Patent Publication Number: US-2015060056-A1

Title: Systems and Methods for Restricting Fluid Flow in a Wellbore with an Autonomous Sealing Device and Motion-Arresting Structures

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional No. 61/871,675, filed Aug. 29, 2013, the entirety of which is incorporated herein by reference for all purposes. 
    
    
     FIELD OF THE DISCLOSURE 
     The present disclosure is directed generally to systems and methods for restricting fluid flow within a casing conduit, and more particularly to systems and methods that utilize an autonomous sealing device and a plurality of motion-arresting structures to restrict fluid flow within the casing conduit. 
     BACKGROUND OF THE DISCLOSURE 
     A well may be utilized to produce one or more reservoir fluids, such as liquid and/or gaseous hydrocarbons, from a subterranean formation. The well may include a wellbore, which extends between a surface region and the subterranean formation, and a casing string that extends within the wellbore and defines a casing conduit. 
     During construction and/or operation of the well, it may be desirable to restrict fluid flow between an uphole portion of the casing conduit and a downhole portion of the casing conduit, such as to stimulate the subterranean formation. Illustrative examples of stimulation processes include fracturing the formation and acidizing, or acid treating, the formation. Often, the stimulating process may be repeated a plurality of times along a length of the production casing to stimulate a plurality of zones of the subterranean formation. As an illustrative, non-exclusive example, the stimulating may include providing a stimulant fluid to the casing conduit, with the stimulant fluid flowing from the casing conduit into the subterranean formation to thereby stimulate the subterranean formation, and with the fluid flow restriction being utilized to focus the stimulant fluid flow into a desired portion, region, and/or zone of the subterranean formation. 
     A number of processes have been utilized to stimulate subterranean formations. While these processes may be effective under certain conditions, they may be ineffective under others. As an illustrative, non-exclusive example, a well may include a wellbore with a long horizontal section. This long horizontal section may extend within the subterranean formation, and it may be desirable to stimulate a plurality of zones of the subterranean formation that may be distributed along the length of the horizontal section. 
     Traditional stimulating processes may include establishing fluid communication between the casing conduit and a given zone of the subterranean formation, providing the stimulant fluid to the given zone of the subterranean formation to stimulate the given zone of the subterranean formation, and then fluidly isolating at least a portion of the casing conduit from the subterranean formation. This process may be repeated a plurality of times along a length of the horizontal section to stimulate the plurality of zones of the subterranean formation. 
     Generally, the traditional stimulating processes fluidly isolate the portion of the casing conduit from downhole portions of the casing conduit using isolation plugs or using traditional isolation balls and seats. It follows that this isolation from the downhole portions also isolates the portion of the casing conduit from corresponding regions of the subterranean formation that are in fluid communication with the downhole portions. Isolation plugs may include and/or be expandable plugs that may be located within the casing conduit and subsequently expanded to fill a portion of the casing conduit, thereby blocking fluid flow therepast. Traditional isolation balls may include and/or be elastomeric balls that are sized to fit within the casing conduit and to seal with a respective seat that is sized to receive the isolation ball to block the flow of fluid therepast. 
     However, as the length of the well is increased, setting the required number of isolation plugs becomes increasingly difficult and/or expensive and may inhibit economic and/or efficient stimulating of the subterranean formation. Moreover, the isolation plugs must be removed from the casing conduit, typically by time-consuming and/or expensive processes that include drilling the isolation plugs from the casing conduit, prior to production of the reservoir fluid from the subterranean formation. 
     Similarly, traditional isolation balls and seats rely on progressively smaller balls and seats to stimulate a desired number of zones of the subterranean formation. Thus, there is a practical limit to the number of zones that may be stimulated with isolation balls and seats while still permitting sufficient fluid flow rates within the casing conduit. In addition, the progressively smaller seats effectively may limit access to portions of the casing conduit that are downhole therefrom, as many downhole assemblies simply may be too large to fit, or flow, through the seats. Furthermore, these seats often must be removed from the casing conduit prior to production of the reservoir fluid from the subterranean formation, and doing so increases the overall cost of the stimulation, and subsequent production, process. Thus, there exists a need for improved systems and methods for restricting fluid flow in a casing conduit. 
     SUMMARY OF THE DISCLOSURE 
     Systems and methods for restricting fluid flow in a casing conduit are disclosed herein. The systems include a wellbore that extends within a subterranean formation, a casing string that extends within the wellbore and defines a portion of the casing conduit, a plurality of motion-arresting structures that project from an inner surface of the casing string to define a plurality of reduced-area regions of the casing conduit, and an autonomous sealing device that defines a contracted configuration and an expanded configuration. The autonomous sealing device is sized to flow past, or through, the plurality of reduced-area regions when in the contracted configuration, to be retained on a selected motion-arresting structure upon transitioning to the expanded configuration, and to restrict fluid flow within the casing conduit upon being retained on the selected motion-arresting structure. 
     In some embodiments, the autonomous sealing device is configured to form a fluid seal with the selected motion-arresting structure. In some embodiments, the selected motion-arresting structure is defined by the selected transitioning of the motion-arresting structure to the expanded configuration. In some embodiments, the selected motion-arresting structure defines a sealing surface that is sized to form the fluid seal. In some embodiments, the autonomous sealing device is configured to form a fluid seal with an inner surface of the casing string. In some embodiments, the autonomous sealing device includes an expansion mechanism that is configured to transition the autonomous sealing device to the expanded configuration. In some embodiments, the autonomous sealing device is further configured to transition from the expanded configuration to a retracted configuration. In some embodiments, the autonomous sealing device is configured to release a supplemental material into the casing conduit. In some embodiments, the autonomous sealing device is operatively attached to a perforation device. 
     In some embodiments, the autonomous sealing device further includes an autonomous controller. In some embodiments, the autonomous controller is programmed to determine a location of the autonomous sealing device within the casing conduit and to transition the autonomous sealing device to the expanded configuration based on the determined location. 
     In some embodiments, the plurality of motion-arresting structures includes a plurality of isolation rings. In some embodiments, the plurality of motion-arresting structures includes a plurality of stops. In some embodiments, the plurality of motion-arresting structures includes a plurality of sliding sleeves. In some embodiments, the well further includes a hydraulically actuated sleeve. 
     The methods include conveying the autonomous sealing device through the casing conduit, determining that the autonomous sealing device is located within a target portion of the casing conduit, expanding the autonomous sealing device to the expanded configuration, retaining the autonomous sealing device on a selected motion-arresting structure, and restricting fluid flow within the casing conduit with the autonomous sealing device. 
     In some embodiments, the methods further include supplying a stimulant fluid to the casing conduit, and the conveying includes conveying the autonomous sealing device within the stimulant fluid. In some embodiments, the methods further include detecting a variable associated with the autonomous sealing device. In some embodiments, the determining is based upon the variable associated with the autonomous sealing device. 
     In some embodiments, the restricting includes forming a fluid seal between the selected motion-arresting structure and the autonomous sealing device. In some embodiments, the restricting includes forming a fluid seal with the inner surface of the casing string. In some embodiments, the methods further include removing the autonomous sealing device from the casing conduit. In some embodiments, the removing includes transitioning the autonomous sealing device from the expanded configuration to a retracted configuration. 
