DOWNHOLE TOOL INCLUDING A MOVABLE ELEMENT COUPLED TO A DEPLOYMENT PISTON VIA A SHEAR FEATURE

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application Serial No. 63/740,874, filed on December 31, 2024, entitled “LUBRICATOR VALVES WHEN USED WITH AN EMOTION TO ENSURE THEY ARE PERMANENTLY OPEN, PARTICULARLY FOR CCUS APPLICATIONS,” commonly assigned with this application and incorporated herein by reference in its entirety.

BACKGROUND

It is well known in the subterranean well drilling, formation, and storage arts that many types of downhole tools are responsive to pressure, either in the annulus or in the tool string. For example, different types of tools for performing drill stem testing operations are responsive to either tubing or annulus pressure, or to a differential therebetween. Additionally, other downhole tools, such as safety valves, flow valves, interval control valves (ICVs) or drill string drain valves, among others, may be responsive to such a pressure differential.

Such well tools typically have some member, such as a deployment piston, which moves in response to the selected pressure stimuli, which is also coupled to a movable element (e.g., actuation device) of one form or fashion. The deployment piston can be driven back and forth within a deployment piston chamber by fluid pressure for a predetermined number of reciprocations to exert pressure on the movable element (e.g., actuation device), after which a responsive downhole tool may be actuated in a way intended by its design.

BRIEF DESCRIPTION

Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

FIG. 1 is a well system designed, manufactured, and/or operated according to one or more embodiments of the disclosure;

FIGS. 2A through 2F illustrate various different views of a downhole tool designed, manufactured and/or operated according to one or more embodiments of the disclosure; and

FIGS. 3A through 3L illustrate various different cross-sectional views of a downhole tool, including the deployment piston and movable element (e.g., actuation device, such as a deployment piston mandrel) of FIGS. 2A through 2F, at various different states of deployment.

DETAILED DESCRIPTION

In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.

Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. Furthermore, unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally toward the surface of the subterranean formation; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” “downstream,” or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. Additionally, unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

Various values and/or ranges are explicitly disclosed in certain embodiments herein. However, values/ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited. Similarly, values/ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited. In the same way, values/ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are 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 even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. Similarly, an individual value disclosed herein may be combined with another individual value or range disclosed herein to form another range.

The term “substantially XYZ,” as used herein, means that it is within 10 percent of perfectly XYZ. The term “significantly XYZ,” as used herein, means that it is within 5 percent of perfectly XYZ. The term “ideally XYZ,” as used herein, means that it is within 1 percent of perfectly XYZ. The monicker “XYZ” could refer to parallel, perpendicular, alignment, or other relative features disclosed herein.

The present disclosure has acknowledged that deployment pistons, such as floating pistons, are often driven within a deployment piston chamber defined by a housing and a moveable element (e.g., inner tube mandrel) of a downhole tool. The deployment piston is operated by a first control fluid on one side of the deployment piston chamber and a second control fluid on the other side of the deployment piston chamber to create a pressure force against a deployment piston coupled to a movable element (e.g., an actuation device) that can manipulate a downhole feature, such as a flow valve, to an open position or a closed position. The deployment piston, in one or more embodiments, includes seals located about its outer perimeter that seal against the housing and the moveable element (e.g., inner tube mandrel) of a downhole tool.

While these seals typically perform within operating parameters in traditional downhole applications, the present disclosure has recognized for the first time that such seals often do not perform within operating parameters in low temperature operations, such as what may occur in carbon capture, utilization and storage (CCUS) applications. Specifically, the present disclosure has recognized that certain of the seals may be compromised during the low temperature situations that occur within CCUS applications, and if/when this occurs the movable element (e.g., actuation device, such as a flow valve, including without limitation a ball-type valve, interval control valve (ICV), etc.) may unintentionally open or close. If all of the seals were to be simultaneously compromised, the deployment piston located within the deployment piston chamber would not move, however, if the seal associated with the close line alone were to leak, the movable element (e.g., actuation device, such as a flow valve, ball-type valve, interval control valve (ICV), etc.) could start to close, or vice versa if the seal associated with the open line alone were to leak. Similarly, the present disclosure has recognized that the rapid temperature changes that may occur in downhole applications (e.g., particularly CCUS applications) may rapidly expand/contract the fluid within the fixed piston chamber (e.g., within one side of the piston chamber more so the other), which may also cause the movable element to unintentionally move in one direction or another. In CCUS applications, the unintentional moving (e.g., closing) of the movable element (e.g., actuation device, such as a flow valve, ball-type valve, interval control valve (ICV), etc.) could be catastrophic, whether it be as a result of the aforementioned leaking seals and/or rapid expansion/contraction of the fluid within the fixed piston chamber. Notwithstanding the foregoing, the inventive aspects of the present disclosure may be used in higher temperature operations, and thus are not limited to the low temperature operations disclosed above.

