Patent Publication Number: US-11047178-B2

Title: Downhole release apparatus

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and the benefit of U.S. Provisional Patent Application No. 62/739,663, titled “DOWNHOLE APPARATUS,” filed on Oct. 1, 2018, the entire disclosure of which is hereby incorporated herein by reference. 
    
    
     BACKGROUND OF THE DISCLOSURE 
     Wells are generally drilled into a land surface or ocean bed to recover natural deposits of oil and gas, and other natural resources that are trapped in geological formations in the Earth&#39;s crust. Testing and evaluation of completed and partially finished wells has become commonplace, such as to increase well production and return on investment. Downhole measurements of formation pressure, formation permeability, and recovery of formation fluid samples, may be useful for predicting economic value, production capacity, and production lifetime of geological formations. Completion and stimulation operations of wells, such as perforating and fracturing operations, may also be performed to optimize well productivity. Plugging and perforating tools may be utilized to set plugs within a wellbore to isolate portions of the wellbore and subterranean rock formations surrounding the wellbore from each other and to perforate the well in preparation for fracturing. Each fracturing stage interval along the wellbore can be perforated with one or more perforating tools (i.e., perforating guns) forming one or more clusters of perforation tunnels along the wellbore. Intervention operations in completed wells, such as installation, removal, or replacement of various production equipment, may also be performed as part of well repair or maintenance operations or permanent abandonment. Such testing, completion, and intervention operations have become complicated as wellbores are drilled deeper and through more difficult materials. Consequently, in working with deeper and more complex wellbores, it has become more likely that downhole tools, tool strings, tubulars, and other downhole equipment may become stuck within a wellbore. 
     A downhole tool, such as an impact (i.e., jarring) tool, may be utilized to dislodge a tool string or other downhole equipment when it becomes stuck within a wellbore. The impact tool may be included as part of the tool string and deployed downhole or the impact tool may be deployed after the tool string becomes stuck. Tension may be applied from a wellsite surface to the deployed impact tool via a wireline or other conveyance means to generate elastic energy. After sufficient tension is applied, the impact tool may be triggered to release the elastic energy and deliver an impact intended to dislodge the stuck tool string. If the impact tool is not able to dislodge a stuck tool string, a release tool included in the stuck tool string may be operated to disconnect a free portion of the tool string from a stuck portion of the tool string. The release tool may be operated, for example, by applying a predetermined amount of tension either from the wellsite surface or by operating an impact tool included in the tool string to break a shear pin of the release tool. After the shear pin is broken, the release tool may be separated to uncouple upper and lower portions of the tool string from each other. Thereafter, the freed upper portion of the tool string may be removed to the wellsite surface. Fishing equipment may then be conveyed downhole to couple with and retrieve the stuck lower portion of the tool string. 
     Release tool shear pins are configured to break at relatively low tensions, permitting tool string separation by various means. However, such release tool shear pins also limit the amount of upward jarring force that can be applied to a stuck tool string by an impact tool in an attempt to free the tool string. Thus, an impact tool may not be utilized to impart an impact force that exceeds the breaking force limit of the release tool shear pin. Furthermore, release tool shear pins can experience wear or fatigue, which can limit the number of impacts that an impact tool can apply to a stuck tool string even when magnitudes of such impacts are below the breaking force limit of the release tool shear pin. 
     SUMMARY OF THE DISCLOSURE 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter. 
     The present disclosure introduces a downhole tool comprising: (A) a first connector sub connectable with a first portion of a tool string, wherein the first connector sub comprises: (i) a housing; (ii) a first latching member slidably connected with the housing; and (iii) a blocking member movable with respect to the first latching member; and (B) a second connector sub connectable with a second portion of the tool string, wherein the second connector sub comprises a second latching member, and wherein: (i) the first and second latching members engage thereby connecting the first and second connector subs; and (ii) the blocking member is movable from a first position in which the blocking member prevents the first and second latching members from disengaging to a second position in which the blocking member permits the first and second latching members to disengage thereby permitting the first and second connector subs to disconnect. 
     The present disclosure also introduces a downhole tool comprising: (A) a first connector sub connectable with a first portion of a tool string, wherein the first connector sub comprises: (i) a housing; (ii) a first latching member; and (iii) a blocking member; and (B) a second connector sub connectable with a second portion of the tool string, wherein the second connector sub comprises a second latching member, and wherein: (i) the first and second latching members engage thereby connecting the first and second connector subs; (ii) the blocking member is movable from a first position in which the blocking member prevents the first and second latching members from disengaging to a second position in which the blocking member permits the first and second latching members to disengage thereby permitting the first and second connector subs to disconnect; and (iii) relative movement between the housing and first latching member facilitates movement of the blocking member from the first position to the second position. 
     The present disclosure also introduces a method comprising: (A) operating a downhole tool connected between an upper portion of a tool string and a lower portion of the tool string while the lower portion of the tool string is stuck downhole, wherein the downhole tool comprises an upper portion connected with the upper portion of the tool string, wherein the downhole tool comprises a lower portion connected with the lower portion of the tool string, and wherein operating the downhole tool comprises: (i) moving the upper portion of the downhole tool upward with respect to the lower portion of the downhole tool and the lower portion of the tool string; and then (ii) moving the upper portion of the downhole tool downward with respect to the lower portion of the downhole tool and the lower portion of the tool string to unlatch the upper portion of the downhole tool from the lower portion of the downhole tool; and then (B) applying tension to the tool string to cause an upper portion of the downhole tool to separate from the lower portion of the downhole tool thereby separating the upper portion of the tool string from the lower portion of the tool string. 
     These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG. 1  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 2  is a side sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 3  is a side sectional view of the apparatus shown in  FIG. 2  in another stage of operations according to one or more aspects of the present disclosure. 
         FIG. 4  is a side sectional view of the apparatus shown in  FIG. 3  in another stage of operations according to one or more aspects of the present disclosure. 
         FIG. 5  is a side sectional view of the apparatus shown in  FIG. 4  in another stage of operations according to one or more aspects of the present disclosure. 