     In some embodiments, the methods further include stimulating the subterranean formation. In some embodiments, the stimulating includes supplying a stimulant fluid to the subterranean formation. In some embodiments, the stimulant fluid is supplied via a sleeve port, via an injection port, and/or via a perforation. In some embodiments, the methods further include repeating the methods to restrict fluid flow within a plurality of portions of the casing conduit. In some embodiments, the methods further include producing a reservoir fluid from the subterranean formation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic representation of illustrative, non-exclusive examples of a hydrocarbon well that may be utilized with and/or may include the systems and methods according to the present disclosure. 
         FIG. 2  is a schematic cross-sectional view of illustrative, non-exclusive examples of a casing string that includes a motion-arresting structure and may be utilized with an autonomous sealing device according to the present disclosure. 
         FIG. 3  is a schematic cross-sectional view of illustrative, non-exclusive examples of another motion-arresting structure that may be utilized with an autonomous sealing device according to the present disclosure. 
         FIG. 4  is a schematic representation of illustrative, non-exclusive examples of a process flow that may be utilized with a flow-arresting structure and an autonomous sealing device according to the present disclosure. 
         FIG. 5  is another schematic representation of illustrative, non-exclusive examples of a process flow that may be utilized with a flow-arresting structure and an autonomous sealing device according to the present disclosure. 
         FIG. 6  is another schematic representation of illustrative, non-exclusive examples of a process flow that may be utilized with a flow-arresting structure and an autonomous sealing device according to the present disclosure. 
         FIG. 7  is another schematic representation of illustrative, non-exclusive examples of a process flow that may be utilized with a flow-arresting structure and an autonomous sealing device according to the present disclosure. 
         FIG. 8  is another schematic representation of illustrative, non-exclusive examples of a process flow that may be utilized with a flow-arresting structure and an autonomous sealing device according to the present disclosure. 
         FIG. 9  is another schematic representation of illustrative, non-exclusive examples of a process flow that may be utilized with a flow-arresting structure and an autonomous sealing device according to the present disclosure. 
         FIG. 10  is a flowchart depicting methods according to the present disclosure of restricting fluid flow between an uphole portion of a casing conduit and a downhole portion of the casing conduit. 
     
    
    
     DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE 
       FIGS. 1-9  provide illustrative, non-exclusive examples of hydrocarbon wells  30  according to the present disclosure and/or of components of hydrocarbon wells  30 , such as motion-arresting structures  100  and/or autonomous sealing devices  150 . Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of  FIGS. 1-9 , and these elements may not be discussed in detail herein with reference to each of  FIGS. 1-9 . Similarly, all elements may not be labeled in each of  FIGS. 1-9 , but reference numerals associated therewith may be utilized herein for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of  FIGS. 1-9  may be included in and/or utilized with any of  FIGS. 1-9  without departing from the scope of the present disclosure. 
     In general, elements that are likely to be included in a given (i.e., a particular) embodiment are illustrated in solid lines, while elements that are optional to a given embodiment are illustrated in dashed lines. However, elements that are shown in solid lines are not essential to all embodiments, and an element shown in solid lines may be omitted from a particular embodiment without departing from the scope of the present disclosure. 
       FIG. 1  is a schematic representation of illustrative, non-exclusive examples of a hydrocarbon well  30  that may be utilized with and/or include the systems and methods according to the present disclosure and with and/or within which the methods according to the present disclosure may be utilized and/or implemented. Hydrocarbon well  30  includes a wellbore  32  that extends from a surface region  10  and/or within a subterranean formation  22  that is present within a subsurface region  20 . A casing string  40  extends within wellbore  32  and has an inner surface  42  that defines a portion of a casing conduit  44 . Casing string  40  may include a plurality of sections  43  of casing that may be operatively attached to one another with respective casing collars  41  to form the casing string.  FIG. 1  illustrates hydrocarbon well  30  as including a single, continuous, and/or unbranched wellbore  32 . However, the wellbore shown in  FIG. 1  is intended to schematically depict wellbore  30 , and therefore to include, but not be limited to, such a single, continuous, and/or unbranched wellbore. Accordingly, it also is within the scope of the present disclosure and the schematic depiction of  FIG. 1  that hydrocarbon well  30  may include a plurality of branches and/or laterals. Each of these branches and/or laterals, when present, may include a respective casing string  40 ; and the systems and methods according to the present disclosure may be located in and/or utilized with any and/or all branches and/or laterals of hydrocarbon well  30 . 
     Hydrocarbon well  30 , which also may be referred to herein as a well  30 , further includes a plurality of motion-arresting structures  100  that are spaced apart from one another along a (longitudinal) length of casing string  40 . Motion-arresting structures  100  project from inner surface  42  to define a plurality of reduced-area regions  102  of casing conduit  44 . Hydrocarbon well  30  further includes one or more autonomous sealing devices  150  and also may include a perforation device  170  and/or one or more hydraulically actuated sleeves  74 . 
     During the construction, formation, and/or operation of hydrocarbon well  30 , one or more autonomous sealing devices  150  may be located within casing conduit  44  and a stimulant fluid  62  may be provided to the casing conduit. This may flow the autonomous sealing device within the casing conduit in a downhole direction  38  and/or toward subterranean formation  22 . Upon reaching a desired, or target, location within the casing conduit, the autonomous sealing device may transition from a contracted configuration  152  to an expanded configuration  154  and be retained on a selected motion-arresting structure  100 , thereby fluidly isolating an uphole portion  46  of casing conduit  44  from a downhole portion  48  of the casing conduit. This fluid isolation may facilitate performing one or more completion and/or stimulation operations within hydrocarbon well  30 . 
     Autonomous sealing device  150  may include any suitable structure that may define contracted configuration  152  and expanded configuration  154 . When in contracted configuration  152 , the autonomous sealing device is adapted, configured, constructed, designed, and/or sized to pass through the plurality of reduced-area regions  102  within casing conduit  44 . However, and upon transitioning to expanded configuration  154 , the autonomous sealing device is adapted, configured, constructed, and/or sized not to pass through reduced-area regions  102 , to be retained on a selected motion-arresting structure  100 , and/or to restrict fluid flow between a portion of casing conduit  44  that is uphole from (or located in an uphole direction  36  from) the selected motion-arresting structure (i.e., uphole portion  46  of the casing conduit) and a portion of the casing conduit that is downhole from (or located in downhole direction  38  from) the selected motion-arresting structure (i.e., downhole portion  48  of the casing conduit). 
     As discussed in more detail herein, autonomous sealing device  150  may be adapted, configured, constructed, and/or programmed for autonomous, or independent, operation within casing conduit  44 . As such, the autonomous sealing device may not be attached to a tether, a working line, a wireline, and/or tubing. Illustrative, non-exclusive examples of autonomous devices that may be utilized within a wellbore are disclosed in U.S. Patent Application Publication No. 2013/0062055; U.S. Patent Application Publication No. 2013/0255939; and U.S. Patent Application Publication No. 2013/0248174, the complete disclosures of which are hereby incorporated by reference. 
