Patent Publication Number: US-9896895-B2

Title: Annulus pressure release running tool

Description:
BACKGROUND 
     In completing production or injection wells in the oil and gas industry, it is common practice to run various downhole tools into the wellbore in a retracted or “run-in” position and then set or actuate the downhole tool once reaching a target destination. Such downhole tools are normally run into the wellbore on some type of running tool, which, in turn, is releasably connected, to the lower end of a tubing string conveyance extended from a surface location. After the downhole tool is set within the wellbore, the running tool is then released from the downhole tool and withdrawn from the wellbore along with the tubing string. 
     Some running tools incorporate the use of shearable elements (e.g., shear pins, shear rings, etc.) to protect against premature disconnection of the running tool from the downhole tool when the running tool is rotated in a direction that would normally disconnect the running tool from the well tool. Unfortunately, such shearable elements frequently undergo substantial wear before the downhole tool assembly reaches its target destination, which can result in premature shearing and, therefore, premature setting of the downhole tool or disconnection of the running tool. This possibility is especially present in the modern, long and heavy downhole tool assemblies required for completing long production intervals and in those downhole tool assemblies required to complete production intervals in horizontal or inclined wellbores where the forces exerted on any shearable elements during installation can be substantial. 
     One proposed solution for preventing the premature shearing of the shearable elements is to include additional or stronger shearable elements. However, as may be expected, for a shearable element to be strong enough to prevent premature shearing, the force required to deliberately shear the shearable element be more than can be developed through the tubing string on which the downhole tool assembly is carried. Further, there may be instances where the downhole tool assembly becomes stuck in the wellbore before it reaches its target destination. When this occurs, it is highly desirable to be able to release the running tool and recover it along with the tubing string from the wellbore without the need for first setting the downhole tool. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure. 
         FIG. 1  is a well system that may embody or otherwise employ one or more principles of the present disclosure. 
         FIGS. 2A and 2B  are side views of an exemplary running tool. 
         FIGS. 3A and 3B  depict enlarged isometric views of a portion of the running tool of  FIGS. 2A and 2B  moving from the torque-locked position to the torque-released position. 
         FIGS. 4A and 4B  are cross-sectional side views of the running tool of  FIGS. 2A and 2B  depicting how the running tool may move from the torque-locked position to the torque-released position. 
         FIG. 5  is another cross-sectional side view of the running tool of  FIGS. 2A and 2B . 
         FIGS. 6A-6F  are partial cross-sectional side views of exemplary releasable connections. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, more particularly, to a running tool that may be released from a downhole tool assembly using annulus pressure. 
     The embodiments disclosed herein provide a running tool capable of deploying downhole equipment and releasing the running tool using annular pressure. The running tool is designed to carry the downhole equipment while maintaining the entire assembly torque-locked. Once the downhole equipment has been delivered and set, the presently disclosed torque-lock feature can be released by increasing fluid pressure within the annulus defined between the running tool and a wall of a wellbore and subsequently applying a tensile load in the uphole direction, or by using a contingency release option activated by increasing the pressure within the running tool and subsequently rotating the running tool to unthread it from the downhole equipment. 
     Referring to  FIG. 1 , illustrated is a well system  100  that may embody or otherwise employ one or more principles of the present disclosure, according to one or more embodiments. As illustrated, the well system  100  may include a service rig  102  that is positioned on the earth&#39;s surface  104  and extends over and around a wellbore  106  that penetrates a subterranean formation  108 . The service rig  102  may be a drilling rig, a completion rig, a workover rig, or the like. In some embodiments, the service rig  102  may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure. Moreover, while the well system  100  is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure could equally be applied in any sea-based or sub-sea application where the service rig  102  may be a floating platform, a semi-submersible platform, or a sub-surface wellhead installation as generally known in the art. 
     The wellbore  106  may be drilled into the subterranean formation  108  using any suitable drilling technique and may extend in a substantially vertical direction away from the earth&#39;s surface  104  over a vertical wellbore portion  110 . At some point in the wellbore  106 , the vertical wellbore portion  110  may deviate from vertical relative to the earth&#39;s surface  104  and transition into a substantially horizontal wellbore portion  112 . In some embodiments, the wellbore  106  may be completed by cementing a casing string  114  within the wellbore  106  along all or a portion thereof. In other embodiments, however, the casing string  114  may be omitted from all or a portion of the wellbore  106  and the principles of the present disclosure may equally apply to an “open-hole” environment. 
