Patent Publication Number: US-9428976-B2

Title: System and method for servicing a wellbore

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a divisional of and claims priority to U.S. patent Ser. No. 13/025,041 filed Feb. 10, 2011, published as U.S. Patent Application Publication No. 2012/0205121 and entitled “System and Method for Servicing a Wellbore.” 
     This application is related to U.S. patent application Ser. No. 12/539,392 entitled “System and Method for Servicing a Wellbore,” by Williamson, et al., filed Aug. 11, 2009, now U.S. Pat. No. 8,276,675. The subject matter of this application is also related to U.S. patent application Ser. No. 12/617,405 entitled “Downhole Progressive Pressurization Actuated Tool and Method of Using the Same,” by Watson, et al., filed Nov. 12, 2009, now U.S. Pat. No. 8,272,443. The subject matter of this application is also related to U.S. patent application Ser. No. 13/025,039 entitled “A Method for Individually Servicing a Plurality of Zones of a Subterranean Formation,” by Howell, published as U.S. Patent Application Publication No. 2012/0205120. The subject matter of this application is also related to U.S. patent application Ser. No. 13/025,041 entitled “System and Method for Servicing a Wellbore,” by Porter, et al., filed Feb. 10, 2011, published as U.S. Patent Application Publication No. 2012/0205121. The subject matter of this application is also related to U.S. patent application Ser. No. 13/151,457 entitled “System and Method for Servicing a Wellbore,” by Porter, et al., filed Jun. 2, 2011, published as U.S. Patent Application Publication No. 2011/0253383. The subject matter of this application is also related to U.S. patent application Ser. No. 13/156,155 entitled “Responsively Activated Wellbore Stimulation Assemblies and Methods of Using the Same,” by Miller, filed Jun. 8, 2011, published as U.S. Patent Application Publication No. 2012/0312547. The subject matter of this application is also related to U.S. patent application Ser. No. 13/215,553 entitled “System and Method for Servicing a Wellbore,” by Merron, et al., filed Aug. 23, 2011, published as U.S. Patent Application Publication No. 2013/0048298. The subject matter of this application is also related to U.S. patent application Ser. No. 13/248,145 entitled “Responsively Activated Wellbore Stimulation Assemblies and Methods of Using the Same,” by Norrid, et al., filed Sep. 29, 2011, published as U.S. Patent Application Publication No. 2013/0081817. The subject matter of this application is also related to U.S. patent application Ser. No. 13/460,453 entitled “Delayed Activation Activatable Stimulation Assembly,” by Merron, filed Apr. 30, 2012, published as U.S. Patent Application Publication No. 2013/0284451. The subject matter of this application is also related to U.S. patent application Ser. No. 13/538,911 entitled “System and Method for Servicing a Wellbore,” by Neer, filed Jun. 29, 2012. The subject matter of this application is also related to U.S. patent application Ser. No. 12/274,193 entitled “Apparatus and Method for Servicing a Wellbore,” by Surjaatmadja, et al., filed Nov. 19, 2008, now U.S. Pat. No. 7,775,285. Each of these applications is incorporated by reference herein, in its entirety. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     REFERENCE TO A MICROFICHE APPENDIX 
     Not applicable. 
     BACKGROUND 
     Subterranean formations that contain hydrocarbons are sometimes non-homogeneous in their composition along the length of wellbores that extend into such formations. It is sometimes desirable to treat and/or otherwise manage the formation and/or the wellbore differently in response to the differing formation composition. Some wellbore servicing systems and methods allow such treatment, referred to by some as zonal isolation treatments. However, in some wellbore servicing systems and methods, while multiple tools for use in treating zones may be activated by a single obturator, such activation of one tool by the obturator may cause activation of additional tools to be more difficult. For example, a ball may be used to activate a plurality of stimulation tools, thereby allowing fluid communication between a flow bore of the tools with a space exterior to the tools. However, such fluid communication accomplished by activated tools may increase the working pressure required to subsequently activate additional tools. Accordingly, there exists a need for improved systems and methods of treating multiple zones of a wellbore. 
     SUMMARY 
     Disclosed herein is a wellbore servicing system, comprising a first sleeve system, the first sleeve system comprising a first ported case, a first sliding sleeve at least partially carried within the first ported case and movable relative to the first ported case between a first sleeve position in which the first sliding sleeve restricts fluid communication via the ported case and a second sleeve position in which the first sliding sleeve does not restrict fluid communication via the ported case, a first segmented seat, the first segmented seat being radially divided into a plurality of segments and movable relative to the first ported case between a first seat position in which the first seat restricts movement of the sliding sleeve relative to the ported case and a second seat position in which the first seat does not restrict movement of the sliding sleeve relative to the ported case, and a first sheath forming a continuous layer that covers one or more surfaces of the first segmented seat, the first sleeve system being transitionable from a first mode to a second mode and transitionable from the second mode to a third mode, wherein, when in the first mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is retained in the first seat position, wherein, when in the second mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is in the second seat position, and wherein, when in the third mode, the first sliding sleeve is in the second sleeve position. 
     Also disclosed herein is a wellbore servicing method comprising positioning a first sleeve system within the wellbore proximate to a first treatment zone, the first sleeve system comprising a first ported case, a first sliding sleeve at least partially carried within the first ported case and movable relative to the first ported case between a first sleeve position in which the first sliding sleeve restricts fluid communication via the ported case and a second sleeve position in which the first sliding sleeve does not restrict fluid communication via the ported case, a first segmented seat, the first segmented seat being radially divided into a plurality of segments and movable relative to the first ported case between a first seat position in which the first seat restricts movement of the sliding sleeve relative to the ported case and a second seat position in which the first seat does not restrict movement of the sliding sleeve relative to the ported case, and a first sheath forming a continuous layer that covers one or more surfaces of the first segmented seat, the first sleeve system being transitionable from a first mode to a second mode and transitionable from the second mode to a third mode, wherein, when in the first mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is retained in the first seat position, wherein, when in the second mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is in the second seat position, and wherein, when in the third mode, the first sliding sleeve is in the second sleeve position. 
    
    
     
       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 cut-away view of an embodiment of a wellbore servicing system according to the disclosure; 
         FIG. 2  is a cross-sectional view of a sleeve system of the wellbore servicing system of  FIG. 1  showing the sleeve system in an installation mode; 
         FIG. 2A  is a cross-sectional end-view of a segmented seat of the sleeve system of  FIG. 2  showing the segmented seat divided into three segments; 
         FIG. 2B  is a cross-sectional view of a segmented seat of the sleeve system of  FIG. 2  having a protective sheath applied thereto; 
         FIG. 3  is a cross-sectional view of the sleeve system of  FIG. 2  showing the sleeve system in a delay mode; 
         FIG. 4  is a cross-sectional view of the sleeve system of  FIG. 2  showing the sleeve system in a fully open mode; 
         FIG. 5  is a cross-sectional view of an alternative embodiment of a sleeve system according to the disclosure showing the sleeve system in an installation mode; 
         FIG. 6  is a cross-sectional view of the sleeve system of  FIG. 5  showing the sleeve system in another stage of the installation mode; 
         FIG. 7  is a cross-sectional view of the sleeve system of  FIG. 5  showing the sleeve system in a delay mode; and 
         FIG. 8  is a cross-sectional view of the sleeve system of  FIG. 5  showing the sleeve system in a fully open mode. 
     
    
    
     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. 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. 
     Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other 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. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Reference to up or down will be made for purposes of description with “up,” “upper,” “upward,” or “upstream” meaning toward the surface of the wellbore and with “down,” “lower,” “downward,” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. The term “zone” or “pay zone” as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally and/or vertically spaced portions of the same formation. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments and by referring to the accompanying drawings. 
     Disclosed herein are improved components, more specifically, a sheathed, segmented seat, for use in downhole tools. Such a sheathed, segmented seat may be employed alone or in combination with other components to transition one or more downhole tools from a first configuration to a second, third, or fourth, etc. configuration or mode by selectively receiving, retaining, and releasing an obturator (or any other suitable actuator or actuating device). 
     Also disclosed herein are sleeve systems and methods of using downhole tools, more specifically sleeve systems employing a sheathed, segmented seat that may be placed in a wellbore in a “run-in” configuration or an “installation mode” where a sleeve of the sleeve system blocks fluid transfer between a flow bore of the sleeve system and a port of the sleeve system. The installation mode may also be referred to as a “locked mode” since the sleeve is selectively locked in position relative to the port. In some embodiments, the locked positional relationship between the sleeves and the ports may be selectively discontinued or disabled by unlocking one or more components relative to each other, thereby potentially allowing movement of the sleeves relative to the ports. Still further, once the components are no longer locked in position relative to each other, some of the embodiments are configured to thereafter operate in a “delay mode” where relative movement between the sleeve and the port is delayed insofar as (1) such relative movement occurs but occurs at a reduced and/or controlled rate and/or (2) such relative movement is delayed until the occurrence of a selected wellbore condition. The delay mode may also be referred to as an “unlocked mode” since the sleeves are no longer locked in position relative to the ports. In some embodiments, the sleeve systems may be operated in the delay mode until the sleeve system achieves a “fully open mode” where the sleeve has moved relative to the port to allow maximum fluid communication between the flow bore of the sleeve system and the port of the sleeve system. It will be appreciated that devices, systems, and/or components of sleeve system embodiments that selectively contribute to establishing and/or maintaining the locked mode may be referred to as locking devices, locking systems, locks, movement restrictors, restrictors, and the like. It will also be appreciated that devices, systems, and/or components of sleeve system embodiments that selectively contribute to establishing and/or maintaining the delay mode may be referred to as delay devices, delay systems, delays, timers, contingent openers, and the like. 
     Also disclosed herein are methods for configuring a plurality of such sleeve systems so that one or more sleeve systems may be selectively transitioned from the installation mode to the delay mode by passing a single obturator through the plurality of sleeve systems. As will be explained below in greater detail, in some embodiments, one or more sleeve systems may be configured to interact with an obturator of a first configuration while other sleeve systems may be configured not to interact with the obturator having the first configuration, but rather, configured to interact with an obturator having a second configuration. Such differences in configurations amongst the various sleeve systems may allow an operator to selectively transition some sleeve systems to the exclusion of other sleeve systems. 
     Also disclosed herein are methods for performing a wellbore servicing operation employing a plurality of such sleeve systems by configuring such sleeve systems so that one or more of the sleeve systems may be selectively transitioned from the delay mode to the fully open mode at varying time intervals. Such differences in configurations amongst the various sleeve systems may allow an operator to selectively transition some sleeve systems to the exclusion of other sleeve systems, for example, such that a servicing fluid may be communicated (e.g., for the performance of a servicing operation) via a first sleeve system while not being communicated via a second, third, fourth, etc. sleeve system. The following discussion describes various embodiments of sleeve systems, the physical operation of the sleeve systems individually, and methods of servicing wellbores using such sleeve systems. 
