Patent Publication Number: US-10309195-B2

Title: Selective stimulation ports including sealing device retainers and methods of utilizing the same

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application Ser. No. 62/411,004 filed Oct. 21, 2016, entitled “Selective Stimulation Ports Including Sealing Device Retainers And Methods Of Utilizing The Same,” and benefit of U.S. Provisional Application Ser. No. 62/263,067 filed Dec. 4, 2015, entitled “Ball-Sealer Check-Valves for Wellbore Tubulars and Methods of Utilizing the Same,” and is also related to U.S. patent application Ser. No. 15/264,052 filed Sep. 13, 2016; U.S. patent application Ser. No. 15/264,064 filed Sep. 13, 2016; U.S. Provisional Application Ser. No. 62/263,065 filed Dec. 4, 2015; U.S. patent application Ser. No. 15/264,076 filed Sep. 13, 2016; and U.S. Provisional Application Ser. No. 62/329,690 filed Apr. 29, 2016, the disclosures of each of which are incorporated herein by reference in their entireties. 
    
    
     FIELD OF THE DISCLOSURE 
     The present disclosure relates generally to selective stimulation ports and more particularly to selective stimulation ports that include and/or utilize sealing device retainers and/or to methods of utilizing the selective stimulation ports. 
     BACKGROUND OF THE DISCLOSURE 
     Hydrocarbon wells generally include a wellbore that extends from a surface region and/or that extends within a subterranean formation that includes a reservoir fluid, such as liquid and/or gaseous hydrocarbons. Often, it may be desirable to stimulate the subterranean formation, such as to enhance production of the reservoir fluid therefrom. Stimulation of the subterranean formation may be accomplished in a variety of ways and generally includes supplying a stimulant fluid to the subterranean formation to increase reservoir contact. As an example, the stimulation may include supplying an acid to the subterranean formation to acid-treat the subterranean formation and/or to dissolve at least a portion of the subterranean formation. As another example, the stimulation may include fracturing the subterranean formation, such as by supplying a fracturing fluid, which is pumped at a high pressure, to the subterranean formation. The fracturing fluid may include particulate material, such as a proppant, which may at least partially fill fractures that are generated during the fracturing, thereby facilitating flow of the reservoir fluid into the hydrocarbon well, via the fractures, after supply of the fracturing fluid has ceased. 
     A variety of systems and/or methods have been developed to facilitate stimulation of subterranean formations, and each of these systems and methods generally has inherent benefits and drawbacks. Many of these systems and methods utilize a shape-charge perforation gun to create perforations within a wellbore tubular that defines a tubular conduit and extends within the wellbore, and the stimulant fluid then is provided to the subterranean formation via the perforations. However, such systems suffer from a number of limitations. As an example, the perforations may not be round or may have burrs, which may make it challenging to seal the perforations subsequent to stimulating a given region of the subterranean formation. As another example, the perforations often will erode and/or corrode due to flow of the stimulant fluid, flow of proppant, and/or long-term flow of reservoir fluid therethrough. 
     As yet another example, a stimulation process may involve sealing perforations with a sealing device, such as a ball sealer, in order to facilitate stimulation of various zones, or regions, of the subterranean formation. In such a stimulation process, a pressure within the tubular conduit must be maintained higher than a pressure within the subterranean formation proximate the tubular conduit or the sealing devices may unseat from corresponding perforations, thereby unsealing the corresponding perforations. In some circumstances, it may be difficult to maintain the higher pressure within the tubular conduit, especially if the perforations are only partially sealed. Additionally or alternatively, unexpected events may cause the pressure within the tubular conduit to drop, thereby unseating the sealing devices from the corresponding perforations. Unseated sealing balls may be difficult to reseat on the corresponding perforations. Such events may be costly and/or time-consuming to mitigate. Thus, there exists a need for selective stimulation ports with preformed sealing device seats and sealing device retainers that are configured to retain sealing devices proximate the corresponding sealing device seats. 
     SUMMARY OF THE DISCLOSURE 
     Selective stimulation ports including sealing device retainers and methods of utilizing the same are disclosed herein. The selective stimulation ports (SSPs) have a conduit-facing region and a formation-facing region and are configured to be operatively attached to a wellbore tubular that defines a tubular conduit. The wellbore tubular is configured to extend within a wellbore that extends within a subterranean formation. The SSPs include an SSP conduit, which extends at least substantially perpendicular to a wall of the wellbore tubular, and a sealing device receptacle, which defines at least a portion of the SSP conduit and is sized to receive a sealing device. The SSPs also include a sealing device seat, which defines at least a portion of the SSP conduit, is defined within the sealing device receptacle, and is shaped to form a fluid seal with the sealing device. The SSPs further include a sealing device retainer, which is configured to retain the sealing device within the sealing device receptacle. 
     The methods include methods of stimulating the hydrocarbon well. These methods include pressurizing a wellbore tubular and opening a selected SSP of a plurality of SSPs, with the plurality of SSPs being spaced-apart along a length of the wellbore tubular. These methods also include flowing a first volume of stimulant fluid into the subterranean formation via an SSP conduit of the selected SSP and releasing a sealing device within the tubular conduit. These methods further include receiving the sealing device within a sealing device receptacle of the selected SSP and retaining the sealing device within the sealing device receptacle with a sealing device retainer of the selected SSP. The retaining may include retaining while a pressure within the tubular conduit is greater than a pressure within the subterranean formation, retaining while the pressure within the subterranean formation is greater than the pressure within the tubular conduit, and/or retaining during pressure cycling of the hydrocarbon well. These methods also include seating the sealing device on a sealing device seat of the selected SSP and repeating at least a portion of the methods to stimulate a plurality of subsequent regions of the subterranean formation. 
