DOWNHOLE TOOL INCLUDING A PRESSURE INTENSIFIER

Abstract

A downhole tool, method, and well system. The downhole tool, in one aspect, includes a pressure intensifier positioned radially about a mandrel, the pressure intensifier configured to receive a setting force (F1) applied to the mandrel and amplify it to an amplified force (FA) sufficient to continue to move a deployable element from a partially deployed state to a fully deployed state. In at least one aspect, the pressure intensifier includes a first piston having a first piston surface area (A1), a second piston having a second piston surface area (A2), wherein (A2) > (A1), and a fluid chamber defined between the (A1) and (A2). In at least this one aspect, the (A1) is configured to extend at least partially within the fluid chamber as the mandrel is receiving the (F1) thereby pressing fluid located within the fluid chamber against the (A2) to create the (FA).

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application Serial No. 63/781,569, filed on Apr. 1, 2025, entitled “DOWNHOLE TOOL INCLUDING A SETTING FORCE MULTIPLIER,” commonly assigned with this application and incorporated herein by reference in its entirety.

BACKGROUND

A typical downhole tool (e.g., packer, bridge plug, frac plug, anchor, etc.) generally has one or more radially deployable 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 deployable elements radially deploy, thereby providing the fluid-tight seal or anchor between the mandrel and the casing and/or wellbore. In certain embodiments, the radially deployable elements are axially compressed between element retainers (e.g., deployment shoes) that straddle them, which in turn radially compress the radially deployable elements causing them to move from their radially retracted state to their radially deployed state.

BRIEF DESCRIPTION

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

FIG. 1 illustrates a schematic view of a well system designed, manufactured and/or operated according to one or more embodiments disclosed herein;

FIG. 2 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more embodiments of the disclosure;

FIGS. 3A through 3E, and optional FIG. 3F, illustrate cross-sectional views of a downhole tool designed, manufactured and/or operated according to one embodiment of the disclosure at various different deployment states;

FIG. 4 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIG. 5 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIGS. 6A through 6F illustrate cross-sectional views of a downhole tool designed, manufactured and/or operated according to one alternative embodiment of the disclosure at various different deployment states;

FIG. 7 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIG. 8 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIG. 9 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIGS. 10A through 10E illustrate cross-sectional views of a downhole tool designed, manufactured and/or operated according to one alternative embodiment of the disclosure at various different deployment states;

FIG. 11 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIG. 12 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIG. 13 illustrates a cross-sectional view a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure; and

FIG. 14 illustrates a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure.

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 term “exactly 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.

Deployable 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 deploying the deployable elements of such downhole tools (e.g., actuating the deployable elements of a sealing assembly, anchoring assembly, and/or valve assembly), the setting force can be a design limitation. In at least one scenario, surface equipment coupled to the deployable element is limited in an amount of setting force it can provide, and the limited amount of setting force is insufficient to fully deploy the deployable element (e.g., sealing assembly, anchoring assembly, or valve assembly). For example, in at least this one scenario, the setting force alone is only capable of moving the deployable element from the retracted state to a partially deployed state, and not to a fully deployed state. In at least one other scenario, the amount of 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 force is applied to deploy the deployable element (e.g., sealing assembly, anchoring assembly, or valve assembly).

It should be noted that the reference to partially deployed state and fully deployed state is not limited to changes in deployment distance, but could also encompass changes in deployment force. For example, in at least one embodiment, the deployment element might be deployed a distance (d) (e.g., axial or radial) when in the partially deployed state and a greater distance (d’) when in the fully deployed state. However, in yet another embodiment, the deployment element might be deployed a distance (d) (e.g., axial or radial) when in the partially deployed state, but only be able to seal an amount of pressure (X) or only be able to hold an amount of force (Y), and remain deployed the distance (d) when in the fully deployed state, but be able to seal an greater amount of pressure (X’) or be able to hold a greater amount of force (Y’). This might result when in the partially deployed state the deployable element is not compressed or compacted enough (e.g., lower contact pressure with the wellbore tubular), but in the fully deployed state the deployable element is compressed or compacted enough to sustain higher pressure sealing or greater holding force. Thus, a difference between the partially deployed state and the fully deployed state is not limited to movement, but could also incorporate other changing features of the deployable element, including sealing pressure, holding pressure, etc. This, similarly, holds true with the phrases partially radially deployed state, fully radially deployed state, partially axially deployed state, and fully axially deployed state, when used.

Given the foregoing, the present disclosure proposes to combine a traditional mechanical setting mechanism and a pressure intensifier to achieve higher localized setting forces (e.g., for a given applied setting force) than was traditionally achievable. The pressure intensifier, in at least one embodiment, is based at least in part on Pascal’s Law. Pascal’s Law tells us that pressure is defined as force divided by cross sectional area (e.g., P = F / A). Through Pascal’s Law, it is known that the fluid pressure is equal in all directions, hence input pressure equals output pressure (e.g., F₁ / A₁ = F₂/ A₂). Through the manipulation of the input and output surface areas within the downhole tool design, the setting force (F₁) (e.g., mechanical, as opposed to fluid, setting force in one embodiment, such as the tool weight itself) can be amplified to an amplified force (F_A). For example, in at least one embodiment, the pressure intensifier employs a plurality of pistons coupled together via a fluid chamber having fluid (e.g., incompressible fluid) therein. In at least this one embodiment, the first piston receiving the initial force (e.g., setting force (F₁)) has a first piston surface area (A₁) and the second piston coupled thereto via the fluid chamber has a second piston surface area (A₂). For the amplification to work, the second piston surface area (A₂) is greater than the first piston surface area (A₁).

Accordingly, depending on the surface area difference between the first piston surface area (A₁) and the second piston surface area (A₂), the intensification and/or amplification can be significant. For example, depending on a surface area difference between the first piston surface area (A₁) of the first piston and the second piston surface area (A₂) of the second piston, the amplified force (F_A) may be 25% greater, if not 50% greater, if not 75% greater, if not 100% greater, if not 150% greater, if not 200% greater, if not 300% greater, if not 400% greater, if not 500% greater if not 750% greater, if not 1000% greater, if not 2000% greater, or more, than the setting force (F₁). As an example, in one example embodiment wherein the first piston surface area (A₁) is 25 cm² and the second piston surface area (A₂) is 125 cm², the amplification would be approximately 500% (e.g., 5X). Thus, in this example, if the setting force (F₁) acting on the first piston surface area (A₁) were 450 kilonewtons (kN), the second piston surface area (A₂) will generate an output of approximately 2,250 kN. If, in fact, the second piston surface area (A₂) were coupled with a radially deployable element, this 2,250 kN would be impart on the radially deployable element. Thus, when the second piston surface area (A₂) is compressing a radially deployable element, such as a compressible packer, this intensification and/or amplification is significant, and thus in the above embodiment helps to continue to move the radially deployable element from a partially radially deployed state to a fully radially deployed state.

The present disclosure has further realized that there is a demand for high pressure high temperature (HPHT) rating packers, but the set down weight or hang weight (e.g., setting force (F₁)) is as low as 9,500 kg (e.g., approximately 21,000 lbs.), which may be insufficient to set the high pressure high temperature (HPHT) packer elements. The above disclosed pressure intensifier may be used, along with the allotted set down weight or hang weight (e.g., setting force (F₁)), to increase (e.g., amplify) the setting force (F₁) of the high pressure high temperature (HPHT) packer elements. Thus, this disclosure also discloses a method to amplify or multiply the input force or weight to achieve the required element setting force for the high pressure high temperature (HPHT) rating packers. The above scenarios are detailed with applying downhole compressive forces on the high pressure high temperature (HPHT) packer elements, but the above may also be used to amplify an uphole tensile force or overpull to set the high pressure high temperature (HPHT) packer elements.