     As used herein, the phrases “expanded configuration” and “contracted configuration” are relative phrases that do not, necessarily, refer to discrete and/or single configurations for autonomous sealing device  150 . Instead, these phrases refer to configurations in which autonomous sealing device  150  is sized to pass through reduced-area regions  102  (i.e., contracted configuration  152 ) and configurations in which autonomous sealing device  150  is sized to be retained on motion-arresting structures  100  and/or not to pass through reduced-area regions  102  (i.e., expanded configuration  154 ). As such, contracted configuration  152  and expanded configuration  154  optionally may refer to a range of configurations that is bounded by a fully contracted configuration and a fully expanded configuration, respectively. 
     With this in mind, it is within the scope of the present disclosure that contracted configuration  152  and/or expanded configuration  154  may be defined in any suitable manner and/or may define any suitable configuration, or relative configuration, for autonomous sealing device  150  such that the autonomous sealing device may pass through reduced-area regions  102  while in the contracted configuration but is retained on motion-arresting structures  100  (i.e., may/can not pass through reduced-area regions  102 ) when in the expanded configuration. As an illustrative, non-exclusive example, contracted configuration  152  may define a contracted volume and expanded configuration  154  may define an expanded volume that is greater than the contracted volume. As another illustrative, non-exclusive example, contracted configuration  152  may define a contracted characteristic dimension (or diameter and/or cross-sectional area transverse to the longitudinal axis of the corresponding portion of the casing conduit within which the motion-arresting structure is located) and expanded configuration  154  may define an expanded characteristic dimension (or diameter and/or cross-sectional area transverse to the longitudinal axis of the corresponding portion of the casing conduit within which the motion-arresting structure is located) that is greater than the contracted characteristic dimension. As additional illustrative, non-exclusive examples, contracted configuration  152  and/or expanded configuration  154  may define respective cylindrical and/or spherical configurations, profiles, and/or surface profiles. 
     Autonomous sealing device  150  may include an expansion mechanism  158  that may be configured to transition (or provide a motive force for transitioning) the autonomous sealing device to expanded configuration  154  and/or from contracted configuration  152  to expanded configuration  154 . Expansion mechanism  158  may include any suitable structure. As illustrative, non-exclusive examples, expansion mechanism  158  may include and/or be an explosive charge, a mechanical actuator, an electric actuator, a hydraulic actuator, a chemical reaction, and/or a material that swells upon contact with a wellbore fluid. 
     As a more specific but still illustrative, non-exclusive example, autonomous sealing device  150  and/or expansion mechanism  158  may include a reservoir chamber  190  and an expansion chamber  192 . Under these conditions, expansion mechanism  158  may be configured to direct an expansion fluid from reservoir chamber  190  to expansion chamber  192  to swell the autonomous sealing device and/or to transition the autonomous sealing device to the expanded configuration. When autonomous sealing device  150  includes reservoir chamber  190  and expansion chamber  192 , the autonomous sealing device further may include a check valve  194  that is configured to at least temporarily retain the expansion fluid within the expansion chamber subsequent to the autonomous sealing device transitioning to the expanded configuration. 
     Autonomous sealing device  150  further may be configured to transition from expanded configuration  154  to a retracted configuration  156 , which also may be referred to herein as a spent configuration  156  and/or a post-expansion configuration  156 . Upon transitioning to retracted configuration  156 , the autonomous sealing device may be configured to permit fluid flow between uphole portion  46  and downhole portion  48  and/or may be configured to pass through reduced-area regions  102 . As an illustrative, non-exclusive example, retracted configuration  156  may define a retracted configuration volume that is less than the expanded configuration volume. As another illustrative, non-exclusive example, retracted configuration  156  may define a retracted configuration characteristic dimension, or diameter, that is less than the expanded characteristic dimension, or diameter. 
     It is within the scope of the present disclosure that autonomous sealing device  150  may transition from expanded configuration  154  to retracted configuration  156  in any suitable manner, at any suitable timing, and/or responsive to any suitable conditions or actuator. As illustrative, non-exclusive examples, the autonomous sealing device may shrink, retract, break apart, and/or dissolve to transition to, or toward, the retracted configuration. As a more specific but still illustrative, non-exclusive example, the autonomous sealing device may be a frangible autonomous sealing device that is formed, at least partially, from a frangible material, and the autonomous sealing device further may include a fragmentation charge  196  that is configured to be actuated to break apart the frangible autonomous sealing device and thereby transition the frangible autonomous sealing device to the retracted configuration. 
     Autonomous sealing device  150  further may include a supplemental material  198 , and the autonomous sealing device may be configured to release the supplemental material within casing conduit  44 . This may include releasing the supplemental material subsequent to transitioning to the expanded configuration, upon transitioning to the contracted configuration, upon breaking apart within the casing conduit, and/or upon dissolving within the casing conduit. Illustrative, non-exclusive examples of supplemental material  198  include any suitable gel breaker, paraffin inhibitor, corrosion inhibitor, and/or tracer material. It also is within the scope of the present disclosure that the systems and/or methods may utilize supplemental material and/or mechanisms or devices for delivering and/or releasing supplemental material that are not attached to, are not included in, and/or do not form a portion of an autonomous sealing device  150 . 
     Hydrocarbon well  30  and/or casing conduit  44  thereof may include and/or contain a plurality of autonomous sealing devices  150  that each may contain a respective volume of supplemental material  198 . Under these conditions, each of the respective volumes of supplemental material  198  may include a respective (or unique) tracer material that may be readily distinguished from the tracer material that may be included in a remainder of the respective volumes of supplemental sealing material. In addition, the systems and methods disclosed herein may be configured to detect the presence of the respective tracer materials within a reservoir fluid  24  that is produced from hydrocarbon well  30 , thereby providing information regarding which region(s) of subterranean formation  22  are producing the reservoir fluid and/or which autonomous sealing device(s) are restricting fluid flow between respective uphole and downhole portions of the casing conduit. 
     Autonomous sealing device  150  may be configured to form a fluid seal with the selected motion-arresting structure  100  upon transitioning to expanded configuration  154  and to thereby restrict the fluid flow between uphole portion  46  and downhole portion  48 . As an illustrative, non-exclusive example, motion-arresting structures  100  may define a sealing surface  112  that may be designed, constructed, shaped, and/or sized to form the fluid seal with the autonomous sealing device. Under these conditions, and when autonomous sealing device  150  is in expanded configuration  154 , an outer diameter of the autonomous sealing device may be less than an inner diameter of casing conduit  44 . Additionally or alternatively, and when autonomous sealing device  150  is in expanded configuration  154 , the outer diameter of the autonomous sealing device may be equal to the inner diameter of the casing conduit and/or the autonomous sealing device may be designed, constructed, shaped, and/or sized to form the fluid seal with inner surface  42  of casing string  40 . This is discussed in more detail herein with reference to  FIG. 2 . 