     The methods also may include methods of conveying a downhole tool within the hydrocarbon well utilizing the SSPs. These methods include restricting fluid flow through each SSP in a plurality of SSPs, with the plurality of SSPs being spaced-apart along a length of a wellbore tubular, with a respective sealing device by receiving the respective sealing device within a respective sealing device receptacle and on a respective sealing device seat of each SSP. These methods also include retaining the respective sealing device within the respective sealing device receptacle with a respective sealing device retainer of each SSP and establishing fluid communication between the subterranean formation and a downhole region of the tubular conduit. These methods further include positioning a downhole tool within an uphole region of the tubular conduit, providing a conveyance fluid to the tubular conduit, and pumping the downhole tool in a downhole direction within the tubular conduit. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic representation of examples of a hydrocarbon well that may include and/or utilize selective stimulation ports, wellbore tubulars, and/or methods, according to the present disclosure. 
         FIG. 2  is a schematic representation of examples of a selective stimulation port, according to the present disclosure, illustrating a seated sealing device. 
         FIG. 3  is another schematic representation of the selective stimulation port of  FIG. 2  illustrating an unseated sealing device. 
         FIG. 4  is another schematic representation of the selective stimulation port of  FIG. 2  illustrating a sealing device entering a sealing device receptacle. 
         FIG. 5  is a schematic representation of examples of a selective stimulation port according to the present disclosure. 
         FIG. 6  is a flowchart depicting methods, according to the present disclosure, of stimulating a hydrocarbon well. 
         FIG. 7  is a flowchart depicting methods, according to the present disclosure, of conveying a downhole tool within a hydrocarbon well. 
     
    
    
     DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE 
       FIGS. 1-7  provide examples of hydrocarbon wells  10 , of wellbore tubulars  40 , of selective stimulation ports  100 , of methods  1100 , and/or of methods  1200 , according to the present disclosure. Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of  FIGS. 1-7 , and these elements may not be discussed in detail herein with reference to each of  FIGS. 1-7 . Similarly, all elements may not be labeled in each of  FIGS. 1-7 , 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. 1-7  may be included in and/or utilized with any of  FIGS. 1-7  without departing from the scope of the present disclosure. In general, elements that are likely to be included in a particular embodiment are illustrated in solid lines, while elements that are optional are illustrated in dashed lines. However, elements that are shown in solid lines may not be essential and, in some embodiments, may be omitted without departing from the scope of the present disclosure. 
       FIG. 1  is a schematic representation of examples of a hydrocarbon well  10  that may include and/or utilize selective stimulation ports  100 , wellbore tubulars  40 , and/or methods  1100  and/or  1200 , according to the present disclosure. Hydrocarbon wells  10  include wellbore tubular  40 , which defines a tubular conduit  42 . Hydrocarbon wells  10  also include a wellbore  20 , which extends within a subterranean formation  34 , and wellbore tubular  40  extends within the wellbore. Wellbore  20  also may be referred to herein as extending within a subsurface region  32  that includes subterranean formation  34  and/or as extending between a surface region  30  and subterranean formation  34 . Subterranean formation  34  may include a reservoir fluid  36 , such as a hydrocarbon, and hydrocarbon well  10  may be utilized to produce the reservoir fluid from the subterranean formation. 
     Hydrocarbon wells  10  also include a plurality of selective stimulation ports (SSPs)  100 . As discussed in more detail herein with reference to  FIGS. 2-5 , each SSP  100  is operatively attached to wellbore tubular  40  such that a corresponding conduit-facing region  112  of the SSP faces toward tubular conduit  42  and also such that a corresponding formation-facing region  114  of the SSP faces away from tubular conduit  42 , toward subsurface region  32 , and/or toward subterranean formation  34 . 
     As illustrated in  FIG. 1 , SSPs  100  may be spaced-apart from one another, such as along a length, or longitudinal length, of wellbore  20  and/or of wellbore tubular  40 . Wellbore  20  and/or wellbore tubular  40  may include, have, and/or define an uphole end, or region,  26  and a downhole end, or region,  24 . Downhole end  24  may be defined within subsurface region  32 , may be defined within subterranean formation  34 , and/or may be distal surface region  30  relative to uphole end  26 . Uphole end  26  may open to surface region  30  and/or may be proximal surface region  30  relative to downhole end  24 . Wellbore  20  further may define an uphole direction  28  and a downhole direction  29 . Uphole direction  28  may be defined along a length of wellbore  20  and/or may point toward surface region  30 . Conversely, downhole direction  29  may be defined along the length of wellbore  20  but may point toward downhole end  24 . 
     As illustrated in dashed lines in  FIG. 1 , hydrocarbon well  10  may include a shockwave generation device  190 , which may be positioned within tubular conduit  42 . As illustrated in  FIGS. 2-5 , SSPs  100  may include an isolation device  120 , and shockwave generation device  190 , when present, may be configured to generate a shockwave  194  within a wellbore fluid  22  that extends within tubular conduit  42 . Shockwave  194  may be utilized to transition isolation device  120  of a corresponding SSP  100  from a closed state to an open state. When in the closed state, the corresponding SSP may resist, block, and/or occlude fluid flow therethrough and/or between tubular conduit  42  and subterranean formation  34 . When in the open state, the corresponding SSP may permit fluid flow therethrough and/or between the tubular conduit and the subterranean formation. Shockwave generation device  190  may be operatively attached to an umbilical  192 , which may extend within tubular conduit  42  and/or may interconnect shockwave generation device  190  with surface region  30 . Additional examples of shockwave generation devices  190 , of components of SSPs  100 , and/or of methods of operating SSPs  100  that may be included in and/or utilized with hydrocarbon wells  10 , wellbore tubulars  40 , SSPs  100 , and/or methods  1100  and/or  1200 , according to the present disclosure, are disclosed in U.S. Provisional Patent Application Nos. 62/262,034 and 62/262,036, which were filed on Dec. 2, 2015, and U.S. Provisional Patent Application No. 62/263,069, which was filed on Dec. 4, 2015, and the complete disclosures of which are hereby incorporated by reference. 
     Wellbore tubular  40  may include and/or be any suitable elongate tubular structure that may extend within wellbore  20  and/or that may define tubular conduit  42 . As an example, wellbore tubular  40  may include and/or be a casing string  50 . As another example, wellbore tubular  40  may include and/or be inter-casing tubing  60 . 
     When wellbore tubular  40  includes casing string  50 , SSPs  100  may be operatively attached to any suitable portion, or region, of casing string  50 . As examples, one or more SSPs  100  may be operatively attached to one or more of a casing collar  54  of the casing string, a casing segment  52  of the casing string, a blade centralizer  56  of the casing string, and/or a sleeve  58  that slides over the casing string. 
