  64  and one of the upper notches  63   d  of the slot  63 , and/or by the engagement between the sleeve  55  (e.g., second sleeve terminal end  55   b ) and a shoulder  56  of the housing  51 , as shown in  FIG. 2D . 
     In an embodiment, the AVT  200  may be maintained within the fourth, re-indexing mode for so long as the downward forces applied to sleeve  55  (e.g., as a result of the application of a fluid force to the sleeve  55 ) is sufficient to overcome the upward forces also applied to the sleeve  55  (e.g., by the biasing member  57 ). In an embodiment, a fluid may be communicated through the well string  112  (e.g., downwardly through the AVT  200 ) while the AVT  200  is maintained in the fourth mode. For example, in such an embodiment, a second wellbore servicing fluid (e.g., a fracturing fluid, an acidizing fluid, a clean-out fluid, the like, or combinations thereof) may be communicated downwardly through the well string  112  (e.g., downwardly through the AVT  200 ) while the AVT  200  is maintained in the fourth mode. 
     Also, in an embodiment where the AVT  200  is activated by the communication of fluid therethrough (e.g., by pressure and/or flow rate), for example, in the embodiment of  FIGS. 2A-2D , transitioning AVT  200  from the fourth mode again to the first mode may comprise decreasing the downward force applied to the sleeve  55 . For example, by decreasing the pressure within work string  112  (for example, to less than the pressure and/or flow rate threshold), the upward axial force applied to sleeve  55  (e.g., applied by biasing member  57 ) may overcome the axially downward forces applied to sleeve  55 , and produce a net force in the upward axial direction. The resulting net upward force may shift the sleeve  55  axially upward into the first configuration as the lug  64  follows the profile of the slot  63 . As the sleeve moves upward, the lug  64  may be displaced from the upper notch  63   d  into one of the long lower notches  63   f . As the lugs  64  enter the long lower notches  63   f , the sleeve  55  comes to rest in the first, run-in mode and at its upward maximum position, as shown in  FIG. 2A . 
     In an embodiment, and as similarly disclosed herein, the work string  112  may be repositioned within the wellbore  114  with the AVT  200  or removed from the wellbore while the AVT  200  is configured in the first mode, for example, with the sleeve  55  in the first position as disclosed herein and as shown in  FIG. 2A . As disclosed herein, in such an embodiment, with the AVT  200  configured in the first mode, the AVT  200  will not allow upward fluid communication therethrough (and, as such, will not allow upward fluid communication through the work string  112 ) but will allow downward fluid communication therethrough (and, as such, will allow downward fluid communication through the work string  112 ). 
     In an embodiment, upon repositioning the work string  112  within the wellbore  114 , the process of communicating a fluid through the work string  112  (e.g., so as to perform a wellbore servicing operation with respect to various formation zones), and repositioning the work string  112  may be repeated for so many cycles as may be desired. As such, in an embodiment, the AVT  200  may be cycled (e.g., for as many cycles as may be desired) from the first mode to the second mode (e.g., to allow forward circulation, if desired), from the second mode to the third mode (e.g., to allow reverse circulation, if desired), from the third mode to the fourth mode (e.g., to again allow forward circulation, if desired), and from the fourth mode back to the first mode (e.g., to block upward fluid communication, for example, during run-in, repositioning, and/or run-out). 
     One of skill in the art, upon viewing this disclosure, will appreciate that an AVT (like AVT  200 ) may be modified (e.g., via one or modifications to the “J-slot,” as disclosed herein) so as to transition between various modes (e.g., as disclosed herein) upon any suitable combination of alternatingly applying fluid force (e.g., pressure and/or flow rate above a threshold) to the AVT  200  and allowing the force applied to the AVT  200  to dissipate (e.g., decreasing the pressure and/or flow rate to less than a threshold), as disclosed herein. Similarly, an AVT may be modified so as to similarly have a fifth, sixth, seventh, eighth, ninth, or tenth mode. 
     In an embodiment, an AVT (like AVT  200 ), a system utilizing an AVT, and/or a method utilizing such an AVT and/or system a system may be advantageously employed in the performance of a wellbore servicing operation. For example, as disclosed herein, the AVT allows for an operator to selectively block fluid communication upwardly through a work string (or other tubular, wellbore string). As such, an AVT may be employed to improve safety in a wellbore/wellsite environment, for example, by providing a means of controlling the unintended escape of fluids/pressures from a wellbore (e.g., when the AVT is so-configured, as disclosed herein). Also, whereas conventional flapper-type valves are often unprotected from abrasive, corrosive, or erosive wellbore fluids during a wellbore servicing operation (e.g., during pumping a high-pressure or high flow-rate fluid), an AVT as disclosed herein will protect flapper valves therein, for example, thereby improving the reliability with which such components operate. Further still, an AVT as disclosed herein does not require that a signaling member (e.g., a ball, dart, or other tool) be run into the wellbore to transition the AVT between modes. As such, the AVT may be quickly and efficiently transitioned between various modes, as disclosed herein, via either increasing and/or decreasing the pressure applied thereto. 
     Additional Disclosure 
     The following are nonlimiting, specific embodiments in accordance with the present disclosure: 
     A first embodiment, which is wellbore servicing system comprising: 
     a work string; and 
     an actuatable valve tool defining an axial flowbore and incorporated within the work string,
         wherein the actuatable valve tool is transitionable from a first mode to a second mode, from the second mode to a third mode, and from the third mode to a fourth mode,   wherein the actuatable valve tool is configured to transition from the first mode to the second mode upon an application of pressure to the axial flowbore of at least a threshold pressure,   wherein the actuatable valve tool is configured to transition from the second mode to the third mode upon a dissipation of pressure from the axial flowbore to not more than the threshold pressure,   wherein, in the first mode, the actuatable valve tool is configured to allow fluid communication via the axial flowbore in a first direction and to disallow fluid communication via the axial flowbore in a second direction, and   wherein, in the second, and third modes, the actuatable valve tool is configured to allow fluid communication via the axial flowbore in both the first direction and the second direction.       