     The system  100  may further include a downhole tool or downhole tool assembly  116  that may be conveyed into the wellbore  106  on a conveyance  118  that extends from the service rig  102 . The downhole tool assembly  116  may comprise a variety of tools or assemblies used in drilling or completing the wellbore  106  and may be intended to be set or actuated and subsequently left in the wellbore  106 . Exemplary downhole tools or tool assemblies  116  include, but are not limited to, a completion string including one or more packers and associated well screens, one or more well screens, one or more wellbore packers, a wellbore packer test tool, a liner hanger, a polished bore receptacle, etc. The conveyance  118  that delivers the downhole tool assembly  116  into the wellbore  106  may be, but is not limited to, casing, coiled tubing, drill pipe, tubing, or the like. 
     The downhole tool assembly  116  may be conveyed downhole to a target location within the wellbore  106  and subsequently set at the target location. After being set within the wellbore  106 , the downhole tool assembly  116  may be released from the conveyance  118  by operation of a running tool  120 . As described in greater detail below, the running tool  120  may be designed to carry the downhole tool assembly  116  into the wellbore  106  while maintaining the entire downhole tool assembly  116  torque-locked. The torque-locked feature on the running tool  120  may be released by increasing fluid pressure within the conveyance  118 , and the downhole tool assembly  116  may be subsequently released from the running tool  120  by increasing the fluid pressure within the annulus  122  defined between the conveyance  118  and the wellbore  106 . 
     It will be appreciated by those skilled in the art that even though  FIG. 1  depicts the downhole tool assembly  116  as being arranged and operating in the horizontal portion  112  of the wellbore  106 , the embodiments described herein are equally applicable for use in portions of the wellbore  106  that are vertical, deviated, or otherwise slanted. Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward or uphole direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well. As used herein, the term “proximal” refers to that portion of the component being referred to that is closest to the wellhead, and the term “distal” refers to the portion of the component that is furthest from the wellhead. 
     Referring now to  FIGS. 2A and 2B , with continued reference to  FIG. 1 , illustrated are side views of an exemplary running tool  200 , according to one or more embodiments of the present disclosure. More particularly,  FIG. 2A  depicts the running tool  200  in a torque-locked position, and  FIG. 2B  depicts the running tool  200  in a torque-released position. The running tool  200  may be the same as or similar to the running tool  120  of  FIG. 1  and, therefore, may be used to run the downhole tool assembly  116  (shown in dashed outline) into the wellbore  106  and subsequently release the downhole tool assembly  116  at a target location. 
     As illustrated, the running tool  200  may include an elongate, cylindrical mandrel or body  202  and a connection sub  204  disposed about the body  202 . The connection sub  204  may be configured to facilitate and provide a releasable connection or coupling engagement between the running tool  200  and the downhole tool assembly  116 . In the illustrated embodiment, for example, the releasable connection of the connection sub  204  is depicted as a collet  206  disposed at the distal end of the connection sub  204  and used to couple the running tool  200  to the downhole tool assembly  116 . In other embodiments, however, and as described in greater detail below, the collet  206  may be replaced with several different types of releasable connections that are equally suitable for coupling the running tool  200  to the downhole tool assembly, without departing from the scope of the disclosure. Accordingly, the following description of the collet  206  and its operation should not be considered as limiting the present disclosure to any one type of releasable connection for the connection sub  204 . 
     In the illustrated embodiment, the collet  206  may define and otherwise provide a plurality of axially extending collet fingers  208  separated by axially extending slots  210  defined through the collet  206 . The collet  206  may further define an engagement profile  212  at the ends of each collet finger  208 . The engagement profile  212  may be configured to mate with a corresponding engagement profile (not shown) defined on the inner radial surface of the downhole tool assembly  116  to thereby couple the downhole tool assembly  116  to the collet  206  and, therefore, to the running tool  200 . In some embodiments, as illustrated, the engagement profile may comprise radial grooves or helical threading configured to threadably engage corresponding threading (not shown) provided on the inner radial surface of the downhole tool assembly  116 . In other embodiments, as discussed below, the engagement profile  212  may comprise non-helical grooves, dogs or other geometric features that may secure the downhole tool assembly  116  to the collet  206 . 