     It is within the scope of the present disclosure that SSPs  100  may be operatively attached to wellbore tubular  40  prior to wellbore tubular  40  being positioned within wellbore  20 . In addition, it is also within the scope of the present disclosure that SSPs  100  may be operatively attached to wellbore tubular  40  in any suitable manner. As examples, one or more SSPs  100  may be operatively attached to wellbore tubular  40  via one or more of a threaded connection, a glued connection, a press-fit connection, a welded connection, and/or a brazed connection. As additional examples, one or more SSPs  100  may be formed within wellbore tubular  40  and/or may be formed within a given segment, region, and/or portion of the wellbore tubular. 
       FIGS. 2-5  provide additional and/or more detailed examples of SSPs  100  according to the present disclosure. SSPs  100  of  FIGS. 2-5  may include and/or be more detailed representations, or illustrations, of SSPs  100  of  FIG. 1 , and any of the structures, functions, and/or features that are discussed herein with reference to SSPs  100  of  FIGS. 2-5  may be included in and/or utilized with hydrocarbon wells  10  of  FIG. 1  without departing from the scope of the present disclosure. Similarly, any of the structures, functions, and/or features that are discussed herein with reference to hydrocarbon wells  10  of  FIG. 1  may be utilized with SSPs  100  of  FIGS. 2-5  without departing from the scope of the present disclosure. 
       FIG. 2  is a schematic representation of examples of an SSP  100 , according to the present disclosure, illustrating a seated sealing device  142 , while  FIG. 3  is another schematic representation of SSP  100  of  FIG. 2  illustrating an unseated sealing device  142  that is retained within sealing device receptacle  134  by sealing device retainer  138 .  FIG. 4  is another schematic representation of SSP  100  of  FIG. 2  illustrating sealing device  142  entering a sealing device receptacle  134  thereof, while  FIG. 5  is a schematic representation of additional examples of a selective stimulation port  100  according to the present disclosure. 
     As illustrated in  FIGS. 2-5 , SSPs  100  are configured to be operatively attached to wellbore tubular  40  and define conduit-facing region  112  and formation-facing region  114 . SSPs  100  include an SSP conduit  116  that extends perpendicular, or at least substantially perpendicular, to a wall  68  of wellbore tubular  40  and between conduit-facing region  112  and formation-facing region  114 . 
     SSPs  100  also include a sealing device receptacle  134 , which is sized to receive a sealing device  142  and defines at least a portion of SSP conduit  116 . As perhaps best illustrated in  FIG. 4 , sealing device  142  may flow into sealing device receptacle  134  via tubular conduit  42 . SSPs  100  further include a sealing device seat  140 . Sealing device seat  140  defines at least a portion of SSP conduit  116  and is defined within and/or by sealing device receptacle  134 . In addition, sealing device seat  140  is shaped to form a fluid seal  144 , as illustrated in  FIGS. 2 and 5 , with sealing device  142 . 
     SSPs  100  further include a sealing device retainer  138 . Sealing device retainer  138  may be configured to permit sealing device  142  to enter and/or to be received within sealing device receptacle  134 , such as to seat upon sealing device seat  140  to form a fluid seal therewith. Subsequent to the sealing device being received within the sealing device receptacle, sealing device retainer  138  is configured to retain the sealing device within the sealing device receptacle and also to permit the sealing device to be unseated from sealing device seat  140  while remaining within the sealing device receptacle, as illustrated in  FIG. 3 . 
     When sealing device  142  forms fluid seal  144  with sealing device seat  140 , as illustrated in  FIGS. 2 and 5 , the sealing device selectively restricts a fluid outflow  35  from tubular conduit  42  and into subsurface region  32  via SSP conduit  116 . Stated another way, fluid seal  144 , when present, blocks, restricts, and/or occludes fluid flow through the SSP conduit. Conversely, when sealing device  142  does not form the fluid seal with sealing device seat  140 , when sealing device  142  contacts sealing device retainer  138 , and/or when sealing device  142  is unseated from sealing device seat  140 , SSP  100  permits a fluid inflow  33  from subsurface region  32  into tubular conduit  42  via SSP conduit  116 , as illustrated in  FIG. 3 . Under these conditions, sealing device retainer  138  may be referred to herein as retaining sealing device  142  within sealing device receptacle  134 . SSPs  100  that include sealing devices  142  received within sealing device receptacles  134  automatically may form fluid seal  144  when a pressure within tubular conduit  42  is greater than a pressure within subsurface region  32 , thus restricting fluid outflow  35 . In addition, SSPs  100  automatically may permit fluid inflow  33  when the pressure within tubular conduit  42  is less than the pressure within subsurface region  32 . Thus, and as discussed, the combination of a given sealing device  142  with a given SSP  100  may permit repeated seating of sealing device  142  on sealing device seat  140  and unseating of sealing device  142  from sealing device seat  140 , which may cause sealing and unsealing of SSP conduit  116 , respectively, during pressure cycling of the hydrocarbon well. 
     Referring generally to  FIGS. 1-5 , and during operation of hydrocarbon wells  10 , tubular conduit  42  may be pressurized with a stimulant fluid and a selected SSP  100  then may be transitioned from the closed state to the open state. A volume of stimulant fluid then may be flowed into subterranean formation  34 , such as to stimulate the subterranean formation. Subsequently, a sealing device  142  may be released within tubular conduit  42  and may be received by sealing device receptacle  134  of a corresponding SSP  100  and seated upon sealing device seat  140  thereof. The sealing device then is retained within sealing device receptacle  134  by sealing device retainer  138  of the SSP and permits fluid flow from the subterranean formation into the tubular conduit while restricting fluid flow from the tubular conduit into the subterranean formation. The combination of the SSP and the sealing device may be cycled between a configuration in which the sealing device restricts fluid flow and a configuration in which the sealing device permits fluid flow any suitable number of times. This cycling may be based solely upon a pressure differential between the tubular conduit and the subterranean formation and across the SSP and also may be referred to herein as pressure cycling the hydrocarbon well. Thus, the sealing device may be selectively and repeatedly seated on and unseated from the sealing device seat, with the sealing device retainer preventing the sealing device from being dissociated from the corresponding sealing device receptacle. 