         FIG. 6  is a side sectional view of the apparatus shown in  FIG. 5  in another stage of operations according to one or more aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows, may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. 
     Terms, such as upper, upward, above, lower, downward, and/or below are utilized herein to indicate relative positions and/or directions between apparatuses, tools, components, parts, portions, members and/or other elements described herein as shown in the corresponding figures. Such terms do not necessarily indicate relative positions and/or directions when actually implemented. Such terms, however, may indicated relative positions and/or directions with respect to a wellbore when an apparatus according to one or more aspects of the present disclosure is utilized or otherwise disposed within a wellbore. 
       FIG. 1  is a schematic view of at least a portion of a wellsite system  100  showing an example environment comprising or utilized in conjunction with a downhole tool string  110  according to one or more aspects of the present disclosure. The tool string  110  may be suspended within a wellbore  102  that extends from a wellsite surface  104  into one or more subterranean formations  106 . The wellbore  102  may be a cased-hole implementation comprising a casing  108  secured by cement  109 . However, one or more aspects of the present disclosure are also applicable to and/or readily adaptable for utilizing in open-hole implementations lacking the casing  108  and cement  109 . The tool string  110  may be suspended within the wellbore  102  via a conveyance means  120  operably coupled with a tensioning device  130  and/or other surface equipment  140  disposed at the wellsite surface  104 . The tool string  110  is shown suspended in a vertical portion of the wellbore  102 , however, it is to be understood that the tool string  110  may be utilized within a non-vertical, horizontal, and otherwise deviated portion of the wellbore  102 . 
     The tensioning device  130  may apply an adjustable tensile force to the tool string  110  via the conveyance means  120  to convey the tool string  110  along the wellbore  102 . The tensioning device  130  may be, comprise, or form at least a portion of a crane, a winch, a draw-works, an injector, a top drive, and/or another lifting device coupled to the tool string  110  via the conveyance means  120 . The conveyance means  120  may be or comprise a wireline, a slickline, an e-line, coiled tubing, and/or other conveyance means, and may comprise and/or be operable in conjunction with means for communication between the tool string  110 , the tensioning device  130 , and/or one or more other portions of the surface equipment  140 , including a power and control system  150 . The conveyance means  120  may comprise or contain a multi-conductor wireline and/or another electrical conductor  122  extending between the tool string  110  and the surface equipment  140 , such as the power and control system  150 . The power and control system  150  may include a source of electrical power  152 , a memory device  154 , and a surface controller  156  operable to receive and process electrical signals or information from the tool string  110  and/or commands from a human wellsite operator. 
     The tool string  110  may comprise an upper (e.g., uphole) portion  112 , a lower (e.g., downhole) portion  114 , and a release tool  116  connected between and coupling together the upper and lower tool string portions  112 ,  114 . The release tool  116  may be selectively operable to separate, uncouple, disconnect, part, or otherwise release the upper portion  112  from the lower portion  114  or otherwise from each other, while conveyed within the wellbore  102 . The release tool  116  may permit a portion (e.g., the lower portion  114 ) of the tool string  110  connected downhole from the release tool  116  to be left in the wellbore  102  and a portion (e.g., upper portion  112 ) of the tool string  110  located uphole from the release tool  116  to be retrieved to the wellsite surface  104 . Accordingly, if a portion of the tool string  110  is stuck within the wellbore  102  and cannot be freed, the release tool  116  located uphole from the stuck portion of the tool string  110  may be operated to release the free portion of the tool string  110  such that it can be retrieved to the wellsite surface  104 . 
     The upper portion  112  of the tool string  110  may comprise at least one electrical conductor  113  in electrical communication with one or more components of the surface equipment  140  via the conductor  122 . The lower portion  114  of the tool string  110  may comprise at least one electrical conductor  115 . The electrical conductors  113 ,  115  may be in electrical communication via at least one electrical conductor  117  of the release tool  116 . Thus, one or more of the upper portion  112 , lower portion  114 , and the release tool  116  may be electrically connected with each other and with one or more components of the surface equipment  140 , such as the power and control system  150 , via the electrical conductors  113 ,  115 ,  117 ,  122 . For example, the electrical conductors  113 ,  115 ,  117 ,  122  may transmit and/or receive electrical power, data, and/or control signals between the power and control system  150  and one or more of the upper portion  112 , the lower portion  114 , and the release tool  116 . The electrical conductors  113 ,  115 ,  117  may further facilitate electrical communication between two or more of the upper portion  112 , the lower portion  114 , and the release tool  116 . Each of the upper portion  112 , the lower portion  114 , the release tool  116 , and/or portions thereof may comprise one or more electrical conductors, connectors, and/or interfaces, such as may form and/or electrically connect the electrical conductors  113 ,  115 ,  117 ,  122 . 
     The upper and lower portions  112 ,  114  of the tool string  110  may each be or comprise at least a portion of one or more downhole tools, modules, subs, and/or other apparatuses  118  operable in wireline, while-drilling, coiled tubing, completion, production, and/or other implementations. The apparatuses  118  of the upper and lower portions  112 ,  114  of the tool string  110  may each be or comprise an acoustic tool, a cable head, a casing collar locator (CCL), a cutting tool, a density tool, a depth correlation tool, a directional tool, an electrical power module, an electromagnetic (EM) tool, a formation testing tool, a fluid sampling tool, a gamma ray (GR) tool, a gravity tool, a formation logging tool, a hydraulic power module, a magnetic resonance tool, a formation measurement tool, a jarring tool, a mechanical interface tool, a monitoring tool, a neutron tool, a nuclear tool, a perforating tool, a photoelectric factor tool, a plug setting tool, a porosity tool, a power module, a ram, a reservoir characterization tool, a resistivity tool, a seismic tool, a stroker tool, a surveying tool, and/or a telemetry tool, among other examples also within the scope of the present disclosure. Although the tool string  110  is shown comprising a single release tool  116 , it is to be understood that one, two, three, or more additional release tools  116  may be coupled at other locations along the tool string  110  between the downhole apparatuses  118  forming the tool string  110 . Multiple release tools  116  along the tool string  110  may permit a smaller or greater portion of the tool string  110  to be retrieved to the wellsite surface  104 , such as based on which portion of the tool string  110  is stuck. 