Turning to FIG. 1, illustrated is a schematic view of a well system 100 designed, manufactured and/or operated according to one or more embodiments disclosed herein. The well system 100, in the illustrated embodiment, includes a platform 120 positioned over a subterranean formation 110 located below the earth’s surface 115. The platform 120, in at least one embodiment, includes a derrick 125, along with a hoisting apparatus 130, for raising and lowering one or more downhole tools (e.g., including pipe strings, such as a drill string 140). Although a land-based oil and gas platform 120 is illustrated in FIG. 1, the scope of this disclosure is not thereby limited, and thus could potentially apply to over water or 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 wellbore 150 has been formed (e.g., drilled) through the various earth strata, including the subterranean formation 110. The term “main” wellbore is used herein to designate a wellbore from which another wellbore may be drilled. It is to be noted, however, that a main wellbore 150 does not necessarily extend directly to the earth's surface, but could instead be a branch of yet another wellbore. A casing string 160 may be at least partially located within the main wellbore 150 (e.g., using cement 165 to fix the casing string 160 within the main wellbore 150). 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 FIG. 1, a downhole tool 170 is positioned at a location in the main wellbore 150. Specifically, in one or more embodiments the downhole tool 170 could be placed at a location in the main wellbore 150 where it is desirable for a lateral wellbore 190 to exit. Accordingly, in this example embodiment the downhole tool 170 may be used to support a milling tool used to penetrate a window in the casing string 160 of the main wellbore 150, and subsequent thereto support a drilling tool that is used to ultimately form the lateral wellbore 190.

The downhole tool 170, in at least one embodiment, includes a variety of features while remaining within the scope of the disclosure. For example, in one embodiment, the downhole tool includes a mandrel, a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state. In this example embodiment, the mandrel is configured to receive a setting force (F₁) sufficient to move the deployable element from the retracted state to the partially deployed state. The downhole tool of this embodiment may further include a pressure intensifier positioned about the mandrel, the pressure intensifier configured to receive the setting force (F₁) and amplify it to an amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state. In accordance with this one embodiment, the pressure intensifier includes a first piston having a first piston surface area (A₁), a second piston having a second piston surface area (A₂) (e.g., wherein the second piston surface area (A₂) is greater than the first piston surface area (A₁)), and a fluid chamber defined between the first piston surface area (A₁) of the first piston and the second piston surface area (A₂) of the second piston. In at least this one embodiment, the first piston surface area (A₁) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel is receiving the setting force (F₁) thereby pressing fluid located within the fluid chamber against the second piston surface area (A₂) of the second piston to create the amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state. While one specific configuration for the downhole tool 170 is described with respect to FIG. 1, other configurations for the downhole tool 170 are within the purview of the disclosure.

In at least one embodiment, the deployable element of the downhole tool 170 is a radially deployable element, the retracted state is a radially retracted state, the partially deployed state is a partially radially deployed state, and the fully deployed state is a fully radially deployed state, the radially deployable element configured to move between the radially retracted state, the partially radially deployed state, and the fully radially deployed state. In at least this one embodiment, the downhole tool 170 might further include first and second deployment shoes located on opposing sides of the radially deployable element, the first and second deployment shoes configured to translate relative to one another to move the radially deployable element between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, wherein the mandrel is configured to receive a setting force (F₁) sufficient to move the radially deployable element from the radially retracted state to the partially radially deployed state.

In at least one embodiment, the deployable element of the downhole tool 170 is an axially deployable element, the retracted state is an axially retracted state, the partially deployed state is a partially axially deployed state, and the fully deployed state is a fully axially deployed state, the axially deployable element configured to move between the axially retracted state, the partially axially deployed state, and the fully axially deployed state. In even yet another embodiment, the deployable element of the downhole tool 170 may both axially and radially deploy.

Turning now to FIG. 2, illustrated is a cross-sectional view of a downhole tool 200 designed, manufactured and/or operated according to one or more embodiments of the disclosure. For clarity, in one or more embodiments, the left side of the downhole tool 200 is an uphole side and the right side of the downhole tool 200 is a downhole side, but as understood more fully below, the opposite could apply. The downhole tool 200, in the illustrated embodiment of FIG. 2 includes a mandrel 210. The mandrel 210, in the illustrated embodiment, may be centered about a centerline (C_L). The mandrel 210, in one or more embodiments, is a tubular mandrel or a solid stock mandrel, among others. The mandrel 210 may comprise a variety of different materials and remain within the scope of the disclosure, nevertheless, in the embodiment of FIG. 2 the mandrel 210 is a metal mandrel.

The downhole tool 200, in the illustrated embodiment of FIG. 2, additionally includes a deployable element (e.g., radially deployable element 215) positioned about the mandrel 210. In the illustrated embodiment, the deployable element is configured to move between a retracted state, a partially deployed state, and a fully deployed state. In the embodiment wherein the deployable element is the radially deployable element 215, the radially deployable element is configured to move between a radially retracted state (e.g., as shown in FIG. 2), a partially radially deployed state, and a fully radially deployed state. In at least one embodiment, the radially deployable element 215 is a sealing element, such as an elastomeric sealing element, among others. In yet another embodiment, however, the radially deployable element 215 is an anchoring element, such as a metal anchoring element, among others. The present disclosure, however, is not limited to any specific deployable element, unless otherwise stated. Accordingly, while the below embodiments may be discussed with regard to radially deployable elements, other moveable elements, such as sliding elements, are withing the purview of the disclosure.

The downhole tool 200, in the illustrated embodiment of FIG. 2, additionally includes first and second deployment shoes 220a, 220b located on opposing sides of the radially deployable element 215. In at least one embodiment, the first and second deployment shoes 220a, 220b are configured to translate relative to one another to move the radially deployable element 215 between the radially retracted state, the partially radially deployed state, and the fully radially deployed state. For example, in the illustrated embodiment, the first and second deployment shoes 220a, 220b are configured to move toward each other to incrementally squeeze the radially deployable element 215, for example to move it between the radially retracted state, the partially radially deployed state, and the fully radially deployed state. In at least one embodiment, one of the first and second deployment shoes 220a, 220b is fixed and the other of the first and second deployment shoes 220a, 220b moves to generate the relative movement. In yet another embodiment, both the first and second deployment shoes 220a, 220b move to generate the relative movement.

In at least one embodiment, such as shown, the mandrel 210 is configured to receive a setting force (F₁). In at least this one embodiment, the setting force (F₁) is sufficient to translate the first and second deployment shoes 220a, 220b relative to one another in a manner and/or degree to move the radially deployable element 215 from the radially retracted state to the partially radially deployed state, but alone is insufficient to translate the first and second deployment shoes 220a, 220b relative to one another in a manner and/or degree sufficient to move the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state.

Given the foregoing, in accordance with one or more embodiments of the disclosure, the downhole tool 200 may additionally include a pressure intensifier 230 positioned radially about the mandrel 210. The pressure intensifier 230, in at least one embodiment, is configured to assist the setting force (F₁) in moving the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state. In at least one embodiment, the pressure intensifier 230 is configured to receive the setting force (F₁) and amplify it to an amplified force (F_A), for example sufficient to continue to move the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state.

The pressure intensifier 230 may undertake many different designs while remaining within the purview of the disclosure, so long as it is operable to generate a suitable amplified force (F_A) to move the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state. Nevertheless, in at least one embodiment, the pressure intensifier 230 is designed to include a first piston 232 having a first piston surface area (A₁), and a second piston 234 having a second piston surface area (A₂), wherein the second piston surface area (A₂) is greater than the first piston surface area (A₁) (e.g., to create the amplification). In this disclosed embodiment, the pressure intensifier 230 includes a fluid chamber 236 defined between the first piston surface area (A₁) of the first piston 232 and the second piston surface area (A₂) of the second piston 234, for example using one or more seal elements 237 (e.g., one or more static or dynamic elastomeric seal elements). In at least this one embodiment, the first piston surface area (A₁) of the first piston 232 is configured to extend at least partially within the fluid chamber 236 as the mandrel 210 is receiving the setting force (F₁), thereby pressing fluid 238 located within the fluid chamber 236 against the second piston surface area (A₂) of the second piston 234. It is this process that may be used to create the amplified force (F_A) sufficient to continue to move the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state.