     Sealing device retainer  138  may include and/or be any suitable structure that may be adapted, configured, designed, sized, shaped, and/or constructed to permit sealing device  142  to enter, or to be received within, sealing device receptacle  134  and/or to retain the sealing device within the sealing device receptacle. As an example, and as illustrated in  FIGS. 2-5 , sealing device receptacle  134  may include and/or define an aperture  135  within conduit-facing region  112  and sealing device retainer  138  may extend and/or project at least partially across the aperture. 
     As another example, sealing device retainer  138  may be biased, or may include a biasing structure, to permit motion of the sealing device into the sealing device receptacle and also to resist motion of the sealing device out of the sealing device receptacle. Stated another way, the sealing device retainer may be configured to permit the sealing device to flow, from the tubular conduit and past the sealing device retainer, into engagement, or sealing engagement, with the sealing device seat. However, the sealing device retainer may be configured to resist flow of the sealing device from and/or out of the sealing receptacle and to and/or into the tubular conduit. 
     Such biasing may be accomplished in any suitable manner. As an example, and as illustrated in solid lines in  FIG. 4 , sealing device retainer  138  may be configured to be compressed and/or deformed to permit the sealing device to enter the sealing device receptacle. As another example, and as illustrated in dashed lines in  FIG. 4 , sealing device retainer  138  may be configured to rotate and/or pivot to permit the sealing device to enter the sealing device receptacle. However, and subsequent to the sealing device entering the sealing device receptacle, sealing device retainer  138  may return to a configuration in which the sealing device retainer restricts movement of the sealing device from and/or out of the sealing device receptacle, as illustrated in  FIGS. 2-3 and 5 . 
     As discussed, SSP  100  and/or sealing device retainer  138  thereof may be configured to permit sealing device  142  to be unseated from sealing device seat  140  and to be reseated with the sealing device seat a plurality of times. As an example, sealing device retainer  138  may retain the sealing device within the sealing device receptacle while the sealing device is repeatedly seated on, and unseated from, the sealing device seat. Thus, SSPs  100  that include sealing devices  142  received within sealing device receptacles  134  may be configured to repeatedly permit fluid inflow  33  and/or to repeatedly restrict fluid outflow  35  during construction, completion, and/or operation of a hydrocarbon well  10  that includes the SSPs. 
     It is within the scope of the present disclosure that sealing device retainer  138  may include and/or be a permanent, or at least substantially permanent, sealing device retainer configured to retain a respective sealing device indefinitely. This may include retaining the respective sealing device over an operational lifetime of hydrocarbon well  10  and/or while the sealing device is seated upon, and unseated from, the sealing device seat any suitable number of times. 
     Conversely, it is also within the scope of the present disclosure that sealing device retainer  138  may be configured to temporarily retain the respective sealing device, such as to retain the respective sealing device for a predetermined, or desired, retention time and then to release the respective sealing device or otherwise permit the sealing device to flow out of the sealing device receptacle. Such a configuration may permit SSP  100  to selectively permit the fluid inflow and restrict the fluid outflow during the retention time and subsequently to permit increased and/or two-way fluid flow through SSP  100  subsequent to the removal of the respective sealing device from the sealing device receptacle. 
     The retention time may include and/or be any suitable time, timeframe, and/or time period. As an example, the retention time may be a fixed, predetermined, pre-established, and/or desired length of time. As more specific examples, the retention time may be at least 1 hour, at least 6 hours, at least 12 hours, at least 1 day, at least 5 days, at least 10 days, at least 20 days, and/or at least 30 days. Additionally or alternatively, the retention time may be at most 180 days, at most 150 days, at most 120 days, at most 90 days, at most 60 days, at most 30 days, at most 20 days, at most 10 days, at most 5 days, and/or at most 1 day. 
     With the above in mind, sealing device retainer  138  may include and/or be formed from any suitable material and/or materials. As examples, sealing device retainer  138  may include and/or be formed from a soluble material configured to dissolve within the wellbore fluid and/or a corrodible material configured to corrode within the wellbore fluid. Such a material may degrade, dissolve, and/or corrode to permit release of the sealing device after the retention time has elapsed. As additional examples, sealing device retainer  138  may include and/or be formed from an insoluble material, a non-corrodible material, and/or an inert material that does not degrade upon contact with the wellbore fluid. Such a material may permit the sealing device retainer to retain the respective sealing device indefinitely and/or to retain a plurality of different sealing devices, as discussed in more detail herein. 
     As illustrated in dashed lines in  FIGS. 2-5 , SSPs  100  may include one or more channels  152 . Channels  152 , when present, may be adapted, configured, sized, and/or shaped to permit and/or facilitate fluid inflow  33  to flow past sealing device  142  and/or sealing device retainer  138  when sealing device  142  is received within sealing device receptacle  134 . As examples, channels  152  may decrease a resistance to the fluid inflow and/or may increase a cross-sectional area for flow of the fluid inflow. 
     Channels  152  may include any suitable structure. As examples, channels  152  may include and/or be one or more of grooves, recesses, and/or flutes. In addition, channels  152  may be defined by and/or within any suitable portion of SSP  100 . As an example, channels  152  may be defined by sealing device retainer  138 . As another example, channels  152  may be defined by an SSP body  110 . SSP body  110 , when present, also may define one or more of SSP conduit  116 , sealing device receptacle  134 , sealing device seat  140 , and/or sealing device retainer  138 . 
     Sealing device receptacle  134  may have and/or define any suitable shape. As an example, the shape of the sealing device receptacle may correspond to a shape of a corresponding sealing device  142  that is to be received by, or is received within, the sealing device receptacle. As another example, the sealing device receptacle may be a cylindrical, or at least partially cylindrical, sealing device receptacle. As yet another example, sealing device  142  may define a sealing device diameter  147  and sealing device receptacle  134  may define a receptacle diameter  137  that is greater than the sealing device diameter. This is illustrated in  FIG. 2 . 