     A second embodiment, which is the wellbore servicing system of the first embodiment, wherein the actuatable valve tool is transitionable from the fourth mode the first mode. 
     A third embodiment, which is the wellbore servicing system of the second embodiment,
         wherein the actuatable valve tool is configured to transition from the third mode to the fourth mode upon an application of pressure to the axial flowbore of at least a threshold pressure, and   wherein the actuatable valve tool is configured to transition from the fourth mode to the first mode upon a dissipation of pressure from the axial flowbore to not more than the threshold pressure.       

     A fourth embodiment, which is the wellbore servicing system of one of the first through the third embodiments, wherein the actuatable valve tool comprises:
         a housing defining the axial flowbore,   a sliding sleeve; and   a flapper valve,
           wherein, when the flapper valve is in an activated state, the flapper valve is free to move between a closed position in which the flapper valve blocks the axial flowbore and an open position in which the flapper valve does not block the axial flowbore, and   wherein, when the flapper valve is in an inactivated state, the flapper valve is retained in the open position.   
               

     A fifth embodiment, which is the wellbore servicing system of the fourth embodiment, wherein the sliding sleeve is movable from a first longitudinal position to a second position, from the second longitudinal position to a third longitudinal position. 
     A sixth embodiment, which is the wellbore servicing system of the fifth embodiment,
         wherein, in the first position, the sliding sleeve does not interact with the flapper valve, and   wherein, in the second and third positions, the sliding sleeve retains the flapper valve in the open position.       

     A seventh embodiment, which is the wellbore servicing system of one of fifth through the sixth embodiments, further comprising a transition system configured to control the longitudinal movement of the sliding sleeve. 
     An eighth embodiment, which is the wellbore servicing system of the seventh embodiment, wherein the transition system comprises:
         a j-slot; and   a lug, wherein the lug is disposed within a least a portion of the j-slot.       