Based upon the foregoing, the present disclosure places a shear feature (e.g., shear ring, shear pin, etc.) between the deployment piston and the movable element (e.g., actuation device) to address one or more of the aforementioned concerns. The shear ring can have a variety of different shear values, for example depending on the design of the downhole tool. The shear ring, however, would need to have a shear value less than a greatest amount of pressure that may be applied to the piston, or else it would never shear. Notwithstanding, in at least one embodiment, the shear ring has a shear value of 133 Kilonewtons (KN) (e.g., about 30,000 pound-force (lbf)) or less. In even yet another embodiment, the shear ring has a shear value of 122 KN (e.g., about 27,500 lbf) or less. In yet another embodiment, the shear ring has a shear value ranging from 22 KN (e.g., about 5,000 lbf) to 111 KN (e.g., 25,000 lbf), if not from 45 KN (e.g., about 10,000 lbf) to about 89 KN (e.g., about 20,000 lbf), if not from 56 KN (e.g., about 12,500 lbf) to 78 KN (e.g., about 17,500 lbf). Accordingly, the deployment piston and movable element (e.g., actuation device) may be operated at lower pressures, while at the same time if there is a desire for the movable element (e.g., actuation device) to remain in a fixed position, a higher pressure could be applied to the deployment piston, thereby shearing the shear feature, and thus detaching the deployment piston from the movable element (e.g., actuation device). For example, in at least one embodiment, the deployment piston and movable element (e.g., actuation device) could have an actuation fluid pressure (e.g., an opening and/or closing pressure) at or below X, wherein X is 20.7 MPa (e.g., ranging from 6.9 MPa to 19.3 MPa, if not from 8.3 MPa to 17.9 MPa, if not from 9.7 MPa psi to 16.5 MPa, if not from 11.0 MPa to 15.2 MPa, if not from 12.4 MPa to 13.8 MPa). In this embodiment, the shear feature might have a shear value equal to an applied shear fluid pressure that is at least 1.1X of the needed actuation fluid pressure (e.g., an opening and/or closing pressure) (e.g., if not at least 1.2X, if not at least 1.4X, if not at least 1.6X, if not at least 1.67X, if not at least 1.8X, if not at least 2.0X, if not at least 2.25X, if not at least 2.5X, if not at least 3.0X, if not at least 4.0X, if not ranging from 1.2X to 1.67X). For example, in at least one embodiment the activation fluid pressure might be about 20.7 MPa (e.g., about 3000 psi), whereas the shear fluid pressure might range from 24.8 MPa (e.g., 3600 psi) to 34.5 MPa (e.g., 5000 psi) .

In the above embodiments, so long as the applied fluid pressure remains above the chosen activation fluid pressure, but below the shear fluid pressure, the deployment piston and movable element (e.g., actuation device) will continue to move together back and forth as necessary. However, the act of applying a pressure equal to or greater than the shear fluid pressure, would shear the shear feature, and thereby decouple the two, thereby allowing the movable element (e.g., actuation device) to remain in a fixed position, regardless of any pressures being applied to the deployment piston. In CCUS applications, the shearing of the shear feature could occur after the downhole tool is downhole, the movable element (e.g., actuation device) is in the open position, and just prior to the CCUS injection. In at least one embodiment, a retention mechanism, such as a collet feature, could be used to maintain the movable element in the open position once the shear feature and the movable element (e.g., actuation device) have decoupled from one another.

In one or more embodiments, the shearing operation could also release a radio-frequency identification device (RFID), as the deployment piston could move a bit (e.g., move up a bit) and release something. It should be noted that the movable element (e.g., actuation device) may require a minor redesign to allow for overtravel, which may occur due to the shearing of the shear feature. Furthermore, the addition of the shear feature may allow for the use of cheaper and/or less effective seals when used with the low temperature operations disclosed above.

FIG. 1 illustrates a well system 100 designed, manufactured and/or operated according to one or more embodiments of the disclosure, the well system including a downhole tool 102 including one or more innovating features disclosed herein. The well system 100, in the illustrated embodiment, includes a wellbore 110 (e.g., submerged oil/gas wellbore), in addition to a flow valve 115 and one or more sand screens 120. The downhole tool 102, in one or more embodiments, will be connected to a tubular string 125 that extends from the surface of the wellbore 110 to at least an injection/production zone 130 of the wellbore 110. In FIG. 1, an example of one type of operating environment in which the downhole tool 102 may be implemented is a platform 135 (e.g., offshore platform) positioned over the wellbore 110 located in the sea floor 140, with the wellbore 110 penetrating the injection/production zone 130 (e.g., one or more subterranean formations). In the illustrated embodiment, the wellbore 110 is shown to be lined with casing 145 (e.g., steel casing), which is cemented into place.