     It is within the scope of the present disclosure that sealing device receptacle  134  may be shaped and/or sized to contain and/or house an entirety of sealing device  142 , at least when the sealing device forms fluid seal  144  with sealing device seat  140 . Stated another way, sealing device  142  may be contained entirely within sealing device receptacle  134  when it is seated on and unseated from the sealing device seat. Under these conditions, sealing device receptacle  134  may be referred to herein as having a receptacle depth  136  that is greater than the sealing device diameter. Such a configuration may permit operation of SSP  100  without sealing device  142  projecting into subsurface region  32  and/or into tubular conduit  42  and also is illustrated in  FIG. 2 . 
     Alternatively, it is also within the scope of the present disclosure that a portion (typically a minority portion) of sealing device  142  may project from sealing device receptacle  134  and into tubular conduit  42  and/or into subsurface region  32 , as illustrated in  FIG. 5  when the sealing device is seated upon and/or unseated from the sealing device seat. Such a configuration may permit SSP  100  to be narrower and/or may permit a width  101  of SSP  100  to correspond to a wellbore tubular thickness  44  of wellbore tubular  40 . 
     Sealing device seat  140  may include any suitable structure that defines at least a portion of SSP conduit  116 , is defined within sealing device receptacle  134 , and/or is shaped to form the fluid seal with sealing device  142 . As an example, and as discussed, sealing device seat  140  may be formed and/or defined by SSP body  110 . As another example, a shape of sealing device seat  140  may correspond to, or complement, a shape of sealing device  142 . As yet another example, sealing device seat  140  may have a seat radius of curvature that is at least substantially similar to, and optionally the same as, a sealing device radius of curvature of sealing device  142 . As another example, sealing device seat  140  may be a pre-formed and/or premanufactured sealing device seat that may have a preconfigured geometry, or shape, that is established prior to SSP  100  being operatively attached to tubular conduit  42  and/or prior to tubular conduit  42  being installed within subterranean formation  34 . 
     It is within the scope of the present disclosure that sealing device seat  140  may be configured to resist damage and/or deterioration upon exposure to environmental conditions present within hydrocarbon well  10 . As an example, sealing device seat  140  may include and/or be an erosion-resistant sealing device seat that is configured to resist erosion by particulate matter that may be present within a wellbore fluid when the wellbore fluid flows through and/or past the sealing device seat. As another example, sealing device seat  140  may include and/or be a corrosion-resistant sealing device seat configured to resist corrosion by the wellbore fluid when the wellbore fluid contacts the sealing device seat. 
     As discussed, SSPs  100  may be operatively attached to wellbore tubular  40 , and SSPs  100  may define any suitable spatial relationship, orientation, relative size, and/or geometry relative to wellbore tubular  40 . As an example, wellbore tubular  40  may have and/or define wall thickness  44 , and sealing device receptacle  134  may define a receptacle depth  136  that is greater than, equal to, or less than, wall thickness  44 . 
     When receptacle depth  136  is greater than wall thickness  44 , and as illustrated in  FIG. 3 , wellbore tubular  40 , SSP  100 , and/or SSP body  110  thereof may include a projecting region  69  that projects from an external surface  41  of wellbore tubular  40 . Under these conditions, SSP  100  may be positioned within, or may define, projecting region  69 . An example of projecting region  69  includes a centralizer wing for wellbore tubular  40 . 
     It is within the scope of the present disclosure that SSPs  100  may be operatively attached to wellbore tubular  40  in any suitable manner and/or that SSPs  100  may be operatively attached to any suitable portion of wellbore tubular  40 . As examples, SSPs  100  may be at least partially defined by the wellbore tubular, at least partially formed within the wellbore tubular, at least partially defined by a tubular collar of the wellbore tubular, at least partially formed within the tubular collar, at least partially defined by a tubular segment of the wellbore tubular, and/or at least partially formed within the tubular segment. 
     Sealing device  142  may include and/or be any suitable structure and/or structures that is/are sized and/or configured to be received within sealing device receptacle  134 , to form fluid seal  144  with sealing device seat  140 , and to be retained by sealing device retainer  138 . As an example, sealing device  142  may include any known ball sealer or perforation sealer. A conventional ball sealer has a generally spherical shape and may include an abrasion-resistant and/or cut-resistant outer layer. Another example of a suitable sealing device is a PERF PODS™ sealing device that is available from Thru Tubing Solutions, Inc. of Oklahoma City, Okla. A PERF PODS™ sealing device includes a primary sealing core from which a plurality of secondary tendrils extends to form secondary seals, such as of one or more leakage pathways between the primary sealing core and the sealing device seat. 
     Similarly, sealing device  142  may be formed from any suitable material and/or materials. As examples, sealing device  142  may be formed from a soluble material configured to dissolve within the wellbore fluid and/or from a corrodible material configured to be corroded by the wellbore fluid. Such a configuration may permit the sealing device to be retained within the sealing device receptacle for the retention time and then to degrade such that the sealing device is released from the sealing device receptacle. Under these conditions, it is within the scope of the present disclosure that a second, or subsequent, sealing device later may be received within the sealing device receptacle. 
     As additional examples, sealing device  142  may be formed from an insoluble material and/or from a non-corrodible material that does not degrade upon contact with the wellbore fluid. Such a material may permit the sealing device to be retained within the sealing device receptacle indefinitely. 
     As illustrated in dashed lines in  FIGS. 2-4  and discussed herein, SSPs  100  optionally may include an isolation device  120  and a retention device  130 . Isolation device  120 , when present, may extend within SSP conduit  116 . In addition, isolation device  120  may be configured to selectively transition, or be transitioned, from a closed state, in which the isolation device restricts fluid flow through the SSP conduit, to an open state, in which the isolation device permits fluid flow through the SSP conduit. This transition may be, may occur, and/or may be initiated responsive to receipt of a shockwave, which has greater than a threshold shockwave intensity, by the isolation device. The shockwave may be generated by a shockwave generation device, such as shockwave generation device  190  of  FIG. 1 , within a wellbore fluid, such as wellbore fluid  22  of  FIG. 1 , that extends within tubular conduit  42 . Retention device  130  may be configured to retain isolation device  120  in the closed state prior to receipt of the shockwave. 