     Referring to  FIG. 1 , an embodiment of a wellbore servicing system  100  is shown in an example of an operating environment. As depicted, the operating environment comprises a servicing rig  106  (e.g., a drilling, completion, or workover rig) that is positioned on the earth&#39;s surface  104  and extends over and around a wellbore  114  that penetrates a subterranean formation  102  for the purpose of recovering hydrocarbons. The wellbore  114  may be drilled into the subterranean formation  102  using any suitable drilling technique. The wellbore  114  extends substantially vertically away from the earth&#39;s surface  104  over a vertical wellbore portion  116 , deviates from vertical relative to the earth&#39;s surface  104  over a deviated wellbore portion  136 , and transitions to a horizontal wellbore portion  118 . In alternative operating environments, all or portions of a wellbore may be vertical, deviated at any suitable angle, horizontal, and/or curved. 
     At least a portion of the vertical wellbore portion  116  is lined with a casing  120  that is secured into position against the subterranean formation  102  in a conventional manner using cement  122 . In alternative operating environments, a horizontal wellbore portion may be cased and cemented and/or portions of the wellbore may be uncased. The servicing rig  106  comprises a derrick  108  with a rig floor  110  through which a tubing or work string  112  (e.g., cable, wireline, E-line, Z-line, jointed pipe, coiled tubing, casing, or liner string, etc.) extends downward from the servicing rig  106  into the wellbore  114  and defines an annulus  128  between the work string  112  and the wellbore  114 . The work string  112  delivers the wellbore servicing system  100  to a selected depth within the wellbore  114  to perform an operation such as perforating the casing  120  and/or subterranean formation  102 , creating perforation tunnels and/or fractures (e.g., dominant fractures, micro-fractures, etc.) within the subterranean formation  102 , producing hydrocarbons from the subterranean formation  102 , and/or other completion operations. The servicing rig  106  comprises a motor driven winch and other associated equipment for extending the work string  112  into the wellbore  114  to position the wellbore servicing system  100  at the selected depth. 
     While the operating environment depicted in  FIG. 1  refers to a stationary servicing rig  106  for lowering and setting the wellbore servicing system  100  within a land-based wellbore  114 , in alternative embodiments, mobile workover rigs, wellbore servicing units (such as coiled tubing units), and the like may be used to lower a wellbore servicing system into a wellbore. It should be understood that a wellbore servicing system may alternatively be used in other operational environments, such as within an offshore wellbore operational environment. 
     The subterranean formation  102  comprises a zone  150  associated with deviated wellbore portion  136 . The subterranean formation  102  further comprises first, second, third, fourth, and fifth horizontal zones,  150   a ,  150   b ,  150   c ,  150   d ,  150   e , respectively, associated with the horizontal wellbore portion  118 . In this embodiment, the zones  150 ,  150   a ,  150   b ,  150   c ,  150   d ,  150   e  are offset from each other along the length of the wellbore  114  in the following order of increasingly downhole location:  150 ,  150   e ,  150   d ,  150   c ,  150   b , and  150   a . In this embodiment, stimulation and production sleeve systems  200 ,  200   a ,  200   b ,  200   c ,  200   d , and  200   e  are located within wellbore  114  in the work string  112  and are associated with zones  150 ,  150   a ,  150   b ,  150   c ,  150   d , and  150   e , respectively. It will be appreciated that zone isolation devices such as annular isolation devices (e.g., annular packers and/or swellpackers) may be selectively disposed within wellbore  114  in a manner that restricts fluid communication between spaces immediately uphole and downhole of each annular isolation device. 
     Referring now to  FIG. 2 , a cross-sectional view of an embodiment of a stimulation and production sleeve system  200  (hereinafter referred to as “sleeve system”  200 ) is shown. Many of the components of sleeve system  200  lie substantially coaxial with a central axis  202  of sleeve system  200 . Sleeve system  200  comprises an upper adapter  204 , a lower adapter  206 , and a ported case  208 . The ported case  208  is joined between the upper adapter  204  and the lower adapter  206 . Together, inner surfaces  210 ,  212 ,  214  of the upper adapter  204 , the lower adapter  206 , and the ported case  208 , respectively, substantially define a sleeve flow bore  216 . The upper adapter  204  comprises a collar  218 , a makeup portion  220 , and a case interface  222 . The collar  218  is internally threaded and otherwise configured for attachment to an element of work string  112  that is adjacent and uphole of sleeve system  200  while the case interface  222  comprises external threads for engaging the ported case  208 . The lower adapter  206  comprises a nipple  224 , a makeup portion  226 , and a case interface  228 . The nipple  224  is externally threaded and otherwise configured for attachment to an element of work string  112  that is adjacent and downhole of sleeve system  200  while the case interface  228  also comprises external threads for engaging the ported case  208 . 
     The ported case  208  is substantially tubular in shape and comprises an upper adapter interface  230 , a central ported body  232 , and a lower adapter interface  234 , each having substantially the same exterior diameters. The inner surface  214  of ported case  208  comprises a case shoulder  236  that separates an upper inner surface  238  from a lower inner surface  240 . The ported case  208  further comprises ports  244 . As will be explained in further detail below, ports  244  are through holes extending radially through the ported case  208  and are selectively used to provide fluid communication between sleeve flow bore  216  and a space immediately exterior to the ported case  208 . 
     The sleeve system  200  further comprises a piston  246  carried within the ported case  208 . The piston  246  is substantially configured as a tube comprising an upper seal shoulder  248  and a plurality of slots  250  near a lower end  252  of the piston  246 . With the exception of upper seal shoulder  248 , the piston  246  comprises an outer diameter smaller than the diameter of the upper inner surface  238 . The upper seal shoulder  248  carries a circumferential seal  254  that provides a fluid tight seal between the upper seal shoulder  248  and the upper inner surface  238 . Further, case shoulder  236  carries a seal  254  that provides a fluid tight seal between the case shoulder  236  and an outer surface  256  of piston  246 . In the embodiment shown and when the sleeve system  200  is configured in an installation mode, the upper seal shoulder  248  of the piston  246  abuts the upper adapter  204 . The piston  246  extends from the upper seal shoulder  248  toward the lower adapter  206  so that the slots  250  are located downhole of the seal  254  carried by case shoulder  236 . In this embodiment, the portion of the piston  246  between the seal  254  carried by case shoulder  236  and the seal  254  carried by the upper seal shoulder  248  comprises no apertures in the tubular wall (i.e., is a solid, fluid tight wall). As shown in this embodiment and in the installation mode of  FIG. 2 , a low pressure chamber  258  is located between the outer surface  256  of piston  246  and the upper inner surface  238  of the ported case  208 . 
     The sleeve system  200  further comprises a sleeve  260  carried within the ported case  208  below the piston  246 . The sleeve  260  is substantially configured as a tube comprising an upper seal shoulder  262 . With the exception of upper seal shoulder  262 , the sleeve  260  comprises an outer diameter substantially smaller than the diameter of the lower inner surface  240 . The upper seal shoulder  262  carries two circumferential seals  254 , one seal  254  near each end (e.g., upper and lower ends) of the upper seal shoulder  262 , that provide fluid tight seals between the upper seal shoulder  262  and the lower inner surface  240  of ported case  208 . Further, two seals  254  are carried by the sleeve  260  near a lower end  264  of sleeve  260 , and the two seals  254  form fluid tight seals between the sleeve  260  and the inner surface  212  of the lower adapter  206 . In this embodiment and installation mode shown in  FIG. 2 , an upper end  266  of sleeve  260  substantially abuts a lower end of the case shoulder  236  and the lower end  252  of piston  246 . In this embodiment and installation mode shown in  FIG. 2 , the upper seal shoulder  262  of the sleeve  260  seals ports  244  from fluid communication with the sleeve flow bore  216 . Further, the seal  254  carried near the lower end of the upper seal shoulder  262  is located downhole of (e.g., below) ports  244  while the seal  254  carried near the upper end of the upper seal shoulder  262  is located uphole of (e.g., above) ports  244 . The portion of the sleeve  260  between the seal  254  carried near the lower end of the upper seal shoulder  262  and the seals  254  carried by the sleeve  260  near a lower end  264  of sleeve  260  comprises no apertures in the tubular wall (i.e., is a solid, fluid tight wall). As shown in this embodiment and in the installation mode of  FIG. 2 , a fluid chamber  268  is located between the outer surface of sleeve  260  and the lower inner surface  240  of the ported case  208 . 
     The sleeve system  200  further comprises a segmented seat  270  carried within the lower adapter  206  below the sleeve  260 . The segmented seat  270  is substantially configured as a tube comprising an inner bore surface  273  and a chamfer  271  at the upper end of the seat, the chamfer  271  being configured and/or sized to selectively engage and/or retain an obturator of a particular size and/or shape (such as obturator  276 ). In the embodiment of  FIG. 2 , the segmented seat  270  may be radially divided with respect to central axis  202  into segments. For example, referring now to  FIG. 2A , the segmented seat  270  is divided (e.g., as represented by dividing or segmenting lines/cuts  277 ) into three complementary segments of approximately equal size, shape, and/or configuration. In the embodiment of  FIG. 2A , the three complementary segments ( 270 A,  270 B, and  270 C, respectively) together form the segmented seat  270 , with each of the segments ( 270 A,  270 B, and  270 C) constituting about one-third (e.g., extending radially about 120°) of the segmented seat  270 . In an alternative embodiment, a segmented seat like segmented seat  270  may comprise any suitable number of equally or unequally-divided segments. For example, a segmented seat may comprise two, four, five, six, or more complementary, radial segments. The segmented seat  270  may be formed from a suitable material. Nonlimiting examples of such a suitable material include composites, phenolics, cast iron, aluminum, brass, various metal alloys, rubbers, ceramics, or combinations thereof. In an embodiment, the material employed to form the segmented seat may be characterized as drillable, that is, the segmented seat  270  may be fully or partially degraded or removed by drilling, as will be appreciated by one of skill in the art with the aid of this disclosure. Segments  270 A,  270 B, and  270 C may be formed independently or, alternatively, a preformed seat may be divided into segments. It will be appreciated that while obturator  276  is shown in  FIG. 2  with the sleeve system  200  in an installation mode, in most applications of the sleeve system  200 , the sleeve system  200  would be placed downhole without the obturator  276 , and the obturator  276  would subsequently be provided as discussed below in greater detail. Further, while the obturator  276  is a ball, an obturator of other embodiments may be any other suitable shape or device for sealing against a protective sheath  272  and or a seat gasket (both of which will be discussed below) and obstructing flow through the sleeve flow bore  216 . 