     A ninth embodiment, which is the wellbore servicing system of one of the fifth through the eighth embodiments, further comprising a biasing member, wherein the biasing member is configured to bias the sliding sleeve in the second direction. 
     A tenth embodiment, which is the wellbore servicing system of one of the fifth through the ninth embodiments, where the sliding sleeve comprises a differential between the surfaces exposed to the axial flowbore facing the first direction and the surfaces exposed to the axial flowbore facing the second direction. 
     An eleventh embodiment, which is the wellbore servicing system of one of the first through the tenth embodiments, wherein the work string comprises a coiled tubing segment, a jointed tubing segment, or combinations thereof. 
     A twelfth embodiment, which is the wellbore servicing system of one of the first through the eleventh embodiments, wherein the wellbore servicing system further comprises a wellbore servicing tool incorporated within the work string at a location downhole from the actuatable valve tool. 
     A thirteenth embodiment, which is a wellbore servicing method comprising: 
     disposing a wellbore servicing system comprising an actuatable valve tool in a wellbore, the actuatable valve tool generally defining an axial flowbore, wherein the actuatable valve tool is configured in a first mode, wherein in the first mode, the actuatable valve tool allows downward fluid communication via the axial flowbore and disallows upward fluid communication via the axial flowbore; 
     making a first application of fluid pressure of at least a pressure threshold to the axial flowbore, wherein the first application of fluid pressure transitions the actuatable valve tool to a second mode in which the actuatable valve tool allows both upward and downward fluid communication; 
     allowing a first dissipation of fluid pressure applied to the axial flowbore to less than the pressure threshold, wherein allowing the first dissipation of fluid pressure transitions the actuatable valve tool to a third mode in which the actuatable valve tool allows both upward and downward fluid communication; 
     making a second application of fluid pressure of at least the pressure threshold to the axial flowbore, wherein the second application of fluid pressure transitions the actuatable valve tool to a fourth mode in which the actuatable valve tool allows both upward and downward fluid communication; 
     allowing a second dissipation of fluid pressure applied to the axial flowbore to less than the pressure threshold, wherein allowing the fluid pressure applied to the axial flowbore to dissipate transitions the actuatable valve tool to the first mode. 
     A fourteenth embodiment, which is the wellbore servicing method of the thirteenth embodiment, wherein making the first application of fluid pressure comprises downwardly communicating a fluid via the axial flowbore. 
     A fifteenth embodiment, which is the wellbore servicing method of one of the thirteenth through the fourteenth embodiments, wherein allowing the first dissipation of fluid pressure comprises upwardly communicating a fluid via the axial flowbore. 
     A sixteenth embodiment, which is the wellbore servicing method of one of the thirteenth through the fifteenth embodiments, wherein making the second application of fluid pressure comprises downwardly communicating a fluid via the axial flowbore. 
     A seventeenth embodiment, which is the wellbore servicing method of one of the thirteenth through the sixteenth embodiments, wherein making the second application of fluid pressure comprises upwardly communicating a fluid via the axial flowbore. 
     An eighteenth embodiment, which is a wellbore servicing method comprising: 
     disposing a wellbore servicing system in a wellbore, the wellbore servicing system comprising a actuatable valve tool generally defining an axial flowbore, wherein during disposing the wellbore servicing system within the wellbore, the actuatable valve tool is configured so as to allow downward fluid communication via the axial flowbore and to disallow upward fluid communication via the axial flowbore; 
     reconfiguring the actuatable valve tool so as to allow downward and upward fluid communication via the axial flowbore, wherein reconfiguring the actuatable valve tool comprises applying a fluid pressure of at least a pressure threshold to the axial flowbore, allowing a fluid pressure applied to the axial flowbore to dissipate to less than the pressure threshold, or combinations thereof; 
     reconfiguring the actuatable valve tool so as to allow downward fluid communication via the axial flowbore and to disallow upward fluid communication via the axial flowbore, wherein reconfiguring the actuatable valve tool comprises applying a fluid pressure of at least a pressure threshold to the axial flowbore, allowing a fluid pressure applied to the axial flowbore to dissipate to less than the pressure threshold, or combinations thereof; and 
     repositioning the wellbore servicing system. 
     A nineteenth embodiment, which is the wellbore servicing method of the eighteenth embodiment, wherein reconfiguring the actuatable valve tool so as to allow downward and upward fluid communication via the axial flowbore comprises communicating a fluid downwardly via the axial flowbore. 
     A twentieth embodiment, which is the wellbore servicing method of the nineteenth embodiment, wherein the fluid is communicated into a subterranean formation zone at a rate and/or pressure sufficient to initiate and/or extend a perforation and/or fracture. 
     A twenty-first embodiment, which is the wellbore servicing method of the nineteenth embodiment, wherein the fluid is a perforating fluid, a hydrajetting fluid, a fracturing fluid, an acidizing fluid, or combinations thereof. 
     A twenty-second embodiment, which is the wellbore servicing method of one of the eighteenth through the twenty-first embodiments, further comprising communicating a fluid upwardly through the axial flowbore. 
     A twenty-third embodiment, which is the wellbore servicing method of one of the eighteenth through the twenty-second embodiments, wherein repositioning the wellbore servicing system comprises repositioning at least a portion of the wellbore servicing system within the wellbore. 
     A twenty-fourth embodiment, which is the wellbore servicing method of one of the eighteenth through the twenty-third embodiments, wherein repositioning the wellbore servicing system comprises removing the wellbore servicing system from the wellbore. 
     A twenty-fifth embodiment, which is an actuatable valve tool comprising:
         a housing defining the axial flowbore,   a flapper valve,
           wherein, when the flapper valve is in an activated state, the flapper valve is free to move between a closed position in which the flapper valve blocks the axial flowbore and an open position in which the flapper valve does not block the axial flowbore, and   wherein, when the flapper valve is in an inactivated state, the flapper valve is retained in the open position,   
           a sliding sleeve;
           wherein, in a first position, the sliding sleeve does not interact with the flapper valve, and   wherein, in a second position and a third position, the sliding sleeve retains the flapper valve in the open position; and   
           a transition system configured to control the longitudinal movement of the sliding sleeve, wherein the transition system comprises:
           a j-slot; and   a lug, wherein the lug is disposed within a least a portion of the j-slot.   
               

     A twenty-sixth embodiment, which is the actuatable valve tool of the twenty-fifth embodiment, wherein the transition system is configured to guide the sliding sleeve from the first position to the second position, from the second position to the third position, from the third position back to the second position, and from the second position back to the first position. 
     While embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−Rl), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc. 
     Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the embodiments of the present invention. The discussion of a reference in the Detailed Description of the Embodiments is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural or other details supplementary to those set forth herein.