In the illustrated embodiment of FIG. 2, the downhole tool 200 further includes a reactive force assembly 240 positioned about the mandrel 210. The reactive force assembly 240, in at least this one embodiment, is configured to substantially focus the amplified force (F_A) upon the radially deployable element 215 to continue to move the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state. In yet another embodiment, the reactive force assembly 240, is configured to significantly, if not ideally, if not perfectly focus the amplified force (F_A) upon the radially deployable element 215. In the illustrated embodiment of FIG. 2, the reactive force assembly 240 includes (e.g., without limitation) a mechanical slip 242 (e.g., first mechanical slip) and a barrel wedge 244 (e.g., first barrel wedge). In this embodiment, the barrel wedge 244 is positioned between the mechanical slip 242 and the first deployment shoe 220a. The barrel wedge 244, in this embodiment, is configured to generate an opposing force (F_R) that opposes the setting force (F₁), which forces the mechanical slip 242 into contact with a wellbore tubular located thereabout (e.g., to substantially focus the amplified force (F_A) upon the radially deployable element 215). In at least one embodiment, the opposing force (F_R) might be substantially similar to the amplified force (F_A) (e.g., apart from frictional and other inherent forces), if not significantly similar, if not ideally similar, if not exactly similar, if not perfectly similar. In yet another embodiment, for example prior to any amplification occurring, the opposing force (F_R) might be substantially similar to the setting force (F₁) (e.g., apart from frictional and other inherent forces), if not significantly similar, if not ideally similar, if not exactly similar, if not perfectly similar. In the embodiment of FIG. 2, the mechanical slip 242 and the barrel wedge 244 have opposing surfaces that are angled relative to one another, such that when the two engage one another the mechanical slip 242 may be urged radially outward. In the embodiment of FIG. 2, the mandrel 210 also includes an angled surface that is configured to engage with another angled surface of the mechanical slip 242, such that when the two engage one another the mandrel 210 may assist in urging the mechanical slip 242 radially outward.

The mandrel 210, in certain embodiments (not illustrated) may be designed such that after it has urged the mechanical slip 242 radially outward, its angled surface is no longer in contact with the another angled surface of the mechanical slip 242 and the mandrel 210 may continue to translate and move under (e.g., and potentially support) the mechanical slip 242. This embodiment, however, might require extremely specific tolerances between a lower surface of the mechanical slip 242 and the upper surface of the mandrel 210 (e.g., to keep the mechanical slip 242 tightly engaged with the wellbore tubular) or a spring force of some sort to keep the mechanical slip tightly engaged with the wellbore tubular.

It should be noted that the term “barrel wedge,” unless otherwise required, is not limited to any specific design, other than having a wedge that is configured to engage with the mechanical slip 242 to force it radially outward. Accordingly, the term “barrel wedge,” again unless otherwise required, could have any shape, be formed of a single piece or a collection of pieces or segments, as well as may be formed of any material, including metals, plastics, etc..

In the embodiment of FIG. 2, the second piston 234 forms at least a portion of the first deployment shoe 220a. Further to the embodiment of FIG. 2, at least a portion of the fluid chamber 236 is formed within the barrel wedge 244. Further to this embodiment, the first piston 232 having the first piston surface area (A₁) is coupled to and moves with the mandrel 210, and thus as the mandrel 210 moves the first piston surface area (A₁) of the first piston 232 may at least partially move within the at least the portion of the fluid chamber 236 formed within the barrel wedge 244, thereby pressing the fluid 238 located within the fluid chamber 236 against the second piston surface area (A₂) of the second piston 234 to create the amplified force (F_A), and thus move the radially deployable element 215 from the partially radially deployed state to the fully radially deployed state.

Further to the embodiment of FIG. 2, the mechanical slip 242 and the barrel wedge 244 are a first mechanical slip and a first barrel wedge, and the downhole tool 200 further includes a second mechanical slip 252 and a second barrel wedge 254. In this embodiment, the second mechanical slip 252 and the second barrel wedge 254 are positioned on an opposing side of the radially deployable element 215 as the mechanical slip 242 (e.g., first mechanical slip) and the barrel wedge 244 (e.g., first barrel wedge). Further to one or more embodiments, such as the embodiment of FIG. 2, the second barrel wedge 254 and the second deployment shoe 220b form a single integral element. Moreover, as shown, in at least one embodiment the mechanical slip 242 (e.g., first mechanical slip) and barrel wedge 244 (e.g., first barrel wedge) are located about the mandrel 210 proximate an uphole side of the radially deployable element 215 and the second mechanical slip 252 and second barrel wedge 254 are located about the mandrel 210 proximate a downhole side of the radially deployable element 215. In accordance with this embodiment, the setting force (F₁) may be a downhole directed force acting upon the mandrel 210, in essence providing compression to the mandrel 210. As will be discussed in detail below, the above could be reversed, and thus the setting force (F₁) may be an uphole directed force acting upon the mandrel 210, in essence providing tension to the mandrel 210.

The downhole tool 200, in at least one embodiment, may further include a locking mechanism 280. The locking mechanism 280, in one or more embodiments, is configured to fix the radially deployable element 215 in the radially retracted state when the downhole tool 200 is being run-in-hole, but configured to release to allow the radially deployable element 215 to move to the partially radially deployed state or fully radially deployed state when the downhole tool 200 is ready to be set. In at least one embodiment, the locking mechanism 280 is configured to fix the mandrel 210, first and second deployment shoes 220a, 220b, and radially deployable element 215 relative to one another when the downhole tool 200 is being run-in-hole, but configured to release to allow the mandrel 210, first and second deployment shoes 220a, 220b, and radially deployable element 215 to translate relative to one another when the downhole tool 200 is ready to be set. The locking mechanism 280, in at least one embodiment, is a J-slot mechanism 282, the J-slot mechanism 282 configured to translate and/or rotate to move the locking mechanism 280 between its locked state (e.g., as shown in FIG. 2) and its released state.

The downhole tool 200, in at least one additional embodiment, may further include a drag block 290 releasably coupled with the mandrel 210. In at least this one embodiment, the drag block 290 is configured to engage with and generate friction with a bore (e.g., wellbore tubular, not shown) as the downhole tool 200 is being deployed within the wellbore tubular. Accordingly, the drag block 290 may provide a degree of friction, which the locking mechanism 280 may employ to move between its locked state and released state. Similarly, the downhole tool 200 may employ this friction of the drag block 290 to initially set the second mechanical slip 252 and the second barrel wedge 254.

Turning to FIGS. 3A through 3E, illustrated are cross-sectional views of a downhole tool 300 designed, manufactured and/or operated according to one embodiment of the disclosure at various different deployment states. The downhole tool 300, in the illustrated embodiment of FIGS. 3A through 3E, is similar in one or more respects to the downhole tool 200 of FIG. 2. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 300, in the illustrated embodiment of FIGS. 3A through 3E is positioned within a bore 395. The bore 395, in at least one embodiment, is a wellbore, such as an open-hole wellbore. The bore 395, in at least one other embodiment, is a wellbore tubular positioned within a wellbore, such as casing, liner, production tubing, etc. In accordance with one aspect of the disclosure, the mandrel 210 and the bore 395 form an annulus 390 therebetween.

Turning initially to FIG. 3A, the downhole tool 300 is configured in its run-in-hole orientation. In this run-in-hole orientation, the radially deployable element 215 is in its radially retracted state, and thus is not in engagement with the bore 395. Additionally, the mechanical slip 242, barrel wedge 244, second mechanical slip 252 and second barrel wedge 254 are all in their run-in-hole orientations, and thus the mechanical slip 242 and the second mechanical slip 252 are in their radially retracted orientations, and also not in engagement with the bore 395. Moreover, as shown in FIG. 3A the locking mechanism 280 is engaged, thereby fixing the radially deployable element 215 in the radially retracted state, as well fixing the mandrel 210, first and second deployment shoes 220a, 220b, and radially deployable element 215 relative to one another. Accordingly, no movement may arise within the features of the downhole tool 300 that would cause (e.g., unintentionally or otherwise) the radially deployable element 215 to move from the radially retracted state to the partially radially deployed state, let alone all the way to the fully radially deployed state. Similarly, no movement may arise within the features of the downhole tool 300 that would additionally cause (e.g., unintentionally or otherwise) the mechanical slip 242 and/or second mechanical slip 252 to deploy. Ultimately, the locking mechanism 280 substantially prevents (e.g., if not perfectly prevents) any frictional forces that may generate between the bore 395 and the drag block 290 as the downhole tool 300 is being deploying within the wellbore (e.g., using a run-in-hole force (F_RIH)) from transferring to the features of the downhole tool 300, and particularly the radially deployable element 215, the mechanical slip 242 or the second mechanical slip 252.