     In an example implementation of the tool string  110 , an apparatus  118  of the upper portion  112  of the tool string  110  may be or comprise a telemetry/control tool, such as may facilitate communication between the tool string  110  and the surface equipment  140  and/or control of one or more portions of the tool string  110 . The telemetry/control tool may comprise a downhole controller (not shown) communicatively connected with the power and control system  150 , including the surface controller  156 , via conductors  113 ,  122  and with other portions of the tool string  110  via conductors  113 ,  115 ,  117 . The downhole controller may be operable to receive, store, and/or process control commands from the power and control system  150  for controlling one or more portions of the tool string  110 . The controller may be further operable to store and/or communicate to the power and control system  150  signals or information generated by one or more sensors or instruments of the tool string  110 . An apparatus  118  of the tool string  110  may be or comprise inclination sensors and/or other sensors, such as one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for determining the orientation of the tool string  110  relative to the wellbore  102 . An apparatus  118  of the tool string  110  may be or comprise a depth correlation tool, such as a CCL for detecting ends of casing collars by sensing a magnetic irregularity caused by the relatively high mass of an end of a collar of the casing  108 . The depth correlation tool may also or instead be or comprise a GR tool that may be utilized for depth correlation. The CCL and/or GR may be utilized to determine the position of the tool string  110  or portions thereof, such as with respect to known casing collar numbers and/or positions within the wellbore  102 . Therefore, the CCL and/or GR tools may be utilized to detect and/or log the location of the tool string  110  within the wellbore  102 , such as during deployment within the wellbore  102  or other downhole operations. 
     One or more apparatuses  118  of the tool sting  110  may further comprise a jarring or impact tool operable to impart an impact to a stuck portion of the tool string  110  to help free the tool string  110 . The energy for the impact may be stored in the conveyance means  120  for conveying the tool string  110  into the wellbore  102 . Namely, when a portion of the tool string  110  becomes stuck or jammed within the wellbore  102 , the conveyance means  120  may be pulled in the uphole direction by the tensioning device  130  to build up tension and, thus, store energy in the stretched conveyance means  120 . The stored energy may then be released by the impact tool, causing the impact tool to impart an impact to the stuck portion of the tool string  110 . However, the energy for the impact may also or instead be stored as a pressure differential between internal and external portions of the impact tool, which may be utilized to actuate the impact tool to impart the impact to the stuck portion of the tool string  110 . The energy for the impact may also or instead be imparted to a jarring tool by a stroker or ram tool, which may impart an uphole and a downhole force to the impact tool, thereby permitting the impact tool to impart impacts in the uphole and the downhole directions. A tubular jarring tool may also or instead be utilized to impart an impact in the downhole direction. 
     An apparatus  118  of the lower portion  114  of the tool sting  110  may be or comprise one or more perforating guns or tools, such as may be operable to perforate or form holes though the casing  108 , the cement  109 , and the portion of the formation  106  surrounding the wellbore  102  to prepare the well for hydraulic fracturing and/or production. The perforating tools may contain one or more shaped explosive charges operable to perforate the casing  108 , the cement  109 , and the formation  106  upon detonation. An apparatus  118  of the lower portion  114  of the tool string  110  may be or comprise a plug and a plug setting tool for setting the plug at a predetermined position within the wellbore  102 , such as to isolate or seal a lower portion of the wellbore  102 . The plug may be permanent or retrievable, facilitating the lower portion of the wellbore  102  to be permanently or temporarily isolated or sealed, such as during well treatment operations. 
       FIG. 2  is a sectional view of at least a portion of an example implementation of a release tool  200  according to one or more aspects of the present disclosure. The release tool  200  may comprise one or more features of the release tool  116  described above and shown in  FIG. 1 .  FIG. 2  shows the release tool  200  in a normal or inactivated position (referred to hereinafter as a “first position”), in which the release tool  200  is utilized to transmit tension and compression between opposing portions of the tool string  110  comprising the release tool  200 . For example, while in the first position, the release tool  200  may be operable to transmit tension generated by the tensioning device  130  during downhole conveyance of the tool string  110  to a portion of the tool string  110  located downhole from the release tool  200 . The following description refers to  FIGS. 1 and 2 , collectively. 
     The release tool  200  may include an upper (e.g., uphole) connector section or sub  202  (i.e., a removable connector sub) configured to connect with the upper portion  112  of the tool string  110  and a lower (e.g., downhole) connector section or sub  204  (i.e., a remaining connector sub) configured to connect with the lower portion  114  of the tool string  110 . Each connector sub  202 ,  204  may comprise a corresponding housing  203 ,  205  (or body) collectively forming or otherwise defining one or more internal spaces, volumes, bores, and/or chambers for accommodating or otherwise containing various components of the release tool  200 . 
     Each housing  203 ,  205  may comprise or be connected with a corresponding head  206 ,  208  (e.g., a crossover), which may include connectors, interfaces, and/or other means for mechanically and electrically coupling the release tool  200  with corresponding mechanical and electrical interfaces (not shown) of the upper and lower portions  112 ,  114  of the tool string  110 . The upper head  206  may include a mechanical interface, a sub, and/or other means  210  for mechanically coupling the release tool  200  with a corresponding mechanical interface of a downhole apparatus  118  (e.g., an impact tool) of the upper portion  112  of the tool string  110 . The lower head  208  may include a mechanical interface, a sub, and/or other means  212  for mechanically coupling with a corresponding mechanical interface of a downhole apparatus  118  (e.g., a perforating gun) of the lower portion  114  of the tool string  110 . Although the interface means  210 ,  212  are shown comprising ACME box and pin couplings, respectively, the interface means  210 ,  212  may alternatively comprise other pin and box couplings, threaded connectors, fasteners, and/or other mechanical coupling means. 