     In an alternative embodiment, a sleeve system like sleeve system  200  may comprise an expandable seat. Such an expandable seat may be constructed of, for example but not limited to, a low alloy steel such as AISI 4140 or 4130, and is generally configured to be biased radially outward so that if unrestricted radially, a diameter (e.g., outer/inner) of the seat  270  increases. In some embodiments, the expandable seat may be constructed from a generally serpentine length of AISI 4140. For example, the expandable seat may comprise a plurality of serpentine loops between upper and lower portions of the seat and continuing circumferentially to form the seat. In an embodiment, such an expandable seat may be covered by a protective sheath  272  (as will be discussed below) and/or may comprise a seat gasket. 
     In the embodiment of  FIG. 2 , one or more surfaces of the segmented seat  270  are covered by a protective sheath  272 . Referring to  FIG. 2B , an embodiment of the segmented seat  270  and protective sheath  272  are illustrated in greater detail. In the embodiment of  FIG. 2B  the protective sheath  272  covers the chamfer  271  of the segmented seat  270 , the inner bore  273  of the segmented seat  270 , and a lower face  275  of the segmented seat  270 . In an alternative embodiment, the protective sheath  272  may cover the chamfer  271 , the inner bore  273 , and a lower face  275 , the back  279  of the segmented seat  270 , or combinations thereof. In another alternative embodiment, a protective sheath may cover any one or more of the surfaces of a segmented seat  270 , as will be appreciated by one of skill in the art viewing this disclosure. In the embodiment illustrated by  FIGS. 2, 2A, and 2B , the protective sheath  272  forms a continuous layer over those surfaces of the segmented seat  270  in fluid communication with the sleeve flow bore  216 . For example, small crevices or gaps (e.g., at dividing lines  277 ) may exist at the radially extending divisions between the segments (e.g.,  270 A,  270 B, and  270 C) of the segmented seat  270 . In an embodiment, the continuous layer formed by the protective sheath  272  may fill, seal, minimize, or cover, any such crevices or gaps such that a fluid flowing via the sleeve flow bore  216  will be impeded from contacting and/or penetrating any such crevices or gaps. 
     In an embodiment, the protective sheath  272  may be applied to the segmented seat  270  while the segments  270 A,  270 B, and  270 C are retained in a close conformation (e.g., where each segment abuts the adjacent segments, as illustrated in  FIG. 2A ). For example, the segmented seat  270  may be retained in such a close conformation by bands, bindings, straps, wrappings, or combinations thereof. In an embodiment, the segmented seat  270  may be coated and/or covered with the protective sheath  272  via any suitable method of application. For example, the segmented seat  270  may submerged (e.g., dipped) in a material (as will be discussed below) that will form the protective sheath  272 , a material that will form the protective sheath  272  may be sprayed and/or brushed onto the desired surfaces of the segmented seat  270 , or combinations thereof. In such an embodiment, the protective sheath  270  may adhere to the segments  270 A,  270 B, and  270 C of the segmented seat  270  and thereby retain the segments in the close conformation. 
     In an alternative embodiment, the protective sheath  272  may be applied individually to each of the segments  270 A,  270 B, and  270 C of the segmented seat  270 . For example, the segments  270 A,  270 B, and/or  270 C may individually submerged (e.g., dipped) in a material that will form the protective sheath  272 , a material that will form the protective sheath  272  may be sprayed and/or brushed onto the desired surfaces of the segments  270 A,  270 B, and  270 C, or combinations thereof. In such an embodiment, the protective sheath  272  may adhere to some or all of the surfaces of each of the segments  270 A,  270 B, and  270 C. After the protective sheath  272  has been applied, the segments  270 A,  270 B, and  270 C may be brought together to form the segmented seat  270 . The segmented seat  270  may be retained in such a close conformation (e.g., as illustrated in  FIG. 2A ) by bands, bindings, straps, wrappings, or combinations thereof. In such an embodiment, the protective sheath  272  may be sufficiently malleable or pliable that when the sheathed segments are retained in the close conformation, any crevices or gaps between the segments (e.g., segments  270 A,  270 B, and  270 C) will be filled or minimized by the protective sheath  272  such that a fluid flowing via the sleeve flow bore  216  will be impeded from contacting and/or penetrating any such crevices or gaps. 
     In still another alternative embodiment, the protective sheath  272  need not be applied directly to the segmented seat  270 . For example, a protective sheath may be fitted to or within the segmented seat  270 , draped over a portion of segmented seat  270 , or the like. The protective sheath may comprise a sleeve or like insert configured and sized to be positioned within the bore of the segmented sheath and to fit against the chamfer  271  of the segmented seat  270 , the inner bore  273  of the segmented seat  270 , and/or the lower face  275  of the segmented seat  270  and thereby form a continuous layer that may fill, seal, or cover, any such crevices or gaps such that a fluid flowing via the sleeve flow bore  216  will be impeded from contacting and/or penetrating any such crevices or gaps. In another embodiment where the protective sheath  272  comprises a heat-shrinkable material (as will be discussed below), such a material may be positioned over, around, within, about, or similarly, at least a portion of the segmented seat  270  and/or one or more of the segments  270 A,  270 B, and  270 C, and heated sufficiently to cause the shrinkable material to shrink to the surfaces of the segmented seat  270  and/or the segments  270 A,  270 B, and  270 C. 
     In an embodiment, the protective sheath  272  may be formed from a suitable material. Nonlimiting examples of such a suitable material include ceramics, carbides, hardened plastics, molded rubbers, various heat-shrinkable materials, or combinations thereof. In an embodiment, the protective sheath may be characterized as having a hardness of from about 25 durometers to about 150 durometers, alternatively, from about 50 durometers to about 100 durometers, alternatively, from about 60 durometers to about 80 durometers. In an embodiment, the protective sheath may be characterized as having a thickness of from about 1/64 th  of an inch to about 3/16 th  of an inch, alternatively, about 1/32 nd  of an inch. Examples of materials suitable for the formation of the protective sheath include nitrile rubber, which commercially available from several rubber, plastic, and/or composite materials companies. 
     In an embodiment, a protective sheath, like protective sheath  272 , may be employed to advantageously lessen the degree of erosion and/or degradation to a segmented seat, like segmented seat  270 . Not intending to be bound by theory, such a protective sheath may improve the service life of a segmented seat covered by such a protective sheath by decreasing the impingement of erosive fluids (e.g., cutting, hydrojetting, and/or fracturing fluids comprising abrasives and/or proppants) with the segmented seat. In an embodiment, a segmented seat protected by such a protective sheath may have a service life at least 20% greater, alternatively, at least 30% greater, alternatively, at least 35% greater than an otherwise similar seat not protected by such a protective sheath. 
     In an embodiment, the segmented seat  270  may further comprise a seat gasket that serves to seal against an obturator. In some embodiments, the seat gasket may be constructed of rubber. In such an embodiment and installation mode, the seat gasket may be substantially captured between the expandable seat and the lower end of the sleeve. In an embodiment, the protective sheath  272  may serve as such a gasket, for example, by engaging and/or sealing an obturator. In such an embodiment, the protective sheath  272  may have a variable thickness. For example, the surface(s) of the protective sheath  272  configured to engage the obturator (e.g., chamfer  271 ) may comprise a greater thickness than the one or more other surfaces of the protective sheath  272 . 
     The sleeve system  200  further comprises a seat support  274  carried within the lower adapter  206  below the seat  270 . The seat support  274  is substantially formed as a tubular member. The seat support  274  comprises an outer chamfer  278  on the upper end of the seat support  274  that selectively engages an inner chamfer  280  on the lower end of the segmented seat  270 . The seat support  274  comprises a circumferential channel  282 . The seat support  274  further comprises two seals  254 , one seal  254  carried uphole of (e.g., above) the channel  282  and the other seal  254  carried downhole of (e.g., below) the channel  282 , and the seals  254  form a fluid seal between the seat support  274  and the inner surface  212  of the lower adapter  206 . In this embodiment and when in installation mode as shown in  FIG. 2 , the seat support  274  is restricted from downhole movement by a shear pin  284  that extends from the lower adapter  206  and is received within the channel  282 . Accordingly, each of the seat  270 , protective sheath  272 , sleeve  260 , and piston  246  are captured between the seat support  274  and the upper adapter  204  due to the restriction of movement of the seat support  274 . 
     The lower adapter  206  further comprises a fill port  286 , a fill bore  288 , a metering device receptacle  290 , a drain bore  292 , and a plug  294 . In this embodiment, the fill port  286  comprises a check valve device housed within a radial through bore formed in the lower adapter  206  that joins the fill bore  288  to a space exterior to the lower adapter  206 . The fill bore  288  is formed as a substantially cylindrical longitudinal bore that lies substantially parallel to the central axis  202 . The fill bore  288  joins the fill port  286  in fluid communication with the fluid chamber  268 . Similarly, the metering device receptacle  290  is formed as a substantially cylindrical longitudinal bore that lies substantially parallel to the central axis  202 . The metering device receptacle  290  joins the fluid chamber  268  in fluid communication with the drain bore  292 . Further, drain bore  292  is formed as a substantially cylindrical longitudinal bore that lies substantially parallel to the central axis  202 . The drain bore  292  extends from the metering device receptacle  290  to each of a plug bore  296  and a shear pin bore  298 . In this embodiment, the plug bore  296  is a radial through bore formed in the lower adapter  206  that joins the drain bore  292  to a space exterior to the lower adapter  206 . The shear pin bore  298  is a radial through bore formed in the lower adapter  206  that joins the drain bore  292  to sleeve flow bore  216 . However, in the installation mode shown in  FIG. 2 , fluid communication between the drain bore  292  and the flow bore  216  is obstructed by seat support  274 , seals  254 , and shear pin  284 . 
     The sleeve system  200  further comprises a fluid metering device  291  received at least partially within the metering device receptacle  290 . In this embodiment, the fluid metering device  291  is a fluid restrictor, for example a precision microhydraulics fluid restrictor or micro-dispensing valve of the type produced by The Lee Company of Westbrook, Conn. However, it will be appreciated that in alternative embodiments any other suitable fluid metering device may be used. For example, any suitable electro-fluid device may be used to selectively pump and/or restrict passage of fluid through the device. In further alternative embodiments, a fluid metering device may be selectively controlled by an operator and/or computer so that passage of fluid through the metering device may be started, stopped, and/or a rate of fluid flow through the device may be changed. Such controllable fluid metering devices may be, for example, substantially similar to the fluid restrictors produced by The Lee Company. Suitable commercially available examples of such a fluid metering device include the JEVA1835424H and the JEVA1835385H, commercially available from The Lee Company. 