Turning to FIG. 3B, illustrated is the downhole tool 300 of FIG. 3A after it has reached its desired location, for example using the run-in-hole force (F_RIH). With the downhole tool 300 at the desired locations, the locking mechanism 280 may be disengaged. For example, in the illustrated embodiment wherein the locking mechanism 280 is J-slot mechanism 282, one or more features of the downhole tool 300 may be rotated and/or translated to move the locking mechanism 280 between the engaged state of FIG. 3A and the disengaged state of FIG. 3B. Accordingly, at this orientation, given the disengaged nature of the locking mechanism 280 (e.g., along with any existing frictional forces between the bore 395 and the drag block 290), any additional force applied to the downhole tool 300 (e.g., by way of the mandrel 210) could potentially start to deploy the radially deployable element 215, mechanical slip 242 and/or second mechanical slip 252.

Turning to FIG. 3C, illustrated is the downhole tool 300 of FIG. 3B after starting to apply an initial setting force (F₀) thereto. For example, in the illustrated embodiment, the initial setting force (F₀) is being applied to the mandrel 210. In this embodiment, so long as frictional forces that may arise as the features of the downhole tool 300 translate relative to one another (e.g., as the initial setting force (F₀) is being applied to the mandrel 210) are less than the frictional forces created between the bore 395 and the drag block 290, the downhole tool 300 will remain in the same location within the bore 395 and the features thereof may start to translate. In at least one embodiment, the initial setting force (F₀) is preferably less than the frictional forces created between the bore 395 and the drag block 290, such that the downhole tool 300 begins to deploy without the drag block 290 sliding within the bore 395.

In the illustrated embodiment of FIG. 3C, the initial setting force (F₀) has caused features of the downhole tool 300 to translate relative to one another, and in this example caused the second mechanical slip 252 and second barrel wedge 254 to translate relative to one another. In this embodiment, this translation has moved the second mechanical slip 252 from the radially retracted state of FIG. 3B to the radially deployed state of FIG. 3C. Thus, in this embodiment the second mechanical slip 252 is now in gripping engagement with the bore 395. In at least one embodiment, any frictional forces (e.g., as a result of the gripping engagement) between the second mechanical slip 252 and the bore 395 is greater than the frictional forces between the drag block 290 and the bore 395. Furthermore, in at least one embodiment, the initial setting force (F₀) is less than the setting force (F₁) that might be required to move the radially deployable element 215 from the radially retracted state to the partially radially deployed state.

Turning to FIG. 3D, illustrated is the downhole tool 300 of FIG. 3C after starting to apply a setting force (F₁) thereto. As the second mechanical slip 252 is now engaged with the bore 395, the setting force (F₁) (e.g., in some embodiments greater than the initial setting force (F₀)) may be used. The setting force (F₁), in this embodiment, moves the radially deployable element 215 from the radially retracted state (e.g., as shown in FIG. 3C) to the partially radially deployed state (e.g., as shown in FIG. 3D). The setting force (F₁) also causes the mechanical slip 242 and the barrel wedge 244 to translate relative to one another, in this example causing the mechanical slip 242 to move into gripping engagement with the bore 395. As indicated above, in at least one embodiment the mechanical slip 242 and the barrel wedge 244 are configured as a reactive force assembly 240, and thus as the setting force (F₁) is applied to the mandrel 210, the barrel wedge 244 generates an opposing force (F_R) that opposes the setting force (F₁).

It should be noted that the relative movement of features is dependent on the design of the downhole tool 300. For example, in one embodiment the radially deployable element 215 moves from its radially retracted state to its partially radially deployed state before the mechanical slip 242 moves into gripping engagement with the bore 395. In yet another embodiment, the mechanical slip 242 moves into gripping engagement with the bore 395 before the radially deployable element 215 moves from its radially retracted state to its partially radially deployed state. In even yet another embodiment, the radially deployable element 215 and the mechanical slip 242 move in partial or complete unison to move the radially deployable element 215 from its radially retracted state to its partially radially deployed state and move the mechanical slip 242 into gripping engagement with the bore 395. Accordingly, unless otherwise required, the present disclosure should not be limited to any specific order of movement.

Turning to FIG. 3E, illustrated is the downhole tool 300 of FIG. 3D after continuing to apply the setting force (F₁) thereto. In this embodiment, with the second mechanical slip 252 and the mechanical slip 242 grippingly engaged with the bore 395 (e.g., on opposing sides of the radially deployable element 215), for example along with the opposing reactive force (F_R), any additional application of the setting force (F₁) may take advantage of the pressure intensifier 230 disclosed above, and thus create the amplified force (F_A). In this embodiment, the amplified force (F_A) would be focused upon the radially deployable element 215, and thus continue to move the radially deployable element 215 from the partially radially deployed state (e.g., as shown in FIG. 3D) to the fully radially deployed state (e.g., as shown in FIG. 3E).

As disclosed above, for example depending on a surface area difference between the first piston surface area (A₁) of the first piston 232 and the second piston surface area (A₂) of the second piston 234, the amplified force (F_A) may be 25% greater, if not 50% greater, if not 75% greater, if not 100% greater, if not 150% greater, if not 200% greater, if not 300% greater, if not 400% greater, if not 500% greater if not 750% greater, if not 1000% greater, if not 2000% greater, or more or less, than the setting force (F₁). Accordingly, in this embodiment a lesser setting force (F₁) (e.g., for whatever reason it may be lesser) may be used to generate a greater amplified force (F_A) for moving (e.g., continuing to move) the radially deployable element 215 from the partially radially deployed state (e.g., of FIG. 3D) to the fully radially deployed state (e.g., of FIG. 3E).

In at least one embodiment, a set load against the radially deployable element 215 may be maintained by holding the setting force (F₁) constant. Alternatively, a mechanical lock, such as a ratchet among others, may be used to maintain the set load on the radially deployable element 215, while reducing and/or eliminating the setting force (F₁). It should also be noted that the fluid pressure may build up over time due to temperature or external induced forces/pressure, thus a series of valves and/or location based fluid ports may be used to accommodate for this (e.g., as discussed in greater detail below).

Turning briefly to optional FIG. 3F, in one or more embodiments, an angled surface of the mandrel 210 may assist in setting the mechanical slip 242, but thereafter the mandrel may be allowed to continue to move under and at least partially past the mechanical slip 242, to in effect to help generate the greater amplified force (F_A). As discussed above, such a design may require modifications to keep the mechanical slip 242 fully engaged with the bore 395 as the upper surface of the mandrel 210 slides under the lower surface of the mechanical slip 242. Nevertheless, this embodiment is within the purview of the disclosure.

Turning now to FIG. 4, illustrated is a cross-sectional view a downhole tool 400 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 400, in the illustrated embodiment of FIG. 4, is similar in one or more respects to the downhole tool 200 of FIG. 2. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 400 of FIG. 4 differs, for the most part, from the downhole tool 200 of FIG. 2, in that its first piston 432 and fluid chamber 436 have moved. For example, in the illustrated embodiment of FIG. 4, at least a portion of the fluid chamber 436 is formed within the mandrel 210, and the first piston 432 having the first piston surface area (A₁) is coupled to and moves with its barrel wedge 444. Further to this embodiment, the first piston 432 having the first piston surface area (A₁) includes a first location fluid port 440 coupling the at least the portion of the fluid chamber 436 formed within the mandrel 210 and another portion of the fluid chamber 436 in contact with the second piston 234 having the second piston surface area (A₂).