     The running tool  200  may further include a torque sleeve  214  disposed about the body  202  and also disposed about at least a portion of the collet  206 . The torque sleeve  214  may be configured to prevent the running tool  200  from prematurely rotating out of engagement with the downhole tool assembly  116 , and also allows an operator to transmit torque to various components run downhole with the running tool  200 , such as a completion string. As illustrated, the torque sleeve  214  may provide and otherwise define one or more arcuate cutouts  216  (one shown) at its distal end. The arcuate cutout(s)  216  may be configured to receive a corresponding one or more axial extensions  218  (one shown in dashed outline) extending from the uppermost sub (i.e., the top sub) of the downhole tool assembly  116 . Accordingly, the arcuate cutout(s)  216  may be designed and otherwise configured to receive the axial extension(s)  218 . 
     As described in greater detail below, the torque sleeve  214  may be configured to move axially with respect to the collet  206  as the running tool  200  transitions from the torque-locked position ( FIG. 2A ) to the torque-released position ( FIG. 2B ). In the torque-locked position, the axial extension(s)  218  is received within the arcuate cutout(s)  216  such that rotation of the running tool  200  correspondingly rotates the downhole tool assembly  116  as engaged at the arcuate cutout(s)  216 . Upon transitioning to the torque-released position, however, the axial extension(s)  218  may become disengaged from the arcuate cutout(s)  216 , and thereby allowing the running tool  200  to be rotated with respect to the downhole tool assembly  116 . In some embodiments, once in the torque-released position, the running tool  200  may be detached from the downhole tool assembly  116  by rotating the running tool  200  to unthread the downhole tool assembly  116  from the engagement profile  212  (e.g., threading), such as by rotating the running tool  200  via the conveyance  118  ( FIG. 1 ) from the surface  104  ( FIG. 1 ). In other embodiments, however, as described in greater detail below, the running tool  200  may be released from the downhole tool assembly  116  by placing an axial load on the connection sub  204  in the uphole direction, which may release one or more lugs, disengage a bump profile, break one or more shear pins, or any combination thereof. 
     Referring to  FIGS. 3A and 3B , with continued reference to  FIGS. 2A and 2B , illustrated are enlarged isometric views of a portion of the running tool  200 . More particularly,  FIG. 3A  depicts the torque sleeve  214  and the collet  206  arranged in the torque-locked position, and  FIG. 3B  depicts the torque sleeve  214  and the collet  206  arranged in the torque-released position. As illustrated, the body  202  may include at its distal end one or more radial protrusions  302  that extend radially outward from the outer surface of the body  202 . The radial protrusions  302  may be sized and otherwise configured to extend into the slots  210  defined between the collet fingers  208  of the collet  206 . The radial protrusions  302  may be configured to transmit torque from the body  202  to the connection sub  204 , and thereby allowing the connection sub  204  to detach (e.g., unthread) from the downhole tool assembly  116 . 
     The outer radial surface of the connection sub  204  may provide and otherwise define a plurality of splines  304  configured to engage and otherwise mate with a splined profile  306  defined on the inner radial surface of the torque sleeve  214 . The splines  304  may comprise any radial protrusion or grooved interface configured to matingly engage the splined profile  306 . Accordingly, the splines  304  and the splined profile  306  may be castellated, as shown, or may alternatively assume any polygonal design or configuration, without departing from the scope of the disclosure. In other embodiments, however, the connection sub  204  and the torque sleeve  214  may alternatively be engaged with keystock placed into corresponding grooves defined in each component part. 
     In the torque-locked position, as shown in  FIG. 3A , the splines  304  are mated with the splined profile  306  and, therefore, torque may be transferred between the connection sub  204  and the torque sleeve  214 . Moreover, as discussed above, when the running tool  200  is in the torque-locked position the axial extension  218  ( FIGS. 2A-2B ) may also be received within the arcuate cutout  216 , thereby allowing torque to be transferred between the running tool  200  and the downhole tool assembly  116  ( FIGS. 2A-2B ). 
     In the torque-released position, however, as shown in  FIG. 3B , the torque sleeve  214  is moved axially (e.g., uphole) with respect to the connection sub  204 , thereby disengaging the axial extension  218  from the arcuate cutout  216  and allowing the running tool  200  to be rotated relative to the downhole tool assembly  116 . In at least one embodiment, as mentioned above, rotating the running tool  200  relative to the downhole tool assembly  116  may detach the downhole tool assembly  116  from the running tool  200 . More particularly, a torsional load may be applied to the body  202 , such as from the conveyance  118  ( FIG. 1 ), and transferred to the connection sub  204  via the radial protrusions  302  engaging the sidewalls of the slots  210  defined between the collet fingers  208 . As the collet  206  rotates, the downhole tool assembly  116  may gradually unthread from the running tool  200  at the engagement profile  212  (e.g., threading). Once unthreaded and otherwise detached from the downhole tool assembly  116 , the running tool  200  may be retracted back uphole as connected to the conveyance  118 . 
     Referring now to  FIGS. 4A and 4B , illustrated are cross-sectional side views of the running tool  200  depicting how the running tool  200  may move from the torque-locked position to the torque-released position, according to one or more embodiments. More particularly,  FIG. 4A  depicts the running tool  200  in the torque-locked position, and  FIG. 4B  depicts the running tool  200  in the torque-released position. As illustrated, the body  202  extends substantially the entire length of the running tool  200  and includes an interior  402  that may be in fluid communication with the conveyance  118  ( FIG. 1 ) such that fluid pressure introduced into the conveyance  118  from a surface location (e.g., the earth&#39;s surface  104  of  FIG. 1 ), for example, may be transmitted to the interior  402 . The connection sub  204  is depicted as being positioned about the body  202 , and the torque sleeve  214  is depicted as being positioned about the body  202  and at least partially about the connection sub  204 , as generally described above. 
     As illustrated, the running tool  200  may further include a housing cylinder  404  and a piston  406 . The housing cylinder  404  may be disposed about the body  202  and positioned at least partially beneath the torque sleeve  214 . The piston  406  may interpose the body  202  and the housing cylinder  404  and may be axially movable with respect to the body  202  and the housing cylinder  404  within a piston chamber  408  cooperatively defined by the body  202  and the housing cylinder  404 . The piston  406  may also be operatively coupled to the torque sleeve  214  such that axial movement of the piston  406  correspondingly moves the torque sleeve  214  in a similar axial direction. More particularly, one or more pins  410  (two shown) may extend between the torque sleeve  214  and the piston  406  and through a corresponding one or more axial slots  412  (two shown) defined in the housing cylinder  404 . Accordingly, axial movement of the piston  406  within the piston chamber  408  correspondingly moves the torque sleeve  214  as the pins  410  translate within the axial slots  412 . 
     To move the piston  406 , and thereby move the running tool  200  from the torque-locked position ( FIG. 4A ) to the torque-released position ( FIG. 4B ), the fluid pressure within the interior  402  may be increased. In some embodiments, as illustrated in  FIG. 4B , a wellbore projectile  414 , such as a ball, a plug, or a dart, may be introduced into the conveyance  118  ( FIG. 1 ) and pumped to the running tool  200  until locating and landing on a seat  416  provided and otherwise defined within the interior  402  of the body  202 . Once landed on the seat  416 , the wellbore projectile  414  may form a seal within the interior  402  that prevents fluid migration further downhole and past the axial location of the seat  416 . As a result, with the wellbore projectile  414  properly landed on the seat  416 , the fluid pressure within the interior  402  may be increased. 
     In other embodiments, however, the fluid pressure within the interior  402  may be increased by other means or methods, without departing from the scope of the disclosure. For example, a wellbore projectile may be landed on a seat or shoulder located further below the running tool  200  and thereby effectively preventing fluid migration further downhole and allowing fluid pressure within the interior of  402  to be increased. In yet other embodiments, a valve (not shown) may be located at a location downhole from the downhole tool  116  below the running tool  200 . The valve may be run downhole in a closed position or otherwise closed prior to applying pressure. 
     Increasing the pressure within the interior  402  may correspondingly increase the pressure within a pressure cavity  419 . More particularly, one or more pressure ports  418  (three shown) may be defined in the body  202  and facilitate fluid communication between the interior  402  and the pressure cavity  419 , which may comprise a section of the piston chamber  408  located downhole from the piston  406 . Opposing seals  420 , such as O-rings or the like, may be positioned at the interface between the piston  406  and the housing cylinder  404  (i.e., seal  420   a ) and the interface between the piston  406  and the body  202  (i.e., seal  420   b ). The seals  420   a,b  may prevent fluid migration past the interfaces and, more importantly, may allow the pressure cavity  419  to be pressurized via the pressure ports  418 . 
     The piston  406  may be coupled to the housing cylinder  404  with one or more shearable devices  422  (two shown), such as shear pins, shear screws, or other similar shearing devices, and the shearable devices  422  may be configured to shear and otherwise fail upon assuming a predetermined axial load. Once the shearable devices  422  fail, the piston  406  may be free from engagement with the housing cylinder  404  and, therefore, free to move axially within the piston chamber  408 . 
     With reference to  FIG. 4B , the wellbore projectile  414  is shown as having landed on the seat  416 , at which point the pressure within the interior  402  may be increased. Increasing the pressure within the interior  402  may correspondingly increase the pressure within the pressure cavity  419  via the pressure ports  418 , and an increased pressure within the pressure cavity  419  may result in an axial load being applied on the piston  406  in the uphole direction (i.e., to the left in  FIGS. 4A and 4B ). Further increasing the fluid pressure may correspondingly increase the axial load assumed by the piston  406  until the predetermined axial load of the shearable devices  422  is met or exceeded, at which point the shearable devices  422  may fail and the piston  406  may then be free from engagement with the housing cylinder  404  and, therefore, may be free to move axially uphole within the piston chamber  408 . As the piston  406  moves axially uphole, the torque sleeve  214  may correspondingly move in the same direction as coupled to the piston  406  via the pins  410 , and thereby transitioning the running tool  200  to the torque-released position. 
     The running tool  200  may further include an upper locking mechanism  424   a  disposed between the piston  406  and the cylinder housing  404 . The upper locking mechanism  424   a  may be configured to secure the piston  406  in the torque-released position. In at least one embodiment, the upper locking mechanism  424   a  may comprise a body lock ring that includes a plurality of ramped teeth  426  defined on its inner radial surface. The piston  406  may likewise define a plurality of ramped teeth  428  on its outer radial surface, and the ramped teeth  428  may be configured to engage the ramped teeth  426  of the upper locking mechanism  424   a . As the piston  406  moves uphole within the piston chamber  408 , as described above, the ramped teeth  426 ,  428  may come into contact with each other. The ramped teeth  426 ,  428  may be angled such that movement of the piston  406  in the uphole direction is allowed and otherwise ratchets the piston  406  in the uphole direction. The ramped teeth  426 ,  428 , however, may further be angled such that movement of the piston  406  in the downhole direction is substantially prevented. Accordingly, once the running tool  200  moves to the torque-released position, as shown in  FIG. 4B , transitioning back to the torque-locked position is prohibited. 
     As indicated above, once the running tool  200  is in the torque-released position, as shown in  FIGS. 2B, 3B, and 4B , the running tool  200  may be detached from the downhole tool assembly  200 . In the illustrated embodiment, for example, the running tool  200  may be rotated with respect to the downhole tool assembly  116  ( FIGS. 2A-2B ) to thereby unthread the downhole tool assembly  116  from the running tool  200 . Once the downhole tool assembly  116  is unthreaded or otherwise detached from the running tool  200 , the running tool  200  may then be retracted to the surface  104  ( FIG. 1 ) as attached to the conveyance  118  ( FIGS. 2A-2B ). In some embodiments, however, the preceding method of unthreading the running tool  200  from the downhole tool assembly  116  may comprise a contingency or secondary method of detaching the running tool  200  from the downhole tool assembly  116 . According to the present disclosure, the running tool  200  may be alternatively detached from the downhole tool assembly  116  by increasing the fluid pressure on the exterior of the running tool  200  and, more particularly, within the annulus  122  ( FIG. 1 ) defined between the running tool  200  and a wall of the wellbore  106  ( FIG. 1 ). This process is described below in conjunction with  FIG. 5 . 
     Referring now to  FIG. 5 , with continued reference to the prior figures, illustrated is another cross-sectional side view of the running tool  200 , according to one or more embodiments. As illustrated, the running tool  200  may further include a connection sub piston  502  disposed about the body  202  and interposing the body  202  and the connection sub  204 . The connection sub piston  502  may be configured to radially support the connection sub  204  and may be axially movable between a supported position, where the connection sub piston  502  radially supports the collet fingers  208 , for example, and an unsupported position, where the connection sub piston  502  is moved axially so that at least a portion of the collet fingers  208  is no longer radially supported.  FIGS. 4A and 4B  depict the connection sub piston  502  in the supported position, and  FIG. 5  shows the connection sub piston  502  after having transitioned to the unsupported position. 
     The running tool  200  may further include a lower locking mechanism  424   b  disposed and otherwise arranged between the connection sub piston  502  and the cylinder housing  404 . The lower locking mechanism  424   b  may be configured to secure the connection sub piston  502  against axial movement in the downhole direction (i.e., away from the piston  406 ) in both the supported and unsupported positions. More specifically, and with reference again to  FIG. 4B , increasing the pressure within the interior  204  and, therefore, within the pressure cavity  419  may not only place an axial load on the piston  406 , as generally described above, but may also place an axial load on the connection sub piston  502  in the opposite direction. Similar to the upper locking mechanism  424   a , the lower locking mechanism  424   b  may comprise a body lock ring that includes a plurality of ramped teeth  504  defined on its inner radial surface. The connection sub piston  502  may likewise define a plurality of ramped teeth  506  on its outer radial surface, and the ramped teeth  506  of the connection sub piston  502  may be configured to engage the ramped teeth  504  of the lower locking mechanism  424   b  in both the supported and unsupported positions. 
     The ramped teeth  504 ,  506  may be angled such that movement of the connection sub piston  502  in the uphole direction (i.e., toward the piston  406 ) allows the connection sub piston  502  to ratchet in the uphole direction. The ramped teeth  504 ,  506 , however, may be angled such that movement of the connection sub piston  502  in the downhole direction relative to the lower locking mechanism  424   b  is substantially prevented. Accordingly, in the supported position, as shown in  FIG. 4B , the engagement between the ramped teeth  504 ,  506  prevents the connection sub piston  502  from moving in the downhole direction, even upon assuming the axial load derived from the pressure increase in the pressure chamber  419 . In moving the connection sub piston  502  to the unsupported position, as shown in  FIG. 5 , the ramped teeth  506  of the connection sub piston  502  may ratchet against the ramped teeth  504  of the lower locking mechanism  424   b  as the connection sub piston  502  moves in the uphole direction. Once in the unsupported position, the angled engagement of the ramped teeth  504 ,  506  may then prevent movement of the connection sub piston  502  in the downhole direction. 
     Those skilled in the art will readily appreciate this advantage. The running tool  200  is prevented from releasing the downhole tool assembly  116  until the torque lock feature is unlocked. Annulus pressure can be applied outside the tool and will not affect the release mechanism until the torque lock is unlocked. The piston abuts and blocks the axial movement of the sub piston  502  while in the torque locked position. The advantage is that annular pressure can be applied without releasing the running tool. For instance, during run-in and before internal pressure is applied, annular pressure can be applied to test position of seals in a seal bore below the downhole tool assembly  116  or activate a valve in the completion below the downhole tool assembly  116 , or activate a tool attached to the tool assembly  116 , or set another packer. More particularly, during run-in and while the running tool  200  transitions between the torque-locked and torque-released positions, as described above, the connection sub piston  502  may be engaged at the lower locking mechanism  424   b  so that it is prevented from axially moving in the downhole direction with respect to the connection sub  204  or the body  202 . This may prove advantageous if the pressure within the interior  402  is inadvertently increased or a pressure spike is unexpectedly experienced, which may act on the connection sub piston  502  via the pressure ports  418 . Conventional running tools are often configured to release from the downhole tool assembly  116  ( FIGS. 2A-2B ) by pressurizing the interior  204 , which could be problematic upon assuming unexpected pressure spikes that may result in the premature detachment of the downhole tool assembly  116 . The running tool  200  of the present disclosure, however, includes the lower locking mechanism  424   b , which effectively prevents the running tool  200  from detaching from the downhole tool assembly  116  upon assuming unexpected (or expected) or inadvertent pressure spikes in the interior  402  of the running tool  200 . 