     Autonomous sealing device  150  may be constructed, configured, and/or programmed to transition from contracted configuration  152 , to expanded configuration  154 , and/or to retracted configuration  156  based upon any suitable criteria and/or responsive to any suitable event. As an illustrative, non-exclusive example, the autonomous sealing device may transition (or be transitioned) to expanded configuration  154  responsive to being located within a target, and/or otherwise selected, portion of casing conduit  44  (such as a portion of casing conduit  44  that is uphole from, directly uphole from, and/or within a threshold distance of the selected motion-arresting structure  100 ). As another illustrative, non-exclusive example, the autonomous sealing device may transition (or be transitioned) to expanded configuration  154  responsive to flowing a target, or desired, distance along a (longitudinal) length of (and/or within) casing conduit  44 . As yet another illustrative, no-exclusive example, autonomous sealing device  150  may transition (or be transitioned) to retracted configuration  156  subsequent to stimulation of a target region of subterranean formation  22 , responsive to (or upon) being located within casing conduit  44  for at least a threshold period of time, and/or responsive to (or upon) production of reservoir fluid  24  from subterranean formation  22 . 
     It is within the scope of the present disclosure that autonomous sealing device  150  may transition among and/or between contracted configuration  152 , expanded configuration  154 , and/or retracted configuration  156  at any suitable transition rate. As an illustrative, non-exclusive example, autonomous sealing device  150  may be configured to partially transition to expanded configuration  154  prior to being retained on the selected motion-arresting structure  100  and to complete the transition to the expanded configuration subsequent to being retained on the selected motion-arresting structure. As another illustrative, non-exclusive example, autonomous sealing device  150  also may be configured to completely transition to expanded configuration  154  prior to being retained on the selected motion-arresting structure. 
     The transitioning of autonomous sealing device  150  among the various configurations thereof may be controlled, regulated, and/or initiated in any suitable manner. As an illustrative, non-exclusive example, expansion mechanism  158  may be a passive structure that is configured to control the transitioning of the autonomous sealing device responsive to temperatures and/or pressures within casing conduit  44  and/or responsive to a residence time of the autonomous sealing device within the casing conduit. 
     As another illustrative, non-exclusive example, the transition may be actively controlled, such as via an autonomous controller  160  that is adapted, configured, and/or programmed to control the operation of the autonomous sealing device. As an illustrative, non-exclusive example, autonomous controller  160  may be programmed to determine a location of autonomous sealing device  150  within casing conduit  44  and/or may transition the autonomous sealing device to expanded configuration  154  based upon the determined location and/or when the determined location corresponds to a target location within the casing conduit. The location of the autonomous sealing device may be and/or may be determined based upon a distance that the autonomous sealing device has traveled within the casing conduit and/or a depth of the autonomous sealing device below a ground surface. Additionally or alternatively, the autonomous controller also may be programmed to time the transition to the expanded configuration such that the autonomous sealing device is retained on the selected motion-arresting structure while passing through motion-arresting structures that may be uphole from the selected motion-arresting structure. 
     Additionally or alternatively, autonomous controller  160  may be programmed to determine a variable associated with the autonomous sealing device and/or to transition the autonomous sealing device to the expanded configuration based upon the determined variable. Illustrative, non-exclusive examples of the variable associated with the autonomous sealing device include a velocity of the autonomous sealing device within the casing conduit, a speed of the autonomous sealing device within the casing conduit, an acceleration of the autonomous sealing device within the casing conduit, a deceleration of the autonomous sealing device within the casing conduit, a pressure proximal to the autonomous sealing device within the casing conduit, a location of the autonomous sealing device along the length of the casing string, and/or a number of casing collars  41  that the autonomous sealing device has traveled past while located within the casing conduit. 
     It is within the scope of the present disclosure that autonomous controller  160  may include one or more sensors and/or detectors. These sensors and/or detectors may be configured to determine, measure, and/or detect any suitable variable associated with autonomous sealing device  150 , illustrative, non-exclusive examples of which are disclosed herein. 
     Motion-arresting structures  100  may include any suitable structure that defines reduced-area regions  102  and/or that is configured to retain autonomous sealing device  150  subsequent to the autonomous sealing device transitioning to expanded configuration  154 . In addition, motion-arresting structures  100  also may be formed in any suitable manner. As an illustrative, non-exclusive example, the casing string may include and/or be a monolithic structure that includes one or more sections of casing  43  and motion-arresting structures  100 . Under these conditions, motion-arresting structures  100  may be formed from casing string  40  (or section(s) of casing  43  thereof). This may include forming the motion-arresting structure with, or concurrently with, the casing string (such as by molding, rolling, and/or extruding the motion-arresting structures with the casing string) and/or deforming the casing string to form the motion-arresting structures (such as by indenting and/or dimpling the casing string). 
     As another illustrative, non-exclusive example, motion-arresting structures  100  may be formed separately from casing string  40  (and/or sections of casing  43  thereof) and/or may be operatively attached to the casing string. As an illustrative, non-exclusive example, casing collars  41  may include and/or define motion-arresting structures  100 . Under these conditions, motion-arresting structures  100  also may be referred to herein as motion-arresting casing collar assemblies  101 . As another illustrative, non-exclusive example, motion-arresting structures  100  may extend through holes in casing string  40  and thus into casing conduit  44 . As yet another illustrative, non-exclusive example, motion-arresting structures  100  may be welded or otherwise secured to the inner surface of the casing conduit. 
     Hydrocarbon well  30  and/or casing string  40  thereof may include any suitable number of motion-arresting structures  100 . As illustrative, non-exclusive examples, the hydrocarbon well may include at least 2, at least 4, at least 6, at least 10, at least 15, at least 20, at least 25, at least 30, at least 35, at least 40, at least 45, at least 50, at least 55, at least 60, at least 70, at least 80, at least 90, at least 100, at least 125, at least 150, at least 200, or at least 250 motion-arresting structures  100 . 
     The plurality of motion-arresting structures  100  may be spaced apart along the length of casing string  40  at any suitable spacing, or relative spacing. As an illustrative, non-exclusive example, an average distance between a given motion-arresting structure and the next adjacent motion-arresting structure (i.e., the next motion-arresting structure in an uphole or downhole direction) may be at least 10 meters, at least 15 meters, at least 20 meters, at least 30 meters, at least 40 meters, at least 50 meters, at least 60 meters, at least 70 meters, at least 80 meters, at least 90 meters, or at least 100 meters. Additionally or alternatively, the average distance between adjacent motion-arresting structures also may be less than 300 meters, less than 250 meters, less than 200 meters, less than 175 meters, less than 150 meters, less than 140 meters, less than 130 meters, less than 120 meters, less than 110 meters, less than 100 meters, less than 90 meters, less than 80 meters, less than 70 meters, less than 60 meters, less than 50 meters, less than 40 meters, or less than 30 meters. 