     The upper and lower interface means  210 ,  212  and/or another portions of the upper and/or lower heads  206 ,  208  may each further comprise a corresponding electrical interface  214 ,  216 . An electrical conductor  217  (schematically shown as a dashed line) may extend between and electrically connect the electrical interfaces  214 ,  216 . The upper electrical interface  214  may comprise means for electrically connecting the electrical conductor  217  with a corresponding electrical interface of an apparatus  118  of the upper portion  112  of the tool string  110 , whereby such corresponding electrical interface may be in electrical connection with the electrical conductor  113  of the upper portion  112  of the tool string  110 . The lower interface  216  may comprise means for electrically connecting the electrical conductor  217  with a corresponding electrical interface of the lower portion  114  of the tool string  110 , whereby such corresponding electrical interface may be in electrical connection with the electrical conductor  115  of the lower portion  114  of the tool string  110 . Although the electrical interfaces  214 ,  216  are shown comprising a receptacle and pin, respectively, the electrical interfaces  214 ,  216  may alternatively each comprise other electrical coupling means, including plugs, terminals, conduit boxes, and/or other electrical connectors. 
     The upper and lower heads  206 ,  208  and/or other portions of the housings  206 ,  208  may each comprise and/or contain a corresponding bulkhead connector  218 ,  219  configured to form a fluid seal along the electrical conductor  217 , such as to prevent or inhibit wellbore fluid or other external fluid from leaking into the internal spaces, bores, or chambers of the release tool  200  along the electrical conductor  217  during downhole operations. The electrical conductor  217 , the bulkhead connectors  218 ,  219 , and the electrical interfaces  214 ,  216 , may collectively form the electrical conductor  117  of the release tool  116 , such as may facilitate electrical communication through the release tool  200 . 
     The housing  203  of the upper connector sub  202  may comprise an inner surface defining a bore (or chamber) extending longitudinally (e.g., axially) through a portion of the upper connector sub  202 . The bore may comprise a first bore portion  248 , a second bore portion  250  connected with and located above the first bore portion  248 , and a third bore portion  251  connected with and located above the second bore portion  250 . The diameter of the first bore portion  248  may be significantly larger and the diameter of the second bore portion  250 . The diameter of the third bore portion  251  may progressively increase (i.e., taper outwardly) in an upward (e.g., uphole) direction from a lower end of the third bore portion  251 , adjacent the second bore portion  250 , to an upper end of the third bore portion  251 . The first, second, and third bore portions  248 ,  250 ,  251  may be concentrically (i.e., axially) aligned. 
     The release tool  200  may further comprise a latching mechanism  220  operable to latch (e.g., lock, connect, couple) together the upper and lower connector subs  202 ,  204 , and selectively unlatch (e.g., unlock, release, disconnect, uncouple) the upper connector sub  202  from the lower connector sub  204  or otherwise from each other, while deployed within the wellbore  102 . The latching mechanism  220  may be at least partially located within the internal bores of the release tool  200  and comprise an upper latching member  222 , a lower latching member  224 , and a blocking member  226 . The upper latching member  222  and the blocking member  226  may be a portion of or be operatively connected with the upper sub  202 . For example, the upper latching member  222  may be slidably (e.g., telescopically) or otherwise movably connected with the housing  203 , having a limited range of motion (e.g., axial motion, longitudinal motion) with respect to the housing  203 . The lower latching member  224  may be a portion of the lower connector sub  204 . For example, the lower latching member  224  may be integral to or fixedly connected with the housing  205 . The upper latching member  222  may be or comprise a male latching member and the lower latching member  224  may be or comprise a female latching member configured to receive the upper latching member  222 . The upper and lower latching members  222 ,  224  may be operable to engage (e.g., latch against) each other to latch the connector subs  202 ,  204  and to selectively disengage (e.g., unlatch) from each other to selectively unlatch or otherwise permit separation of the connector subs  202 ,  204 . 
     The blocking member  226  may be slidably disposed or otherwise movable with respect to the upper and lower latching members  222 ,  224  to selectively prevent the upper and lower latching members  222 ,  224  from disengaging and permit the upper and lower latching members  222 ,  224  to disengage. The blocking member  226  may be slidably or otherwise movingly disposed within or otherwise with respect to the upper latching member  222 . A portion (e.g., an upper end) of the blocking member  226  may extend from or be disposed above the upper latching member  222 . The blocking member  226  may be operable to block or otherwise prevent disengagement of the upper and lower latching members  222 ,  224  to maintain latched connection between the upper and lower latching members  222 ,  224  and, thus, the connector subs  202 ,  204 . For example, the blocking member  226  can be moved from a position (referred to hereinafter as a “first position”) (shown in  FIG. 2 ) in which the blocking member  226  prevents the upper and lower latching members  222 ,  224  from disengaging to a position (referred to hereinafter as a “second position”) (shown in  FIG. 5 ) in which the blocking member  226  permits the upper and lower latching members  222 ,  224  to disengage, thereby permitting the upper and lower connector subs  202 ,  204  to be disconnected (e.g., released, separated, uncoupled). The blocking member  226  may also be referred to as an anti-release, anti-unlatching, or anti-disengaging member because the blocking member  226  prevents the upper and lower latching members  222 ,  224  and, thus, the upper and lower connector subs  202 ,  204  from releasing, unlatching, or disengaging. 