     The lower adapter  206  may be described as comprising an upper central bore  300  having an upper central bore diameter  302 , the seat catch bore  304  having a seat catch bore diameter  306 , and a lower central bore  308  having a lower central bore diameter  310 . The upper central bore  300  is joined to the lower central bore  308  by the seat catch bore  304 . In this embodiment, the upper central bore diameter  302  is sized to closely fit an exterior of the seat support  274 , and in an embodiment is about equal to the diameter of the outer surface of the sleeve  260 . However, the seat catch bore diameter  306  is substantially larger than the upper central bore diameter  302 , thereby allowing radial expansion of the expandable seat  270  when the expandable seat  270  enters the seat catch bore  304  as described in greater detail below. In this embodiment, the lower central bore diameter  310  is smaller than each of the upper central bore diameter  302  and the seat catch bore diameter  306 , and in an embodiment is about equal to the diameter of the inner surface of the sleeve  260 . Accordingly, as described in greater detail below, while the seat support  274  closely fits within the upper central bore  300  and loosely fits within the seat catch bore diameter  306 , the seat support  274  is too large to fit within the lower central bore  308 . 
     Referring now to  FIGS. 2-4 , a method of operating the sleeve system  200  is described below. Most generally,  FIG. 2  shows the sleeve system  200  in an “installation mode” where sleeve  260  is restricted from moving relative to the ported case  208  by the shear pin  284 .  FIG. 3  shows the sleeve system  200  in a “delay mode” where sleeve  260  is no longer restricted from moving relative to the ported case  208  by the shear pin  284  but remains restricted from such movement due to the presence of a fluid within the fluid chamber  268 . Finally,  FIG. 4  shows the sleeve system  200  in a “fully open mode” where sleeve  260  no longer obstructs a fluid path between ports  244  and sleeve flow bore  216 , but rather, a fluid path is provided between ports  244  and the sleeve flow bore  216  through slots  250  of the piston  246 . 
     Referring now to  FIG. 2 , while the sleeve system  200  is in the installation mode, each of the piston  246 , sleeve  260 , protective sheath  272 , segmented seat  270 , and seat support  274  are all restricted from movement along the central axis  202  at least because the shear pin  284  is received within both the shear pin bore  298  of the lower adapter  206  and within the circumferential channel  282  of the seat support  274 . Also in this installation mode, low pressure chamber  258  is provided a volume of compressible fluid at atmospheric pressure. It will be appreciated that the fluid within the low pressure chamber  258  may be air, gaseous nitrogen, or any other suitable compressible fluid. Because the fluid within the low pressure chamber  258  is at atmospheric pressure, when sleeve system  200  is located downhole, the fluid pressure within the sleeve flow bore  216  is substantially greater than the pressure within the low pressure chamber  258 . Such a pressure differential may be attributed in part due to the weight of the fluid column within the sleeve flow bore  216 , and in some circumstances, also due to increased pressures within the sleeve flow bore  216  caused by pressurizing the sleeve flow bore  216  using pumps. Further, a fluid is provided within the fluid chamber  268 . Generally, the fluid may be introduced into the fluid chamber  268  through the fill port  286  and subsequently through the fill bore  288 . During such filling of the fluid chamber  268 , one or more of the shear pin  284  and the plug  294  may be removed to allow egress of other fluids or excess of the filling fluid. Thereafter, the shear pin  284  and/or the plug  294  may be replaced to capture the fluid within the fill bore  288 , fluid chamber  268 , the metering device  291 , and the drain bore  292 . With the sleeve system  200  and installation mode described above, though the sleeve flow bore  216  may be pressurized, movement of the above-described restricted portions of the sleeve system  200  remains restricted. 
     Referring now to  FIG. 3 , the obturator  276  may be passed through the work string  112  until the obturator  276  substantially seals against the protective sheath  272  (as shown in  FIG. 2 ), alternatively, the seat gasket in embodiments where a seat gasket is present. With the obturator  276  in place against the protective sheath  272  and/or seat gasket, the pressure within the sleeve flow bore  216  may be increased uphole of the obturator until the obturator  276  transmits sufficient force through the protective sheath  272 , the segmented seat  270 , and the seat support  274  to cause the shear pin  284  to shear. Once the shear pin  284  has sheared, the obturator  276  drives the protective sheath  272 , the segmented seat  270 , and the seat support  274  downhole from their installation mode positions. However, even though the sleeve  260  is no longer restricted from downhole movement by the protective sheath  272  and the segmented seat  270 , downhole movement of the sleeve  260  and the piston  246  above the sleeve  260  is delayed. Once the protective sheath  272  and the segmented seat  270  no longer obstruct downward movement of the sleeve  260 , the sleeve system  200  may be referred to as being in a “delayed mode.” 
     More specifically, downhole movement of the sleeve  260  and the piston  246  are delayed by the presence of fluid within fluid chamber  268 . With the sleeve system  200  in the delay mode, the relatively low pressure within the low pressure chamber  258  in combination with relatively high pressures within the sleeve flow bore  216  acting on the upper end  253  of the piston  246 , the piston  246  is biased in a downhole direction. However, downhole movement of the piston  246  is obstructed by the sleeve  260 . Nonetheless, downhole movement of the obturator  276 , the protective sheath  272 , the segmented seat  270 , and the seat support  274  are not restricted or delayed by the presence of fluid within fluid chamber  268 . Instead, the protective sheath  272 , the segmented seat  270 , and the seat support  274  move downhole into the seat catch bore  304  of the lower adapter  206 . While within the seat catch bore  304 , the protective sheath  272  expands, tears, breaks, or disintegrates, thereby allowing the segmented seat  270  to expand radially at the divisions between the segments (e.g.,  270 A,  270 B, and  270 C) to substantially match the seat catch bore diameter  306 . In an embodiment where a band, strap, binding, or the like is employed to hold segments (e.g.,  270 A,  270 B, and  270 C) of the segmented seat  270  together, such band, strap, or binding may similarly expand, tear, break, or disintegrate to allow the segmented seat  270  to expand. The seat support  274  is subsequently captured between the expanded seat  270  and substantially at an interface (e.g., a shoulder formed) between the seat catch bore  304  and the lower central bore  308 . For example, the outer diameter of seat support  274  is greater than the lower central bore diameter  310 . Once the seat  270  expands sufficiently, the obturator  276  is free to pass through the expanded seat  270 , through the seat support  274 , and into the lower central bore  308 . In an alternative embodiment, the segmented seat  270 , the segments (e.g.,  270 A,  270 B, and  270 C) thereof, the protective sheath  272 , or combinations thereof may be configured to disintegrate when acted upon by the obturator  276  as described above. In such an embodiment, the remnants of the segmented seat  270 , the segments (e.g.,  270 A,  270 B, and  270 C) thereof, or the protective sheath  272  may fall (e.g., by gravity) or be washed (e.g., by movement of a fluid) out of the sleeve flow bore  216 . In either embodiment and as will be explained below in greater detail, the obturator  276  is then free to exit the sleeve system  200  and flow further downhole to interact with additional sleeve systems. 
     Even after the exiting of the obturator  276  from sleeve system  200 , downhole movement of the sleeve  260  occurs at a rate dependent upon the rate at which fluid is allowed to escape the fluid chamber  268  through the fluid metering device  291 . It will be appreciated that fluid may escape the fluid chamber  268  by passing from the fluid chamber  268  through the fluid metering device  291 , through the drain bore  292 , through the shear pin bore  298  around the remnants of the sheared shear pin  284 , and into the sleeve flow bore  216 . As the volume of fluid within the fluid chamber  268  decreases, the sleeve  260  moves in a downhole direction until the upper seal shoulder  262  of the sleeve  260  contacts the lower adapter  206  near the metering device receptacle  290 . It will be appreciated that shear pins or screws with central bores that provide a convenient fluid path may be used in place of shear pin  284 . 
     Referring now to  FIG. 4 , when substantially all of the fluid within fluid chamber  268  has escaped, sleeve system  200  is in a “fully open mode.” In the fully open mode, upper seal shoulder  262  of sleeve  260  contacts lower adapter  206  so that the fluid chamber  268  is substantially eliminated. Similarly, in a fully open mode, the upper seal shoulder  248  of the piston  246  is located substantially further downhole and has compressed the fluid within low pressure chamber  258  so that the upper seal shoulder  248  is substantially closer to the case shoulder  236  of the ported case  208 . With the piston  246  in this position, the slots  250  are substantially aligned with ports  244  thereby providing fluid communication between the sleeve flow bore  216  and the ports  244 . It will be appreciated that the sleeve system  200  is configured in various “partially opened modes” when movement of the components of sleeve system  200  provides fluid communication between sleeve flow bore  216  and the ports  244  to a degree less than that of the “fully open mode.” It will further be appreciated that with any degree of fluid communication between the sleeve flow bore  216  and the ports  244 , fluids may be forced out of the sleeve system  200  through the ports  244 , or alternatively, fluids may be passed into the sleeve system  200  through the ports  244 . 
     Referring now to  FIG. 5 , a cross-sectional view of an alternative embodiment of a stimulation and production sleeve system  400  (hereinafter referred to as “sleeve system”  400 ) is shown. Many of the components of sleeve system  400  lie substantially coaxial with a central axis  402  of sleeve system  400 . Sleeve system  400  comprises an upper adapter  404 , a lower adapter  406 , and a ported case  408 . The ported case  408  is joined between the upper adapter  404  and the lower adapter  406 . Together, inner surfaces  410 ,  412  of the upper adapter  404  and the lower adapter  406 , respectively, and the inner surface of the ported case  408  substantially define a sleeve flow bore  416 . The upper adapter  404  comprises a collar  418 , a makeup portion  420 , and a case interface  422 . The collar  418  is internally threaded and otherwise configured for attachment to an element of a work string, such as for example, work string  112 , that is adjacent and uphole of sleeve system  400  while the case interface  422  comprises external threads for engaging the ported case  408 . The lower adapter  406  comprises a makeup portion  426  and a case interface  428 . The lower adapter  406  is configured (e.g., threaded) for attachment to an element of a work string that is adjacent and downhole of sleeve system  400  while the case interface  428  comprises external threads for engaging the ported case  408 . 
     The ported case  408  is substantially tubular in shape and comprises an upper adapter interface  430 , a central ported body  432 , and a lower adapter interface  434 , each having substantially the same exterior diameters. The inner surface  414  of ported case  408  comprises a case shoulder  436  between an upper inner surface  438  and ports  444 . A lower inner surface  440  is adjacent and below the upper inner surface  438 , and the lower inner surface  440  comprises a smaller diameter than the upper inner surface  438 . As will be explained in further detail below, ports  444  are through holes extending radially through the ported case  408  and are selectively used to provide fluid communication between sleeve flow bore  416  and a space immediately exterior to the ported case  408 . 