Turning now to FIG. 5, illustrated is a cross-sectional view a downhole tool 500 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 500, in the illustrated embodiment of FIG. 5, is similar in one or more respects to the downhole tool 200 of FIG. 2. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 500 of FIG. 5 differs, for the most part, from the downhole tool 200 of FIG. 2, in that the downhole tool 500 additionally includes a third piston 532 having a third piston surface area (A₃), and a fourth piston 534 having a fourth piston surface area (A₄). In at least one embodiment, the fourth piston surface area (A₄) is greater than the third piston surface area (A₃). In at least one other embodiment, a ratio of the fourth piston surface area (A₄) to the third piston surface area (A₃) is equal (e.g., substantially equal, significantly equal, ideally equal, exactly equal, or perfectly equal) to a ratio of second piston surface area (A₂) to the first piston surface area (A₁) (e.g., A₄/A₃= A₂/A₁). Similarly, in at least one embodiment, a ratio of a volume (V₁) of the fluid in contact with the first piston surface area (A₁) and a volume (V₃) of the fluid in contact with the third piston surface area (A₃) is equal (e.g., substantially equal, significantly equal, ideally equal, exactly equal, or perfectly equal) to a ratio of a volume (V₂) of the fluid in contact with the second piston surface area (A₂) and a volume (V₄) of the fluid in contact with the fourth piston surface area (A₄) (e.g., V₁/V₃= V₂/V₄). In yet another embodiment, volume (V₂) is greater than volume (V₄), and thus volume (V₁) is not equal to volume (V₃). The downhole tool 500, in the illustrated embodiment, additionally includes a second fluid chamber 536 defined between the third piston surface area (A₃) of the third piston 532 and the fourth piston surface area (A₄) of the fourth piston 534, wherein the third piston surface area (A₃) of the third piston 532 is configured to extend at least partially within the second fluid chamber 536 thereby pressing a second fluid 538 located within the second fluid chamber 536 against the fourth piston surface area (A₄) of the fourth piston 534 to create a return force (F₄) sufficient move the radially deployable element 215 from the fully radially deployed state toward the partially radially deployed state. Essentially, in this embodiment the third and fourth pistons 532, 534 (e.g., and associated second fluid chamber 536 and second fluid 538) are configured to assist in the radially deployable element 215 relaxing and/or returning toward the radially retracted state when the setting force (F₁) is removed. In at least one embodiment, the volume of the fluid chamber 236 and the fluid chamber 536 are substantially similar, if not significantly similar, if not ideally similar, if not exactly similar, if not perfectly similar.

Further to the embodiment of FIG. 5, in one or more embodiments at least a portion of the second fluid chamber 536 is formed within the mandrel 210, and the third piston 532 having the third piston surface area (A₃) is coupled to and moves with the second barrel wedge 254. Further to the embodiment of FIG. 5, in one or more embodiment, the second and fourth pistons 234, 534 form a single first integral piston having the second piston surface area (A₂) on a first side thereof distal the radially deployable element 215 and the third piston surface area (A₃) on a second side thereof proximate the radially deployable element 215. In at least one embodiment, the second and fourth pistons 234, 534 are attached together to form the single first integral piston, and in yet another embodiment the second and fourth pistons 234, 534 are integrally manufactured together to form the single first integral piston.

Turning to FIGS. 6A through 6F, illustrated are cross-sectional views of a downhole tool 600 designed, manufactured and/or operated according to one embodiment of the disclosure at various different deployment states. The downhole tool 600, in the illustrated embodiment of FIGS. 6A through 6F, is similar in one or more respects to the downhole tool 500 of FIG. 5. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 600, in the illustrated embodiment of FIGS. 6A through 6F is operated in a similar fashion to the downhole tool 300 of FIGS. 3A through 3E. For example, the operational steps of FIGS. 6A through 6E are substantially similar to the operational steps of FIGS. 3A through 3E. The downhole tool 600, however, benefits from having the third and fourth pistons 532, 534 (e.g., and associated second fluid chamber 536 and second fluid 538), which are configured to assist in the radially deployable element 215 relaxing and/or returning toward the radially retracted state when the setting force (F₁) is removed. It is this step that is shown in FIG. 6F. One skilled in the art, given the above, would understand how to operate the downhole tool 600 of FIGS. 6A through 6F.

Turning now to FIG. 7, illustrated is a cross-sectional view a downhole tool 700 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 700, in the illustrated embodiment of FIG. 7, is similar in one or more respects to the downhole tool 500 of FIG. 5. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 700 of FIG. 7 differs, for the most part, from the downhole tool 500 of FIG. 5, in that in the downhole tool 700 at least a portion of the second fluid chamber 736 (e.g., having a second fluid 738 therein) is formed within the second barrel wedge 754, and the third piston 732 having the third piston surface area (A₃) is coupled to and moves with the mandrel 210. Further to this embodiment, the third piston 732 having the third piston surface area (A₃) includes a second location fluid port 780 therein coupling the at least the portion of the second fluid chamber 736 formed within the second barrel wedge 754 and another portion of the second fluid chamber 736 in contact with the fourth piston 534 having the fourth piston surface area (A₄).

Turning now to FIG. 8, illustrated is a cross-sectional view a downhole tool 800 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 800, in the illustrated embodiment of FIG. 8, is similar in one or more respects to the downhole tool 200 of FIG. 2. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 800 of FIG. 8 differs, for the most part, from the downhole tool 200 of FIG. 2, in that in the downhole tool 800 includes a return mechanism 810 positioned about the mandrel 210. In at least this one embodiment, the return mechanism 810 is configured to create a return force (F₅) sufficient to move the radially deployable element 215 from the fully radially deployed state toward the partially radially deployed state. Essentially, in this embodiment the return mechanism 810 is configured to assist in the radially deployable element 215 relaxing and/or returning toward the radially retracted state when the setting force (F₁) is removed. The return mechanism 810 can be any device capable of creating the return force (F₅) sufficient to move the radially deployable element 215 from the fully radially deployed state toward the partially radially deployed state. In at least one embodiment, the return mechanism 810 is a spring mechanism, whether a mechanical spring mechanism or a fluid spring mechanism, among others. It should be noted that the embodiment of FIG. 8 may be used alone, or in conjunction with the embodiment of FIG. 5, to return the radially deployable element 215 from the fully radially deployed state toward the partially radially deployed state.

Turning now to FIG. 9, illustrated is a cross-sectional view a downhole tool 900 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 900, in the illustrated embodiment of FIG. 9, is similar in one or more respects to the downhole tool 200 of FIG. 2. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 900 of FIG. 9 differs, for the most part, from the downhole tool 200 of FIG. 2, in that in the downhole tool 900 the mechanical slip 242 and barrel wedge 244 are located about the mandrel 210 proximate the downhole side of the radially deployable element 215 and the second mechanical slip 252 and second barrel wedge 254 are located about the mandrel 210 proximate the uphole side of the radially deployable element 215. Accordingly, in this embodiment, the setting force (F₁) is an uphole directed force upon the mandrel 210, for example creating tension in the mandrel 210.

Turning to FIGS. 10A through 10E, illustrated are cross-sectional views of a downhole tool 1000 designed, manufactured and/or operated according to one embodiment of the disclosure at various different deployment states. The downhole tool 1000, in the illustrated embodiment of FIGS. 10A through 10E, is similar in one or more respects to the downhole tool 900 of FIG. 9. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1000, in the illustrated embodiment of FIGS. 10A through 10E is operated in a similar fashion to the downhole tool 300 of FIGS. 3A through 3E, except for it is reversed and thus tension is applied to the mandrel 210 to set it. One skilled in the art, given the above, would understand how to operate the downhole tool 1000 of FIGS. 10A through 10E.

Turning now to FIG. 11, illustrated is a cross-sectional view a downhole tool 1100 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1100, in the illustrated embodiment of FIG. 11, is similar in one or more respects to the downhole tool 700 of FIG. 7. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1100 of FIG. 11 differs, for the most part, from the downhole tool 700 of FIG. 7, in that the downhole tool 1100 further includes a fifth piston 1132 having a fifth piston surface area (A₅) located on an opposing side of the radially deployable element 215 as the first and second pistons 232, 234, as well as a sixth piston 1134 having a sixth piston surface area (A₆) located on the opposing side of the radially deployable element 215 as the first and second pistons 232, 234. The downhole tool 1100 of FIG. 11, in at least one embodiment, further includes a third fluid chamber 1136 defined between the fifth piston surface area (A₅) of the fifth piston 1132 and a first edge 1154a of the second barrel wedge 1154, as well as a fourth fluid chamber 1138 defined between the sixth piston surface area (A₆) of the sixth piston 1134 and a second edge 1154b of the second barrel wedge 1154. In at least one other embodiment, the downhole tool 1100 additionally includes a third location fluid port 1180 fluidly coupling the third piston 732 having the third piston surface area (A₃), the fourth piston 534 having the fourth piston surface area (A₄), and the fifth piston 1132 having a fifth piston surface area (A₅), as well as a fourth location fluid port 1185 fluidly coupling the second piston 234 having the second piston surface area (A₂) and the sixth piston 1134 having the sixth piston surface area (A₆). Further to this embodiment, the third location fluid port 1180 is located at least partially within the second barrel wedge 1154 and the mandrel 210, and the fourth location fluid port 1185 is located at least partially within the mandrel 210. It should be noted that the embodiment of FIG. 11 can be configured in such a way to act symmetrically on both the first and second deployment shoes 220a, 220b, for example by controlling the location of the third and fourth location fluid ports 1180, 1185. Additionally, this design may be employed on the tension based design of FIGS. 9 through 10E.

