Downhole Tool Employing a Pressure Intensifier

This application is a continuation of U.S. patent application Ser. No. 18/407,842, entitled “DOWNHOLE TOOL EMPLOYING A PRESSURE INTENSIFIER”, filed on Jan. 9, 2024. The above-listed application IS commonly assigned with the present application is incorporated herein by reference as if reproduced herein in its entirety.

A typical downhole tool (e.g., packer, bridge plug, frac plug, anchor, etc.) generally has one or more radially extending elements that are employed to provide a fluid-tight seal or anchor radially between a mandrel of the downhole tool, and the casing or wellbore into which the downhole tool is disposed. Such a downhole tool is commonly conveyed into a subterranean wellbore suspended from tubing extending to the earth's surface.

To prevent damage to the radially extending elements of the downhole tool while the downhole tool is being conveyed into the wellbore, the radially extending elements may be carried on the mandrel in a retracted or uncompressed state, in which they are radially inwardly spaced apart from the casing. When the downhole tool is set, the radially extending elements radially expand, thereby providing the fluid-tight seal or anchor between the mandrel and the casing and/or wellbore. In certain embodiments, the radially extending elements are axially compressed between element retainers that straddle them, which in turn radially expand the radially extending elements.

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. Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well; 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. 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.

Sliding elements are traditionally a critical part of a downhole tool, such as a sealing assembly, anchoring assembly, and/or valve assembly, among others. The present disclosure, however, has recognized that when hydraulically moving the sliding elements of such downhole tools (e.g., setting the radially extending elements of a sealing assembly or anchoring assembly), the hydraulic setting force can be a design limitation. In at least one scenario, surface equipment coupled to the sliding element is limited in an amount of hydraulic setting force it can provide, and the limited amount of setting force is insufficient to fully deploy the sliding element (e.g., sealing assembly, anchoring assembly, or valve assembly). In at least one other scenario, the amount of hydraulic setting force provided downhole is intentionally reduced, so as to not prematurely shear other wellbore features (e.g., shear features, collets, etc. located within the wellbore), such as might be the case if too high of a setting pressure is applied to deploy the sliding element (e.g., sealing assembly, anchoring assembly, or valve assembly).

Understanding these concerns, the industry has moved to employing a plurality (e.g., two or more, three or more, etc.) of setting pistons connected in series, for example to take the otherwise insufficient hydraulic setting force provided downhole and locally increase it to a higher hydraulic setting force that might be required to fully deploy the sliding elements (e.g., sealing assembly, anchoring assembly, or valve assembly). Take, for example, a triple piston design, wherein each piston has a 5 sq. in. surface area, for a total surface area of 15 sq. in. Applying 400 psi of pressure to the triple piston design would result in 6,000 lbs. of force (e.g., 400 psi×15 sq. in.) impart upon the sliding element. When the pressure impart on the triple piston design is increased to 2,500 psi, 37,500 lbs. of force (2,500 psi×15 sq. in.) would be imparted upon the sliding element. Unfortunately, such a design requires that each piston of the triple piston design travel its full length to move the sliding element its full stroke length. Thus, if it were necessary to move the sliding element (e.g., stroke the sealing assembly or anchoring assembly) a given total stroke length distance (e.g., say 13 inches), 3 times that distance (e.g., say 39 inches) of combined piston movement would be required to do so.

Given the foregoing, the present disclosure proposes to combine a traditional hydraulic setting mechanism and a pressure intensifier to achieve higher localized pressures (e.g., for a given applied pressure) than was traditionally achievable. A pressure intensifier, as disclosed herein, employs a first piston having different surface areas at a pressure receiving end and a pressure output end thereof, connected to a second piston having a second larger surface area. For example, the pressure receiving end of the first piston might have a larger surface area (A) and the pressure output end of the first piston might have a smaller surface area (A). The pressure output end of the first piston having the smaller surface area (A) could then be coupled to the second piston having a second larger surface area (A), for example via an incompressible fluid.