     The sleeve system  400  further comprises a sleeve  460  carried within the ported case  408  below the upper adapter  404 . The sleeve  460  is substantially configured as a tube comprising an upper section  462  and a lower section  464 . The lower section  464  comprises a smaller outer diameter than the upper section  462 . The lower section  464  comprises circumferential ridges or teeth  466 . In this embodiment and when in installation mode as shown in  FIG. 5 , an upper end  468  of sleeve  460  substantially abuts the upper adapter  404  and extends downward therefrom, thereby blocking fluid communication between the ports  444  and the sleeve flow bore  416 . 
     The sleeve system  400  further comprises a piston  446  carried within the ported case  408 . The piston  446  is substantially configured as a tube comprising an upper portion  448  joined to a lower portion  450  by a central body  452 . In the installation mode, the piston  446  abuts the lower adapter  406 . Together, an upper end  453  of piston  446 , upper sleeve section  462 , the upper inner surface  438 , the lower inner surface  440 , and the lower end of case shoulder  436  form a bias chamber  451 . In this embodiment, a compressible spring  424  is received within the bias chamber  451  and the spring  424  is generally wrapped around the sleeve  460 . The piston  446  further comprises a c-ring channel  454  for receiving a c-ring  456  therein. The piston also comprises a shear pin receptacle  457  for receiving a shear pin  458  therein. The shear pin  458  extends from the shear pin receptacle  457  into a similar shear pin aperture  459  that is formed in the sleeve  460 . Accordingly, in the installation mode shown in  FIG. 5 , the piston  446  is restricted from moving relative to the sleeve  460  by the shear pin  458 . It will be appreciated that the c-ring  456  comprises ridges or teeth  469  that complement the teeth  466  in a manner that allows sliding of the c-ring  456  upward relative to the sleeve  460  but not downward while the sets of teeth  466 ,  469  are engaged with each other. 
     The sleeve system  400  further comprises a segmented seat  470  carried within the piston  446  and within an upper portion of the lower adapter  406 . In the embodiment of  FIG. 5 , the segmented seat  470  is substantially configured as a tube comprising an inner bore surface  473  and a chamfer  471  at the upper end of the seat, the chamfer  471  being configured and/or sized to selectively engage and/or retain an obturator of a particular size and/or shape (such as obturator  476 ). Similar to the segmented seat  270  disclosed above with respect to  FIGS. 2-4 , in the embodiment of  FIG. 5  the segmented seat  470  may be radially divided with respect to central axis  402  into segments. For example, like the segmented seat  270  illustrated in  FIG. 2A , the segmented seat  470  is divided into three complementary segments of approximately equal size, shape, and/or configuration. In an embodiment, the three complementary segments (similar to segments  270 A,  270 B, and  270 C disclosed with respect to  FIG. 2A ) together form the segmented seat  470 , with each of the segments constituting about one-third (e.g., extending radially about 120°) of the segmented seat  470 . In an alternative embodiment, a segmented seat like segmented seat  470  may comprise any suitable number of equally or unequally-divided segments. For example, a segmented seat may comprise two, four, five, six, or more complementary, radial segments. The segmented seat  470  may be formed from a suitable material and in any suitable manner, for example, as disclosed above with respect to segmented seat  270  illustrated in  FIGS. 2-4 . It will be appreciated that while obturator  476  is shown in  FIG. 5  with the sleeve system  400  in an installation mode, in most applications of the sleeve system  400 , the sleeve system  400  would be placed downhole without the obturator  476 , and the obturator  476  would subsequently be provided as discussed below in greater detail. Further, while the obturator  476  is a ball, an obturator of other embodiments may be any other suitable shape or device for sealing against a protective sheath  272  and/or a seat gasket (both of which will be discussed below) and obstructing flow through the sleeve flow bore  216 . 
     In an alternative embodiment, a sleeve system like sleeve system  200  may comprise an expandable seat. Such an expandable seat may be constructed of, for example but not limited to, a low alloy steel such as AISI 4140 or 4130, and is generally configured to be biased radially outward so that if unrestricted radially, a diameter (e.g., outer/inner) of the seat  270  increases. In some embodiments, the expandable seat may be constructed from a generally serpentine length of AISI 4140. For example, the expandable seat may comprise a plurality of serpentine loops between upper and lower portions of the seat and continuing circumferentially to form the seat. In an embodiment, such an expandable seat may be covered by a protective sheath  272  (as will be discussed below) and/or may comprise a seat gasket. 
     Similar to the segmented seat  270  disclosed above with respect to  FIGS. 2-4 , in the embodiment of  FIG. 5 , one or more surfaces of the segmented seat  470  are covered by a protective sheath  472 . Like the segmented seat  270  illustrated in  FIG. 2A , the segmented seat  470  covers one or more of the chamfer  471  of the segmented seat  470 , the inner bore  473  of the segmented seat  470 , a lower face  475  of the segmented seat  470 , or combinations thereof. In an alternative embodiment, a protective sheath may cover any one or more of the surfaces of a segmented seat  470 , as will be appreciated by one of skill in the art viewing this disclosure. In an embodiment, the protective sheath  472  may form a continuous layer over those surfaces of the segmented seat  470  in fluid communication with the sleeve flow bore  416 , may be formed in any suitable manner, and may be formed of a suitable material, for example, as disclosed above with respect to segmented seat  270  illustrated in  FIGS. 2-4 . In summary, all disclosure herein with respect to protective sheath  272  and segmented seat  270  are applicable to protective sheath  472  and segmented seat  470 . 
     In an embodiment, the segmented seat  470  may further comprise a seat gasket that serves to seal against an obturator. In some embodiments, the seat gasket may be constructed of rubber. In such an embodiment and installation mode, the seat gasket may be substantially captured between the expandable seat and the lower end of the sleeve. In an embodiment, the protective sheath  472  may serve as such a gasket, for example, by engaging and/or sealing an obturator. In such an embodiment, the protective sheath  472  may have a variable thickness. For example, the surface(s) of the protective sheath  472  configured to engage the obturator (e.g., chamfer  471 ) may comprise a greater thickness than the one or more other surfaces of the protective sheath  472 . 
     The seat  470  further comprises a seat shear pin aperture  478  that is radially aligned with and substantially coaxial with a similar piston shear pin aperture  480  formed in the piston  446 . Together, the apertures  478 ,  480  receive a shear pin  482 , thereby restricting movement of the seat  470  relative to the piston  446 . Further, the piston  446  comprises a lug receptacle  484  for receiving a lug  486 . In the installation mode of the sleeve system  400 , the lug  486  is captured within the lug receptacle  484  between the seat  470  and the ported case  408 . More specifically, the lug  486  extends into a substantially circumferential lug channel  488  formed in the ported case  408 , thereby restricting movement of the piston  446  relative to the ported case  408 . Accordingly, in the installation mode, with each of the shear pins  458 ,  482  and the lug  486  in place as described above, the piston  446 , sleeve  460 , and seat  470  are all substantially locked into position relative to the ported case  408  and relative to each other so that fluid communication between the sleeve flow bore  416  and the ports  444  is prevented. 
     The lower adapter  406  may be described as comprising an upper central bore  490  having an upper central bore diameter  492  and a seat catch bore  494  having a seat catch bore diameter  496  joined to the upper central bore  490 . In this embodiment, the upper central bore diameter  492  is sized to closely fit an exterior of the seat  470 , and, in an embodiment, is about equal to the diameter of the outer surface of the lower sleeve section  464 . However, the seat catch bore diameter  496  is substantially larger than the upper central bore diameter  492 , thereby allowing radial expansion of the expandable seat  470  when the expandable seat  470  enters the seat catch bore  494  as described in greater detail below. 
     Referring now to  FIGS. 5-8 , a method of operating the sleeve system  400  is described below. Most generally,  FIG. 5  shows the sleeve system  400  in an “installation mode” where sleeve  460  is at rest in position relative to the ported case  408  and so that the sleeve  460  prevents fluid communication between the sleeve flow bore  416  and the ports  444 . It will be appreciated that sleeve  460  may be pressure balanced.  FIG. 6  shows the sleeve system  400  in another stage of the installation mode where sleeve  460  is no longer restricted from moving relative to the ported case  408  by either the shear pin  482  or the lug  486 , but remains restricted from such movement due to the presence of the shear pin  458 . In the case where the sleeve  460  is pressure balanced, the pin  458  may primarily be used to prevent inadvertent movement of the sleeve  460  due to accidentally dropping the tool or other undesirable acts that cause the sleeve  460  to move due to undesired momentum forces.  FIG. 7  shows the sleeve system  400  in a “delay mode” where movement of the sleeve  460  relative to the ported case  408  has not yet occurred but where such movement is contingent upon the occurrence of a selected wellbore condition. In this embodiment, the selected wellbore condition is the occurrence of a sufficient reduction of fluid pressure within the flow bore  416  following the achievement of the mode shown in  FIG. 6 . Finally,  FIG. 8  shows the sleeve system  400  in a “fully open mode” where sleeve  460  no longer obstructs a fluid path between ports  444  and sleeve flow bore  416 , but rather, a maximum fluid path is provided between ports  444  and the sleeve flow bore  416 . 
     Referring now to  FIG. 5 , while the sleeve system  400  is in the installation mode, each of the piston  446 , sleeve  460 , protective sheath  472 , and seat  470  are all restricted from movement along the central axis  402  at least because the shear pins  482 ,  458  lock the seat  470 , piston  446 , and sleeve  460  relative to the ported case  408 . In this embodiment, the lug  486  further restricts movement of the piston  446  relative to the ported case  408  because the lug  486  is captured within the lug receptacle  484  of the piston  446  and between the seat  470  and the ported case  408 . More specifically, the lug  486  is captured within the lug channel  488 , thereby preventing movement of the piston  446  relative to the ported case  408 . Further, in the installment mode, the spring  424  is partially compressed along the central axis  402 , thereby biasing the piston  446  downward and away from the case shoulder  436 . It will be appreciated that in alternative embodiments, the bias chamber  451  may be adequately sealed to allow containment of pressurized fluids that supply such biasing of the piston  446 . For example, a nitrogen charge may be contained within such an alternative embodiment. It will be appreciated that the bias chamber  451 , in alternative embodiments, may comprise one or both of a spring such as spring  424  and such a pressurized fluid. 