Turning now to FIG. 12, illustrated is a cross-sectional view a downhole tool 1200 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1200, in the illustrated embodiment of FIG. 12, is similar in one or more respects to the downhole tool 1100 of FIG. 11. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1200 of FIG. 12 differs, for the most part, from the downhole tool 1100 of FIG. 11, in that its third location fluid port 1280 is located at least partially within the third piston 732 and the mandrel 210, and the fourth location fluid port 1285 is located at least partially within the mandrel 210.

Turning now to FIG. 13, illustrated is a cross-sectional view a downhole tool 1300 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1300, in the illustrated embodiment of FIG. 13, is similar in one or more respects to the downhole tool 1200 of FIG. 12. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1300 of FIG. 13 differs, for the most part, from the downhole tool 1200 of FIG. 12, in that the downhole tool 1300 additionally includes one or more additional location fluid ports 1380 and one or more associated valve members (V) selectively allowing fluid to move between two more of the first, second, third and fourth fluid chambers 236, 736, 1136, 1138. In one or more embodiment, various valve arrangements can be employed to equalize the hydrostatic pressure with or without exchange of fluid with the wellbore. Fluid flow may also be split to activate other mechanisms. Hence a system of valves (check, relief, reducing, flow control, divider, counterbalance, etc.) can be incorporated to manipulate (relief, direct, equalize, etc.) the fluid pressure and flow.

Turning now to FIG. 14, illustrated is a cross-sectional view a downhole tool 1400 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1400, in the illustrated embodiment of FIG. 14, is similar in one or more respects to the downhole tool 1200 of FIG. 12. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1400 of FIG. 14 differs, for the most part, from the downhole tool 1200 of FIG. 12, in that in the downhole tool 1400 the first and second barrel wedges 1444a, 1444b are a single unitary barrel wedge 1448, and furthermore the third and fourth location fluid ports 1480, 1485 are at least partially routed through the single unitary barrel wedge 1448. Further to the embodiment of FIG. 14, the single unitary barrel wedge 1448 is connected to the second mechanical slip 252 (e.g., shared mechanical slip), thus eliminating any sliding between the elements and mandrel 210 when symmetric pack-off is performed. While not illustrated, the aforementioned one or more additional valve and/or ports may also be employed with this embodiment.

It should be noted that the above ideas and/or methods can be extended to the use of an external mechanical setting/activation/operational tool where the force multiplier is separate and disconnected from the downhole tool after activation. Besides amplifying the setting force (F₁), this method can also be used to produce a lower output force to shift components (e.g., sleeves, housings, flanges, etc.) in order to open or close ports or flow channels, for example. Additionally, multiple combination of this method with or without the use of valves can be arranged in series or parallel to produce a series of chain reactions to activate different components requiring varying forces and hence varying sequence.

Aspects disclosed herein include:

A. A downhole tool, the downhole tool including: 1) a mandrel; 2) a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state, wherein the mandrel is configured to receive a setting force (F₁) sufficient to move the deployable element from the retracted state to the partially deployed state; and 3) a pressure intensifier positioned about the mandrel, the pressure intensifier configured to receive the setting force (F₁) and amplify it to an amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state, the pressure intensifier including: a) a first piston having a first piston surface area (A₁); b) a second piston having a second piston surface area (A₂), wherein the second piston surface area (A₂) is greater than the first piston surface area (A₁); and c) a fluid chamber defined between the first piston surface area (A₁) of the first piston and the second piston surface area (A₂) of the second piston, wherein the first piston surface area (A₁) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel is receiving the setting force (F₁) thereby pressing fluid located within the fluid chamber against the second piston surface area (A₂) of the second piston to create the amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state.

B. A method, the method including: 1) positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including: a) a mandrel; b) a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state; and c) a pressure intensifier positioned about the mandrel, the pressure intensifier including: i) a first piston having a first piston surface area (A₁); ii) a second piston having a second piston surface area (A₂), wherein the second piston surface area (A₂) is greater than the first piston surface area (A₁); and iii) a fluid chamber defined between the first piston surface area (A₁) of the first piston and the second piston surface area (A₂) of the second piston, wherein the first piston surface area (A₁) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel moves; 2) applying a setting force (F₁) to the mandrel, the setting force (F₁) moving the deployable element from the retracted state to the partially deployed state; and 3) continuing to apply the setting force (F₁) to the mandrel, the continued application of the setting force (F₁) causing the first piston having the first piston surface area (A₁) to press fluid located within the fluid chamber against the second piston surface area (A₂) of the second piston to create an amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state.

C. A well system, the well system including:

• • 1) a wellbore extending through one or more subterranean formations; and
  • 2) a downhole tool positioned within the wellbore, the downhole tool including:
    • a) a mandrel;
    • b) a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state, wherein the mandrel is configured to receive a setting force (F₁) sufficient to move the deployable element from the retracted state to the partially deployed state; and
    • c) a pressure intensifier positioned about the mandrel, the pressure intensifier configured to receive the setting force (F₁) and amplify it to an amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state, the pressure intensifier including:
      • i) a first piston having a first piston surface area (A₁);
      • ii) a second piston having a second piston surface area (A₂), wherein the second piston surface area (A₂) is greater than the first piston surface area (A₁); and
      • iii) a fluid chamber defined between the first piston surface area (A₁) of the first piston and the second piston surface area (A₂) of the second piston, wherein the first piston surface area (A₁) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel is receiving the setting force (F₁) thereby pressing fluid located within the fluid chamber against the second piston surface area (A₂) of the second piston to create the amplified force (F_A) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state.