Take, for example, a pressure intensifier having a first piston having a larger surface area (A) of 5 sq. in. at its pressure receiving end and a smaller surface area (A) of 1 sq. in. at its pressure output end, and a second piston having a second larger surface area (A) of 5 sq. in. at its pressure receiving end. In this embodiment, the second piston would be coupled to the pressure output end of the first piston via an incompressible fluid. In this scenario, assuming the pressure intensifier were activated at all times, if one were to initially apply 240 psi to the pressure receiving end of the first piston, 1,200 lbs. of force (e.g., 240 psi×5 sq. in.) would be generated at the output end of the first piston. Given the output end of the first piston has the smaller surface area (A) of 1 sq. in., the 1,200 lbs. of force would translate into 1,200 psi (e.g., 1,200 lbs. of force/1 sq. in.) at the output end of the first piston. This 1,200 psi would then act upon the incompressible fluid, and thus the second piston having the second larger surface area (A) of 5 sq. in. What would result is 6,000 lbs. of force (e.g., 1,200 psi×5 sq. in.) being translated to the second piston, and ultimately the sliding element (e.g., sealing assembly, anchoring assembly, or valve assembly) during this initial phase. In at least one embodiment, the lower pressure might be used for a majority of the total setting stroke of the sliding element.

However, if one were to subsequently (e.g., selectively) apply 1,500 psi to the pressure receiving end of the first piston, 7,500 lbs. of force (e.g., 1,500 psi×5 sq. in.) would be generated at the output end of the first piston. Given the output end of the first piston has the smaller surface area (A) of 1 sq. in., the 7,500 lbs. of force would translate into 7,500 psi (e.g., 7,500 lbs. of force/1 sq. in.) at the output end of the first piston. This 7,500 psi would then act upon the incompressible fluid, and thus the second piston having the larger surface area (A) of 5 sq. in. What would result is 37,500 lbs. of force (e.g., 7,500 psi×5 sq. in.) being translated to the second piston, and ultimately the sliding element (e.g., sealing assembly, anchoring assembly, or valve assembly) during this subsequent phase. In at least one embodiment, this higher pressure might be used for a minority of the total setting stroke of the sliding element.

In accordance with this embodiment, the use of the pressure intensifier would allow the user thereof to advantageously achieve the same increased output force (e.g., 37,500 lbs. of force) using a lower fluid pressure (e.g., 1,500 psi as compared to 2,500 psi), as compared to the triple piston design. Interestingly, the tool length and total stroke length of the sliding element would remain the same as the triple piston design.

Given the foregoing, the present disclosure further proposes using a combination of the traditional hydraulic setting mechanism in conjunction with a selectively engageable pressure intensifier. The selectively engageable pressure intensifier, in at least one embodiment, selectively boosts the setting force of the sealing assembly, for example toward an end of the total setting stroke. In at least one embodiment, the traditional setting mechanism provides a lower setting force (e.g., based upon applying an initial fluid pressure) over a portion of the total setting stroke (e.g., when the pressure intensifier is deactivated), wherein when activated the pressure intensifier provides an increased setting force (e.g., based upon an increased subsequent fluid pressure) over another portion (e.g., a remaining portion) of the total setting stroke. For example, the traditional setting mechanism could be used to provide the setting force over a majority of the total setting stroke (e.g., greater than 50%, if not equal to or greater than 55%, if not equal to or greater than 60%, if not equal to or greater than 65%, if not equal to or greater than 70%, if not equal to or greater than 75%, if not equal to or greater than 80%, if not equal to or greater than 85%, if not equal to or greater than 90%, if not equal to or greater than 95%) while the pressure intensifier could be used to provide the increased subsequent setting force over a minority of the total setting stroke (e.g., less than 50%, if not equal to or less than 45%, if not equal to or less than 40%, if not equal to or less than 35%, if not equal to or less than 30%, if not equal to or less than 25%, if not equal to or less than 20%, if not equal to or less than 15%, if not equal to or less than 10%, if not equal to or less than 5%).

In accordance with at least one embodiment, the pressure intensifier only activates (e.g., is engaged) to provide the increased setting force near the end of the total setting stroke, for example where the increased setting force is actually needed to fully deploy the sliding element (e.g., fully engage the sealing assembly or anchoring assembly with the outer tubular), but otherwise is deactivated (e.g., disengaged). Accordingly, the lower setting force may be used when the sliding element (e.g., sealing assembly, anchoring assembly, or valve assembly) is simply sliding into place, and the increased setting force be used when the sliding element (e.g., sealing assembly, anchoring assembly, or valve assembly) is engaging another feature (e.g., is just about to radially engage the tubular). Not only does the pressure intensifier allow an overall lower applied pressure to achieve the same increased setting force, for example as compared to the triple piston design discussed above, employing the pressure intensifier that only activates near the end of the stroke can do so using a much smaller overall tool length for a given total setting stroke, in relation to the triple piston design or the pressure intensifier design wherein it is always activated.

Take again, for example, a selectively engageable pressure intensifier having the first piston having the larger surface area (A) of 5 sq. in. at its pressure receiving end and the smaller surface area (A) of 1 sq. in. at its pressure output end, and the second piston having the second larger surface area (A) of 5 sq. in. at its pressure receiving end. In this embodiment, when the selectively engageable pressure intensifier is deactivated, the first and second pistons are physically coupled to one another, such that when the first piston moves a fixed distance the second piston also moves the same fixed distance (e.g., for an initial part of the total setting stroke). However, when the selectively engageable pressure intensifier is activated, the first piston is fluidly coupled to the second piston via the incompressible fluid, such that when the first piston moves a fixed distance the second piston moves a lesser distance (e.g., for a remaining part of the total setting stroke).

Given this scenario, and assuming that the selectively engageable pressure intensifier is deactivated, if one were to initially apply 1,200 psi to the pressure receiving end of the first piston, 6,000 lbs. of force (e.g., 1,200 psi×5 sq. in.) would be generated at the output end of the first piston. As the first piston and the second piston are physically coupled to one another (e.g., regardless of the fact that the output end of the first piston has the smaller surface area (A) of 1 sq. in.), the 6,000 lbs. of force would translate directly to the second piston and sliding element, and ultimately the sealing assembly, anchoring assembly or valve assembly during this initial phase.

However, if one were to increase the pressure impart upon the pressure receiving end of the first piston to a value that would break the physical connection between the first piston and the second piston (e.g., and activate the selectively engageable pressure intensifier), and thus allow the first piston and second piston to be fluidly coupled to one another, the benefits of the pressure intensifier could be realized. Say for example if the pressure were increased to 1,500 psi (e.g., enough to activate the selectively engageable pressure intensifier), 7,500 lbs. of force (e.g., 1,500 psi×5 sq. in.) would be generated at the output end of the first piston. Given the output end of the first piston has the smaller surface area (A) of 1 sq. in., the 7,500 lbs. of force would translate into 7,500 psi (e.g., 7,500 lbs. of force/1 sq. in.=7,500 psi) at the output end of the first piston. This 7,500 psi would then act upon the incompressible fluid, and thus the second piston and/or sleeve having a larger surface area (A) of 5 sq. in., resulting in 37,500 lbs. of force (e.g., 7,500 psi×5 sq. in.) translated to the second piston and sliding element, and ultimately the sealing assembly, anchoring assembly or valve assembly during this subsequent phase.

Accordingly, the use of the selectively engageable pressure intensifier would allow the user thereof to advantageously achieve the same increased output force (e.g., 37,500 lbs. of force) using a lower fluid pressure (e.g., 1,500 psi as compared to 2,500 psi), as compared to the triple piston design. However, the use of the selectively engageable pressure intensifier would also allow for a shorter tool length for a given total setting stroke (e.g., 21 inches of tool length as compared to 39 inches of tool length), in relation to the triple piston design or the pressure intensifier design wherein it is always activated.

Given the foregoing, the present disclosure has further recognized that if one can selectively activate the pressure intensifier at a predetermined point (e.g., toward the end of the total setting stroke), the system may receive the benefits of the pressure intensifier (e.g., amplified force) without all of the drawbacks (e.g., increased tool length) of the triple piston design.

A number of different coupling mechanism may exist between the first piston and the second piston that would allow them to be physically coupled to one another at one point in time, and physically decoupled from one another at another point in time. In at least one embodiment, a shear pin (e.g., having a set shear value) may physically couple the first piston and the second piston together. In this embodiment, if the force applied to the second piston is below the shear value of the shear feature the first and second pistons will remain physically coupled, but once the force applied to the second piston is above the shear value of the shear feature the second piston will physically decouple from the first piston. At this state, the first and second pistons would be fluidly coupled to one another using the incompressible fluid, which would in turn activate the pressure intensifier. In yet another embodiment, a collet may be used to selectively couple or decouple the first and second pistons from one another. In yet another embodiment, a burst disc or fluid nozzle may be used to selectively couple or decouple the first and second pistons from one another.

The present disclosure has further recognized that the pressure intensifier design, and the selectively engageable pressure intensifier, may be used with other downhole devices, including valves (e.g., ball valves, interval control valves, etc.), sliding sleeves, etc. and remain within the scope of the present disclosure.

is a schematic view of a well systemdesigned, manufactured and operated according to one or more embodiments disclosed herein. The well systemincludes a platformpositioned over a subterranean formationlocated below the earth's surface. The platform, in at least one embodiment, has a hoisting apparatusand a derrickfor raising and lowering one or more downhole tools including pipe strings, such as a drill string. Although a land-based oil and gas platformis illustrated in, the scope of this disclosure is not thereby limited, and thus could potentially apply to offshore applications. The teachings of this disclosure may also be applied to other land-based well systems different from that illustrated.

As shown, a main wellborehas been drilled through the various earth strata, including the subterranean formation. The term “main” wellbore is used herein to designate a wellbore from which another wellbore is drilled. It is to be noted, however, that a main wellboredoes not necessarily extend directly to the earth's surface, but could instead be a branch of yet another wellbore. A casing stringmay be at least partially cemented within the main wellbore. The term “casing” is used herein to designate a tubular string used to line a wellbore. Casing may actually be of the type known to those skilled in the art as a “liner” and may be made of any material, such as steel or composite material and may be segmented or continuous, such as coiled tubing. The term “lateral” wellbore is used herein to designate a wellbore that is drilled outwardly from its intersection with another wellbore, such as a main wellbore. Moreover, a lateral wellbore may have another lateral wellbore drilled outwardly therefrom.

In the embodiment of, a whipstock assemblyaccording to one or more embodiments of the present disclosure is positioned at a location in the main wellbore. Specifically, the whipstock assemblycould be placed at a location in the main wellborewhere it is desirable for a lateral wellboreto exit. Accordingly, the whipstock assemblymay be used to support a milling tool used to penetrate a window in the main wellbore, and once the window has been milled and a lateral wellboreformed, in some embodiments, the whipstock assemblymay be retrieved and returned uphole by a retrieval tool.

The whipstock assembly, in at least one embodiment, includes a whipstock element section, as well as a sealing/anchoring assemblycoupled to a downhole end thereof. The sealing/anchoring assembly, in one or more embodiments, includes an orienting receptacle tool assembly, a sealing assembly, and an anchoring assembly. The orienting receptacle tool assembly, in one or more embodiments, along with a collet and one or more orienting keys, may be used to land and positioned a guided milling assembly and/or the whipstock element sectionwithin the casing string. The sealing assembly, in at least one embodiment, seals (e.g., provides a pressure tight seal) an annulus between the whipstock assemblyand the casing string. In at least one embodiment, the anchoring assemblyaxially, and optionally rotationally, fixes the whipstock assemblywithin the casing string.

The elements of the whipstock assemblymay be positioned within the main wellborein one or more separate steps. For example, in at least one embodiment, the sealing/anchoring assembly, including the orienting receptacle tool assembly, sealing assemblyand the anchoring assemblyare run in hole first, and then set within the casing string. In the illustrated embodiment, the sealing assemblyis located within an open-hole section of the wellbore. In other embodiments, however, the sealing assemblycould be located within the casing. Thereafter, the sealing assemblymay be pressure tested. Thereafter, the whipstock element sectionmay be run in hole and coupled to the sealing assembly, for example using the orienting receptacle tool assembly. What may result is the whipstock assemblyillustrated in.

In one or more embodiments, the sealing/anchoring assemblyincludes a pressure intensifier designed, manufactured and/or operated according to one or more embodiments of the disclosure. In one or more other embodiments, the well systemfurther includes a valve assembly, and the valve assembly includes a pressure intensifier designed, manufactured and/or operated according to one or more embodiments of the disclosure.

Turning now to, illustrated are different cross-sectional views of various deployment states of a downhole tooldesigned, manufactured and/or operated according to one or more embodiments of the disclosure. The downhole tool, in the illustrated embodiment of, includes a mandrel. The mandrel, in the illustrated embodiment, may be centered about a centerline (CL). The mandrel, in one or more embodiments, is a tubular mandrel such as an inner tubular. The downhole tool, in at least the embodiment of, additionally includes a borepositioned around the mandrel. The bore, in at least one embodiment, is a wellbore, such as an open-hole wellbore. The bore, in at least one other embodiment, is an outer tubular positioned within a wellbore, such as casing, production tubing, etc. In accordance with one aspect of the disclosure, the mandreland the boreform an annulus.

In accordance with one embodiment of the disclosure, the downhole toolincludes a sealing element(e.g., an elastomeric sealing element). The sealing element, in one or more embodiments, is operable to move between a radially retracted state, such as that shown in, a first radially expanded state, such as that shown in(e.g., partially radially expanded state), and a second radially expanded state, such as that shown in(e.g., fully radially expanded state). While a single sealing elementis illustrated in, other embodiments exist wherein multiple sealing elementsare employed, whether together or spaced apart in series along the mandrel. In the embodiment of, the sealing elementcomprises a non-swellable elastomer, among other types and materials. In yet another embodiment, the sealing elementis an anchor element, and thus may have one or more anchoring features thereon.

In the illustrated embodiment of, first and second collar sleeves,, straddle ends of the sealing element.

In the embodiment of, a sliding element(e.g., an axial sliding element) is positioned radially about the mandreland coupled with the first end of the sealing element. In one or more other embodiments, the first collar sleeveand the sliding elementare a single combined feature, as opposed to the multiple separate features shown in.

Those skilled in the art appreciate that one or more anti-extrusion devices such as shoes (not shown) may be used on the downhole tool. Similarly, those skilled in the art appreciate the desire and/or need for the first and second collar sleeves,. For example, in the illustrated embodiment of, the first and second collar sleeves,are configured to axially slide relative to one another to move the sealing elementbetween the radially retracted state, such as that shown in, the first radially expanded state, such as that shown in(e.g., partially radially expanded state), and the second radially expanded state, such as that shown in(e.g., fully radially expanded state).

In the embodiment of, the downhole tooladditionally includes a pressure intensifierpositioned radially about the mandreland coupled to the sliding element. The pressure intensifier, in one or more embodiments, includes a first piston(e.g., primary piston) having a first pressure receiving endwith a larger piston surface area (A) and a first pressure output endwith a smaller piston surface area (A). The pressure intensifier, in one or more embodiments, may further include a second pistoncoupled to the first piston, the second pistonhaving a second pressure receiving endwith a larger piston surface area (A). In the illustrated embodiment, a second endof the second pistonis coupled with the sliding element. For example, in at least one embodiment, the second pistonof the pressure intensifieris in a same force path as the first pistonof the pressure intensifier, and for example in certain other embodiments the same force path as the sliding element.

Those skilled in the art will appreciate that in the images the first pressure receiving endis shown to be in communication with the tubing via a port, but other embodiments may be designed without departing from the scope of the invention. Alternate embodiments include a control line operated tool, a tool operated using a downhole pump, actuator or other power source etc. Alternate embodiments also include a tool whereby the fluid receiving endis initially isolated from any pressure or power source using devices such as a burst disc. When it is desired to actuate the tool, the burst disk may be ruptured by applied pressure or a shifting tool allowing the wellbore hydrostatic pressure to set the tool in line with this invention thereby alleviating the need for any applied pressure from surface or other power source.

Those skilled in the art, given this disclosure, understand how the larger piston surface area (A) of the first pressure receiving end, the smaller piston surface area (A) of the first pressure output end, and the larger piston surface area (A) of the second pressure receiving end, or at least the values thereof, may be tailored to provide different intensification amounts. For example, the less difference in area between the smaller piston surface area (A) of the first pistonand the larger piston surface area (A) of the second piston, the less intensification. Nevertheless, the greater difference in area between the smaller piston surface area (A) of the first pistonand the larger piston surface area (A) of the second piston, the greater intensification.

Further to the embodiment of, a fluid chamberis defined between the first pressure output endof the first pistonwith the smaller piston surface area (A) and the second pressure receiving endof the second pistonwith the larger piston surface area (A), for example using one or more sealing elements. In one or more embodiments, the fluid chamberis filled with an incompressible fluid, such as for example a water-based liquid or oil-based liquid, among others. In one or more embodiments, fluid chamberis filled with the wellbore fluid by having a one way valve to the tubing or annulus so as to allow surrounding fluid to enter chamberand equalize pressure with the wellbore but prevent fluid from exiting chamberwhen the pressure intensifier is activated.

In one or more embodiments, the pressure intensifieris always activated. Accordingly, an application of an applied fluid pressure to the first pressure receiving endof the first pistonwill result in the application of an intensified fluid pressure at the second pressure receiving endof the second piston. Accordingly, this intensified fluid pressure at the second pressure receiving endof the second piston would translate into an intensified force applied to the second pressure receiving endof the second piston, and thus to the sliding elementand ultimately the sealing element. The intensified fluid pressure and resulting intensified force would be achieved and discussed in detail above.

In one or more other embodiments, such as that shown in, the pressure intensifieris a selectively engageable pressure intensifier. Accordingly, the selectively engageable pressure intensifier may be deactivated for a portion of the total stroke length of the sliding element, and then activated for a remaining portion of the total setting stroke of the sliding element, as discussed in detail above. For example, the selectively engageable pressure intensifier, in one or more embodiments, is configured to have an initial state (e.g., as shown in) physically coupling the first pistonand the second pistonwith one another when subjected to an initial fluid pressure below a threshold fluid pressure, and is configured to have a subsequent state (e.g., as shown in) physically decoupling and fluidly coupling the first pistonand the second pistonwith one another when subjected to a subsequent fluid pressure above the threshold fluid pressure.

In the illustrated embodiment of, the pressure intensifieremploys a collet featureto make it selectively engageable. In this one embodiment, the collet featureis configured to set the threshold fluid pressure, and thus remain engaged to physically couple the first pistonand the second pistonwhen the selectively engageable pressure intensifieris subjected to an initial fluid pressure below the threshold fluid pressure, and disengage to physically decouple and fluidly couple the first pistonand the second pistonwhen the selectively engageable pressure intensifieris subjected to a subsequent fluid pressure above the threshold fluid pressure. Those skilled in the art, given that disclosed herein, would understand how to design the collet featureto stay engaged when subjected to the initial fluid pressure below the threshold fluid pressure and then disengage when subjected to the subsequent fluid pressure above the threshold fluid pressure.

In the illustrated embodiment of, the downhole toolmay additionally include one or more one way checksto maintain engagement of the components and prevent the sealing elementfrom relaxing over time and/or if the fluid pressure drops. In at least one embodiment, the one or more one way checksare a series of teeth that allow the sliding elementto slide one way (e.g., to the left in the disclosed embodiment), but not the other way (e.g., to the right in the disclosed embodiment). In yet another embodiment, the one or more one way checksare one or more body lock rings, or one or more slips, etc., In yet another embodiment, the one or more one way checks are a fluid check valve that allows fluid to exit the intensifierbut not to re-enter the intensifier.

In the illustrated embodiments,illustrate the downhole toolas it might exist in a run-in-hole state., however, illustrate the downhole toolas it might exist after applying an initial fluidhaving an initial fluid pressure below the threshold fluid pressure thereto. The initial fluid, in one or more embodiments, moves the sliding elementa majority of its total setting stroke. Furthermore, as the initial fluidhaving the initial fluid pressure is below the threshold fluid pressure, the first pistonand the second pistonremain physically coupled to one another (e.g., via the collet feature) while being subjected to this initial fluid pressure. Accordingly, the pressure intensifier feature is deactivated at this time.

illustrate the downhole toolas it might exist after applying a subsequent fluidhaving a subsequent fluid pressure above the threshold fluid pressure thereto. The subsequent fluid, in one or more embodiments, moves the sliding elementa remaining minority of its total setting stroke. Furthermore, as the subsequent fluidhaving the subsequent fluid pressure is above the threshold fluid pressure, applying the subsequent fluid pressure physically decouples and fluidly couples the first pistonand the second piston. Accordingly, the pressure intensifier feature is activated at this time.

In one or more embodiments, the applying the initial fluid pressure below the threshold fluid pressure moves the sliding elementequal to or greater than 75% of the total setting stroke, and applying the subsequent fluid pressure above the threshold fluid pressure moves the sliding elementequal to or less than 25% of the total setting stroke. In yet another embodiment, the applying the initial fluid pressure below the threshold fluid pressure moves the sliding elementequal to or greater than 85% of the total setting stroke, and applying the subsequent fluid pressure above the threshold fluid pressure moves the sliding elementequal to or less than 15% of the total setting stroke. In even yet another embodiment, the applying the initial fluid pressure below the threshold fluid pressure moves the sliding elementequal to or greater than 95% of the total setting stroke, and applying the subsequent fluid pressure above the threshold fluid pressure moves the sliding elementequal to or less than 5% of the total setting stroke.

Turning now to, illustrated are different cross-sectional views of various deployment states of a downhole tooldesigned, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole toolofis similar in many respects to the downhole toolof. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tooldiffers, for the most part, from the downhole toolin that the downhole toolemploys a shear feature, as compared to the colletof, to set the threshold fluid pressure.

Turning now to, illustrated are different cross-sectional views of various deployment states of a downhole tooldesigned, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole toolofis similar in many respects to the downhole toolof. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tooldiffers, for the most part, from the downhole toolin that the downhole toolemploys a burst disc, as compared to the colletof, to set the threshold fluid pressure.

The downhole tool, in the illustrated embodiment, further includes a check valvelocated in the fluid chamber. In accordance with this embodiment, the check valveis configured to allow uncompressed fluid located within the fluid chamberto move from the first pressure output endof the first pistontoward the second pressure receiving endof the second piston, and stop the uncompressed fluid located within the fluid chamberfrom moving back from the second pressure receiving endof the second pistontoward the first pressure output endof the first piston. One skilled in the art would recognize that one or more embodiments may use a flow restrictor instead of a burst disk. In such a design, the pressure intensifier would be activated after a threshold time of applying the target input pressure. Initially, the flow restrictor stops pressure from building up in chamberso both pistons move together. Over time, pressure makes it past the restrictor and builds up inside chamberwhich will cause the pressure intensifier to activate as the pistons are now fluidically coupled. As a non-limiting example, suppose a pressure of 1,500 psi is applied for 15 minutes. For the first 10 minutes, the pistons move together for a majority of the total stroke and come to a stop as the pressure is still making its way past the restrictor and the load generated by the input pressure is not sufficient to actuate the element past a partially deployed state. After 10 minutes, the pressure starts to build up in chamberto fluidically couple the first and second piston to activate the pressure intensifier. This results in the second piston applying the increased load on the element and moving for a minority of the total stroke over the remaining 5 minutes hence fully actuating the element.

Turning now to, illustrated are different cross-sectional views of various deployment states of a downhole tooldesigned, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole toolofis similar in many respects to the downhole toolof. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tooldiffers, for the most part, from the downhole toolin that the downhole toolis operating as a valve assembly. Accordingly, in the embodiment of, the sliding elementis coupled to a valve elementhaving a fluid passagewaytherein. In one or more embodiments, the fluid passagewayof the valve elementis configured to misalign with an openingin the mandrel, and thus shut the valve assembly, or alternatively at least partially align with the openingin the mandrel, and thus open the valve assembly.

In the embodiment of, the pressure intensifiermay be used to dislodge the valve elementif it were to get stuck. For example, debrismight prevent the valve elementfrom appropriately opening and/or closing. Accordingly, the pressure intensifiercould be activated to force the valve elementpast the debris. Thereafter, the user of the downhole toolmight reduce the pressure from the subsequent fluid pressure above the threshold pressure to a value below the threshold pressure, or alternatively could keep the higher subsequent fluid pressure.

The downhole tool, in the embodiment of, additionally includes a spring memberlocated in the fluid chamber. In accordance with one or more embodiments, the spring memberis configured to allow the pressure intensifierto reset for repeated use, as shown in.

illustrate the downhole toolin a run-in-hole state.