     Rather, to release the running tool  200  from the downhole tool assembly  116 , and otherwise move the connection sub piston  502  to the unsupported position, the fluid pressure on the exterior of the running tool  200  may be increased. More particularly, the pressure within the annulus  122  ( FIG. 1 ) defined between the running tool  200  and a wall of the wellbore  106  ( FIG. 1 ) may be increased. Increasing the pressure within the annulus  122  may be facilitated, in at least one embodiment, by setting a packer (not shown) or another type of wellbore isolation device within the annulus  122  below the running tool  200 . The pressure increase may then be accomplished by pressurizing the annulus  122  from the surface  104  ( FIG. 1 ) or from an intermediate location in the wellbore  106 . 
     Increasing the pressure outside of the running tool  200  may generate a pressure differential across the running tool  200 , and more particularly, across the connection sub piston  502 . The pressure differential may serve to move the connection sub piston  502  axially within the piston chamber  408  (i.e., the pressure cavity  419 ) toward the piston  406  and toward the unsupported position. In some embodiments, however, the connection sub piston  502  may be secured to the collet  206  using one or more shearable devices  508 , such as shear pins or shear screws. The shearable devices  508  (two shown) may be configured to shear and otherwise fail upon assuming a predetermined axial load. Increasing the pressure outside of the running tool  200  may generate the pressure differential across the connection sub piston  502 , and such a pressure differential may result in an axial load being applied on the connection sub piston  502  in the uphole direction. Further increasing the annulus  122  pressure may correspondingly increase the axial load assumed by the connection sub piston  502  until the predetermined axial load of the shearable devices  508  is met or exceeded. When the predetermined axial load of the shearable devices  508  is met or exceeded, the shear pins/screws may fail and the connection sub piston  502  may then be free from engagement with the connection sub  204  and, therefore, free to move axially with respect to the body  202  and the connection sub  204  to the unsupported position. 
     As the connection sub piston  502  moves to the unsupported position, as mentioned above, the ramped teeth  506  of the connection sub piston  502  may ratchet against the ramped teeth  504  of the lower locking mechanism  424   b . Once in the unsupported position, however, the angled engagement of the ramped teeth  504 ,  506  may prevent movement of the connection sub piston  502  in the downhole direction and otherwise back to the supported position. 
     With the connection sub piston  502  in the unsupported position, the distal end of the connection sub  204  becomes unsupported. In the illustrated embodiment, the ends of the collet fingers  208  may no longer be radially supported by the connection sub piston  502  upon moving to the unsupported position. As a result, any tension or load applied on the running tool  200  in the uphole direction may result in the collet fingers  208  being able to flex radially inward and ratchet out of engagement with the downhole tool assembly  116  ( FIGS. 2A-2B ). In such embodiments, the engagement profile  212  defined on the ends of the collet fingers  208  may comprise ramped dogs, lugs, keys, or other ramped geometric features that may allow the collet fingers  208  to flex radially inward and out of engagement with the downhole tool assembly  116  upon assuming an axial load (i.e., tension). With the running tool  200  detached from the downhole tool assembly  116 , the running tool  200  may then be pulled out of the wellbore  106  ( FIG. 1 ) and otherwise in the uphole direction on the conveyance  118  ( FIG. 1 ). 
     Referring now to  FIGS. 6A-6F , illustrated are partial cross-sectional side views of exemplary releasable connections  600 , shown as releasable connections  600   a ,  600   b ,  600   c ,  600   d ,  600   e , and  600   f , respectively, according to one or more embodiments. Like reference numerals used in prior figures correspond to similar components or elements that may not be described again in detail. Any of the releasable connections  600   a - f  may replace the collet  206  of  FIGS. 2A-2B, 3A-3B, 4A-4B, and 5 , and may otherwise be arranged at the distal end of the connection sub  204 . As illustrated, each releasable connection  600   a - f  may facilitate and provide a releasable connection or coupling engagement between the connection sub  204  (and therefore the running tool  200 ) and the downhole tool assembly  116 . 
     In  FIGS. 6A and 6B , the releasable connections  600   a  and  600   b , respectively, may be substantially similar to the collet  206  of  FIGS. 2A-2B, 3A-3B, 4A-4B, and 5 . For instance, each releasable connection  600   a,b  may include the plurality of axially extending collet fingers  208  separated by the axially extending slots  210  (not shown). Moreover, each releasable connection  600   a,b  may further include an engagement profile configured to mate with a corresponding engagement profile defined on the inner radial surface of the downhole tool assembly  116 . In  FIG. 6A , for instance, an engagement profile  602  of the releasable connection  600   a  may comprise a single bump profile configured to engage a corresponding engagement profile  604  defined on the inner radial surface of the downhole tool assembly  116 . Moreover, in  FIG. 6B , an engagement profile  606  of the releasable connection  600   b  may comprise a multi-bump profile configured to engage a corresponding engagement profile  608  defined on the inner radial surface of the downhole tool assembly  116 . 
     As depicted in  FIGS. 6A and 6B , the connection sub  204  is in the supported position, where the connection sub piston  502  radially supports the collet fingers  208 . Upon transitioning the connection sub  204  to the unsupported position, however, the connection sub piston  502  is moved axially in the uphole direction (i.e., to the left in  FIGS. 6A-6F ) so that at least a portion of the collet fingers  208  is no longer radially supported, as generally described above. As a result, any tension or load applied on the running tool  200  in the uphole direction may result in the collet fingers  208  being able to flex radially inward and ratchet the engagement profiles  602 ,  606  out of engagement with the corresponding engagement profiles  604 ,  608 , respectively. As illustrated, the engagement profiles  602 ,  606  and the corresponding engagement profiles  604 ,  608  may provide angled opposing surfaces that help the collet fingers  208  flex radially inward to ratchet out of engagement with the downhole tool assembly  116 . 
     In  FIGS. 6C-6E , the releasable connections  600   c ,  600   d , and  600   e , respectively, may each include one or more lugs  610  spaced circumferentially about the connection sub  204  and, more particularly, about the distal end of the connection sub piston  502 . Each of the lugs  610  may provide an engagement profile on its outer radial surface configured to mate with a corresponding engagement profile defined on the inner radial surface of the downhole tool assembly  116 . More particularly, the lugs  610  in  FIG. 6C  may provide an engagement profile  612  that may comprise radial grooves or threading configured to engage a corresponding engagement profile  614  that may comprise corresponding grooves or threading  614 . The lugs  610  in  FIG. 6D  may provide an engagement profile  616  that may comprise single bump profile configured to engage a corresponding engagement profile  618  that may comprise a radial protrusion defined on the inner radial surface of the downhole tool assembly  116 . Lastly, the lugs  610  in  FIG. 6E  may provide an engagement profile  620  that may comprise a multi-bump profile configured to engage a corresponding engagement profile  622  that may comprise radial protrusions defined on the inner radial surface of the downhole tool assembly  116 . 
     As depicted in  FIGS. 6C-6E , the connection sub  204  is in the supported position, where the connection sub piston  502  radially supports the lugs  610 . Upon transitioning the connection sub  204  to the unsupported position, however, the connection sub piston  502  is moved axially in the uphole direction so that the lugs  610  are no longer radially supported. As a result, any tension or load applied on the running tool  200  in the uphole direction may result in the lugs  610  being able to fall or move radially inward and out of engagement with the downhole tool assembly  116 . In  FIG. 6C , the lugs  610  may alternatively be able to be unthreaded from the corresponding engagement profile  614 . 
     In  FIG. 6F , the releasable connections  600   f  may include one or more shearable devices  624  that couple the downhole tool assembly to the connection sub  204 . The connection sub  204  is depicted in  FIG. 6F  in the supported position, where the shearable devices  624  are intact and received within corresponding holes  626  defined in the connection sub  204 . Upon transitioning the connection sub  204  to the unsupported position, however, the shearable devices  624  will fail and otherwise be sheared, and thereby detaching the connection sub  204 , and therefore the running tool  200 , from the downhole tool assembly  116 . 
     Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 
     As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.