Aspects A, B, and C may have one or more of the following additional elements in combination: Element 1: wherein the deployable element is a radially deployable element, the retracted state is a radially retracted state, the partially deployed state is a partially radially deployed state, and the fully deployed state is a fully radially deployed state, the radially deployable element configured to move between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, and further including: first and second deployment shoes located on opposing sides of the radially deployable element, the first and second deployment shoes configured to translate relative to one another to move the radially deployable element between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, wherein the mandrel is configured to receive a setting force (F₁) sufficient to move the radially deployable element from the radially retracted state to the partially radially deployed state. Element 2: further including a reactive force assembly positioned about the mandrel, the reactive force assembly configured to substantially focus the amplified force (F_A) upon the radially deployable element to continue to move the radially deployable element from the partially radially deployed state to the fully radially deployed state. Element 3: wherein the reactive force assembly includes a mechanical slip and a barrel wedge, the barrel wedge positioned between the mechanical slip and the first deployment shoe, wherein the barrel wedge is configured to generate an opposing reactive force (F_R) that opposes the setting force (F₁) to force the mechanical slip into contact with a wellbore tubular located thereabout and substantially focus the amplified force (F_A) upon the radially deployable element to continue to move the radially deployable element from the partially radially deployed state to the fully radially deployed state. Element 4: wherein the second piston forms at least a portion of the first deployment shoe. Element 5: wherein at least a portion of the fluid chamber is formed within the barrel wedge, and further wherein the first piston having the first piston surface area (A₁) is coupled to and moves with the mandrel. Element 6: wherein at least a portion of the fluid chamber is formed within the mandrel, and further wherein the first piston having the first piston surface area (A₁) is coupled to and moves with the barrel wedge. Element 7: wherein the first piston having the first piston surface area (A₁) includes a first location fluid port coupling the at least the portion of the fluid chamber formed within the mandrel and another portion of the fluid chamber in contact with the second piston having the second piston surface area (A₂). Element 8: wherein the mechanical slip and the barrel wedge are a first mechanical slip and a first barrel wedge, and further including a second mechanical slip and second barrel wedge positioned on an opposing side of the radially deployable element as the first mechanical slip and the first barrel wedge. Element 9: wherein the second barrel wedge and the second deployment shoe form a single integral element. Element 10: wherein the radially deployable element has an uphole side and a downhole side, and further wherein the first mechanical slip and first barrel wedge are located about the mandrel proximate the uphole side and the second mechanical slip and second barrel wedge are located about the mandrel proximate the downhole side, and further wherein the setting force (F₁) is a downhole directed force upon the mandrel. Element 11: wherein the radially deployable element has an uphole side and a downhole side, and further wherein the first mechanical slip and first barrel wedge are located about the mandrel proximate the downhole side and the second mechanical slip and second barrel wedge are located about the mandrel proximate the uphole side, and further wherein the setting force (F₁) is an uphole directed force upon the mandrel. Element 12: further including: a third piston having a third piston surface area (A₃); a fourth piston having a fourth piston surface area (A₄); a second fluid chamber defined between the third piston surface area (A₃) of the third piston and the fourth piston surface area (A₄) of the fourth piston, wherein the third piston surface area (A₃) of the third piston is configured to extend at least partially within the second fluid chamber thereby pressing a second fluid located within the second fluid chamber against the fourth piston surface area (A₄) of the fourth piston to create a return force (F₄) sufficient move the radially deployable element from the fully radially deployed state toward the partially radially deployed state. Element 13: wherein at least a portion of the second fluid chamber is formed within the mandrel, and further wherein the third piston having the third piston surface area (A₃) is coupled to and moves with the second barrel wedge. Element 14: wherein at least a portion of the second fluid chamber is formed within the second barrel wedge, and further wherein the third piston having the third piston surface area (A₃) is coupled to and moves with the mandrel. Element 15: wherein the third piston having the third piston surface area (A₃) includes a second location fluid port therein coupling the at least the portion of the second fluid chamber formed within the second barrel wedge and another portion of the second fluid chamber in contact with the fourth piston having the fourth piston surface area (A₄). Element 16: wherein the second and third pistons form a single first integral piston having the second piston surface area (A₂) on a first side thereof distal the radially deployable element and the third piston surface area (A₃) on a second side thereof proximate the radially deployable element. Element 17: further including: a fifth piston having a fifth piston surface area (A₅) located on an opposing side of the radially deployable element as the first and second pistons; a sixth piston having a sixth piston surface area (A₆) located on the opposing side of the radially deployable element as the first and second pistons; a third fluid chamber defined between the fifth piston surface area (A₅) of the fifth piston and a first edge of the second barrel wedge; a fourth fluid chamber defined between the sixth piston surface area (A₆) of the sixth piston and a second edge of the second barrel wedge; a third location fluid port fluidly coupling the third piston having the third piston surface area (A₃), the fourth piston having the fourth piston surface area (A₄), and the fifth piston having a fifth piston surface area (A₅); and a fourth location fluid port fluidly coupling the second piston having the second piston surface area(A₂) and the sixth piston having the sixth piston having the sixth piston surface area (A₆). Element 18: wherein the third location fluid port is located at least partially within the second barrel wedge and the mandrel, and the fourth location fluid port is located at least partially within the mandrel. Element 19: wherein the third location fluid port is located at least partially within the third piston and the mandrel, and the fourth location fluid port is located at least partially within the mandrel. Element 20: further including additional location fluid ports and associated valve members selectively allowing fluid to move between two more of the first, second, third and fourth fluid chambers. Element 21: wherein the first and second barrel wedges are a single unitary barrel wedge, and further wherein the third and fourth location fluid ports are at least partially routed through the single unitary barrel wedge. Element 22: further including a return mechanism positioned about the mandrel, the return mechanism configured to create a return force (F₅) sufficient to move the radially deployable element from the fully radially deployed state toward the partially radially deployed state. Element 23: further including a locking mechanism, the locking mechanism configured to fix the mandrel, first and second deployment shoes and radially deployable element relative to one another when the downhole tool is being run-in-hole, but configured to release to allow the mandrel, first and second deployment shoes and radially deployable element to translate relative to one another when the downhole tool is ready to be set. Element 24: wherein the locking mechanism is a J-slot mechanism. Element 25: further including a drag block releasably coupled with the mandrel, the drag block configured to engage with and generate friction with a wellbore tubular as the downhole tool is being deployed within the wellbore tubular.

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.

Claims

1. A downhole tool, comprising:

a mandrel;

a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state, wherein the mandrel is configured to receive a setting force (F1) sufficient to move the deployable element from the retracted state to the partially deployed state; and

a pressure intensifier positioned about the mandrel, the pressure intensifier configured to receive the setting force (F1) and amplify it to an amplified force (FA) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state, the pressure intensifier including: a first piston having a first piston surface area (A1); a second piston having a second piston surface area (A2), wherein the second piston surface area (A2) is greater than the first piston surface area (A1); and a fluid chamber defined between the first piston surface area (A1) of the first piston and the second piston surface area (A2) of the second piston, wherein the first piston surface area (A1) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel is receiving the setting force (F1) thereby pressing fluid located within the fluid chamber against the second piston surface area (A2) of the second piston to create the amplified force (FA) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state.

2. The downhole tool as recited in claim 1, wherein the deployable element is a radially deployable element, the retracted state is a radially retracted state, the partially deployed state is a partially radially deployed state, and the fully deployed state is a fully radially deployed state, the radially deployable element configured to move between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, and further including:

first and second deployment shoes located on opposing sides of the radially deployable element, the first and second deployment shoes configured to translate relative to one another to move the radially deployable element between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, wherein the mandrel is configured to receive a setting force (F1) sufficient to move the radially deployable element from the radially retracted state to the partially radially deployed state.

3. The downhole tool as recited in claim 2, further including a reactive force assembly positioned about the mandrel, the reactive force assembly configured to substantially focus the amplified force (FA) upon the radially deployable element to continue to move the radially deployable element from the partially radially deployed state to the fully radially deployed state.

4. The downhole tool as recited in claim 3, wherein the reactive force assembly includes a mechanical slip and a barrel wedge, the barrel wedge positioned between the mechanical slip and the first deployment shoe, wherein the barrel wedge is configured to generate an opposing reactive force (FR) that opposes the setting force (F1) to force the mechanical slip into contact with a wellbore tubular located thereabout and substantially focus the amplified force (FA) upon the radially deployable element to continue to move the radially deployable element from the partially radially deployed state to the fully radially deployed state.

5. The downhole tool as recited in claim 4, wherein the second piston forms at least a portion of the first deployment shoe.

6. The downhole tool as recited in claim 4, wherein at least a portion of the fluid chamber is formed within the barrel wedge, and further wherein the first piston having the first piston surface area (A1) is coupled to and moves with the mandrel.

7. The downhole tool as recited in claim 4, wherein at least a portion of the fluid chamber is formed within the mandrel, and further wherein the first piston having the first piston surface area (A1) is coupled to and moves with the barrel wedge.

8. The downhole tool as recited in claim 7, wherein the first piston having the first piston surface area (A1) includes a first location fluid port coupling the at least the portion of the fluid chamber formed within the mandrel and another portion of the fluid chamber in contact with the second piston having the second piston surface area (A2).

9. The downhole tool as recited in claim 4, wherein the mechanical slip and the barrel wedge are a first mechanical slip and a first barrel wedge, and further including a second mechanical slip and second barrel wedge positioned on an opposing side of the radially deployable element as the first mechanical slip and the first barrel wedge.

10. The downhole tool as recited in claim 9, wherein the second barrel wedge and the second deployment shoe form a single integral element.

11. The downhole tool as recited in claim 9, wherein the radially deployable element has an uphole side and a downhole side, and further wherein the first mechanical slip and first barrel wedge are located about the mandrel proximate the uphole side and the second mechanical slip and second barrel wedge are located about the mandrel proximate the downhole side, and further wherein the setting force (F1) is a downhole directed force upon the mandrel.