     Reduced-area regions  102  may define any suitable cross-sectional area (or transverse cross-sectional area) relative to the cross-sectional area (or transverse cross-sectional area) of casing conduit  44  (or the cross-sectional area that is defined by inner surface  42  of casing string  40 ). As illustrative, non-exclusive examples, the transverse cross-sectional area of reduced-area regions  102  may be at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90%, or at least 95% of the transverse cross-sectional area of the portion of the casing conduit that is defined by inner surface  42  of casing string  40 . As another illustrative, non-exclusive example, the transverse cross-sectional area of reduced-area regions  102  may be less than 99%, less than 98%, less than 97%, less than 96%, less than 95%, less than 94%, less than 93%, less than 92%, less than 91%, less than 90%, less than 89%, less than 88%, less than 87%, less than 86%, or less than 85% of the transverse cross-sectional area of the portion of the casing conduit that is defined by the inner surface of the casing string. 
     It is within the scope of the present disclosure that the plurality of reduced-area regions may define a respective plurality of similar, or even identical, transverse cross-sectional areas. However, it is also within the scope of the present disclosure that the plurality of reduced-area regions may not define a respective plurality of similar transverse cross-sectional areas and/or that a transverse cross-sectional area of a first portion of the plurality of reduced area regions may be different from a transverse cross-sectional area of a second portion of the plurality of reduced area regions. 
     As an illustrative, non-exclusive example, a first reduced-area region may have a first transverse cross-sectional area that is less than a transverse cross-sectional area of the remaining reduced-area regions. In addition, a second reduced-area region may have a second transverse cross-sectional area that is greater than a transverse cross-sectional area of the remaining reduced-area regions. Under these conditions, a ratio of the first transverse cross-sectional area to the second transverse cross-sectional area may be at least a threshold area ratio. Illustrative, non-exclusive examples of the threshold area ratio include threshold area ratios of at least 0.55, at least 0.6, at least 0.65, at least 0.7, at least 0.75, at least 0.8, at least 0.85, at least 0.9, at least 0.95, at least 0.96, at least 0.97, at least 0.98, or at least 0.99. 
     Perforation device  170  may be operatively attached to, included in, and/or form a portion of autonomous sealing device  150  and may include any suitable structure that may be configured to create a perforation within casing string  40 . As an illustrative, non-exclusive example, perforation device  170  may include and/or be a perforation gun that includes one or more perforation charges. It also is within the scope of the present disclosure that the systems and/or methods disclosed herein may utilize one or more perforation devices  170  that are not attached to, are not included in, and/or do not form a portion of an autonomous sealing device  150 . 
     Illustrative, non-exclusive examples of the operation of perforation device  170  within hydrocarbon well  30  are discussed in more detail herein. As illustrative, non-exclusive examples, perforation device  170  may be configured to create the perforation prior to, concurrent with, and/or subsequent to autonomous sealing device  150  being retained on the selected motion-arresting structure  100 . Additionally or alternatively, the perforation device  170  may be configured to create the perforation responsive to the pressure proximal to the autonomous sealing device exceeding a threshold perforating pressure. 
     Casing string  40  may include and/or be any suitable structure that defines the portion of casing conduit  44 . As an illustrative, non-exclusive example, and as discussed, the casing string may include a plurality of sections of casing  43  that are operatively attached to one another via a plurality of casing collars  41 . Under these conditions, a distance between adjacent casing collars (or a length of sections of casing  43 ) may be at least 5 meters, at least 6 meters, at least 7 meters, at least 8 meters, at least 9 meters, at least 10 meters, at least 11 meters, at least 12 meters, or at least 13 meters. Additionally or alternatively, the distance between adjacent casing collars also may be less than 20 meters, less than 19 meters, less than 18 meters, less than 17 meters, less than 16 meters, less than 15 meters, less than 14 meters, or less than 13 meters. As another illustrative, non-exclusive example, the casing string may include and/or be a continuous, or at least substantially continuous, casing string, such as may be formed by a continuous, or at least substantially continuous, length of tubing. 
     It is within the scope of the present disclosure that casing string  40  may be formed from any suitable material. As illustrative, non-exclusive examples, the casing string may be a metallic casing string, a non-metallic casing string, and/or a polymeric casing string. 
     It is also within the scope of the present disclosure that casing string  40  may define any suitable (longitudinal) length. As illustrative, non-exclusive examples, the length of the casing string may be at least 1000 meters, at least 1500 meters, at least 2000 meters, at least 2500 meters, at least 3000 meters, at least 3500 meters, at least 4000 meters, at least 4500 meters, or at least 5000 meters. Additionally or alternatively, the length of the casing string also may be less than 10,000 meters, less than 9000 meters, less than 8000 meters, less than 7000 meters, less than 6000 meters, less than 5000 meters, less than 4500 meters, less than 4000 meters, less than 3500 meters, or less than 3000 meters. 
     The portion of the length of the casing string that includes motion-arresting structures  100  may include at least 25%, at least 30%, at least 35%, at least 40%, at least 45%, at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, or at least 90% of the (total) length of the casing string. Additionally or alternatively, the portion of the length also may be less than 100%, less than 95%, less than 90%, less than 85%, less than 80%, or less than 75% of the (total) length of the casing string. 
     Subterranean formation  22  may include any suitable structure that may include and/or contain reservoir fluid  24 . As illustrative, non-exclusive examples, subterranean formation  22  may include and/or be a hydrocarbon formation, a hydrocarbon reservoir, and/or an oil shale formation. In addition, reservoir fluid  24  may include any suitable fluid, illustrative, non-exclusive examples of which include a liquid, such as oil, and/or a gas, such as natural gas. 
       FIG. 2  is a schematic cross-sectional view of illustrative, non-exclusive examples of a casing string  40  and/or of a casing collar  41  that includes a motion-arresting structure  100  and that may be utilized with an autonomous sealing device  150  according to the present disclosure. As illustrated in solid lines in  FIG. 2 , motion-arresting structure  100  includes an isolation ring  110  that is configured to receive autonomous sealing device  150  and that defines a reduced-area region  102  of a casing conduit  44 . Isolation ring  100  may define a sealing surface  112  that is configured to form a fluid seal with autonomous sealing device  150 , as indicated at  185 . Additionally or alternatively, the autonomous sealing device may be configured to form the fluid seal with an inner surface  42  of casing string  40 , as indicated at  180 . 
     Isolation ring  110  further may include a sealing device seat  114  that is sized to receive autonomous sealing device  150  when the autonomous sealing device is in expanded configuration  154  and/or to define at least a portion of sealing surface  112 . Sealing device seat  114  may be shaped and/or contoured to complement a shape of autonomous sealing device  150  and thereby to enhance the fluid seal between the isolation ring and the autonomous sealing device. 
     Isolation ring  110  also may include and/or define a contoured surface  116 . Contoured surface  116  may be shaped to permit and/or facilitate flow of autonomous sealing device  150  past motion-arresting structure  100  when the autonomous sealing device is in a contracted and/or retracted configuration (as discussed herein). Additionally or alternatively, contoured surface  116  also may include, be, and/or function as sealing surface  112  and/or as sealing device seat  114 . 