     Referring now to  FIG. 6 , the obturator  476  may be passed through a work string such as work string  112  until the obturator  476  substantially seals against the protective sheath  472  (as shown in  FIG. 5 ), alternatively, the seat gasket in embodiments where a seat gasket is present. With the obturator  476  in place against the protective sheath  472  and/or seat gasket, the pressure within the sleeve flow bore  416  may be increased uphole of the obturator  476  until the obturator  476  transmits sufficient force through the protective sheath  472  and the seat  470  to cause the shear pin  482  to shear. Once the shear pin  482  has sheared, the obturator  476  drives the protective sheath  472  and the seat  470  downhole from their installation mode positions. Such downhole movement of the seat  470  uncovers the lug  486 , thereby disabling the positional locking feature formally provided by the lug  486 . Nonetheless, even though the piston  446  is no longer restricted from uphole movement by the protective sheath  472 , the seat  470 , and the lug  486 , the piston remains locked in position by the spring force of the spring  424  and the shear pin  458 . Accordingly, the sleeve system remains in a balanced or locked mode, albeit a different configuration or stage of the installation mode. It will be appreciated that the obturator  476 , the protective sheath  472 , and the seat  470  continue downward movement toward and interact with the seat catch bore  494  in substantially the same manner as the obturator  276 , the protective sheath  272 , and the seat  270  move toward and interact with the seat catch bore  304 , as disclosed above with reference to  FIGS. 2-4 . 
     Referring now to  FIG. 7 , to initiate further transition from the installation mode to the delay mode, pressure within the flow bore  416  is increased until the piston  446  is forced upward and shears the shear pin  458 . After such shearing of the shear pin  458 , the piston  446  moves upward toward the case shoulder  436 , thereby further compressing spring  424 . With sufficient upward movement of the piston  446 , the lower portion  450  of the piston  446  abuts the upper sleeve section  462 . As the piston  446  travels to such abutment, the teeth  469  of c-ring  456  engage the teeth  466  of the lower sleeve section  464 . The abutment between the lower portion  450  of the piston  446  and the upper sleeve section  446  prevents further upward movement of piston  446  relative to the sleeve  460 . The engagement of teeth  469 ,  466  prevents any subsequent downward movement of the piston  446  relative to the sleeve  460 . Accordingly, the piston  446  is locked in position relative to the sleeve  460  and the sleeve system  400  may be referred to as being in a delay mode. 
     While in the delay mode, the sleeve system  400  is configured to discontinue covering the ports  444  with the sleeve  460  in response to an adequate reduction in fluid pressure within the flow bore  416 . For example, with the pressure within the flow bore  416  is adequately reduced, the spring force provided by spring  424  eventually overcomes the upward forced applied against the piston  446  that is generated by the fluid pressure within the flow bore  416 . With continued reduction of pressure within the flow bore  416 , the spring  424  forces the piston  446  downward. Because the piston  446  is now locked to the sleeve  460  via the c-ring  456 , the sleeve is also forced downward. Such downward movement of the sleeve  460  uncovers the ports  444 , thereby providing fluid communication between the flow bore  416  and the ports  444 . When the piston  446  is returned to its position in abutment against the lower adapter  406 , the sleeve system  400  is referred to as being in a fully open mode. The sleeve system  400  is shown in a fully open mode in  FIG. 8 . 
     In some embodiments, operating a wellbore servicing system such as wellbore servicing system  100  may comprise providing a first sleeve system (e.g., of the type of sleeve systems  200 ,  400 ) in a wellbore and providing a second sleeve system in the wellbore downhole of the first sleeve system. Next, wellbore servicing pumps and/or other equipment may be used to produce a fluid flow through the sleeve flow bores of the first and second sleeve systems. Subsequently, an obturator may be introduced into the fluid flow so that the obturator travels downhole and into engagement with the seat of the first sleeve system. When the obturator first contacts the seat of the first sleeve system, each of the first sleeve system and the second sleeve system are in one of the above-described installation modes so that there is not substantial fluid communication between the sleeve flow bores and an area external thereto (e.g., an annulus of the wellbore and/or an a perforation, fracture, or flowpath within the formation) through the ported cases of the sleeve systems. Accordingly, the fluid pressure may be increased to cause unlocking a restrictor of the first sleeve system as described in one of the above-described manners, thereby transitioning the first sleeve system from the installation mode to one of the above-described delayed modes. 
     In some embodiments, the fluid flow and pressure may be maintained so that the obturator passes through the first sleeve system in the above-described manner and subsequently engages the seat of the second sleeve system. The delayed mode of operation of the first sleeve system prevents fluid communication between the sleeve flow bore of the first sleeve and the annulus of the wellbore, thereby ensuring that no pressure loss attributable to such fluid communication prevents subsequent pressurization within the sleeve flow bore of the second sleeve system. Accordingly, the fluid pressure uphole of the obturator may again be increased as necessary to unlock a restrictor of the second sleeve system in one of the above-described manners. With both the first and second sleeve systems having been unlocked and in their respective delay modes, the delay modes of operation may be employed to thereafter provide and/or increase fluid communication between the sleeve flow bores and the proximate annulus of the wellbore and/or surrounding formation without adversely impacting an ability to unlock either of the first and second sleeve systems. 
     Further, it will be appreciated that one or more of the features of the sleeve systems may be configured to cause one or more relatively uphole located sleeve systems to have a longer delay periods before allowing substantial fluid communication between the sleeve flow bore and the annulus as compared to the delay period provided by one or more relatively downhole located sleeve systems. For example, the volume of the fluid chamber  268 , the amount of and/or type of fluid placed within fluid chamber  268 , the fluid metering device  291 , and/or other features of the first sleeve system may be chosen differently and/or in different combinations than the related components of the second sleeve system in order to adequately delay provision of the above-described fluid communication via the first sleeve system until the second sleeve system is unlocked and/or otherwise transitioned into a delay mode of operation, until the provision of fluid communication to the annulus and/or the formation via the second sleeve system, and/or until a predetermined amount of time after the provision of fluid communication via the second sleeve system. In some embodiments, such first and second sleeve systems may be configured to allow substantially simultaneous and/or overlapping occurrences of providing substantial fluid communication (e.g., substantial fluid communication and/or achievement of the above-described fully open mode). However, in other embodiments, the second sleeve system may provide such fluid communication prior to such fluid communication being provided by the first sleeve system. 
     Referring now to  FIG. 1 , one or more methods of servicing wellbore  114  using wellbore servicing system  100  are described. In some cases, wellbore servicing system  100  may be used to selectively treat selected one or more of zone  150 , first, second, third, fourth, and fifth zones  150   a - 150   e  by selectively providing fluid communication via (e.g., opening) one or more the sleeve systems (e.g., sleeve systems  200  and  200   a - 200   e ) associated with a given zone. More specifically, by employing the above-described method of operating individual sleeve systems such as sleeve systems  200  and/or  400 , any one of the zones  150 ,  150   a - 150   e  may be treated using the respective associated sleeve systems  200  and  200   a - 200   e . It will be appreciated that zones  150 ,  150   a - 150   e  may be isolated from one another, for example, via swell packers, mechanical packers, sand plugs, sealant compositions (e.g., cement), or combinations thereof. In an embodiments where the operation of a first and second sleeve system is discussed, it should be appreciated that a plurality of sleeve systems (e.g., a third, fourth, fifth, etc. sleeve system) may be similarly operated to selectively treat a plurality of zones (e.g., a third, fourth, fifth, etc. treatment zone), for example, as discussed below with respect to  FIG. 1 . 
     In a first embodiment, a method of performing a wellbore servicing operation by individually servicing a plurality of zones of a subterranean formation with a plurality of associated sleeve systems is provided. In such an embodiment, sleeve systems  200  and  200   a - 200   e  may be configured substantially similar to sleeve system  200  described above. Sleeve systems  200  and  200   a - 200   e  may be provided with seats configured to interact with an obturator of a first configuration and/or size (e.g., a single ball and/or multiple balls of the same size and configuration). The sleeve systems  200  and  200   a - 200   e  comprise the fluid metering delay system and each of the various sleeve systems may be configured with a fluid metering device chosen to provide fluid communication via that particular sleeve system within a selectable passage of time after being transitioned from installation mode to delay mode. Each sleeve system may be configured to transition from the delay mode to the fully open mode and thereby provide fluid communication in an amount of time equal to the sum of the amount of time necessary to transition all sleeves located further downhole from that sleeve system from installation mode to delay mode (for example, by engaging an obturator as described above) and perform a desired servicing operation with respect to the zone(s) associated with that sleeve system(s); in addition, an operator may choose to build in an extra amount of time as a “safety margin” (e.g., to ensure the completion of such operations). In addition, in an embodiment where successive zones will be treated, it may be necessary to allow additional time to restrict fluid communication to a previously treated zone (e.g., upon the completion of servicing operations with respect to that zone). For example, it may be necessary to allow time for perform a “screenout” with respect to a particular zone, as is discussed below. For example, where an estimated time of travel of an obturator between adjacent sleeve systems is about 10 minutes, where an estimated time to perform a servicing operation is about 1 hour and 40 minutes, and where the operator wishes to have an additional 10 minutes as a safety margin, each sleeve system might be configured to transition from delay mode to fully open mode about 2 hours after the sleeve system immediately downhole from that sleeve system. Referring again to  FIG. 1 , in such an example, the furthest downhole sleeve system ( 200   a ) might be configured to transition from delay mode to fully open mode shortly after being transitioned from installation mode to delay mode (e.g., immediately, within about 30 seconds, within about 1 minute, or within about 5 minutes); the second furthest downhole sleeve system ( 200   b ) might be configured to transition to fully open mode at about 2 hours, the third most downhole sleeve system ( 200   c ) might be configured to transition to fully open mode at about 4 hours, the fourth most downhole sleeve system ( 200   d ) might be configured to transition to fully open mode at about 6 hours, the fifth most downhole sleeve system ( 200   e ) might be configured to transition to fully open mode at about 8 hours, and the sixth most downhole sleeve system might be transitioned to fully open mode at about 10 hours. In various alternative embodiments, any one or more of the sleeve systems (e.g.,  200  and  200   a - 200   e ) may be configured to open within a desired amount of time. For example, a given sleeve may be configured to open within about 1 second after being transitioned from installation mode to delay mode, alternatively, within about 30 seconds, 1 minute, 5 minutes, 15 minutes, 30 minutes, 1 hour, 2 hours, 3 hours, 4 hours, 6 hours, 8 hours, 10 hours, 12 hours, 14 hours, 16 hours, 18 hours, 20 hours, 24 hours, or any amount of time to achieve a given treatment profile, as will be discussed herein below. 