     The upper latching member  222  may comprise a plurality of flexible members  230  configured to collectively detachably engage the lower latching member  224 . The flexible members  230  may be connected with and extend from a shaft  232  (or rod) slidably disposed within the first bore portion  248  extending through the upper connector sub  202 . The shaft  232  may be retained within the bore portion  248  or otherwise operatively connected with the housing  203 , thereby connecting the upper latching member  222  with the housing  203 . For example, the shaft  232  may include a larger diameter portion  234  slidably disposed within the bore portion  248 . The larger diameter portion  234  may comprise opposing outwardly extending radial shoulders (e.g., opposing ends), each configured to contact an opposing radially inward extending shoulder  236 ,  238  of the housing  203  to maintain the larger diameter portion  234  of the shaft  232  within the bore portion  248 , thereby connecting the upper latching member  222  with the housing  203 . An axial distance between the shoulders  236 ,  238  of the housing  203  may be greater than an axial distance between the opposing shoulders of the larger diameter portion  234 , thereby permitting a limited range of axial movement of the larger diameter portion  234  and, thus, the upper latching member  222  with respect to the housing  203 . The upper latching member  222  may be selectively fixedly connected with the housing  203  via one or more shear pins  240  while the release apparatus  200  is in the first position, such as when the upper shoulder of the larger diameter portion  234  is in contact with or adjacent the upper shoulder  236  of the housing  203 . The shear pins  240  may extend through the housing  203  and into the larger diameter portion  234  of the upper latching member  222 . Each flexible member  230  may terminate with an external (i.e., radially outward) profile  242  having an outwardly extending radial shoulder. The flexible members  230  may flex or bend to permit the external profiles  242  to move radially when the external profiles  242  are acted upon by an external force. The upper latching member  222  may further comprise an inner surface defining a bore  244  extending axially through the upper latching member  222 . The bore  244  may be configured to accommodate the blocking member  226 . Thus, the blocking member  226  may be slidably or otherwise movingly disposed within the bore  244  of the upper latching member  222 . The inner surface of the upper latching member  222  may further comprise or define a circumferential groove or channel  245  (a larger diameter portion of the bore  244 ) extending radially outward. 
     The housing  205  and/or the lower latching member  224  may comprise an inner surface defining a bore  260  (or chamber) configured to receive or otherwise accommodate therein a portion of the upper latching member  222  while the release apparatus  200  is in the first position. The inner surface of the lower latching member  224  defining the bore  260  may further comprise or define an inwardly extending radial shoulder  246  configured to engage (e.g., contact, latch against) the outwardly extending radial shoulders of the external profiles  242  of the upper latching member  222  when the upper latching member  222  is inserted or otherwise disposed within the bore  260  of the lower latching member  224 . 
     The blocking member  226  may be slidably disposed within the bore  244  of the upper latching member  222 . An upper portion of the blocking member  226  may extend out of the bore  244  above the upper latching member  222  into the second bore portion  250  of the housing  203 . The upper portion of the blocking member  226  may be or comprise a plurality of biasing (e.g., flexible) members  252 , each terminating with or carrying a corresponding external profile, such as a shoulder  254 , each extending in a radially outward direction. The shoulders  254  and at least a portion of the biasing members  252  may be disposed within the bore portion  250 . The biasing members  252  may flex or bend to permit the shoulders  254  to be forced, compressed, or otherwise moved radially inward when disposed within the bore portion  250 , as indicated by arrows  255 . The biasing members  252  may bias the shoulders  254  to expand in a radially outward or otherwise lateral direction when the shoulders  254  are not disposed within the bore portion  250 . One or more of the biasing members  252  may further comprise or otherwise carry a latching member  253  (e.g., a barb, a spine, a hook, etc.) extending in a radially outward direction. The latching members  253  may be configured to be at least partially received within the channel  245 . While that release tool  200  is in the first position, the shoulder  236  of the housing  203  is disposed below the shoulders  254  of the blocking member  226 . 
     A lower portion (or end) of the blocking member  226  may terminate with a blocking portion  256  (e.g., ring, sleeve) disposed between, along, against, or otherwise adjacent the external profiles  242 . The blocking portion  256  may be sized or otherwise configured to prop or support the external profiles  242  by preventing or blocking the external profiles  242  from deflecting or otherwise moving radially inward toward each other. In the first position of the release tool  200 , the external profiles  242  may be located below the shoulder  246  and the blocking portion  256  may prevent the profiles  242  from moving upward to a position above the shoulder  246 . Accordingly, the blocking portion  256  may prevent the profiles  242  from bypassing the shoulder  246 , thereby preventing the upper and lower latching members  222 ,  224  from disengaging and, thereby, preventing the upper and lower connector subs  202 ,  204  from uncoupling when tension is applied to the tool string  110 . 
     An intermediate portion of the blocking member  226  may comprise an intermediate member  258  (e.g., a tube, a rod, a shaft) extending between and connecting the biasing members  252  and the blocking portion  256 . The intermediate member  258  may progressively taper or narrow from the biasing members  252  to the blocking portion  256 , whereby the intermediate member  258  adjacent or at the blocking portion  256  comprises an outer diameter that is significantly smaller than an outer diameter of the blocking portion  256  and/or significantly smaller than a radial distance between the external profiles  242 . The blocking member  226  may further comprise a bore  264  extending axially through the blocking member  226 . The bore  264  may be configured to accommodate the electrical conductor  217  extending through the release tool  200 . The blocking member  226  may be selectively fixedly connected with the upper latching member  222  via one or more shear pins  262  while the release apparatus  200  is in the first position. The shear pins  262  may extend through the shaft  232  of the upper latching member  222  and into the intermediate member  258  of the blocking member  226 . 
     An upper end of the lower connector sub  204 , such as an upper end of the lower latching member  224 , may comprise a neck  266  and/or internal or external features or profiles  268 , which may be exposed when the upper connector sub  202  is disconnected and moved away from the lower connector sub  204 . The neck  266  and/or internal or external features or profiles  268  may facilitate or otherwise permit the lower connector sub  204  to be coupled with wellbore fishing equipment (not shown) during fishing operations. For example, the upper end of the lower connector sub  204  may comprise one or more external cavities, protrusions, or other profiles (e.g., an external fishing neck) operable for coupling with the wellbore fishing equipment (e.g., an outside grappling device) during fishing operations. However, the lower connector sub  204  may also or instead comprise a substantially smooth or uniform outer surface, such as may permit the lower connector sub  204  to be received or captured by an overshoot fishing tool (e.g., an external catch) during fishing operations. The lower connector sub  204  may also or instead comprise one or more internal cavities, protrusions, or other profiles (e.g., an internal fishing neck profile), which may be exposed when the upper connector sub  202  is removed to permit the fishing equipment (e.g., an inside grappling device, a spear) to enter and thread into or otherwise latch against the internal profile during fishing operations. 