In the illustrated embodiment, a sub-sea conduit 150 extends from a deck 135a of the platform 135 into a wellhead 155 (e.g., sub-sea wellhead), which includes blowout preventer 160. In the illustrated embodiment, the platform 135 carries a derrick 165 thereon, as well as a hoisting apparatus 170, and a pump 175 that communicates with the wellbore 110 by a way of a control conduit 180 and extends below blowout preventer 160. The downhole tool 102 is shown disposed in the wellbore 110 with the blowout preventer 160 closed thereabout. In the illustrated embodiment, testing string 185 extends downward from the platform 135 to the wellhead 155, where a hydraulically operated test tree 190 may be located.

The tubular string 125, in the illustrated embodiment, extends downhole to the downhole tool 102, as discussed below. The downhole tool 102, in one or more embodiments, includes a control module (e.g., an eMotion® module as might be obtained from Halliburton, Inc.) coupled to a movable element (e.g., valve assembly, such as an actuation/device/lubricator valve, for example including a ball-type valve in one embodiment) via a pup joint. The downhole tool 102, and more particularly the movable element, in one or more embodiments may include the shear feature disclosed above, such that it may reliably be used in CCUS applications.

Turning to FIGS. 2A through 2F, illustrated are various different views of a downhole tool 200 designed, manufactured and/or operated according to one or more embodiments of the disclosure. The downhole tool 200, in at least the disclosed embodiment, includes a control module 210, a pup joint 220, and a movable element assembly 230 (e.g., valve assembly). In at least one embodiment, the control module 210 is an eMotion® module, and may have a bypass line 212, a control line 214 to a close port of the movable element assembly 230 (e.g., valve assembly), and a control line 216 to an open port of the movable element assembly 230 (e.g., valve assembly).

The movable element assembly 230 (e.g., valve assembly), in one or more embodiments, may include a housing 232 (e.g., hydraulic housing). The housing 232 may comprise many different housings and remain within the scope of the disclosure. The movable element assembly 230, in one or more additional embodiments, may further include a movable element 234 positioned about the housing 232. In at least one embodiment, the movable element 234 is configured to move between an uphole position and a downhole position, as further discussed below. The term “movable element,” as used herein with respect to this feature, may include any structure, including tubular members and non-tubular members, which may move within the downhole tool 200. The term “about,” as used herein with regard to this feature, means adjacent in a way that would allow the moveable element 234 to move in relation to the housing 232.

The movable element assembly 230, in at least one other embodiment, may further include a deployment piston 236 positioned within a deployment piston chamber 238 located between the movable element 234 and the housing 232. In the illustrated embodiment, the movable element 234 and the housing 232 form the deployment piston chamber 238. In the illustrated embodiments, the deployment piston 236 is shearingly fixed with the movable element 234 via a shear feature 240. As discussed above, the shear feature 240 allows the deployment piston 236 to disconnect from the movable element assembly 230 (e.g., valve assembly) at a desired point in time. In accordance with one or more embodiments, the downhole tool 200, and more particularly the movable element assembly 230, is set up such that: 1) the deployment piston 236 is configured to move the movable element 234 between the uphole position and the downhole position upon receiving a lower actuation fluid pressure on an uphole side or a downhole side thereof; and 2) the shear feature 240 is configured to shear and thereby release the movable element 234 from the deployment piston 236 upon receiving a greater shear fluid pressure on the uphole side or the downhole side of the deployment piston 236. The terms “lower” and “greater,” as used herein with regard to the fluid pressures, are in relation to one another. No specific values are applied to the terms “lower” and “greater,” other than the actuation fluid pressure is less than the shear fluid pressure, and the shear fluid pressure is more than the actuation fluid pressure.

Further to the above embodiment, the movable element assembly 230 may additionally include an actuatable feature 250 (e.g., ball-type valve) coupled to one or the other of the moveable element 234 or the deployment piston 236. In at least one other embodiment, the movable element assembly 230 optionally includes one or more of the following additional elements: body joints 260, a bumper sub system 265, seal groove(s) 270, seal(s) 275, a ball housing 280, and a retention mechanism 285 (e.g., a collet feature). In at least one embodiment, the retention mechanism 285 (e.g., a collet feature) engages with a profile 290 in the housing 232 to fix the movable element 234 in the downhole position after the shear feature 240 has sheared.