     In an alternative embodiment, sleeve systems  200  and  200   b - 200   e  are configured substantially similar to sleeve system  200  described above, and sleeve system  200   a  is configured substantially similar to sleeve system  400  described above. Sleeve systems  200  and  200   a - 200   e  may be provided with seats configured to interact with an obturator of a first configuration and/or size. The sleeve systems  200  and  200   b - 200   e  comprise the fluid metering delay system and each of the various sleeve systems may be configured with a fluid metering device chosen to provide fluid communication via that particular sleeve system within a selectable amount of time after being transitioned from installation mode to delay mode, as described above. The furthest downhole sleeve system ( 200   a ) may be configured to transition from delay mode to fully open mode upon an adequate reduction in fluid pressure within the flow bore of that sleeve system, as described above with reference to sleeve system  400 . In such an alternative embodiment, the furthest downhole sleeve system ( 200   a ) may be transitioned from delay mode to fully open mode shortly after being transitioned to delay mode. Sleeve systems being further uphole may be transitioned from delay mode to fully open mode at selectable passage of time thereafter, as described above. 
     In other words, in either embodiment, the fluid metering devices may be selected so that no sleeve system will provide fluid communication between its respective flow bore and ports until each of the sleeve systems further downhole from that particular sleeve system has achieved transition from the delayed mode to the fully open mode and/or until a predetermined amount of time has passed. Such a configuration may be employed where it is desirable to treat multiple zones (e.g., zones  150  and  150   a - 150   e ) individually and to activate the associated sleeve systems using a single obturator, thereby avoiding the need to introduce and remove multiple obturators through a work string such as work string  112 . In addition, because a single size and/or configuration of obturator may be employed with respect to multiple (e.g., all) sleeve systems a common work string, the size of the flowpath (e.g., the diameter of a flowbore) through that work string may be more consistent, eliminating or decreasing the restrictions to fluid movement through the work string. As such, there may be few deviations with respect to flowrate of a fluid. 
     In either of these embodiments, a method of performing a wellbore servicing operation may comprise providing a work string comprising a plurality of sleeve systems in a configuration as described above and positioning the work string within the wellbore such that one or more of the plurality of sleeve systems is positioned proximate and/or substantially adjacent to one or more of the zones (e.g., deviated zones) to be serviced. The zones may be isolated, for example, by actuating one or more packers or similar isolation devices. 
     Next, when fluid communication is to be provided via sleeve systems  200  and  200   a - 200   e , an obturator like obturator  276  configured and/or sized to interact with the seats of the sleeve systems is introduced into and passed through the work string  112  until the obturator  276  reaches the relatively furthest uphole sleeve system  200  and engages a seat like seat  270  of that sleeve system. Continued pumping may increase the pressure applied against the seat  270  causing the sleeve system to transition from installation mode to delay mode and the obturator to pass through the sleeve system, as described above. The obturator may then continue to move through the work string to similarly engage and transition sleeve systems  200   a - 200   e  to delay mode. When all of the sleeve systems  200  and  200   a - 200   e  have been transitioned to delay mode, the sleeve systems may be transitioned from delay mode to fully open in the order in which the zone or zones associated with a sleeve system are to be serviced. In an embodiment, the zones may be serviced beginning with the relatively furthest downhole zone ( 150   a ) and working toward progressively lesser downhole zones (e.g.,  150   b ,  150   c ,  150   d ,  150   e , then  150 ). Servicing a particular zone is accomplished by transitioning the sleeve system associated with that zone to fully open mode and communicating a servicing fluid to that zone via the ports of the sleeve system. In an embodiment where sleeve systems  200  and  200   a - 200   e  of  FIG. 1  are configured substantially similar to sleeve system  200  of  FIG. 2 , transitioning sleeve system  200   a  (which is associated with zone  150   a ) to fully open mode may be accomplished by waiting for the preset amount of time following unlocking the sleeve system  200   a  while the fluid metering system allows the sleeve system to open, as described above. With the sleeve system  200   a  fully open, a servicing fluid may be communicated to the associated zone ( 150   a ). In an embodiment where sleeve systems  200  and  200   b - 200   e  are configured substantially similar to sleeve system  200  and sleeve system  200   a  is configured substantially similar to sleeve system  400 , transitioning sleeve system  200   a  to fully open mode may be accomplished by allowing a reduction in the pressure within the flow bore of the sleeve system, as described above. 
     One of skill in the art will appreciate that the servicing fluid communicated to the zone may be selected dependent upon the servicing operation to be performed. Nonlimiting examples of such servicing fluids include a fracturing fluid, a hydrajetting or perforating fluid, an acidizing, an injection fluid, a fluid loss fluid, a sealant composition, or the like. 
     As may be appreciated by one of skill in the art viewing this disclosure, when a zone has been serviced, it may be desirable to restrict fluid communication with that zone, for example, so that a servicing fluid may be communicated to another zone. In an embodiment, when the servicing operation has been completed with respect to the relatively furthest downhole zone ( 150   a ), an operator may restrict fluid communication with zone  150   a  (e.g., via sleeve system  200   a ) by intentionally causing a “screenout” or sand-plug. As will be appreciated by one of skill in the art viewing this disclosure, a “screenout” or “screening out” refers to a condition where solid and/or particulate material carried within a servicing fluid creates a “bridge” that restricts fluid flow through a flowpath. By screening out the flow paths to a zone, fluid communication to the zone may be restricted so that fluid may be directed to one or more other zones. 
     When fluid communication has been restricted, the servicing operation may proceed with respect to additional zones (e.g.,  150   b - 150   e  and  150 ) and the associated sleeve systems (e.g.,  200   b - 200   e  and  200 ). As disclosed above, additional sleeve systems will transition to fully open mode at preset time intervals following transitioning from installation mode to delay mode, thereby providing fluid communication with the associated zone and allowing the zone to be serviced. Following completion of servicing a given zone, fluid communication with that zone may be restricted, as disclosed above. In an embodiment, when the servicing operation has been completed with respect to all zones, the solid and/or particulate material employed to restrict fluid communication with one or more of the zones may be removed, for example, to allow the flow of wellbore production fluid into the flow bores of the of the open sleeve systems via the ports of the open sleeve systems. 
     In an alternative embodiment, employing the systems and/or methods disclosed herein, various treatment zones may be treated and/or serviced in any suitable sequence, that is, a given treatment profile. Such a treatment profile may be determined and a plurality of sleeve systems like sleeve system  200  may be configured (e.g., via suitable time delay mechanisms, as disclosed herein) to achieve that particular profile. For example, in an embodiment where an operator desires to treat three zones of a formation beginning with the lowermost zone, followed by the uppermost zone, followed by the intermediate zone, three sleeve systems of the type disclosed herein may be positioned proximate to each zone. The first sleeve system (e.g., proximate to the lowermost zone) may be configured to open first, the third sleeve system (e.g., proximate to the uppermost zone) may be configured to open second (e.g., allowing enough time to complete the servicing operation with respect to the first zone and obstruct fluid communication via the first sleeve system) and the second sleeve system (e.g., proximate to the intermediate zone) may be configured to open last (e.g., allowing enough time to complete the servicing operation with respect to the first and second zones and obstruct fluid communication via the first and second sleeve systems). 
     While the following discussion is related to actuating two groups of sleeves (each group having three sleeves), it should be understood that such description is non-limiting and that any suitable number and/or grouping of sleeves may be actuated in corresponding treatment stages. In a second embodiment where treatment of zones  150   a ,  150   b , and  150   c  is desired without treatment of zones  150   d ,  150   e  and  150 , sleeve systems  200   a - 200   e  are configured substantially similar to sleeve system  200  described above. In such an embodiment, sleeve systems  200   a ,  200   b , and  200   c  may be provided with seats configured to interact with an obturator of a first configuration and/or size while sleeve systems  200   d ,  200   e , and  200  are configured not to interact with the obturator having the first configuration. Accordingly, sleeve systems  200   a ,  200   b , and  200   c  may be transitioned from installation mode to delay mode by passing the obturator having a first configuration through the uphole sleeve systems  200 ,  200   e , and  200   d  and into successive engagement with sleeve systems  200   c ,  200   b , and  200   a . Since the sleeve systems  200   a - 200   c  comprise the fluid metering delay system, the various sleeve systems may be configured with fluid metering devices chosen to provide a controlled and/or relatively slower opening of the sleeve systems. For example, the fluid metering devices may be selected so that none of the sleeve systems  200   a - 200   c  actually provide fluid communication between their respective flow bores and ports prior to each of the sleeve systems  200   a - 200   c  having achieved transition from the installation mode to the delayed mode. In other words, the delay systems may be configured to ensure that each of the sleeve systems  200   a - 200   c  has been unlocked by the obturator prior to such fluid communication. 
     To accomplish the above-described treatment of zones  150   a ,  150   b , and  150   c , it will be appreciated that to prevent loss of fluid and/or fluid pressure through ports of sleeve systems  200   c ,  200   b , each of sleeve systems  200   c ,  200   b  may be provided with a fluid metering device that delays such loss until the obturator has unlocked the sleeve system  200   a . It will further be appreciated that individual sleeve systems may be configured to provide relatively longer delays (e.g., the time from when a sleeve system is unlocked to the time that the sleeve system allows fluid flow through its ports) in response to the location of the sleeve system being located relatively further uphole from a final sleeve system that must be unlocked during the operation (e.g., in this case, sleeve system  200   a ). Accordingly, in some embodiments, a sleeve system  200   c  may be configured to provide a greater delay than the delay provided by sleeve system  200   b . For example, in some embodiments where an estimated time of travel of an obturator from sleeve system  200   c  to sleeve system  200   b  is about 10 minutes and an estimated time of travel from sleeve system  200   b  to sleeve system  200   a  is also about 10 minutes, the sleeve system  200   c  may be provided with a delay of at least about 20 minutes. The 20 minute delay may ensure that the obturator can both reach and unlock the sleeve systems  200   b ,  200   a  prior to any fluid and/or fluid pressure being lost through the ports of sleeve system  200   c.    
     Alternatively, in some embodiments, sleeve systems  200   c ,  200   b  may each be configured to provide the same delay so long as the delay of both are sufficient to prevent the above-described fluid and/or fluid pressure loss from the sleeve systems  200   c ,  200   b  prior to the obturator unlocking the sleeve system  200   a . For example, in an embodiment where an estimated time of travel of an obturator from sleeve system  200   c  to sleeve system  200   b  is about 10 minutes and an estimated time of travel from sleeve system  200   b  to sleeve system  200   a  is also about 10 minutes, the sleeve systems  200   c ,  200   b  may each be provided with a delay of at least about 20 minutes. Accordingly, using any of the above-described methods, all three of the sleeve systems  200   a - 200   c  may be unlocked and transitioned into fully open mode with a single trip through the work string  112  of a single obturator and without unlocking the sleeve systems  200   d ,  200   e , and  200  that are located uphole of the sleeve system  200   c.    
     Next, if sleeve systems  200   d ,  200   e , and  200  are to be opened, an obturator having a second configuration and/or size may be passed through sleeve systems  200   d ,  200   e , and  200  in a similar manner to that described above to selectively open the remaining sleeve systems  200   d ,  200   e , and  200 . Of course, this is accomplished by providing  200   d ,  200   e , and  200  with seats configured to interact with the obturator having the second configuration. 
     In alternative embodiments, sleeve systems such as  200   a ,  200   b , and  200   c  may all be associated with a single zone of a wellbore and may all be provided with seats configured to interact with an obturator of a first configuration and/or size while sleeve systems such as  200   d ,  200   e , and  200  may not be associated with the above-mentioned single zone and are configured not to interact with the obturator having the first configuration. Accordingly, sleeve systems such as  200   a ,  200   b , and  200   c  may be transitioned from an installation mode to a delay mode by passing the obturator having a first configuration through the uphole sleeve systems  200 ,  200   e , and  200   d  and into successive engagement with sleeve systems  200   c ,  200   b , and  200   a . In this way, the single obturator having the first configuration may be used to unlock and/or activate multiple sleeve systems (e.g.,  200   c ,  200   b , and  200   a ) within a selected single zone after having selectively passed through other uphole and/or non-selected sleeve systems (e.g.,  200   d ,  200   e , and  200 ). 
     An alternative embodiment of a method of servicing a wellbore may be substantially the same as the previous examples, but instead, using at least one sleeve system substantially similar to sleeve system  400 . It will be appreciated that while using the sleeve systems substantially similar to sleeve system  400  in place of the sleeve systems substantially similar to sleeve system  200 , a primary difference in the method is that fluid flow between related fluid flow bores and ports is not achieved amongst the three sleeve systems being transitioned from an installation mode to a fully open mode until pressure within the fluid flow bores is adequately reduced. Only after such reduction in pressure will the springs of the sleeve systems substantially similar to sleeve system  400  force the piston and the sleeves downward to provide the desired fully open mode. 
     Regardless of which type of the above-disclosed sleeve systems  200 ,  400  are used, it will be appreciated that use of either type may be performed according to a method described below. A method of servicing a wellbore may comprise providing a first sleeve system in a wellbore and also providing a second sleeve system downhole of the first sleeve system. Subsequently, a first obturator may be passed through at least a portion of the first sleeve system to unlock a restrictor of the first sleeve, thereby transitioning the first sleeve from an installation mode of operation to a delayed mode of operation. Next, the obturator may travel downhole from the first sleeve system to pass through at least a portion of the second sleeve system to unlock a restrictor of the second sleeve system. In some embodiments, the unlocking of the restrictor of the second sleeve may occur prior to loss of fluid and/or fluid pressure through ports of the first sleeve system. 
     In either of the above-described methods of servicing a wellbore, the methods may be continued by flowing wellbore servicing fluids from the fluid flow bores of the open sleeve systems out through the ports of the open sleeve systems. Alternatively and/or in combination with such outward flow of wellbore servicing fluids, wellbore production fluids may be flowed into the flow bores of the open sleeve systems via the ports of the open sleeve systems. 
     ADDITIONAL DISCLOSURE 
     The following are nonlimiting, specific embodiments in accordance with the present disclosure: 
     Embodiment A 
     A wellbore servicing system, comprising: 
     a first sleeve system, the first sleeve system comprising:
         a first ported case;   a first sliding sleeve at least partially carried within the first ported case and movable relative to the first ported case between a first sleeve position in which the first sliding sleeve restricts fluid communication via the ported case and a second sleeve position in which the first sliding sleeve does not restrict fluid communication via the ported case;   a first segmented seat, the first segmented seat being radially divided into a plurality of segments and movable relative to the first ported case between a first seat position in which the first seat restricts movement of the sliding sleeve relative to the ported case and a second seat position in which the first seat does not restrict movement of the sliding sleeve relative to the ported case; and   a first sheath forming a continuous layer that covers one or more surfaces of the first segmented seat,   the first sleeve system being transitionable from a first mode to a second mode and transitionable from the second mode to a third mode,   wherein, when in the first mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is retained in the first seat position,   wherein, when in the second mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is in the second seat position, and   wherein, when in the third mode, the first sliding sleeve is in the second sleeve position.       

     Embodiment B 
     The wellbore servicing system of Embodiment A, further comprising: 
     a second sleeve system, the second sleeve system comprising:
         a second ported case;   a second sliding sleeve at least partially carried within the second ported case and movable relative to the second ported case between a first sleeve position in which the second sliding sleeve restricts fluid communication via the ported case and a second sleeve position in which the second sliding sleeve does not restrict fluid communication via the ported case;   a second segmented seat, the second segmented seat being radially divided into a plurality of segments and movable relative to the second ported case between a first seat position in which the second seat restricts movement of the sliding sleeve relative to the ported case and a second seat position in which the second seat does not restrict movement of the sliding sleeve relative to the ported case; and   a second sheath forming a continuous layer that covers one or more surfaces of the second segmented seat,   the second sleeve system being transitionable from a first mode to a second mode and transitionable from the second mode to a third mode,   wherein, when in the first mode, the second sliding sleeve is retained in the first sleeve position and the second segmented seat is retained in the first seat position,   wherein, when in the second mode, the second sliding sleeve is retained in the first sleeve position and the second segmented seat is in the second seat position, and   wherein, when in the third mode, the second sliding sleeve is in the second sleeve position.       

     Embodiment C 
     The wellbore servicing system of Embodiment A, wherein the first segmented seat comprises at least three radially divided segments. 
     Embodiment D 
     The wellbore servicing system of Embodiment A, wherein the first segmented seat comprises a drillable material. 
     Embodiment E 
     The wellbore servicing system of Embodiment A, wherein the first segmented seat comprises a composite, a phenolic, cast iron, aluminum, brass, a metal alloy, a rubber, a ceramics, or combinations thereof. 
     Embodiment F 
     The wellbore servicing system of Embodiment A, wherein the first segmented seat comprises a first radial diameter when the first segmented seat is in the first seat position and a second radial diameter when the first segmented seat is in the second seat position, the second radial diameter being greater than the first radial diameter. 
     Embodiment G 
     The wellbore servicing system of Embodiment A, wherein the protective sheath covers those portions of the first segmented seat in contact with a flow bore of the first sleeve system. 
     Embodiment H 
     The wellbore servicing system of Embodiment A, wherein the first protective sheath comprises a ceramic, a carbide, a hardened plastic, a molded rubber, a heat-shrinkable material, or combinations thereof. 
     Embodiment I 
     The wellbore servicing system of Embodiment A, wherein the first protective sheath is characterized as having a hardness of from about 50 durometers to about 100 durometers. 
     Embodiment J 
     The wellbore servicing system of Embodiment A, wherein the first protective sheath is applied to the first segmented seat, one or more segments of the first segmented seat, or combinations thereof. 
     Embodiment K 
     The wellbore servicing system of Embodiment A, wherein first the protective sheath is preformed and is inserted within a longitudinal flow bore of the first segmented seat. 
     Embodiment L 
     The wellbore servicing system of Embodiment A, wherein the first protective sheath is received within a recess within the segmented seat. 
     Embodiment M 
     The wellbore servicing system of Embodiment A, wherein a first portion of the first protective sheath is configured to receive an obturator, wherein the first portion of the first protective sheath comprises a thickness greater than the thickness of another portion of the first protective sheath. 
     Embodiment N 
     The wellbore servicing system of Embodiment A, further comprising: 
     a fluid chamber formed between the first ported case and the first sliding sleeve; and 
     a fluid metering device in fluid communication with the fluid chamber. 
     Embodiment O 
     The wellbore servicing system of Embodiment N, wherein fluid flow through the fluid metering device is prevented while the first segmented seat is retained in the first seat position. 
     Embodiment P 
     The wellbore servicing system of Embodiment O, wherein the first segmented seat is retained in the first seat position by a shear pin and wherein fluid flow through the metering device is allowed subsequent to a shearing of the shear pin. 
     Embodiment Q 
     The wellbore servicing system of Embodiment P, wherein the shear pin is received within each of a seat support of the first sleeve system and a lower adapter of the first sleeve system. 
     Embodiment R 
     The wellbore servicing system of Embodiment A, further comprising: 
     a first piston carried at least partially within the first ported case; and 
     a low pressure chamber formed between the first piston and the first ported case. 
     Embodiment S 
     The wellbore servicing system of Embodiment A, the first restrictor comprising: 
     a first piston at least partially received substantially concentrically between the first sliding sleeve and the first ported case. 
     Embodiment T 
     The wellbore servicing system of Embodiment S, further comprising: 
     a lug selectively received through the first piston and between the first segmented seat and the first ported case. 
     Embodiment U 
     The wellbore servicing system of Embodiment T, wherein the lug is selectively received within a lug channel of the first ported case. 
     Embodiment V 
     The wellbore servicing system of Embodiment I, further comprising: 
     a bias chamber at least partially defined by each of the first ported case, the first sliding sleeve, and the first piston. 
     Embodiment W 
     The wellbore servicing system of Embodiment V, further comprising: 
     a spring received at least partially within the bias chamber. 
     Embodiment X 
     The wellbore servicing system of Embodiment A, wherein the first sleeve system is configured such that transitioning the first sleeve system from the second mode to the third mode comprises allowing a first amount of time to pass after the first sleeve system transitions to the second mode. 
     Embodiment Y 
     A wellbore servicing method comprising: 
     positioning a first sleeve system within the wellbore proximate to a first treatment zone, the first sleeve system comprising:
         a first ported case;   a first sliding sleeve at least partially carried within the first ported case and movable relative to the first ported case between a first sleeve position in which the first sliding sleeve restricts fluid communication via the ported case and a second sleeve position in which the first sliding sleeve does not restrict fluid communication via the ported case;   a first segmented seat, the first segmented seat being radially divided into a plurality of segments and movable relative to the first ported case between a first seat position in which the first seat restricts movement of the sliding sleeve relative to the ported case and a second seat position in which the first seat does not restrict movement of the sliding sleeve relative to the ported case; and   a first sheath forming a continuous layer that covers one or more surfaces of the first segmented seat,   the first sleeve system being transitionable from a first mode to a second mode and transitionable from the second mode to a third mode,   wherein, when in the first mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is retained in the first seat position,   wherein, when in the second mode, the first sliding sleeve is retained in the first sleeve position and the first segmented seat is in the second seat position, and   wherein, when in the third mode, the first sliding sleeve is in the second sleeve position.       

     Embodiment Z 
     The method of Embodiment Y, further comprising: 
     transitioning the first sleeve system to the third mode; and 
     communicating a wellbore servicing fluid via the ported case of the first sleeve system to the first treatment zone. 
     At least one embodiment is disclosed and variations, combinations, and/or modifications of the embodiment(s) and/or features of the embodiment(s) made by a person having ordinary skill in the art are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. 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, R l , and an upper limit, R u , is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R l +k*(R u −R l ), 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 means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim. Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present invention.