     The upper connector sub  202  may further comprise a sleeve  270  extending around the upper latching member  222  and the blocking member  226 . The sleeve  270  may be connected to or carried by the upper latching member  222 , such as via bolts  271  or other fasteners. The sleeve  270  may be configured to at least partially cover (e.g., extend around) the latching mechanism  220  and the fishing neck  266  while the release apparatus  200  is in the first position. The sleeve  270  may protect the latching mechanism  220  and fishing neck  266 , such as during downhole conveyance of the tool string  110 . 
     While in the first position, the release tool  200  may be operable to transmit tension and compression between upper and lower portions  112 ,  114  of the tool string  110 . For example, during conveyance or other downhole operations, tension applied to the tool string  110  may cause the outwardly extending radial shoulders of the external profiles  242  to engage (i.e., contact) the inwardly extending radial shoulder  246  to prevent or inhibit relative motion between the upper and lower latching members  222 ,  224  and, thus, prevent or limit relative motion between the upper and lower connector subs  202 ,  204 . While in the first position, the release tool  200  may be further operable to transmit impact forces generated by an impact tool in the downhole direction. While in the first position, the release tool  200  may be operable to transmit impact forces generated by an impact tool in the uphole direction, if the magnitude of such impact forces is less than the breaking force limit of the shear pins  240 . 
     The release tool  200  may comprise a plurality of threadedly or otherwise interconnected parts or portions. For example, the upper and lower housings  203 ,  205  may comprise a plurality of interconnected portions collectively forming the upper and lower housings  203 ,  205 . Accordingly, assembly of the release tool  200  may include a predetermined procedure or order of connecting the various portions of the release tool  200 . For example, the upper latching member  222  may be inserted into the first bore portion  248  of a portion of the housing  203  comprising the bore portion  248 . When the larger diameter portion  234  is disposed at a predetermined distance from the lower shoulder  238 , the shear pins  262  may be utilized to fixedly connect the upper latching member  222  with the portion of the housing  203  comprising the bore portion  248 . Thereafter, a portion of the housing  203  comprising the second and third bore portions  250 ,  251  may be connected with the portion of the housing  203  comprising the bore portion  248 , thereby connecting the bore portions  248 ,  250  with the bore portion  251  and locking the larger diameter portion  234  within the bore portion  248 . After the upper latching member  222  is inserted into the lower latching member  224  such that the external profiles  242  engage the shoulder  246 , the blocking member  226  may be inserted into the bore  244  of the upper latching member  222  and the bore portion  250  via the bore portion  251 . While the blocking member  226  is moved through the bore portion  251 , the tapered sidewall of the bore portion  251  may force, compress, or otherwise move the shoulders  254  radially inward, as indicated by arrows  255 , flexing or bending the biasing members  252 , to permit the shoulders  254  to be disposed within the bore portion  250 . After the blocking portion  256  is disposed against and/or between the external profiles  242 , the blocking member  226  may be fixedly connected with the upper latching member  222  via the shear pins  262 . Thereafter, the portions of the housing  203  comprising the bulkhead connector  218  and the upper interface means  210  (e.g., the upper head  206 ) may be connected with the portion of the housing  203  comprising the bore portions  250 ,  251 , thereby covering the bore portion  251 . 
     When it is intended to release an upper portion  112  of the tool string  110  coupled uphole from the release tool  200 , from a lower portion  114  of the tool string  110  coupled downhole from the release tool  200 , such as when the lower portion  114  of the tool string  110  is stuck within the wellbore  102 , the release tool  200  may be operated to unlatch (e.g., release, unlock, disconnect) the upper connector sub  202  from the lower connector sub  204 . The release tool  200  may progress though a sequence of operational stages or positions during such release operations.  FIGS. 3-6  are sectional views of the release tool  200  shown in  FIG. 2  in subsequent operational positions of the release operations according to one or more aspects of the present disclosure. The following description refers to  FIGS. 1-6 , collectively. 
     While the release tool  200  is in the first position, as shown in  FIG. 2 , the release operations may be initiated by operating an impact tool connected uphole from the release tool  200  (e.g., in the upper portion  112  of the tool string  110 ) to impart an uphole directed impact (i.e., jarring action) to the tool string  110 . As shown in  FIG. 3 , the impact should impart a sufficient upward force (i.e., tension) along the release tool  200  to break the shear pins  240  and pull the housing  203  upward with respect to the upper latching member  222 , as indicated by arrow  272 . The upward movement of the housing  203  with respect to the upper latching member  222  may cause the shoulder  236  of the housing  203  to move from a position in which the shoulder  236  is disposed below the shoulders  254  of the blocking member  226  to a position in which the shoulder  236  is disposed above the shoulders  254 . Such upward movement  272  of the housing  203  may cause the shoulders  254  (and perhaps the biasing members  252 ) to be withdrawn from the second bore portion  250 , permitting the biasing members  252  to expand the shoulders  254  to their normal (uncompressed) state, as indicated by arrows  274 . While the shoulders  254  are in their normal state, distance between outer surfaces of the shoulders  254  may be greater than the inner diameter of the bore portion  250 . The housing  203  may continue to move upward until the lower shoulder  230  of the housing  203  contacts the lower shoulder of the larger diameter portion  234  of the upper latching member  222 .  FIG. 3  shows the release tool  200  in a transitional (e.g., intermediate, cocked) stage or position (referred to hereinafter as a “second position”) of the release tool  200  during the release operations, in which the release tool  200  is ready to be operated or otherwise moved to a subsequent unlatched position of the release operations. While the release tool  200  is in the second position, the housing  203  and the upper latching member  222  cannot expand further or disconnect and, thus, the impact tool connected uphole from the release tool  200  may be operated repeatedly and/or indefinitely to impart impacts in the uphole direction to the tool string  110  until, for example, the stuck portion of the tool string  110  is freed. 