     As illustrated in dashed lines in  FIG. 2 , isolation ring  110  further may include and/or be a sliding sleeve  130  that is configured to transition between a closed configuration  137  and an open configuration  138 . This may include transitioning responsive to retaining autonomous sealing device  150  and/or responsive to establishing at least a threshold pressure differential between an uphole portion  46  of casing conduit  44  and a downhole portion  48  of the casing conduit. 
     When in closed configuration  137 , sliding sleeve  130  may be configured to restrict, block, and/or occlude a fluid flow through an injection port  132  that is associated therewith. However, and upon transitioning to open configuration  138 , sliding sleeve  130  may permit the fluid flow through the injection port (i.e., from the casing string to the subterranean formation, or vice versa). As used herein, the fluid conduit from the casing string to the subterranean formation additionally or alternatively referred to as an injection conduit  132 , an injection passage  132 , and/or a casing port  132 , a casing-to-wellbore  132 , and/or a casing-to-wellbore passage  132 . 
       FIG. 3  is a schematic cross-sectional view of an illustrative, non-exclusive example of another motion-arresting structure  100  that may be utilized with an autonomous sealing device  150  according to the present disclosure. Motion-arresting structure  100  of  FIG. 3  includes a plurality of (discrete) stops  120 , which also may be referred to herein as pins  120  and/or as projections  120 , that project into a casing conduit  44  and/or from an inner surface  42  of a casing string  40  to define a reduced-area region  102 . Stops  120  are sized to retain autonomous sealing device  150  thereon when the autonomous sealing device is in expanded configuration  154 . However, stops  120  may not include sealing surface  112  of  FIG. 2 . Thus, autonomous motion-arresting structure  150  may be configured to form the fluid seal with inner surface  42 , as indicated at  180 . 
       FIGS. 4-9  are illustrative, non-exclusive examples of hydrocarbon wells  30  that include flow-arresting structures  100  and autonomous sealing devices  150  according to the present disclosure and/or of process flows that may be utilized with the flow-arresting structures and the autonomous sealing devices. The flow-arresting structures and/or the autonomous sealing devices of  FIGS. 4-9  may include and/or be the flow-arresting structures and/or the autonomous sealing devices of  FIGS. 1-3  and the process flows that are described herein with reference to  FIGS. 4-9  may be utilized with hydrocarbon well  30  of  FIG. 1  without departing from the scope of the present disclosure. 
       FIGS. 4-5  are schematic representations of illustrative, non-exclusive examples of a process flow that may be utilized with a hydrocarbon well  30  according to the present disclosure that includes a flow-arresting structure  100  that includes sliding sleeves  130 . In  FIG. 4 , sliding sleeves  130  are in a closed configuration  137  and restrict fluid flow through injection conduits  132  that are associated therewith. As illustrated in dash-dot lines, autonomous sealing device  150  may flow with stimulant fluid  62  through a first motion-arresting structure  100  while in a contracted configuration  152 . Subsequently, the autonomous sealing device may transition to an expanded configuration  154  and be retained on a second motion-arresting structure  100  (as illustrated in solid lines). 
     The autonomous sealing device forms a fluid seal with the second motion-arresting structure, thereby restricting fluid flow from an uphole portion  46  of a casing conduit  44  to a downhole portion  48  of the casing conduit. This may permit pressurization of the uphole portion of the casing conduit. Then, and as illustrated in  FIG. 5 , sliding sleeve  130  of the second motion-arresting structure may transition to an open configuration  138  (such as responsive to the pressure within the uphole portion of the casing conduit exceeding a threshold stimulating pressure), thereby permitting stimulant fluid  62  to flow through injection conduit  132  and into subterranean formation  22 , such as to stimulate and/or fracture the subterranean formation. 
       FIGS. 4-5  illustrate hydrocarbon well  30  including two motion-arresting structures  100 . However, it is within the scope of the present disclosure that any suitable number of motion-arresting structures may be present within hydrocarbon well  30 . Thus, the above-described process may be repeated any suitable number of times to transition any suitable number of sliding sleeves  130  from the closed configuration to the open configuration and thereby to stimulate and/or fracture any suitable number of regions, zones, and/or portions of subterranean formation  22 . 
       FIGS. 6-7  are schematic representations of illustrative, non-exclusive examples of another process flow that may be utilized with a hydrocarbon well  30  according to the present disclosure that includes an autonomous sealing device  150  that includes and/or is operatively attached to a perforation device  170 . As illustrated in dash-dot lines in  FIG. 6 , autonomous sealing device  150  and perforation device  170  may flow with stimulant fluid  62  through a first motion-arresting structure  100  while autonomous sealing device  150  is in a contracted configuration  152 . Subsequently, the autonomous sealing device may transition to an expanded configuration  154  and be retained on a second motion-arresting structure  100  (as illustrated in solid lines). 
     The autonomous sealing device forms a fluid seal with the second motion-arresting structure, thereby restricting fluid flow from an uphole portion  46  of a casing conduit  44  to a downhole portion  48  of the casing conduit. This may permit pressurization of the uphole portion of the casing conduit. Then, and as illustrated in  FIG. 7 , perforation device  170  may create one or more perforations  172  within a casing string  40  that defines casing conduit  44  (such as responsive to the pressure within the uphole portion of the casing conduit exceeding a threshold perforating pressure). This may permit stimulant fluid  62  to flow through perforations  172  into subterranean formation  22 , such as to stimulate and/or fracture the subterranean formation. 
       FIGS. 6-7  illustrate hydrocarbon well  30  with only two motion-arresting structures  100 . However, and as discussed herein with reference to  FIGS. 4-5 , hydrocarbon well  30  may include any suitable number of motion-arresting structures  100  and the above-described process may be repeated any suitable number of times to simulate and/or fracture any suitable number of regions, zones, and/or portions of subterranean formation  22 . 
       FIGS. 8-9  are schematic representations of illustrative, non-exclusive examples of another process flow that may be utilized with a hydrocarbon well  30  according to the present disclosure that includes a motion-arresting structure  100 , an autonomous sealing device  150 , and a hydraulically actuated sleeve  74 . In  FIG. 8 , hydraulically actuated sleeve  74  is in a closed configuration  77  and restricts fluid flow through a sleeve port  76  that is associated therewith. As illustrated in dash-dot lines, autonomous sealing device  150  may flow with stimulant fluid  62  through a first motion-arresting structure  100  while in a contracted configuration  152 . Subsequently, the autonomous sealing device may transition to an expanded configuration  154  and be retained on a second motion-arresting structure  100  (as illustrated in sold lines). 
     The autonomous sealing device forms a fluid seal with the second motion-arresting structure, thereby restricting fluid flow from an uphole portion  46  of a casing conduit  44  to a downhole portion  48  of the casing conduit. This may permit pressurizing of the uphole portion of the casing conduit. Then, and as illustrated in  FIG. 9 , hydraulically actuated sleeve  74  may transition to an open configuration  78  (such as responsive to the pressure within the uphole portion of the casing conduit exceeding a threshold stimulating pressure and/or a pressure differential between the uphole portion of the casing conduit and the subterranean formation exceeding a threshold pressure differential), thereby permitting stimulant fluid  62  to flow through sleeve port  76  and into subterranean formation  22 , such as to stimulate and/or fracture the subterranean formation. 
       FIGS. 8-9  illustrate hydrocarbon well  30  as including only two motion-arresting structures  100  and a single hydraulically actuated sleeve  74 . However, and as discussed herein with reference to  FIGS. 4-7 , hydrocarbon well  30  may include any suitable number of motion-arresting structures  100  and/or hydraulically actuated sleeves  74  and the above-described process may be repeated any suitable number of times to stimulate and/or fracture any suitable number of regions, zones, and/or portions of subterranean formation  22 . 
       FIG. 10  is a flowchart depicting methods according to the present disclosure of restricting fluid flow between an uphole portion of a casing conduit and a downhole portion of the casing conduit. The casing conduit is partially defined by a casing string that extends within a wellbore that is defined within a subterranean formation. In addition, the casing string includes, contains, and/or is operatively attached to a plurality of motion-arresting structures that are spaced apart from one another along a (longitudinal) length of the casing string. The motion-arresting structures project from an inner surface of the casing string to define a plurality of reduced-area regions of the casing conduit. 
     Methods  200  may include locating an autonomous sealing device within the casing conduit at  205  and/or supplying a stimulant fluid to the casing conduit at  210 . Methods  200  include conveying the autonomous sealing device within the casing conduit at  215  and may include detecting a variable associated with the autonomous sealing device at  220 . Methods  200  further include determining that the autonomous sealing device is located within a target portion of the casing conduit at  225 , expanding the autonomous sealing device at  230 , retaining the autonomous sealing device on a selected motion-arresting structure at  235 , and restricting fluid flow between an uphole portion of the casing conduit and a downhole portion of the casing conduit at  240 . Methods  200  further may include stimulating the subterranean formation at  245 , repeating the methods at  250 , removing the autonomous sealing device from the casing conduit at  255 , and/or producing a reservoir fluid from the subterranean formation at  260 . 
     Locating the autonomous sealing device within the casing conduit at  205  may include locating any suitable autonomous sealing device, such as autonomous sealing device  150  of  FIGS. 1-9 , within the casing conduit in any suitable manner. As an illustrative, non-exclusive example, the locating at  205  may include placing the autonomous sealing device within the casing conduit and/or lubricating the autonomous sealing device into the casing conduit. Additionally or alternatively, the locating at  205  also may include transferring the autonomous sealing device from a surface region into the casing conduit. 
     Supplying the stimulant fluid to the casing conduit at  210  may include supplying any suitable stimulant fluid, illustrative, non-exclusive examples of which are disclosed herein, to the casing conduit. This may include pumping the stimulant fluid into the casing conduit. It is within the scope of the present disclosure that, when methods  200  include the supplying at  210 , the supplying at  210  may include (at least substantially) continuously supplying the stimulant fluid to the casing conduit during a remainder of methods  200  and/or supplying the stimulant fluid to the casing conduit during at least the conveying at  215 , the determining at  225 , the expanding at  230 , the retaining at  235 , and/or the restricting at  240 . 
     Conveying the autonomous sealing device within the casing conduit at  215  may include conveying while the autonomous sealing device is in a contracted configuration and/or conveying the autonomous sealing device through at least a portion of the plurality of reduced-area regions. As an illustrative, non-exclusive example, the conveying at  215  may include hydraulically conveying, such as by flowing the autonomous sealing device with the stimulant fluid that is provided during the supplying at  210 . As another illustrative, non-exclusive example, the conveying at  215  also may include mechanically conveying, such as by tractoring the autonomous sealing device into, along, and/or through the casing conduit. As yet another illustrative, non-exclusive example, the conveying at  215  may include conveying the autonomous sealing device along the (longitudinal) length of the casing string under the influence of gravity. 
     It is within the scope of the present disclosure that the conveying at  215  may include conveying at any suitable speed and/or velocity, including relatively high speeds and/or velocities. As illustrative, non-exclusive examples, the conveying at  215  may include conveying at a speed and/or velocity of at least 2 meters per second (m/s), at least 4 m/s, at least 6 m/s, at least 8 m/s, at least 10 m/s, at least 12 m/s, at least 14 m/s, at least 16 m/s, at least 18 m/s, at least 20 m/s, at least 22 m/s, at least 24 m/s, at least 26 m/s, at least 28 m/s, or at least 30 m/s. 
     Detecting the variable associated with the autonomous sealing device at  220  may include detecting any suitable variable that may be associated with the autonomous sealing device. This may include detecting with any suitable detector and/or utilizing any suitable autonomous controller, such as autonomous controller  160  of  FIG. 1 . Illustrative, non-exclusive examples of the variable associated with the autonomous sealing device are disclosed herein. When methods  200  include the detecting at  220 , it is within the scope of the present disclosure that the determining at  225  may be based, at least in part, on the detecting at  220  and/or based, at least in part, on the variable associated with the autonomous sealing device. 
     Determining that the autonomous sealing device is located within the target portion of the casing conduit at  225  may include determining in any suitable manner. As an illustrative, non-exclusive example, the determining at  225  may include determining that the variable associated with the autonomous sealing device is equal to, is greater than, and/or is less than a threshold value. As more specific but still illustrative, non-exclusive examples, the determining at  225  may include determining that the autonomous sealing device has reached a target depth within the subterranean formation, determining that the autonomous sealing device has traversed a target (longitudinal) length of the casing conduit and/or of the casing string, determining that the autonomous sealing device has been conveyed through a target number of reduced-area regions, and/or determining that the autonomous sealing device has been conveyed past a target number of casing collars (such as casing collar  41  of  FIGS. 1-9 ). 
     Expanding the autonomous sealing device at  230  may include expanding the autonomous sealing device based, at least in part, on the determining at  225  and/or expanding the autonomous sealing device responsive to the determining at  225 . The expanding at  230  may include automatically expanding, such as by expanding without the autonomous sealing device receiving an external input. 
     It is within the scope of the present disclosure that the expanding at  230  may include completely expanding prior to the retaining at  235 . However, it is also within the scope of the present disclosure that the expanding at  230  may include partially expanding prior to the retaining at  235 , with complete expansion to the expanded state being accomplished subsequent to the retaining at  235 . 
     The expanding at  235  may be initiated such that the autonomous sealing device is retained on the selected motion-arresting structure. As such, initiation of the expanding at  235  may be based, at least in part, on the velocity and/or acceleration of the autonomous sealing device within the casing conduit and/or upon a distance between the autonomous sealing device and the selected motion-arresting structure. 
     It is within the scope of the present disclosure that the expanding at  235  may be accomplished in any suitable manner. As an illustrative, non-exclusive example, the expanding at  235  may include triggering an expansion mechanism, such as expansion mechanism  158  of  FIG. 1 , illustrative, non-exclusive examples of which are disclosed herein. 
     Retaining the autonomous sealing device on the selected motion-arresting structure at  235  may include retaining the autonomous sealing device on any suitable motion-arresting structure, such as motion-arresting structure  100  of  FIGS. 1-9 . As an illustrative, non-exclusive example, and subsequent to the expanding at  230 , the autonomous sealing device may no longer be sized to pass through the plurality of reduced area regions, causing the autonomous sealing device to be retained on the selected motion-arresting structure. As another illustrative, non-exclusive example, the retaining at  235  may include ceasing a motion of the autonomous sealing device along the (longitudinal) length of the casing string. As additional illustrative, non-exclusive examples, the retaining at  235  may include mechanically, physically, and/or directly contacting the autonomous sealing device with the selected motion-arresting structure to retain the autonomous sealing device on the selected motion-arresting structure. 
     Restricting fluid flow between the uphole portion of the casing conduit and the downhole portion of the casing conduit at  240  may include restricting, blocking, limiting, occluding, and/or eliminating the fluid flow with the autonomous sealing device. This may include forming a fluid seal between the autonomous sealing device and the selected motion-arresting structure and/or forming a fluid seal between the autonomous sealing device and the inner surface of the casing string. As an illustrative, non-exclusive example, the restricting at  240  may include fluidly isolating the uphole portion of the casing conduit from the downhole portion of the casing conduit. This may include resisting fluid flow from the uphole portion of the casing conduit into the downhole portion of the casing conduit and/or resisting fluid flow from the downhole portion of the casing conduit into the uphole portion of the casing conduit. 
     Stimulating the subterranean formation at  245  may include stimulating the subterranean formation in any suitable manner As illustrative, non-exclusive examples, the stimulating may include fracturing the subterranean formation and/or acid treating the subterranean formation. This may include supplying the stimulant fluid to the subterranean formation, and it is within the scope of the present disclosure that the stimulant fluid may be supplied to the subterranean formation subsequent to the retaining at  235 , responsive to the retaining at  235 , and/or responsive to a pressure within the casing conduit exceeding a threshold stimulating pressure. 
     As an illustrative, non-exclusive example, the stimulating at  245  may include translating a sliding sleeve at  246 . This may include opening an injection conduit, such as injection conduit  132  of  FIGS. 1-2  and  4 - 5 , that is associated with the sliding sleeve, such as sliding sleeve  130  of  FIGS. 1-2  and  4 - 5 , to establish fluid communication, via the injection port, between the casing conduit and the subterranean formation. Additionally or alternatively, this also may include opening a sleeve port, such as sleeve port  76  of FIGS.  1  and  8 - 9 , that is associated with a hydraulically actuated sleeve, such as hydraulically actuated sleeve  74  of FIGS.  1  and  8 - 9 . 
     As yet another illustrative, non-exclusive example, the stimulating at  245  also may include perforating the casing string at  247 . As an illustrative, non-exclusive example, the autonomous sealing device may be operatively attached to and/or may include a perforation device, such as perforation device  170  of FIGS.  1  and  5 - 6 , and the perforating at  247  may include creating a perforation within the casing string to establish fluid communication, via the perforation, between the casing conduit and the subterranean formation. 
     Repeating the methods at  250  may include repeating any suitable portion of methods  200 . As an illustrative, non-exclusive example, the autonomous sealing device may be a first autonomous sealing device, the selected motion-arresting structure may be a first selected motion-arresting structure, the downhole portion of the casing conduit may be a first downhole portion of the casing conduit, and the uphole portion of the casing conduit may be a first uphole portion of the casing conduit. Under these conditions, the repeating at  250  may include repeating at least the conveying at  215 , the determining at  225 , the expanding at  230 , the retaining at  235 , and the restricting at  240  to retain a second (or subsequent) autonomous sealing device on a second (or subsequent) selected motion-arresting structure that is uphole from the first motion-arresting structure and to restrict fluid flow between a second (or subsequent) uphole portion of the casing conduit and a second (or subsequent) downhole portion of the casing conduit. 
     Additionally, the stimulating at  245  may include stimulating a first region of the subterranean formation and the repeating at  250  may include repeating the stimulating at  245  to stimulate a second (or subsequent) region of the subterranean formation that is uphole from the first region of the subterranean formation. 
     It is within the scope of the present disclosure that the repeating at  250  may include repeating any suitable portion of methods  200  any suitable number of times to restrict fluid flow between any suitable number of uphole portions of the casing conduit and a corresponding number of downhole portions of the casing conduit and/or to stimulate any suitable number of regions of the subterranean formation. As illustrative, non-exclusive examples, the repeating at  250  may include repeating at least 2, at least 4, at least 6, at least 10, at least 15, at least 20, at least 25, at least 30, at least 35, at least 40, at least 45, at least 50, at least 55, at least 60, at least 70, at least 80, at least 90, at least 100, at least 125, at least 150, at least 200, or at least 250 times. 
     Removing the autonomous sealing device from the casing conduit at  255  may include removing the autonomous sealing device in any suitable manner. As an illustrative, non-exclusive example, and subsequent to the restricting at  240 , the stimulating at  245 , and/or the repeating at  250 , the autonomous sealing device may be configured to transition (from the expanded configuration) to a retracted configuration and, in the retracted configuration, the autonomous sealing device may be sized to be removed from the casing conduit and/or to pass through the plurality of reduced-area regions (in an uphole and/or downhole direction). As another illustrative, non-exclusive example, the removing at  255  also may include flowing the autonomous sealing device to the surface region. As yet another illustrative, non-exclusive example, the removing at  255  may include shrinking, retracting, breaking apart, and/or dissolving the autonomous sealing device to permit and/or to accomplish the removing at  255 . 
     Producing the reservoir fluid from the subterranean formation at  260  may include producing any suitable reservoir fluid, illustrative, non-exclusive examples of which are disclosed herein, in any suitable manner. This may include producing without drilling (and/or otherwise removing) a bridge plug from the casing conduit and/or producing without drilling (and/or otherwise removing) an isolation ball (or a plurality of differently sized isolation balls) from the casing conduit. 
     As discussed, the systems and methods disclosed herein are illustrative, non-exclusive examples; and it is within the scope of the present disclosure that autonomous sealing devices and motion-arresting structures according to the present disclosure may be utilized with and/or within any suitable systems and/or methods. As illustrative, non-exclusive examples, hydrocarbon wells  30  according to the present disclosure further may include and/or otherwise utilize one or more perforation guns, chemical treatment devices, and/or data recording devices that are not directly coupled to or integrated with an autonomous sealing device or motion-arresting structure. As additional illustrative, non-exclusive examples, methods  200  according to the present disclosure further may include perforating a casing string with the perforation gun, chemically treating any suitable portion of hydrocarbon well  30  and/or of subsurface region  20 , and/or collecting and/or recording any suitable data and/or process parameter that is related to hydrocarbon well  30  and/or to subsurface region  20 . Furthermore, such methods may do so in conjunction with and/or independent of the utilization of the specific configuring and/or locating of the motion-arresting structures. 
     In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. It is also within the scope of the present disclosure that the blocks, or steps, may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions. 
     As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like. 
     As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity. 
     In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally. 
     As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa. 
     INDUSTRIAL APPLICABILITY 
     The systems and methods disclosed herein are applicable to the oil and gas industry. 
     It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.