12. The downhole tool as recited in claim 9, wherein the radially deployable element has an uphole side and a downhole side, and further wherein the first mechanical slip and first barrel wedge are located about the mandrel proximate the downhole side and the second mechanical slip and second barrel wedge are located about the mandrel proximate the uphole side, and further wherein the setting force (F1) is an uphole directed force upon the mandrel.

13. The downhole tool as recited in claim 9, further including:

a third piston having a third piston surface area (A3);

a fourth piston having a fourth piston surface area (A4); and

a second fluid chamber defined between the third piston surface area (A3) of the third piston and the fourth piston surface area (A4) of the fourth piston, wherein the third piston surface area (A3) of the third piston is configured to extend at least partially within the second fluid chamber thereby pressing a second fluid located within the second fluid chamber against the fourth piston surface area (A4) of the fourth piston to create a return force (F4) sufficient move the radially deployable element from the fully radially deployed state toward the partially radially deployed state.

14. The downhole tool as recited in claim 13, wherein at least a portion of the second fluid chamber is formed within the mandrel, and further wherein the third piston having the third piston surface area (A3) is coupled to and moves with the second barrel wedge.

15. The downhole tool as recited in claim 13, wherein at least a portion of the second fluid chamber is formed within the second barrel wedge, and further wherein the third piston having the third piston surface area (A3) is coupled to and moves with the mandrel.

16. The downhole tool as recited in claim 15, wherein the third piston having the third piston surface area (A3) includes a second location fluid port therein coupling the at least the portion of the second fluid chamber formed within the second barrel wedge and another portion of the second fluid chamber in contact with the fourth piston having the fourth piston surface area (A4).

17. The downhole tool as recited in claim 13, wherein the second and third pistons form a single first integral piston having the second piston surface area (A2) on a first side thereof distal the radially deployable element and the third piston surface area (A3) on a second side thereof proximate the radially deployable element.

18. The downhole tool as recited in claim 13, further including:

a fifth piston having a fifth piston surface area (A5) located on an opposing side of the radially deployable element as the first and second pistons;

a sixth piston having a sixth piston surface area (A6) located on the opposing side of the radially deployable element as the first and second pistons;

a third fluid chamber defined between the fifth piston surface area (A5) of the fifth piston and a first edge of the second barrel wedge;

a fourth fluid chamber defined between the sixth piston surface area (A6) of the sixth piston and a second edge of the second barrel wedge;

a third location fluid port fluidly coupling the third piston having the third piston surface area (A3), the fourth piston having the fourth piston surface area (A4), and the fifth piston having a fifth piston surface area (A5); and

a fourth location fluid port fluidly coupling the second piston having the second piston surface area (A2) and the sixth piston having the sixth piston having the sixth piston surface area (A6).

19. The downhole tool as recited in claim 18, wherein the third location fluid port is located at least partially within the second barrel wedge and the mandrel, and the fourth location fluid port is located at least partially within the mandrel.

20. The downhole tool as recited in claim 18, wherein the third location fluid port is located at least partially within the third piston and the mandrel, and the fourth location fluid port is located at least partially within the mandrel.

21. The downhole tool as recited in claim 18, further including additional location fluid ports and associated valve members selectively allowing fluid to move between two more of the first, second, third and fourth fluid chambers.

22. The downhole tool as recited in claim 18, wherein the first and second barrel wedges are a single unitary barrel wedge, and further wherein the third and fourth location fluid ports are at least partially routed through the single unitary barrel wedge.

23. The downhole tool as recited in claim 4, further including a return mechanism positioned about the mandrel, the return mechanism configured to create a return force (F5) sufficient to move the radially deployable element from the fully radially deployed state toward the partially radially deployed state.

24. The downhole tool as recited in claim 2, further including a locking mechanism, the locking mechanism configured to fix the mandrel, first and second deployment shoes and radially deployable element relative to one another when the downhole tool is being run-in-hole, but configured to release to allow the mandrel, first and second deployment shoes and radially deployable element to translate relative to one another when the downhole tool is ready to be set.

25. The downhole tool as recited in claim 24, wherein the locking mechanism is a J-slot mechanism.

26. The downhole tool as recited in claim 2, further including a drag block releasably coupled with the mandrel, the drag block configured to engage with and generate friction with a wellbore tubular as the downhole tool is being deployed within the wellbore tubular.

27. A method, comprising:

positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including: a mandrel; a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state; and a pressure intensifier positioned about the mandrel, the pressure intensifier including: a first piston having a first piston surface area (A1); a second piston having a second piston surface area (A2), wherein the second piston surface area (A2) is greater than the first piston surface area (A1); and a fluid chamber defined between the first piston surface area (A1) of the first piston and the second piston surface area (A2) of the second piston, wherein the first piston surface area (A1) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel moves; applying a setting force (F1) to the mandrel, the setting force (F1) moving the deployable element from the retracted state to the partially deployed state; and continuing to apply the setting force (F1) to the mandrel, the continued application of the setting force (F1) causing the first piston having the first piston surface area (A1) to press fluid located within the fluid chamber against the second piston surface area (A2) of the second piston to create an amplified force (FA) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state.

28. The method as recited in claim 27, wherein the deployable element is a radially deployable element, the retracted state is a radially retracted state, the partially deployed state is a partially radially deployed state, and the fully deployed state is a fully radially deployed state, the radially deployable element configured to move between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, and further including:

first and second deployment shoes located on opposing sides of the radially deployable element, the first and second deployment shoes configured to translate relative to one another to move the radially deployable element between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, wherein the mandrel is configured to receive a setting force (F1) sufficient to move the radially deployable element from the radially retracted state to the partially radially deployed state.

29. The method as recited in claim 28, wherein the downhole tool further includes a reactive force assembly positioned about the mandrel, the reactive force assembly configured to substantially focus the amplified force (FA) upon the radially deployable element to continue to move the radially deployable element from the partially radially deployed state to the fully radially deployed state.

30. The method as recited in claim 29, wherein the reactive force assembly includes a mechanical slip and a barrel wedge, the barrel wedge positioned between the mechanical slip and the first deployment shoe, wherein the barrel wedge is configured to generate an opposing force (FR) that opposes the setting force (F1) to force the mechanical slip into contact with a wellbore tubular located thereabout and substantially focus the amplified force (FA) upon the radially deployable element to continue to move the radially deployable element from the partially radially deployed state to the fully radially deployed state.

31. The method as recited in claim 30, wherein the applying the setting force (F1) generates the opposing force (FR).

32. A well system, comprising:

a wellbore extending through one or more subterranean formations; and

a downhole tool positioned within the wellbore, the downhole tool including: a mandrel; a deployable element positioned about the mandrel, the deployable element configured to move between a retracted state, a partially deployed state, and a fully deployed state, wherein the mandrel is configured to receive a setting force (F1) sufficient to move the deployable element from the retracted state to the partially deployed state; and a pressure intensifier positioned about the mandrel, the pressure intensifier configured to receive the setting force (F1) and amplify it to an amplified force (FA) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state, the pressure intensifier including: a first piston having a first piston surface area (A1); a second piston having a second piston surface area (A2), wherein the second piston surface area (A2) is greater than the first piston surface area (A1); and a fluid chamber defined between the first piston surface area (A1) of the first piston and the second piston surface area (A2) of the second piston, wherein the first piston surface area (A1) of the first piston is configured to extend at least partially within the fluid chamber as the mandrel is receiving the setting force (F1) thereby pressing fluid located within the fluid chamber against the second piston surface area (A2) of the second piston to create the amplified force (FA) sufficient to continue to move the deployable element from the partially deployed state to the fully deployed state.

33. The well system as recited in claim 32, wherein the deployable element is a radially deployable element, the retracted state is a radially retracted state, the partially deployed state is a partially radially deployed state, and the fully deployed state is a fully radially deployed state, the radially deployable element configured to move between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, and further including:

first and second deployment shoes located on opposing sides of the radially deployable element, the first and second deployment shoes configured to translate relative to one another to move the radially deployable element between the radially retracted state, the partially radially deployed state, and the fully radially deployed state, wherein the mandrel is configured to receive a setting force (F1) sufficient to move the radially deployable element from the radially retracted state to the partially radially deployed state.