     Thereafter, an impact tool, a stroker tool, or another tool connected uphole from the release tool  200  may be operated to impart a downward force (e.g., impact) to the tool string  110 . As shown in  FIG. 4 , the downward force may push the housing  203  downward with respect to the upper latching member  222 , as indicated by arrow  276 . Such downward movement  276  of the housing  203  may cause the upper shoulder  236  of the of the housing  203  to contact the shoulders  254  of the blocking member  226  and push the blocking member  226  downward with respect to the upper latching member  222 , as indicated by arrows  278 . The downward force imparted to the housing  203  should have sufficient magnitude to break the shear pins  262  that connect the blocking member  226  with the upper latching member  222 , thereby permitting the blocking member  226  to move downward with respect to the upper latching member  222 . In an implementation of the release tool  200 , the shear pins  262  may be sized or otherwise selected to permit the weight of the upper portion  112  of the tool string  110  to break the shear pins  262 . For example, some or all of the weight of the upper portion  112  of the tool string  110  to be transferred to the shear pins  262  thereby causing the shear pins  262  to break by releasing some or all tension from the conveyance means  120 . 
     As shown in  FIG. 5 , the housing  203  may continue to be moved downward  278  with respect to the upper latching member  222 , pushing the blocking member  226  downward, as indicated by arrow  280 , until the blocking portion  256  moves below, is not between, or otherwise exits the external profiles  242 . When the blocking portion  256  exits the external profiles  242 , the latching members  253  can enter the channel  245 , thereby latching the blocking member  226  with the upper latching member  222  to prevent further relative movement between the blocking member  226  and the upper latching member  222 . When the blocking portion  256  exits the external profiles  242 , the upper and lower latching members  222 ,  224  are unlatched, whereby the external profiles  242  can deflect or otherwise move radially inward toward each other, thereby permitting the upper latching member  222  to be moved (e.g., pulled) out of the lower latching member  224 . The position of the release tool  200  shown in  FIG. 5  may be referred to as an unlatched (e.g., releasable, unlocked, unblocked) stage or position (referred to hereinafter as a “third position”) of the release operations because, while the upper latching member  222  is still within the lower latching member  224 , the blocking member  226  does not block or otherwise prevent the upper and lower latching members  222 ,  224  and, thus, the upper and lower subs  202 ,  204  from separating. 
     Thereafter, tension may be applied from the wellsite surface  104  by the tensioning device  130  to the tool string  110  via the conveyance mean  120  to separate the upper connector sub  202  from the lower connector sub  204  and retrieve the free upper portion  112  of the tool string  110  to the wellsite surface  104 . When tension is applied, the upper latching member  222  of the upper sub  202  may be pulled upward with respect to the lower latching member  224  of the lower sub  204 , as indicated by arrow  282 , causing the shoulder  246  to force, compress, or otherwise move the external profiles  242  radially inward against the intermediate member  258 , as indicated by arrows  284 , thereby permitting the external profiles  242  to bypass the shoulder  246 . The tension may be applied until the upper latching member  222  fully exits the lower latching member  224  to separate the upper connector sub  202  from the lower connector sub  204 .  FIG. 6  shows the release tool  200  in a separated stage or position (referred to hereinafter as a “fourth position”) of the release operations, in which the upper connector sub  202  is fully separated or removed from the lower connector sub  204  and the neck  266  and profile  268  are exposed. 
     Thereafter, the uncoupled portion of the tool string  110 , including the upper tool string portion  112  and the upper connector sub  202 , may be returned to the wellsite surface  104 . Fishing equipment (not shown) may then be deployed downhole and coupled or otherwise engaged with the neck  266  and/or profile  268 , such as may permit fishing operations to be performed. Thereafter, tension may be applied from the wellsite surface  104  by the tensioning device  130  via the conveyance means  120  to the lower portion  114  (i.e., stuck portion) of the tool string  110  remaining in the wellbore  102  to free the lower portion  114  of the tool string  110 . 
     In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a downhole tool comprising: (A) a first connector sub connectable with a first portion of a tool string, wherein the first connector sub comprises: (i) a housing; (ii) a first latching member slidably connected with the housing; and (iii) a blocking member movable with respect to the first latching member; and (B) a second connector sub connectable with a second portion of the tool string, wherein the second connector sub comprises a second latching member, and wherein: (i) the first and second latching members engage thereby connecting the first and second connector subs; and (ii) the blocking member is movable from a first position in which the blocking member prevents the first and second latching members from disengaging to a second position in which the blocking member permits the first and second latching members to disengage thereby permitting the first and second connector subs to disconnect. 
     Downward movement of the housing with respect to the first latching member may facilitate movement of the blocking member from the first position to the second position. 
     Downward movement of the housing with respect to the first latching member may cause the blocking member to be pushed downward from the first position to the second position. 
     Movement of the housing in a first direction with respect to the first latching member and then movement of the housing in a second direction with respect to the first latching member may facilitate movement of the blocking member from the first position to the second position, wherein the first and second directions are opposing directions. 
     Upward movement of the housing with respect to the first latching member and then downward movement of the housing with respect to the first latching member may facilitate movement of the blocking member from the first position to the second position. In such implementations, among others within the scope of the present disclosure, the housing may be movable upward and downward with respect to the first latching member via a jarring tool while: the tool string is conveyed downhole; the downhole tool is connected between the first and second portions of the tool string; and the second portion of the tool string is stuck downhole. 
     The housing may comprise a first shoulder, the blocking member may comprise a second shoulder, the housing may be movable upward with respect to the first latching member from a position in which the first shoulder is disposed below the second shoulder to a position in which the first shoulder is disposed above the second shoulder, the housing may then be movable downward with respect to the first latching member, and the downward movement of the housing with respect to the first latching member may cause the first shoulder to contact the second shoulder thereby pushing the blocking member downward from the first position to the second position. The first shoulder may extend in a radially inward direction, and the second shoulder may extend in a radially outward direction. The blocking member may comprise a biasing member configured to move the second shoulder in a lateral direction when the housing is moved upward with respect to the first latching member to the position in which the first shoulder is disposed above the second shoulder such that the first and second shoulders make contact when the housing is moved downward. 
     The blocking member may be slidably disposed within the first latching member, and a portion of the blocking member may extend out of the first latching member. 
     An upper end of the blocking member may be disposed above the first latching member. 