In one or more other embodiments, the movable element assembly 230 (e.g., valve assembly) includes less than all of the elements described above, but does at least include the housing 232 (e.g., hydraulic housing), movable element 234 (e.g., actuation device, such as a deployment piston mandrel), deployment piston 236, deployment piston chamber 238, and shear feature 240. For example, the inventive aspects of the disclosure could be used with any piston/sliding sleeve design (e.g., one that uses an alternative barrier device than a ball-type valve to seal) that a user wants certain functionality to begin with, but after a specific period of time wants the deployment piston and/or movable element to decouple from one another (e.g., to decouple the barrier device’s hydraulic based operability).

Turning now to FIGS. 3A through 3L, illustrated are various different cross-sectional views of a downhole tool 300, including the deployment piston 236 and movable element 234 (e.g., actuation device, such as a deployment piston mandrel) of FIGS. 2A through 2F, at various different states of deployment. The downhole tool 300 is similar in many respects to the downhole tool 200. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. FIGS. 3A and 3B illustrate different cross-sectional views the downhole tool 300 in an initial state (e.g., run-in-hole state). In this state, the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) is in an uphole position, and the deployment piston 236 is axially fixed with the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) via the shear feature 240. For example, in this position, the actuatable feature 250 (e.g., ball-type valve) may be in the closed state.

FIGS. 3C and 3D illustrate different cross-sectional views the downhole tool 300 of FIGS. 3A and 3B, after a first lower actuation fluid pressure 310 is applied to an uphole side of the deployment piston 236, thereby moving the deployment piston 236 and the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) downhole. Again, the first lower actuation fluid pressure 310 applied to the deployment piston 236 transfers to the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) via the shear feature 240. In the illustrated embodiment, the movement of the deployment piston 236 and movable element 234 (e.g., actuation device, such as a deployment piston mandrel) may move the actuatable feature 250 (e.g., ball-type valve) to its open state.

FIGS. 3E and 3F illustrate different cross-sectional views the downhole tool 300 of FIGS. 3C and 3D, after a second lower actuation fluid pressure 320 is applied to a downhole side of the deployment piston 236, thereby moving the deployment piston 236 and the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) uphole. Again, the second lower actuation fluid pressure 320 applied to the deployment piston 236 transfers to the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) via the shear feature 240. In the illustrated embodiment, the movement of the deployment piston 236 and movable element 234 (e.g., actuation device, such as a deployment piston mandrel) may move the actuatable feature 250 (e.g., ball-type valve) at least partially or fully back to its closed state. The first and second lower actuation fluid pressures 310, 320 applied in the steps shown in FIGS. 3A through 3F are below the shear value of the shear feature 240.

FIGS. 3G and 3H illustrate different cross-sectional views the downhole tool 300 of FIGS. 3E and 3F, after the first lower actuation fluid pressure 310 is again applied to an uphole side of the deployment piston 236, thereby again moving the deployment piston 236 and the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) downhole. Again, the first lower actuation fluid pressure 310 applied to the deployment piston 236 transfers to the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) via the shear feature 240. In the illustrated embodiment, the movement of the deployment piston 236 and movable element 234 (e.g., actuation device, such as a deployment piston mandrel) may move the actuatable feature 250 (e.g., ball-type valve) back to its open state.

FIGS. 3I and 3J illustrate different cross-sectional views the downhole tool 300 of FIGS. 3GE and 3H, after a third greater shear fluid pressure 330 is applied, for example to an uphole side of the deployment piston 236, thereby moving the deployment piston 236 and the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) downhole, and ultimately shearing the shear feature 240. The third greater shear fluid pressure 330 may be applied to either side of the deployment piston 236 (e.g., in this embodiment on the uphole side of the deployment piston 236) after any number of the lower actuation fluid pressure 310, 320 applications (e.g., whether being applied to the uphole or downhole side of the deployment piston 236). The third greater shear fluid pressure 330 is greater than the shear value of the shear feature 240, thus the reason for the shear feature 240 shearing. At this stage, no amount of pressure applied to the deployment piston 236 will move the movable element 234 (e.g., actuation device, such as a deployment piston mandrel), for example as they are no longer axially coupled together. Accordingly, leaks that may arise in the seals surrounding the deployment piston 236, for example because of the low temperatures associated with the CCUS application, will ultimately have no effect on the position of the movable element 234 (e.g., actuation device, such as a deployment piston mandrel).