     It is within the scope of the present disclosure that isolation device  120  may be configured to exhibit only a single transition from the closed state to the open state. As an example, at least a portion of the isolation device may be configured to separate from a remainder of the SSP upon transitioning from the closed state to the open state. 
     As a more specific example, at least a portion of the isolation device may be configured to break apart, or disintegrate, upon transitioning from the closed state to the open state. As an example, and prior to transitioning from the closed state to the open state, isolation device  120  may have and/or define a first maximum dimension. However, subsequent to transitioning from the closed state to the open state, the isolation device may define a second maximum dimension that is less than the first maximum dimension. As another example, and prior to transitioning from the closed state to the open state, isolation device  120  may include and/or be a single-piece isolation device. However, and upon transitioning to the open state, the isolation device may define a plurality of spaced-apart segments and/or pieces. 
     As yet another example, isolation device  120  may include an isolation disk that may be conveyed into the subterranean formation from a formation-facing end of SSP conduit  116  when the isolation device transitions from the closed state to the open state. 
     Isolation device  120  may include and/or be formed from any suitable material and/or materials. As examples, isolation device  120  may include one or more of a magnetic material, a radioactive material, an acid-soluble material, and a frangible material. 
     As also illustrated in dashed lines in  FIGS. 2-4 , SSP  100  further may include an isolation device recess  119 . Isolation device recess  119  may be configured to receive, house, and/or contain at least a portion of isolation device  120  prior to the isolation device transitioning from the closed state to the open state. 
     It is within the scope of the present disclosure that isolation device  120  may be positioned within any suitable portion, or region, of SSP  100 . As an example, isolation device  120  may be positioned between sealing device seat  140  and subsurface region  32 . Such a configuration may prevent particulate matter, which may be present within the subsurface region, from contacting sealing device seat  140  and/or entering sealing device receptacle  134  at least prior to the isolation device being transitioned from the closed state to the open state. As another example, isolation device  120  may be positioned to separate, or to fluidly separate, sealing device seat  140  from tubular conduit  42 . Such a configuration may protect the sealing device seat from materials that may be conveyed through the tubular conduit. As an example, such a configuration may protect the sealing device seat from abrasion by a proppant and/or from corrosion by an acid that may be conveyed into subsurface region  32  via the tubular conduit. 
       FIG. 6  is a flowchart depicting methods  1100 , according to the present disclosure, of stimulating a hydrocarbon well. The hydrocarbon well includes a wellbore tubular that defines a tubular conduit and extends within a wellbore. The hydrocarbon well further includes a plurality of selective stimulation ports (SSPs) spaced-apart along a length of the wellbore tubular. Examples of the hydrocarbon well are illustrated in  FIG. 1  and discussed in more detail herein with reference thereto. 
     Methods  1100  include pressurizing a tubular conduit at  1105 , opening a selected SSP at  1110 , flowing a first volume a stimulant fluid at  1115 , and releasing a sealing device at  1120 . Methods  1100  further include receiving the sealing device at  1125 , retaining the sealing device at  1130 , and seating the sealing device at  1135 . Methods  1100  also may include waiting a threshold dissolution time at  1140 , producing a reservoir fluid at  1145 , and/or permitting a pressure change at  1150  and include repeating at least a portion of the methods at  1155 . 
     Pressurizing the tubular conduit at  1105  may include pressurizing the tubular conduit with a stimulant fluid. The pressurizing at  1105  may be accomplished in any suitable manner. As examples, the pressurizing at  1105  may include providing the stimulant fluid to, or pumping the stimulant fluid into, the tubular conduit, such as from a surface region. 
     Opening the selected SSP at  1110  may include opening a selected SSP of the plurality of SSPs to permit fluid flow, or a fluid outflow, from the tubular conduit and into the subterranean formation. The fluid flow may be through and/or via an SSP conduit of the selected SSP. The opening at  1110  may be accomplished in any suitable manner. As an example, the opening at  1110  may include transitioning an isolation device of the selected SSP from a closed state to an open state. As a more specific example, the opening at  1110  may include generating, within the tubular conduit, a shockwave of greater than a threshold shockwave intensity to transition the isolation device from the closed state to the open state. Examples of the isolation device are discussed herein with reference to isolation device  120  of  FIGS. 2-4 . 
     Flowing the first volume of the stimulant fluid at  1115  may include flowing the first volume of stimulant fluid into the subterranean formation via the SSP conduit. This may include flowing to stimulate a first region of the subterranean formation and/or flowing responsive to, or as a result of, the pressurizing at  1105  and/or the opening at  1110 . 
     Releasing the sealing device at  1120  may include releasing the sealing device in, within, and/or into the tubular conduit. The releasing at  1120  may be accomplished in any suitable manner. As an example, the releasing at  1120  may include positioning the sealing device within the tubular conduit. As additional examples, the releasing at  1120  may include releasing from the surface region and/or releasing from a sealing device source that is positioned within and/or forms a portion of the hydrocarbon well. Examples of the sealing device are disclosed herein with reference to sealing device  142  of  FIGS. 1-5 . 
     Receiving the sealing device at  1125  may include receiving the sealing device within a sealing device receptacle of the selected SSP. The receiving at  1125  may include flowing the sealing device along the tubular conduit and to the selected SSP, receiving the sealing device from the tubular conduit, and/or flowing the sealing device from the tubular conduit and into the selected SSP. Examples of the sealing device receptacle are disclosed herein with reference to sealing device receptacle  134  of  FIGS. 2-5 . 
     Retaining the sealing device at  1130  may include retaining the sealing device within the sealing device receptacle with a sealing device retainer of the selected SSP. It is within the scope of the present disclosure that the retaining at  1130  may include retaining the sealing device, within the sealing device receptacle, during a remainder of methods  1100  and/or during at least a portion of the repeating at  1155 . As examples, the retaining at  1130  may include retaining during the seating at  1135 , during the waiting at  1140 , during the producing at  1145 , during the permitting at  1150 , and/or during the repeating at  1155 . Examples of the sealing device retainer are disclosed herein with reference to sealing device retainer  138  of  FIGS. 2-5 . 
     Seating the sealing device at  1135  may include seating the sealing device on a sealing device seat of the selected SSP. This may include seating to form a fluid seal between the sealing device and the sealing device seat and/or seating to resist the fluid outflow of the stimulant fluid, which may flow from the tubular conduit and into the subterranean formation via the SSP conduit of the selected SSP. Examples of the sealing device seat are disclosed herein with reference to sealing device seat  140  of  FIGS. 2-5 . 
     Waiting the threshold dissolution time at  1140  may include waiting any suitable threshold dissolution time to permit the sealing device to dissolve and/or to corrode, such as to permit release of the sealing device from the sealing device receptacle of the respective SSP. It is within the scope of the present disclosure that the waiting at  1140  may be performed subsequent to at least a portion of the repeating at  1155 . As an example, the waiting at  1140  may be performed subsequent to repeating the pressurizing at  1105 , the opening at  1110 , the flowing at  1115 , the releasing at  1120 , the receiving at  1125 , the retaining at  1130 , and the seating at  1135  a plurality of times, via the plurality of SSPs, to stimulate a plurality of spaced-apart, or different, regions of the subterranean formation and to seal the plurality of SSPs with a corresponding plurality of sealing devices. This may include pressure cycling the hydrocarbon well and/or repeatedly and sequentially seating the sealing device on the sealing device seat and subsequently unseating the sealing device from the sealing device seat. The waiting at  1140  may include waiting to permit and/or facilitate dissolution and/or corrosion of the corresponding plurality of sealing devices, to release the corresponding plurality of sealing devices from the plurality of SSPs, and/or to permit both fluid inflow and fluid outflow through the plurality of SSPs. 
     Producing the reservoir fluid at  1145  may include producing the reservoir fluid from the subterranean formation. This may include permitting the fluid inflow of the reservoir fluid into the tubular conduit via the SSP conduit of the respective SSP. Additionally or alternatively, the producing at  1145  also may include producing the reservoir fluid while retaining the sealing device within the sealing device receptacle with the sealing device retainer of the respective SSP. It is within the scope of the present disclosure that the producing at  1145  may be performed subsequent to at least a portion of the repeating at  1155 , such as is discussed herein with reference to the waiting at  1140 . Stated another way, the producing at  1145  may be performed subsequent to stimulating the plurality of regions of the subterranean formation and/or subsequent to retaining a respective sealing device within a respective sealing device seat of each of the plurality of SSPs with a corresponding sealing device retainer of each of the plurality of SSPs. Under these conditions, the producing at  1145  may include permitting the fluid inflow via a plurality of SSP conduits of the plurality of SSPs while retaining the respective sealing device within the respective sealing device receptacle of each of the plurality of SSPs. The retaining may permit and/or facilitate re-seating of the respective sealing device with the respective sealing device seat subsequent to the producing at  1145 , during the permitting at  1150 , and/or during the repeating at  1155 . 
     Additionally or alternatively, the producing at  1145  also may be performed subsequent to the waiting at  1140 . Under these conditions, the plurality of respective sealing devices may be released from, or not retained within the respective sealing device receptacle of, the plurality of SSPs during the producing at  1145 . 
     Permitting the pressure change at  1150  may include permitting, or even facilitating, any suitable pressure change within the wellbore tubular and/or within the subterranean formation and may be performed subsequent to at least the portion of the repeating at  1155  that is discussed herein with reference to the waiting at  1140 . The permitting at  1150  also may include unintended, inadvertent, and/or unexpected pressure changes, such as may be caused by failure of a pump that is utilized to pressurize the tubular conduit and/or failure of a sealing device that restricts fluid flow from the tubular conduit and into the subterranean formation. As an example, the permitting at  1150  may include permitting a pressure within the subterranean formation to exceed a pressure within the tubular conduit, such as to provide, or allow, a motive force for flow of a reservoir fluid into the tubular conduit via the SSP conduits of the plurality of SSPs. Under these conditions, the retaining at  1130  may include retaining during the permitting at  1150 . 
     As another example, the permitting at  1150  may include permitting a pressure within a region of the tubular conduit that is associated with the selected SSP to decrease to a conduit pressure that is less than a formation pressure within a region of the subterranean formation that is associated with the selected SSP. Under these conditions, fluid may flow from the subterranean formation into the tubular conduit via the SSP conduit of the selected SSP, and the retaining at  1130  may include retaining during the permitting at  1150 . When methods  1100  include the permitting at  1150 , the repeating at  1155  may include re-seating the sealing devices on their respective sealing device seats to restrict fluid flow from the tubular conduit into the subterranean formation when the pressure within the tubular conduit is increased to a pressure that is greater than the pressure within the subterranean formation. 
     Repeating at least a portion of the methods at  1155  may include repeating any suitable portion of methods  1100  in any suitable order and/or in any suitable manner. As an example, and as discussed, the repeating at  1155  may include repeating the pressurizing at  1105 , repeating the opening at  1110 , repeating the flowing at  1115 , repeating the releasing at  1120 , repeating the receiving at  1125 , repeating the retaining at  1130 , and/or repeating the seating at  1135  a plurality of times to stimulate the plurality of regions of the subterranean formation. This portion of the repeating at  1155  also may be referred to herein as repeating to stimulate the subterranean formation and/or as stimulating the subterranean formation. 
     Subsequent to repeating to stimulate the subterranean formation, and as also discussed, the repeating at  1155  may include performing one or more additional, or optional, steps of methods  1100 , such as by performing the waiting at  1140 , the producing at  1145 , and/or the permitting at  1150 . Additionally or alternatively, and subsequent to performing the producing at  1145 , the repeating at  1155  also may include repeating the pressurizing at  1105  to seat the plurality of sealing devices on the corresponding plurality of sealing device seats of the plurality of SSPs. Additionally or alternatively, the repeating at  1155  may include sequentially repeating the pressurizing at  1105  and the producing at  1145  a plurality of times while continuing the retaining at  1130 . This process also may be referred to herein as pressure cycling the hydrocarbon well. 
     Returning to  FIG. 1 , and as illustrated in dashed lines, hydrocarbon well  10  may include a fluid port  74 , which may be positioned at, proximate, and/or near downhole end  24 . Fluid port  74 , when present, may be configured to be selectively transitioned between an open state and a closed state. When in the open state, fluid port  74  may permit fluid flow between tubular conduit  42  and subterranean formation  34 ; and when in the closed state, fluid port  74  may resist, block, and/or occlude fluid flow between the tubular conduit and the subterranean formation. 
     In general, fluid port  74  is different and/or distinct from SSPs  100 . As an example, fluid port  74  may include and/or be a toe sleeve. As another example, fluid port  74  may exclude, or may not include, a sealing device receptacle and/or a sealing device retainer. In contrast, and as discussed in more detail herein with reference to  FIGS. 2-5 , SSPs  100  include both a sealing device receptacle  134  and a sealing device retainer  138 . However, this is not required to all embodiments, and it is also within the scope of the present disclosure that fluid port  74  may include, or be, an SSP  100 . 
     As discussed in more detail herein with respect to methods  1200  of  FIG. 7 , and during operation of hydrocarbon well  10 , fluid port  74  may be utilized to facilitate conveyance of a downhole tool, such as shockwave generation device  190 , within hydrocarbon well  10 . As an example, and while fluid flow through SSPs  100  is blocked and/or occluded, such as by sealing device  142 , fluid port  74  may be transitioned to the open state. Subsequently, a conveyance fluid may be provided to tubular conduit  42 , such as from surface region  30 , and the conveyance fluid may be utilized to pump the downhole tool in downhole direction  29 . Under these conditions, flow of the conveyance fluid through fluid port  74  may permit and/or facilitate flow of the conveyance fluid into the tubular conduit and/or pumping of the downhole tool in the downhole direction. 
     With the above discussion in mind,  FIG. 7  is a flowchart depicting methods  1200 , according to the present disclosure, of conveying a downhole tool within a hydrocarbon well. The hydrocarbon well includes a wellbore tubular that defines a tubular conduit and extends within a wellbore. The hydrocarbon well also includes a plurality of SSPs spaced-apart along a length of the wellbore tubular. Examples of the hydrocarbon well are illustrated in  FIG. 1  and discussed in more detail herein with reference thereto. Methods  1200  include restricting a fluid flow at  1210 , retaining a sealing device at  1220 , and establishing fluid communication at  1230 . Methods  1200  further include positioning a downhole tool at  1240 , providing a conveyance fluid at  1250 , and pumping the downhole tool at  1260 . 
     Restricting the fluid flow at  1210  may include restricting fluid flow through each SSP in the plurality of SSPs with a respective sealing device of a plurality of sealing devices. The restricting at  1210  may include receiving the respective sealing device within a respective sealing device receptacle and/or on a respective sealing device seat of each SSP. Examples of the sealing device receptacle are disclosed herein with reference to sealing device receptacles  134  of  FIGS. 2-5 . Examples of the sealing device seat are disclosed herein with reference to sealing device seat  140  of  FIGS. 2-5 . 
     Retaining the sealing device at  1220  may include retaining each respective sealing device within the respective sealing device receptacle with a respective sealing device retainer of each SSP. Examples of the sealing device retainer are disclosed herein with reference to sealing device retainers  138  of  FIGS. 2-5 . 
     Establishing fluid communication at  1230  may include establishing fluid communication between the subterranean formation and a downhole region, a downhole portion, and/or a toe-end of the tubular conduit. The establishing at  1230  may be accomplished in any suitable manner. As an example, the establishing at  1230  may include removing a selected sealing device from a downhole SSP of the plurality of SSPs that is present within the downhole region of the tubular conduit. This may include removing without removing the respective sealing device from a remainder of the plurality of SSPs. As an example, the selected sealing device may be soluble within the wellbore fluid, while a remainder of the sealing devices may not be soluble, or may not be as soluble, within the wellbore fluid. Under these conditions, the removing may include dissolving the selected sealing device within the wellbore fluid. As another example, a selected sealing device retainer of the downhole SSP may be soluble within the wellbore fluid, while a remainder of the sealing device retainers may not be soluble, or may not be as soluble, within the wellbore fluid. Under these conditions, the removing may include dissolving the selected sealing device retainer within the wellbore fluid. 
     As another example, the establishing at  1230  may include opening a fluid port that is present within the downhole region of the tubular conduit. This may include opening the fluid port without removing the respective sealing devices from the plurality of SSPs and may be accomplished in any suitable manner. As an example, the opening may include dissolving a selected sealing device, which seals the fluid port, within the wellbore fluid. As another example, the opening may include utilizing a pressure differential to unseat the selected sealing device from the fluid port. As yet another example, the opening may include transitioning the fluid port from a closed state to an open state. Examples of the fluid port are disclosed herein with reference to fluid port  74  of  FIG. 1 . 
     Positioning the downhole tool at  1240  may include positioning any suitable downhole tool within an uphole region, or portion, of the tubular conduit. An example of the downhole tool includes a shockwave generation device, such as shockwave generation device  190  of  FIG. 1 . Additional examples of the downhole tool are disclosed herein. 
     Providing the conveyance fluid at  1250  may include providing any suitable conveyance fluid to the tubular conduit. This may include pumping the conveyance fluid into the tubular conduit, such as from a surface region, and may be at least substantially similar to the pressurizing at  1105 , which is discussed herein with reference to methods  1100  of  FIG. 6 . 
     Pumping the downhole tool at  1260  may include pumping the downhole tool in a downhole direction via flow of the conveyance fluid within the tubular conduit. Stated another way, the pumping at  1260  may include providing a motive force for motion of the downhole tool, within the tubular conduit, via the providing at  1250  and/or via flow of the conveyance fluid through the tubular conduit and into the subterranean formation. Flow of the conveyance fluid into the subterranean formation may be facilitated by the establishing at  1230 . 
     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. 
     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. 
     As used herein, the phrase, “for example,” the phrase, “as an example,” and/or simply the term “example,” when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure. 
     INDUSTRIAL APPLICABILITY 
     The selective stimulation ports, wellbore tubulars, hydrocarbon wells, and methods disclosed herein are applicable to the oil and gas industries. 
     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. 
     It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.