     The present disclosure also introduces an apparatus comprising a downhole tool comprising: (A) a first connector sub connectable with a first portion of a tool string, wherein the first connector sub comprises: (i) a housing; (ii) a first latching member; and (iii) a blocking member; and (B) a second connector sub connectable with a second portion of the tool string, wherein the second connector sub comprises a second latching member, and wherein: (i) the first and second latching members engage thereby connecting the first and second connector subs; (ii) the blocking member is movable from a first position in which the blocking member prevents the first and second latching members from disengaging to a second position in which the blocking member permits the first and second latching members to disengage thereby permitting the first and second connector subs to disconnect; and (iii) relative movement between the housing and first latching member facilitates movement of the blocking member from the first position to the second position. 
     The relative movement between the housing and first latching member that facilitates movement of the blocking member from the first position to the second position may comprise downward movement of the housing with respect to the first latching member to facilitate movement of the blocking member from the first position to the second position. 
     The relative movement between the housing and first latching member that facilitates movement of the blocking member from the first position to the second position may comprise downward movement of the housing with respect to the first latching member to cause the blocking member to be pushed downward from the first position to the second position. 
     The relative movement between the housing and first latching member that facilitates movement of the blocking member from the first position to the second position may comprise: movement of the housing in a first direction with respect to the first latching member; and then movement of the housing in a second direction with respect to the first latching member, wherein the first and second direction are opposing directions. 
     The relative movement between the housing and first latching member that facilitates movement of the blocking member from the first position to the second position may comprise: upward movement of the housing with respect to the first latching member; and then downward movement of the housing with respect to the first latching member. The housing may be movable upward and downward with respect to the first latching member via a jarring tool while: the tool string is conveyed downhole; the downhole tool is connected between the first and second portions of the tool string; and the second portion of the tool string is stuck downhole. 
     The housing may comprise a first shoulder, the blocking member may comprise a second shoulder, the housing may be movable upward with respect to the first latching member from a position in which the first shoulder is disposed below the second shoulder to a position in which the first shoulder is disposed above the second shoulder, the housing may then be movable downward with respect to the first latching member, and the downward movement of the housing with respect to the first latching member may cause the first shoulder to contact the second shoulder thereby pushing the blocking member downward from the first position to the second position. The first shoulder may extend in a radially inward direction, and the second shoulder may extend in a radially outward direction. The blocking member may comprise a biasing member configured to move the second shoulder in a lateral direction when the housing is moved upward with respect to the first latching member to the position in which the first shoulder is disposed above the second shoulder such that the first and second shoulders make contact when the housing is moved downward. 
     The first latching member and the housing may be slidably connected. 
     The present disclosure also introduces a method comprising: (A) operating a downhole tool connected between an upper portion of a tool string and a lower portion of the tool string while the lower portion of the tool string is stuck downhole, wherein the downhole tool comprises an upper portion connected with the upper portion of the tool string, wherein the downhole tool comprises a lower portion connected with the lower portion of the tool string, and wherein operating the downhole tool comprises: (i) moving the upper portion of the downhole tool upward with respect to the lower portion of the downhole tool and the lower portion of the tool string; and then (ii) moving the upper portion of the downhole tool downward with respect to the lower portion of the downhole tool and the lower portion of the tool string to unlatch the upper portion of the downhole tool from the lower portion of the downhole tool; and then (B) applying tension to the tool string to cause an upper portion of the downhole tool to separate from the lower portion of the downhole tool thereby separating the upper portion of the tool string from the lower portion of the tool string. 
     Moving the upper portion of the downhole tool upward with respect to the lower portion of the downhole tool and the lower portion of the tool string may comprise applying tension to the tool string from the wellsite surface to cause the upper portion of the tool string and the upper portion of the downhole tool to move upward with respect to the lower portion of the downhole tool and the lower portion of the tool string. 
     Moving the upper portion of the downhole tool upward with respect to the lower portion of the downhole tool and the lower portion of the tool string may comprise jarring the upper portion of the downhole tool upward with a jarring tool located in the upper portion of the tool string. 
     Moving the upper portion of the downhole tool downward with respect to the lower portion of the tool string and the lower portion of the downhole tool may comprise releasing tension from the tool string to permit gravity to cause the upper portion of the tool string and the upper portion of the downhole tool to move downward with respect to the lower portion of the tool string and the lower portion of the downhole tool. 
     Moving the upper portion of the downhole tool downward with respect to the lower portion of the tool string and the lower portion of the downhole tool may comprise jarring the upper portion of the downhole tool downward with a jarring tool located in the upper portion of the tool string. 
     The upper portion of the downhole tool may comprise a first latching member, the lower portion of the downhole tool may comprise a second latching member, the first and second latching members may engage thereby connecting the upper and lower portions of the downhole tool, the downhole tool may further comprise a blocking member slidably disposed with respect to the first and second latching members, and moving the upper portion of the downhole tool downward with respect to the lower portion of the downhole tool and the lower portion of the tool string may cause the blocking member to move from a first position in which the blocking member prevents the first and second latching members from disengaging to a second position in which the blocking member permits the first and second latching members to disengage thereby unlatching the upper portion of the downhole tool from the lower portion of the downhole tool. 
     The upper portion of the downhole tool may comprise a first latching member and a first shoulder, the lower portion of the downhole tool may comprise a second latching member, the first and second latching members may engage thereby connecting the upper and lower portions of the downhole tool, the downhole tool may further comprise a blocking member slidably disposed with respect to the first and second latching members, the blocking member may comprise a second shoulder, moving the upper portion of the downhole tool upward with respect to the lower portion of the downhole tool and the lower portion of the tool string may move the first shoulder upward from a position in which the first shoulder is disposed below the second shoulder to a position in which the first shoulder is disposed above the second shoulder, and moving the upper portion of the downhole tool downward with respect to the lower portion of the downhole tool and the lower portion of the tool string may move the first shoulder downward causing the first shoulder to contact the second shoulder thereby pushing the blocking member downward from a first position in which the blocking member prevents the first and second latching members from disengaging to a second position in which the blocking member permits the first and second latching members to disengage thereby unlatching the upper portion of the downhole tool from the lower portion of the downhole tool. 
     The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the scope of the present disclosure. 
     The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.