Of note, in one or more embodiments, the downhole tool 300 may include the retention mechanism 285, such as a collet feature. The retention mechanism 285, in this embodiment, may be used to keep the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) in the downhole state, and thus keep the actuatable feature 250 (e.g., ball-type valve) in its open state.

FIGS. 3K and 3L illustrate different cross-sectional views the downhole tool 300 of FIGS. 3I and 3J, after any pressure (e.g., whether above or below the shear value of the shear feature) is applied to the downhole side of the deployment piston 236, thereby moving the deployment piston 236. Again, as shown, the movement of the deployment piston 236 has no effect on the location of the movable element 234 (e.g., actuation device, such as a deployment piston mandrel).

Given the foregoing, it should be readily apparent how the shear feature 240 may be used to originally connect, and subsequently release, the movable element 234 (e.g., actuation device, such as a deployment piston mandrel) and the deployment piston 236 from one another. Accordingly, the shear feature 240 may be used to address the problems discussed above.

Aspects disclosed herein include:

A. A downhole tool, the downhole tool including: 1) a housing; 2) a movable element positioned about the housing, the movable element configured to move between an uphole position and a downhole position; and 3) a deployment piston positioned within a deployment piston chamber located between the movable element and the housing, the deployment piston shearingly fixed with the movable element via a shear feature, wherein: a) the deployment piston is configured to move the movable element between the uphole position and the downhole position upon receiving a lower actuation fluid pressure on an uphole side or a downhole side thereof; and b) the shear feature is configured to shear and thereby release the movable element from the deployment piston upon receiving a greater shear fluid pressure on the uphole side or the downhole side of the deployment piston.

B. A method, the method including: 1) accessing a wellbore extending through one or more subterranean formations, the wellbore having a downhole tool located therein, the downhole tool including: a) a housing; b) a movable element positioned about the housing, the movable element configured to move between an uphole position and a downhole position; and c) a deployment piston positioned within a deployment piston chamber located between the movable element and the housing, the deployment piston shearingly fixed with the movable element via a shear feature, wherein: i) the deployment piston is configured to move the movable element between the uphole position and the downhole position upon receiving a lower actuation fluid pressure on an uphole side or a downhole side thereof; and ii) the shear feature is configured to shear and thereby release the movable element from the deployment piston upon receiving a greater shear fluid pressure on the uphole side or the downhole side of the deployment piston; and 2) applying the greater shear fluid pressure on the uphole side or the downhole side of the deployment piston to release the movable element from the deployment piston.

C. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool located in the wellbore, the downhole tool including: a) a housing; b) a movable element positioned about the housing, the movable element configured to move between an uphole position and a downhole position; and c) a deployment piston positioned within a deployment piston chamber located between the movable element and the housing, the deployment piston shearingly fixed with the movable element via a shear feature, wherein: i) the deployment piston is configured to move the movable element between the uphole position and the downhole position upon receiving a lower actuation fluid pressure on an uphole side or a downhole side thereof; and ii) the shear feature is configured to shear and thereby release the movable element from the deployment piston upon receiving a greater shear fluid pressure on the uphole side or the downhole side of the deployment piston.

Aspects A, B, and C may have one or more of the following additional elements in combination: Element 1: wherein the movable element and the housing form the deployment piston chamber. Element 2: wherein the lower activation fluid pressure required to move the movable element is X, and further wherein the greater shear fluid pressure required to shear the shear feature is at least 1.2X. Element 3: wherein the lower activation fluid pressure required to move the movable element is X, and further wherein the greater shear fluid pressure required to shear the shear feature ranges from 1.2X to 1.67X. Element 4: wherein the greater shear fluid pressure required to shear the shear feature ranges from 24.8 MPa to 34.5 MPa. Element 5: wherein the movable element is coupled to a flow valve, and further wherein the deployment piston is configured move the flow valve between a closed state and an open state upon receiving the lower actuation fluid pressure on the uphole side or the downhole side thereof. Element 6: wherein the flow valve is a ball-type valve. Element 7: further including a retention mechanism coupled to the movable element, the retention mechanism configured to stop the movable element from moving after the shear feature has sheared. Element 8: wherein the retention mechanism is a collet feature. Element 9: wherein the collet feature engages with a profile in the housing to fix the movable element in the downhole position after the shear feature has sheared. 2. Element 10: wherein the shear value is 122 Kilonewtons (KN) or less. Element 11: wherein the shear value ranges from 22 Kilonewtons (KN) to 111 Kilonewtons (KN). Element 12: wherein the shear value ranges from 45 Kilonewtons (KN) to 89 Kilonewtons (KN). Element 13: wherein the shear value ranges from 56 Kilonewtons (KN) to 78 Kilonewtons (KN).

Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments.