Downhole tool with an expandable sleeve

Description

BACKGROUND

There are various methods by which openings are created in a production liner for injecting fluid into a formation. In a “plug and perf” frac job, the production liner is made up from standard lengths of casing. Initially, the liner does not have any openings through its sidewalls. The liner is installed in the wellbore, either in an open bore using packers or by cementing the liner in place, and the liner walls are then perforated. The perforations are typically created by perforation guns that discharge shaped charges through the liner and, if present, adjacent cement.

The production liner is typically perforated first in a zone near the bottom of the well. Fluids then are pumped into the well to fracture the formation in the vicinity of the perforations. After the initial zone is fractured, a plug is installed in the liner at a position above the fractured zone to isolate the lower portion of the liner. The liner is then perforated above the plug in a second zone, and the second zone is fractured. This process is repeated until all zones in the well are fractured.

The plug and perf method is widely practiced, but it has a number of drawbacks, including that it can be extremely time consuming. The perforation guns and plugs are generally run into the well and operated individually. After the frac job is complete, the plugs are removed (e.g., drilled out) to allow production of hydrocarbons through the liner.

SUMMARY

Embodiments of the disclosure may provide a downhole tool including an expandable sleeve defining a bore extending axially therethrough, a first swage positioned at least partially within the bore and including a valve seat configured to receive an obstructing member, such that the obstructing member and the first swage substantially prevent fluid communication through the bore when the obstructing member is seated in the valve seat, and a second swage positioned at least partially within the bore. The first and second swages are configured to move toward one another in the bore, such that the first and second swages deform end portions of the expandable sleeve radially outwards and into engagement with a surrounding tubular, and the expandable sleeve, in an expanded configuration in which the end portions engage the surrounding tubular, defines an unexpanded portion between the expanded end portions.

Embodiments of the disclosure may also provide a tool assembly including a downhole tool that includes an expandable sleeve defining a bore therethrough, a first swage positioned at least partially within the bore and including a valve seat configured to receive an obstructing member, such that the obstructing member and the first swage substantially prevent fluid communication through the bore when the obstructing member is seated in the valve seat, and a second swage positioned at least partially within the bore. The tool assembly also includes a setting tool including an outer body configured to engage the first swage and apply a force on the first swage directed toward the second swage, and an inner body extending through the first swage, the expandable sleeve, and the second swage, the inner body being coupled to the second swage and configured to apply a force on the second swage opposite in direction to the force on the first swage. The first and second swages are configured to move toward one another in the bore, such that the first and second swages deform end portions of the expandable sleeve radially outwards and into engagement with a surrounding tubular, and the expandable sleeve, in an expanded configuration in which the end portions engage the surrounding tubular, defines an unexpanded portion between the expanded end portions.

Embodiments of the disclosure may further provide a downhole tool that includes an expandable sleeve defining a bore extending axially therethrough, a first swage positioned at least partially within the bore and including a valve seat configured to receive an obstructing member, such that the obstructing member and the first swage substantially prevent fluid communication through the bore when the obstructing member is seated in the valve seat, a second swage positioned at least partially within the bore, and a gripping and sealing feature applied to at least a portion of an outer diameter surface of the expandable sleeve. The first and second swages are configured to move toward one another in the bore, such that the first and second swages deform end portions of the expandable sleeve radially outwards and into engagement with a surrounding tubular, wherein the expandable sleeve, in an expanded configuration in which the end portions engage the surrounding tubular, defines an unexpanded portion between the expanded end portions, and wherein the gripping and sealing feature applied to the outer diameter surface grips and seals with the surrounding tubular.

The foregoing summary is intended merely to introduce some aspects of the following disclosure and is thus not intended to be exhaustive, identify key features, or in any way limit the disclosure or the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure may best be understood by referring to the following description and accompanying drawings that are used to illustrate embodiments of the invention. In the drawings:

FIG. 1 illustrates a cross-sectional side view of a downhole tool in a first, run-in configuration, according to an embodiment.

FIG. 2 illustrates a flowchart of a method for actuating the downhole tool, according to an embodiment.

FIG. 3 illustrates a cross-sectional side view of the downhole tool of FIG. 1 after a sleeve has been set, according to an embodiment.

FIG. 4 illustrates a cross-sectional side view of a portion of the downhole tool of FIG. 1 after a setting tool is removed, leaving a swage within the sleeve, according to an embodiment.

FIGS. 5 and 6 illustrate a cross-sectional side view and a cross-sectional perspective view, respectively, of a portion of the downhole tool of FIG. 1 after a ball is received in the sleeve, according to an embodiment.

FIG. 7 illustrates a cross-sectional side view of another downhole tool in a first, run-in configuration, according to an embodiment.

FIG. 8 illustrates a flowchart of another method for actuating the downhole tool of FIG. 8, according to an embodiment.

FIG. 9 illustrates a cross-sectional side view of the downhole tool of FIG. 7 after a sleeve has been set, according to an embodiment.

FIGS. 10 and 11 illustrate a cross-sectional side view and a cross-sectional perspective view, respectively, of a portion of the downhole tool of FIG. 7 after a setting tool is removed and a ball is received in a swage, according to an embodiment.

FIG. 12 illustrates a cross-sectional side view of a portion of the downhole tool of FIG. 7 after a ball is received in the sleeve, according to an embodiment.

FIG. 13 illustrates a cross-sectional side view of another downhole tool in a first, run-in configuration, according to an embodiment.

FIG. 14 illustrates a flowchart of another method for actuating the downhole tool of FIG. 13, according to an embodiment.

FIG. 15 illustrates a cross-sectional side view of the downhole tool of FIG. 13 after a sleeve has been set, according to an embodiment.

FIGS. 16 and 17 illustrate a cross-sectional side view and a cross-sectional perspective view, respectively, of a portion of the downhole tool of FIG. 13 after a setting tool is removed and a ball is received in a swage, according to an embodiment.

FIG. 18 illustrates a cross-sectional side view of a portion of the downhole tool of FIG. 13 after the setting tool is removed and the ball is received in a swage, where the sleeve includes an inner shoulder, according to an embodiment.

FIG. 19 illustrates a perspective view of another expandable sleeve, according to an embodiment.

FIG. 20 illustrates a side, cross-sectional view of another downhole tool in a run-in configuration, according to an embodiment.

FIG. 21 illustrates a side, cross-sectional view of the downhole tool of FIG. 20, but in a set configuration, according to an embodiment.

FIG. 22 illustrates a side, cross-sectional view of the downhole tool of FIGS. 20 and 21, engaging an isolation device, according to an embodiment.

FIG. 23 illustrates a side, cross-sectional view of another downhole tool in a run-in configuration, according to an embodiment.

FIG. 24 illustrates a side, cross-sectional view of the downhole tool of FIG. 23, but in a set configuration, according to an embodiment.

FIG. 25 illustrates a side, cross-sectional view of the downhole tool of FIGS. 23 and 24, engaging an isolation device, according to an embodiment.

FIG. 26 illustrates a side, schematic view of a slips, according to an embodiment.

FIG. 27 illustrates a side, cross-sectional view of a slips, according to an embodiment.

FIGS. 28A, 28B, and 28C illustrate views of an insert for a slips, according to an embodiment.

FIGS. 29, 30, and 31 illustrate side, cross-sectional views of another downhole tool in a run-in configuration, a set configuration, and a released configuration, respectively, according to an embodiment.

FIG. 32 illustrates a flowchart of a method for plugging an oilfield tubular in a well, according to an embodiment.

FIG. 33 illustrates a partial, cross-sectional view of another embodiment of the downhole tool, with a setting tool received therein prior to expansion.

FIG. 34 illustrates a side, cross-sectional view of another embodiment of the downhole tool in set state, showing an “hour-glass” shape of the set tool.

DETAILED DESCRIPTION

The following disclosure describes several embodiments for implementing different features, structures, or functions of the invention. Embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference characters (e.g., numerals) and/or letters in the various embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed in the Figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the embodiments presented below may be combined in any combination of ways, e.g., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure.

Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, in the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. In addition, unless otherwise provided herein, “or” statements are intended to be non-exclusive; for example, the statement “A or B” should be considered to mean “A, B, or both A and B.”

FIG. 1 illustrates a cross-sectional side view of a downhole tool 100 in a run-in configuration, according to an embodiment. The downhole tool 100 may include a setting tool having a setting sleeve 110 and an inner body 120. The downhole tool 100 may also include a first body 130 and an expandable sleeve 160. In this embodiment, the setting sleeve 110 may also be referred to as a “second body” of the downhole tool 100. The first body 130 and the second body (the setting sleeve 110) may cooperate to expand (swage) the expandable sleeve 160 in a radial direction. Such expansion will be explained in greater detail below, according to an embodiment.

The setting sleeve 110 may be substantially cylindrical and may have a bore 112 formed axially-therethrough. An outer surface 114 of the setting sleeve 110 may include a tapered portion 116 proximate to (e.g., extending from) a lower axial end 118 of the setting sleeve 110. More particularly, a thickness of the tapered portion 116 may decrease proceeding toward the lower axial end 118.

The inner body 120 may be positioned within the bore 112 of the setting sleeve 110 and may be movable with respect thereto. The inner body 120 may include an outer shoulder 122 that contacts an inner surface 115 of the setting sleeve 110, so as to guide the movement of the inner body 120. The inner body 120 may also define an axial bore 124 formed at least partially therethrough, proximate to a lower axial end 126 of the inner body 120. An inner surface 128 of the inner body 120 that defines the bore 124 may be threaded.

The first body 130 may be coupled to the inner body 120 proximate to the lower axial end 126 of the inner body 120. The first body 130 may have a bore formed axially-therethrough, in which the inner body 120 of the setting tool may be at least partially received. An inner surface of the first body 130 that defines the bore may include a protrusion (e.g., an annular protrusion) 132 that extends radially-inward therefrom. The protrusion 132 may be integral with the first body 130, or the protrusion 132 may be part of a separate component that is coupled to, or positioned within a recess in, the first body 130. The inner body 120 may abut against the protrusion 132.

The first body 130 may be at least partially tapered. For example, the first body 130 may expand in radial dimension (e.g., in a direction perpendicular to an axial direction parallel to a central longitudinal axis through the tool 100) from the upper axial end to an axially intermediate point, and then reduce to a lower axial end. In other embodiments, the first body 130 may have a section that increases in radial dimension, but may omit the section of decreasing radial dimension. Consistent with such tapered geometry, the first body 130 may be formed as a truncated cone, a truncated sphere, another shape, or a combination thereof.

A locking mechanism 150 may be coupled to the inner body 120 and/or the first body 130. The locking mechanism may be, for example, a bolt or screw, and may include a shank 152 and a head 154. The shank 152 may be received through the bore of the first body 130 and at least partially into the bore 124 of the inner body 120, e.g., threaded thereto, such that the protrusion 132 of the first body 130 is positioned between the lower axial end 126 of the inner body 120 and the head 154 of the locking mechanism 150. In other embodiments, the shank 152 may be otherwise attached to the inner body 120, e.g., the shank 152 may be pinned, adhered, soldered, welded, brazed, etc., to the inner body 120.

The expandable sleeve 160 may be positioned at least partially axially between the tapered portion 116 of the setting sleeve 110 and the first body 130. The expandable sleeve 160 may be positioned radially-outward from the tapered portion 116 of the setting sleeve 110, the inner body 120, the first body 130, or a combination thereof. An outer surface 162 of the expandable sleeve 160 may be configured to set in a surrounding tubular member (e.g., a liner, a casing, a wall of a wellbore, etc.).

In some embodiments, to set the expandable sleeve 160, the outer surface 162 may form a high-friction interface with the surrounding tubular, e.g., with sufficient friction to avoid axial displacement of the expandable sleeve 160 with respect to the surrounding tubular, once set therein. In an embodiment, the outer surface 162 may be applied with, impregnated with, or otherwise include grit. For example, such grit may be provided by a carbide material. Illustrative materials on the outer surface 162 of the expandable sleeve 160 may be found in U.S. Pat. No. 8,579,024, which is incorporated by reference herein in its entirety to the extent not inconsistent with the present disclosure. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, which are both incorporated herein by reference to the extent not inconsistent with the present disclosure. In other embodiments, the outer surface 162 may include teeth, (e.g., wickers, buttons, etc.) designed to bite into (e.g., partially embed in) another material.

The expandable sleeve 160 may include a first, upper axial portion 164 and a second, lower axial portion 166. One or both of the first and second axial portions 164, 166 may be tapered, such that the thickness thereof varies along the axial length thereof. For example, the inner diameter of the expandable sleeve 160 may decrease in the first axial portion 164, as proceeding toward a lower axial end 168 of the expandable sleeve 160, while the outer diameter may remain generally constant. Similarly, the inner diameter of the expandable sleeve 160 in the second axial portion 166 may increase as proceeding toward the lower axial end 168, while the outer diameter remains generally constant. Accordingly, in some embodiments, an inner surface 170 of the expandable sleeve 160 may be oriented at an angle with respect to a central longitudinal axis through the downhole tool 100. For example, the inner surface 170 may be oriented at a first angle in the first axial portion 164 and a second angle in the second axial portion 166. Both angles may be acute, for example, from about 5° to about 20°, about 10° to about 30°, or about 15° to about 40°.

The first body 130 may be positioned at least partially, radially between the expandable sleeve 160 (on one side) and the inner body 120 and/or the locking mechanism 150 (on the other side). For example, an outer surface 134 of the first body 130 may be configured to slide against the inner surface 170 of the expandable sleeve 160. The outer surface 134 of the first body 130 and/or the inner surface 170 of the expandable sleeve 160 may be provided with a high-friction coating, such as a grit. Alternatively or additionally, the outer surface 134 and/or the inner surface 170 may be provided with teeth or a ratcheting mechanism. The function of such coating, teeth, and/or ratcheting mechanism is to maintain the position of the first body 130 relative to the expandable sleeve 160, so as to resist the first body 130 being pushed out of the bore of the expandable sleeve 170 when in the expanded configuration, as will be explained in greater detail below.

In addition, the first body 130 may be positioned proximate to the lower axial end 168 of the expandable sleeve 160, e.g., at least partially within the expandable sleeve 160, when the downhole tool 100 is in the first, run-in configuration. The first body 130 may be configured to remain in the expandable sleeve 160 after the setting tool is removed, as will be described in greater detail below.

FIG. 2 illustrates a flowchart of a method 200 for actuating the downhole tool 100, according to an embodiment. The method 200 may be viewed together with FIGS. 1 and 3-6, which illustrate the various configurations of the downhole tool 100 during operation of the method 200.

The method 200 includes running a downhole tool (e.g., the downhole tool 100) into a wellbore in a first, run-in configuration, as at 202, and as shown in and described above with respect to FIG. 1. The method 200 may also include moving a first portion of a setting tool and a swage axially with respect to a second portion of the setting tool and a sleeve, as at 204. For example, the inner body 120 of the setting tool and the first body 130 (providing the swage) may be moved axially with respect to the setting sleeve 110 of the setting tool and the expandable sleeve 160. More particularly, the inner body 120 may be pulled uphole (to the left in the Figures), while the setting sleeve 110 may be pushed downhole (to the right in the Figures). This may cause the inner body 120, and thus the first body 130, to be moved in the uphole direction with respect to the setting sleeve 110, and thus the expandable sleeve 160. In another embodiment, the setting sleeve 110 and the expandable sleeve 160 may be moved in a downhole direction with respect to the inner body 120 and the first body 130. In either example, the first body 130 slides along the tapered inner surface 170 of the sleeve and drives the expandable sleeve 160 radially-outward (e.g., swages the expandable sleeve 160) along the way. Accordingly, the expandable sleeve 160 is expanded radially-outward into a “set” position, e.g., engaging the surrounding structure.

FIG. 3 illustrates a cross-sectional side view of the downhole tool 100 after the expandable sleeve 160 has been set, according to an embodiment. As shown, the inner body 120, the first body 130, and the locking mechanism 150 have been moved together in the uphole direction relative to the setting sleeve 110. As the first body 130 moves axially-uphole with respect to the expandable sleeve 160, the upper axial portion 164 of the expandable sleeve 160 may slide up the tapered portion 116 of the setting sleeve 110. In addition, the contact between the first body 130 and the inner surface 170 of the lower axial portion 166 of the expandable sleeve 160 may push the expandable sleeve 160 radially-outward due to the decreasing inner diameter of the lower axial portion 166 of the expandable sleeve 160.

The force required to pull the inner body 120, the first body 130, and the locking mechanism 150 in the uphole direction (or to maintain the position thereof while the setting sleeve 110 pushes the expandable sleeve 160 downwards) may increase as the first body 130 moves in the uphole direction due to the decreasing diameter of the inner surface 170 of the lower axial portion 166 of the expandable sleeve 160 (proceeding in the uphole direction). When the force reaches or exceeds a predetermined amount, a portion of the downhole tool 100, e.g., the protrusion 132, may shear, thereby releasing the inner body 120 from the first body 130.

FIG. 4 illustrates a cross-sectional side view of a portion of the downhole tool 100 after the setting sleeve 110 and the inner body 120 are removed, according to an embodiment. This may be referred to as the “set configuration” of the downhole tool 100. As shown, when the force exceeds the predetermined amount, the protrusion 132 of the first body 130 may shear, allowing the inner body 120 and the locking mechanism 150 to be pulled back to the surface, while the first body 130 remains positioned within the expandable sleeve 160. Interference (e.g., hoop stress) between the first body 130 and the expandable sleeve 160 may produce a secure connection therebetween, while the first body 130 continues to exert a radially outward force on the expandable sleeve 160, keeping the expandable sleeve 160 linearly coupled or “set” within the surrounding tubular (e.g., casing or wellbore).

In another embodiment, rather than the protrusion 132 shearing, the threaded engagement between the inner body 120 and the locking mechanism 150 may shear, allowing the inner body 120 to be pulled back to the surface, while the first body 130 remains positioned within the expandable sleeve 160. In this embodiment, the locking mechanism 150 may fall into the sump of the wellbore. In yet another embodiment, the inner body 120 may be coupled (e.g., threaded) to the inner surface of the first body 130, and the locking mechanism 150 may be omitted. In this embodiment, the threaded engagement between the inner body 120 and the first body 130 may shear, allowing the inner body 120 to be pulled back to the surface, while the first body 130 remains positioned within the expandable sleeve 160. In other embodiments, the inner body 120 and/or the locking mechanism 150 may yield, allowing the inner body 120 to be retrieved from the wellbore.

The method 200 may also include perforating a surrounding tubular with a perforating gun, as at 206. The surrounding tubular may be the tubular that the expandable sleeve 160 engages and bites into. In at least one embodiment, the surrounding tubular may be perforated after the expandable sleeve 160 expands and contacts the surrounding tubular.

The method 200 may also include introducing an isolation device 180, such as a ball into the wellbore, where the isolation device 180 is received in the expandable sleeve 160, as at 208. The isolation device 180 may have any suitable shape (spherical or not) employed to be caught by a seat so as to obstruct fluid communication in a wellbore. FIGS. 5 and 6 illustrate a cross-sectional side view and a cross-sectional perspective view, respectively, of a portion of the downhole tool 100 (e.g., the first body 130 and the expandable sleeve 160) after the isolation device 180 is received in the expandable sleeve 160, according to an embodiment. As shown, the isolation device 180 may be received in the inner surface 170 of the upper axial portion 164 of the expandable sleeve 160, which may provide the ball seat. The seat may thus be proximal to the first body 130. Furthermore, the isolation device 180 may be sized to further expand at least a portion of the expandable sleeve 160, by transferring a pressure in the wellbore into a radial force by the wedge-shape of the seat, and thereby forcing the expandable sleeve 160 outward, further engaging the surrounding tubular, in at least some embodiments. In another embodiment, the isolation device 180 may be received by the first body 130, which may provide the seat. The isolation device 180 may plug the wellbore, isolating the portion of the wellbore above the expandable sleeve 160 and the isolation device 180 from the portion of the wellbore below the expandable sleeve 160 and the isolation device 180. In at least one embodiment, the isolation device 180 may be introduced into the wellbore after the surrounding tubular is perforated.

The method 200 may also include increasing a pressure of a fluid in the wellbore, as at 210. The isolation provided by the expandable sleeve 160 and the isolation device 180 may allow the pressure uphole of the expandable sleeve 160 and isolation device 180 to be increased (e.g., using a pump at the surface), while the wellbore below the expandable sleeve 160 and the isolation device 180 may be isolated from such pressure increase. The increased pressure may cause the subterranean formation around the wellbore, above the expandable sleeve 160 and isolation device 180, to fracture. This may take place after perforation occurs.

In at least one embodiment, the first body 130, the expandable sleeve 160, and/or the isolation device 180 may be made of a material that dissolves after a predetermined amount of time in contact with a liquid in the wellbore. The predetermined amount of time may be from about 6 hours to about 12 hours, from about 12 hours to about 24 hours, from about 1 day to about 2 days, from about 2 days to about 1 week, or more. In one specific embodiment, the isolation device 180 may be made of a material the dissolves after the predetermined amount of time, and the first body 130 and the expandable sleeve 160 may be made of a metal, such as aluminum, that does not dissolve after the predetermined amount of time. In some embodiments, the expandable sleeve 160 may be made at least partially from a metal (e.g., aluminum or an alloy thereof), while the first body 130 and/or the isolation device 180 may be made at least partially from a dissolvable material (e.g., a material that includes magnesium), such that the sleeve 160 may remain substantially intact after the dissolvable material is dissolved. In some embodiments, the expandable sleeve 160 may be made from a dissolvable material (e.g., a material that includes magnesium). Further, in some embodiments, all or a portion of a surface of any dissolvable component may include grooves, or other structures configured to increase a surface area of the surface, so as to increase the rate of dissolution.

FIG. 7 illustrates a cross-sectional side view of another downhole tool 700 in a run-in configuration, according to an embodiment. The downhole tool 700 may include a setting tool having a setting sleeve 710 and an inner body 720, with the setting sleeve 710 being disposed around the inner body 720. The downhole tool 700 may further include a first body 740, a second body 730, and a generally cylindrical, expandable sleeve 760. In at least one embodiment, the second body 730 and the expandable sleeve 760 may be integrally formed. The first body 740 may be a swage, which may cause the expandable sleeve 760 to expand radially outwards as the first body 740 is moved through the expandable sleeve 760. The second body 730 may be a stop or plug that may hold the expandable sleeve 760 in place relative to the first body 740 as the first body 740 is moved (and/or may be employed to move the expandable sleeve 760 relative to the first body 740), as will be described in greater detail below.

For example, the first body 740 may be positioned near an upper axial end 767 of the expandable sleeve 760 and adjacent to the setting sleeve 710 when the downhole tool 700 is in the first, run-in position. The setting sleeve 710 may thus be configured to engage and bear upon the first body 740, e.g., in a downhole direction, toward the expandable sleeve 760.

Optionally, an outer surface 714 of the setting sleeve 710 may include the tapered portion 716 proximate to the lower axial end 718 thereof. More particularly, a thickness of the tapered portion 716 may decrease proceeding toward the lower axial end 718. An inner surface 742 of the first body 740 may also be tapered, such that engagement between the setting sleeve 710 and the first body 740 is effected through the tapered interface therebetween. As a further option, the outer surface 714 of the setting sleeve 710 may also include a shoulder 719 that extends radially-outward from the tapered portion 716, and the inner surface 742 of the first body 740 may include a shoulder to engage the shoulder 719. In other embodiments, however, the interface between the first body 740 and the setting sleeve 710 may be generally perpendicular to the central longitudinal axis of the tool 700 (e.g., straight radial), and such tapered surfaces may be substituted with flat surfaces.

The first body 740 may be received at least partially within the upper axial end 767 the expandable sleeve 760. As such, the first body 740 may be positioned at least partially, radially between the inner body 720 and the expandable sleeve 760. Further, at least a portion of the first body 740 may be tapered (e.g., curved or conical, as described above) such that the diameter of an outer surface 744 of the first body 740 decreases proceeding toward the lower axial end of the first body 740.

The second body 730 may be positioned at least partially within a lower axial end 768 of the expandable sleeve 760, opposite to the first body 740. The second body 730 may have a bore formed axially-therethrough, in which the inner body 720 may be at least partially received. An inner surface of the second body 730 that defines the bore may include a protrusion (e.g., an annular protrusion) 732 that extends radially-inward therefrom. The protrusion 732 may be integral with the second body 730 or part of a separate component that is coupled to, or positioned within a recess in, the second body 730. The second body 730 may be tapered such that a diameter of an outer surface 734 of the second body 730 increases proceeding toward a lower axial end of the second body 730.

The tool 700 may also include a locking mechanism 750, which may be or include a screw or both, and may thus include a head 754 and a shank 752. In some embodiments, the shank 752 may be threaded. Further, the shank 752 may be sized to engage threads within a bore formed in the lower axial end 726 of the inner body 720, or otherwise form an engagement with the inner body 720.

The protrusion 732 of the second body 730 may be positioned axially-between the lower axial end 726 of the inner body 720 and the head 754 of the locking mechanism 750. When the inner body 720 is engaged with the locking mechanism 750, the second body 730 may be secured in place between the inner body 720 and the head 754 of the locking mechanism 750.

The expandable sleeve 760 may be positioned at least partially, axially-between the second body 730 and the first body 740. Further, the expandable sleeve 760 may be positioned radially-outward from the inner body 720, the second body 730, the first body 740, or a combination thereof. The outer surface of the first body 740 and/or the inner surface 770 of the expandable sleeve 760 may be provided with a high-friction coating, such as a grit. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above. Alternatively or additionally, the outer surface of the second body 740 and/or the inner surface 770 may be provided with such grit, teeth, buttons, and/or a ratcheting mechanism. The function of such coating, grit, teeth, buttons, and/or ratcheting mechanism is to maintain the position of the second body 740 relative to the expandable sleeve 760, so as to resist the second body 740 being pushed out of the bore of the expandable sleeve 760 when in the expanded configuration, as will be explained in greater detail below.

The upper axial portion 764 of the expandable sleeve 760 may be tapered such that a thickness of the upper axial portion 764 of the expandable sleeve 760 decreases proceeding toward the upper axial end 767 of the expandable sleeve 760. A lower axial portion 766 may be reverse tapered in comparison to the upper axial portion 764, such that the radial thickness of the expandable sleeve 760 decreases as proceeding toward the lower axial end 768 thereof.

In some embodiments, one or more of the first body 730, the second body 740, the expandable sleeve 760, and/or the isolation device 780 or 782 may be dissolvable after a predetermined amount of time within the wellbore. For example, such component(s) may be made at least partially from magnesium. In some embodiments, the expandable sleeve 760 may be made from a material that does not dissolve in a certain fluid, while the first body 730, the second body 740, the isolation devices 780 or 782, or any combination thereof, is made from a material that dissolves in the fluid, such that the expandable sleeve 760 may remain intact after the dissolvable material is dissolved. Further, in some embodiments, all or a portion of a surface of any dissolvable component may include grooves, or other structures configured to increase a surface area of the surface, so as to increase the rate of dissolution.

FIG. 8 illustrates a flowchart of a method 800 for actuating a downhole tool, according to an embodiment. The method 800 is described herein with reference to the downhole tool 700 and may thus be understood with reference to FIGS. 7 and 9-12. The method 800 may begin by running a downhole tool (e.g., the downhole tool 700) into a wellbore in a first, run-in configuration, as at 802.

The method 800 may also include moving a first portion of a setting tool and an expandable sleeve axially with respect to a second portion of the setting tool and a swage, as at 804. For example, the inner body 720 may be pulled uphole, while the setting sleeve 710 may be pushed downhole. In turn, the inner body 720 may pull the second body 730, and thus the expandable sleeve 760 uphole, while the setting sleeve 710 may prevent movement of the first body 740, or may even push the first body 740 downhole. This may cause the expandable sleeve 760 to move over the first body 740, which may result in at least a portion of the expandable sleeve 760 being expanded radially-outward by the first body 740 as the first body 740 slides across the tapered inner surface 770. Accordingly, the expandable sleeve 760 may be actuated into a set position, e.g., in which the expandable sleeve 760 engages a surrounding tubular.

FIG. 9 illustrates a cross-sectional side view of the downhole tool 700 after the expandable sleeve 760 has been set, according to an embodiment. As the second body 730 moves axially-uphole, the lower axial portion 766 of the expandable sleeve 760 may slide up the tapered outer surface 734 of the second body 730. In addition, the upper axial portion 764 of the expandable sleeve 760 may slide up the outer surface 744 of the first body 740. As a result, the first body 740 (and potentially the second body 730 as well) may push the expandable sleeve 760 radially-outward so that the outer surface 762 of the expandable sleeve 760 may contact and set in the surrounding tubular (not shown).

In some embodiments, to set the expandable sleeve 760, the outer surface 762 may form a high-friction interface with the surrounding tubular, e.g., with sufficient friction to avoid axial displacement of the expandable sleeve 760 with respect to the surrounding tubular, once set therein. In an embodiment, the outer surface 762 may be applied with, impregnated with, or otherwise include grit. For example, such grit may be provided by a carbide material or another type of material. Illustrative materials on the outer surface 762 of the expandable sleeve 760 may be found in U.S. Pat. No. 8,579,024, which is incorporated by reference above. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above. In other embodiments, the outer surface 762 may include teeth, wickers, buttons, designed to bite into (e.g., partially embed in) another material.

The force required to pull the inner body 720, the second body 730, the locking mechanism 750, and the expandable sleeve 760 in the uphole direction may increase as the expandable sleeve 760 moves in the uphole direction with respect to the first body 740 due to the decreasing diameter of the inner surface 770 of the upper axial portion 764 of the expandable sleeve 760 (proceeding in the downhole direction). When the force reaches or exceeds a predetermined amount, a portion of the downhole tool 700, e.g., the protrusion 732, may shear. The setting tool may then be removed, while the first body 740 remains in the expandable sleeve 760, continuing to provide a radially-outward force thereon which causes the expandable sleeve 760 to remain in an expanded, set configuration.

FIGS. 10 and 11 illustrate a cross-sectional side view and a cross-sectional perspective view, respectively, of the downhole tool 700 after the setting sleeve 710 and the inner body 720 are removed and an isolation device 780 is received in a seat provided by the first body 740, according to an embodiment. As shown, the protrusion 732 of the second body 730 may shear, allowing the inner body 720 and the locking mechanism 750 to be pulled back to the surface, while the second body 730 and/or the first body 740 remain(s) positioned within the expandable sleeve 760. In another embodiment, rather than the protrusion 732 shearing, the threaded engagement between the inner body 720 and the locking mechanism 750 may shear, allowing the inner body 720 to be pulled back to the surface, while the second body 730 and/or the first body 740 remain(s) positioned within the expandable sleeve 760. In this embodiment, the locking mechanism 750 may fall into the sump of the wellbore. The second body 730 may also disconnect from the expandable sleeve 760 and fall into the sump of the wellbore.

Referring back to FIG. 8, the method 800 may also include perforating a surrounding tubular with a perforating gun, as at 806. The surrounding tubular may be the tubular that the expandable sleeve 760 engages and bites into. In at least one embodiment, the surrounding tubular may be perforated after the expandable sleeve 760 contacts and bites into the surrounding tubular.

The method 800 may also include introducing the isolation device 780 into a wellbore, as at 808. As shown in FIGS. 10 and 11, the isolation device 780 may be received in the first body 740. More particularly, the isolation device 780 may be received in the optional tapered inner surface 742 of the first body 740, which may serve as the ball seat in this embodiment. The isolation device 780 may plug the wellbore, isolating the portion of the wellbore above the first body 740 and the isolation device 780 from the portion of the wellbore below the first body 740 and the isolation device 780. In at least one embodiment, the isolation device 780 may be introduced into the wellbore after the surrounding tubular is perforated. Furthermore, as pressure is applied to the isolation device 780, the resultant force may drive the first body 740 further into the expandable sleeve 760, which may in turn increase the expansion of the expandable sleeve 760 and thereby cause the expandable sleeve 760 to more securely set into the surrounding tubular.

FIG. 12 illustrates a cross-sectional side view of a portion of the downhole tool 700 after a different (e.g., larger) isolation device 782 is received in the expandable sleeve 760, according to an embodiment. In another embodiment, the isolation device 782 may have a larger diameter such that the isolation device 780 is received in (i.e., contacts) the expandable sleeve 760, proximal to the first body 740, such that the expandable sleeve 760, rather than the first body 740, provides the ball seat, e.g., proximal to the first body 740. The larger isolation device 782 may be sized to engage the expandable sleeve 760, exerting an additional radially-outward force on the expandable sleeve 760 when exposed to a pressure.

Referring back to FIG. 8, the method 800 may also include increasing a pressure of a fluid in the wellbore, as at 810. The isolation provided by the isolation device 780, 782, may allow the pressure to be increased (e.g., using a pump at the surface) above the isolation device 780, 782, while preventing such increase below the isolation device 780, 782. The increased pressure may cause the subterranean formation around the wellbore to fracture. This may take place after perforation takes place.

In at least one embodiment, the first body 740, the expandable sleeve 760, and/or the isolation device 780, 782 may be made of a material that dissolves after a predetermined amount of time in contact with a liquid in the wellbore. The predetermined amount of time may be from about 6 hours to about 12 hours, from about 12 hours to about 24 hours, from about 1 day to about 2 days, from about 2 days to about 1 week, or more. In some embodiments, the expandable sleeve 760 may be made at least partially from a metal (e.g., aluminum), while the first body 740 and/or the isolation device 780 or 782 may be made from a dissolvable material (e.g., a material that includes magnesium), such that the sleeve 760 may remain substantially intact after the dissolvable material is dissolved. Further, in some embodiments, all or a portion of a surface of any dissolvable component may include grooves, or other structures configured to increase a surface area of the surface, so as to increase the rate of dissolution.

FIG. 13 illustrates a cross-sectional side view of another downhole tool 1300 in a first, run-in configuration, according to an embodiment. The downhole tool 1300 may include a setting tool having a setting sleeve 1310 and an inner body 1320. The downhole tool 1300 may also include a first body 1330, a second body 1340, and a generally cylindrical, expandable sleeve 1360. In this embodiment, the first and second bodies 1330, 1340 may provide swages that serve to expand the expandable sleeve 1360, e.g., deform the expandable sleeve 1360 radially outwards, as they are moved relative to the expandable sleeve 1360 during setting, as will be described in greater detail below.

For example, the first body 1330 may be positioned proximate to a lower axial end 1326 of the inner body 1320 and a lower axial end 1368 of the expandable sleeve 1360. The first body 1330 may have a bore formed axially-therethrough, and the inner body 1320 may be received at least partially therein. An outer surface 1334 of the first body 1330 may be tapered such that a cross-sectional width of the outer surface 1334 of the first body 1330 decreases proceeding toward the upper axial end of the first body 1330. As such, the outer surface 1334 of the first body 1330 may be oriented at an acute angle with respect to the central longitudinal axis through the downhole tool 1300.

The second body 1340 may be positioned proximate to the upper axial end 1367 of the expandable sleeve 1360, opposite to the first body 1330. Further, the second body 1340 may be positioned adjacent to a lower axial end 1318 of the setting sleeve 1310. Optionally, the setting sleeve 1310 and the second body 1340 may form a tapered engagement therebetween. For example, the second body 1340 may include an inner surface 1342 that is tapered at substantially the same angle as a tapered portion 1316 of the setting sleeve 1310. As an additional option, an upper axial end of the second body 1340 may abut (e.g., directly or indirectly) a shoulder 1319 of the setting sleeve 1310.

The outer surface 1334 of the first body 1330 and/or the inner surface 1370 of the expandable sleeve 1360 may be provided with a high-friction coating, such as a grit. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above. Alternatively or additionally, the outer surface 1334 and/or the inner surface 1370 may be provided with teeth, buttons, or a ratcheting mechanism. The function of such coating, teeth, buttons, and/or ratcheting mechanism is to maintain the position of the first body 1330 relative to the expandable sleeve 1360, so as to resist the first body 1330 being pushed out of the bore of the expandable sleeve 136 when in the expanded configuration, as will be explained in greater detail below. The outer surface of the second body 1340 may include a similar coating, grit, buttons, teeth, ratcheting mechanism, etc., again to resist displacement of the second body 1340 relative to the expandable sleeve 1360 when the tool 1300 is in the set configuration.

Further, the second body 1340 may have a bore formed axially-therethrough, through which the inner body 1320 may pass. At least a portion of an outer surface 1344 of the second body 1340 may be tapered (conical or spherical) such that the cross-sectional width (e.g., diameter) of the outer surface 1344 of the second body 1340 decreases proceeding toward the lower axial end of the second body 1340.

A shear ring 1336 may be positioned within a recess in the first body 1330. The shear ring 1336 may include the protrusion 1338 that is positioned axially-between the lower axial end 1326 of the inner body 1320 and a head 1354 of a locking mechanism 1350. The locking mechanism 1350 may also include a shank 1352 that may be attached to the lower axial end 1326 of the inner body 1320.

The expandable sleeve 1360 may thus be positioned at least partially axially-between the first and second bodies 1330, 1340 when the downhole tool 1300 is in the first, run-in position. Further, the expandable sleeve 1360 may be positioned radially-outward from the inner body 1320, the first and second bodies 1330, 1340, or a combination thereof.

The upper axial portion 1364 of the sleeve 1360 may be tapered. As such, a thickness of the upper axial portion 1364 of the sleeve 1360 may decrease proceeding toward the upper axial end 1367 of the sleeve 1360. The inner surface 1370 of the upper axial portion 1364 of the expandable sleeve 1360 may be oriented at an acute angle with respect to the central longitudinal axis through the downhole tool 1300.

The lower axial portion 1366 of the sleeve 1360 may also be tapered. As such, a thickness of the lower axial portion 1366 of the sleeve 1360 may decrease proceeding toward the lower axial end 1368 of the sleeve 1360. The inner surface 1370 of the lower axial portion 1366 of the sleeve 1360 may be oriented at an acute angle with respect to the central longitudinal axis through the downhole tool 1300. In an embodiment, the upper and lower axial portions 1364, 1366 may be oriented at substantially the same angles (but mirror images of one another).

FIG. 14 illustrates a flowchart of a method 1400 for actuating the downhole tool 1300, according to an embodiment. An example of the method 1400 may be understood with reference to the downhole tool 1300 of FIGS. 13 and 15-18. The method 1400 includes running a downhole tool (e.g., the downhole tool 1300) into a wellbore in a first, run-in configuration, as at 1402.

The method 1400 may also include moving a first portion of a setting tool and a first swage axially with respect to a second portion of the setting tool and a second swage, as at 1404. This may actuate the sleeve 1360 radially-outward into a “set” position. For example, the first and second bodies 1330, 1340 may provide such first and second swages. Further, such moving may be effected by pulling the inner body 1320, the first body 1330, the locking mechanism 1350 and the expandable sleeve 1360 in an uphole direction, or by pushing the setting sleeve 1310, the second body 1340, and the expandable sleeve 1360 in a downhole direction, or both.

During such movement, the first and second bodies 1330 move with respect to the expandable sleeve 1360. The movement of the first body 1330 with respect to the expandable sleeve 1360 causes the lower axial portion 1366 of the expandable sleeve 1360 to expand radially-outward, while the movement of the second body 1340 with respect to the expandable sleeve 1360 causes the upper axial portion 1364 of the expandable sleeve 1360 to expand radially-outward.

FIG. 15 illustrates a cross-sectional side view of the downhole tool 1300 after the sleeve 1360 has been set (i.e., in a “set configuration” of the downhole tool 1300), according to an embodiment. As the first body 1330 moves axially-uphole, the lower axial portion 1366 of the sleeve 1360 may slide up the tapered outer surface 1334 of the first body 1330. In addition, the upper axial portion 1364 of the sleeve 1360 may slide up the outer surface 1344 of the second body 1340. Thus, as shown, the distance between the first and second bodies 1330, 1340 may decrease. As the first and second bodies 1330, 1340 move closer together, the first and second bodies 1330, 1340 may push the sleeve 1360 radially-outward so that the outer surface 1362 of the sleeve 1360 sets in the surrounding tubular.

In some embodiments, to set the expandable sleeve 1360, the outer surface 1362 may form a high-friction interface with the surrounding tubular, e.g., with sufficient friction to avoid axial displacement of the expandable sleeve 1360 with respect to the surrounding tubular, once set therein. In an embodiment, the outer surface 1362 may be applied with, impregnated with, or otherwise include grit. For example, such grit may be provided by a carbide material. Illustrative materials on the outer surface 1362 of the expandable sleeve 1360 may be found in U.S. Pat. No. 8,579,024, which is incorporated by reference above. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above. In other embodiments, the outer surface 1362 may include teeth, buttons, and/or wickers designed to bite into (e.g., partially embed in) another material.

The force required to move the first and second bodies 1330, 1340 with respect to the expandable sleeve 1360 may increase as the movement continues, due to the tapered inner surface 1370. When the force reaches or exceeds a predetermined amount, a portion of the downhole tool 1300, e.g., the shear ring 1336, may shear, releasing the inner body 1320 from the first body 1330. The first and second bodies 1330, 1340 may thus remain in the expandable sleeve 1360 after the setting tool is removed, such that the first and second bodies 1330, 1340 continue to provide a radially outward force on the expandable sleeve 1360, keeping the expandable sleeve 1360 in engagement with the surrounding tubular.

FIGS. 16 and 17 illustrate a cross-sectional side view and a cross-sectional perspective view, respectively of a portion of the downhole tool 1300 after the setting sleeve 1310 and the inner body 1320 are removed, and an isolation device 1380 is received in the second body 1340, according to an embodiment. Accordingly, an axial force on the isolation device 1380 generated by the pressure in the wellbore may be transmitted from the isolation device 1380 to the first body 1340, thereby tending to cause the first body 1340 to be driven further into the expandable sleeve 1360. This may increase the radial outward gripping force that the expandable sleeve 1360 applies to the surrounding tubular.

In another embodiment, the isolation device 1380 may be larger, and may be received by the expandable sleeve 1360, proximate to the first body 1330. The larger isolation device 1380 may also be sized to further radially expand the expandable sleeve 1360 by transmitting at least a portion of a force incident on the isolation device 1380 due to pressure in the wellbore to a radial outward force on the expandable sleeve 1360. As shown, the protrusion 1338 of the shear ring 1336 may shear, allowing the inner body 1320 and the locking mechanism 1350 to be pulled back to the surface, while the first and second bodies 1330, 1340 remain positioned within the sleeve 1360. In another embodiment, rather than the protrusion 1338 shearing, the threaded engagement between the inner body 1320 and the locking mechanism 1350 may shear, allowing the inner body 1320 to be pulled back to the surface, while the first and second bodies 1330, 1340 remain positioned within the sleeve 1360. In this embodiment, the locking mechanism 1350 may fall into the sump of the wellbore.

Referring back to FIG. 14, the method 1400 may also include perforating a surrounding tubular with a perforating gun, as at 1406. The surrounding tubular may be the tubular that the sleeve 1360 engages and bites into. In at least one embodiment, the surrounding tubular may be perforated after the sleeve 1360 contacts and “bites into” the surrounding tubular.

The method 1400 may also include introducing the isolation device 1380 into a wellbore, as at 1408. As shown in FIGS. 16 and 17, the isolation device 1380 may be received in the second body 1340. More particularly, the isolation device 1380 may be received in the tapered inner surface 1342 of the second body 1340, which may serve as a ball seat. The isolation device 1380 may plug the wellbore, isolating the portion of the wellbore above the second body 1340 and the isolation device 1380 from the portion of the wellbore below the second body 1340 and the isolation device 1380. In another embodiment, the isolation device 1380 may engage the expandable sleeve 1360 and apply a radially outward force thereon, while blocking flow through the interior of the expandable sleeve 1360. In at least one embodiment, the isolation device 1380 may be introduced into the wellbore after the surrounding tubular is perforated.

FIG. 18 illustrates a cross-sectional side view of a portion of the downhole tool 1300 after the isolation device 1380 is received in the second body 1340, where the sleeve 1360 includes an inner shoulder 1372, according to an embodiment. In at least one embodiment, the shoulder 1372 extends radially-inward from the inner surface 1370 of the sleeve 1360. The shoulder 1372 may be positioned generally between the upper axial portion 1364 and the lower axial portion 1366. The shoulder 1372 may limit the axial movement of at least one of the first and second bodies (e.g., swages) 1330, 1340 with respect to the sleeve 1360.

More particularly, in an embodiment, the inner surface 1370 in the upper and lower axial portions 1364, 1366 may be tapered, such that the inner diameter thereof decreases as proceeding toward the shoulder 1372. The shoulder 1372 may extend radially-inward from the inner surface 1370, such that the shoulder 1372 defines generally axially-facing bearing end faces against which the respective first and second bodies 1330, 1340 may abut. In at least some embodiments, the end faces may define obtuse angles with respect to the inner surface 1370, as shown.

In some embodiments, whether a shoulder 1372 is provided or not, the first and second bodies 1330, 1340 may include interlocking, axially-extending protrusions that are configured to radially overlap when the tool 1300 is in the set configuration. As such, the first and second bodies 1330, 1340 may be locked to one another, so as to further resist displacement thereof relative to the sleeve 1360 when in the set configuration.

Referring back to FIG. 14, the method 1400 may also include increasing a pressure of a fluid in the wellbore, as at 1410. Due to the isolation provided by the isolation device 1380, the pressure may be increased (e.g., using a pump at the surface) above the isolation device 1380 but not below the isolation device 1380. The increased pressure may cause the subterranean formation around the wellbore to fracture. This may take place after perforation takes place.

In at least one embodiment, the first and second bodies 1330, 1340, the sleeve 1360, and/or the isolation device 1380 may be made of a material that dissolves after a predetermined amount of time in contact with a liquid in the wellbore. The predetermined amount of time may be from about 6 hours to about 12 hours, from about 12 hours to about 24 hours, from about 1 day to about 2 days, from about 2 days to about 1 week, or more. In some embodiments, the sleeve 1360 may be made from a material (e.g., aluminum) that does not dissolve in the liquid in the wellbore, while the first body 1130, the second body 1340, and/or the isolation device 1380 is made from a material (e.g., magnesium) that dissolves in the liquid, such that the sleeve 1360 may remain intact after the dissolvable material is dissolved.

In any of the foregoing embodiments, the isolation device received on either the expandable sleeve or the first or second body may be configured to come off of its seat, thereby allowing for flowback, uphole, through the downhole tool. This may facilitate introduction of fluids configured to dissolve the dissolvable components of the downhole tool in the wellbore. Further, the expandable sleeve and/or the first or second body may be ported, to allow for such fluid to pass, at a predetermined (low) flow rate past the isolation device, so as to facilitate dissolving the dissolvable component(s) of the tool. In addition, various process or techniques may be employed to increase the rate at which the dissolvable component(s) dissolve. For example, if the expandable sleeve is dissolvable, notches or cuts may be made in the inner surface thereof, which increase the surface area in contact with the wellbore fluids and thus increase the rate at which the sleeve dissolves. Further, in at least some embodiments, a sealing element (e.g., an elastomeric member) may be positioned around the expandable sleeve, e.g., on the outer surface thereof, to form a seal with the surrounding tubular, when the expandable sleeve is expanded. In some embodiments, all or a portion of a surface of any dissolvable component may include grooves, or other structures configured to increase a surface area of the surface, so as to increase the rate of dissolution.

FIG. 19 illustrates a perspective view of another expandable sleeve 1900 of a downhole tool 1901, according to an embodiment. The sleeve 1900 includes a body 1902 and may include a seal member 1904 positioned around the body 1902. The sleeve 1900 may define engaging members 1906, such as teeth, wickers, buttons, grit, high-friction coatings, etc., on an outer surface of the body 1902. For example, the engaging members 1906 may be provided by a grit applied (e.g., coated) on the outer surface of the expandable sleeve 1900. The grit may be provided by a carbide material. Illustrative materials on the outer surface of the expandable sleeve 1900 may be found in U.S. Pat. No. 8,579,024, which is incorporated by reference above. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above.

Internally, the sleeve 1900 may include a profiled, e.g., tapered, interior surface or shoulder 1908 defined in the body 1902. In some embodiments, the shoulder 1908 may not be tapered but may extend straight in a radial direction or may be radiused.

In one embodiment, the body 1902 may be made from a dissolvable material, such as a dissolvable alloy or a dissolvable composite. The dissolvable material may be configured to dissolve over a predetermined amount of time or upon contact with a specific type of fluid. In other embodiments, the body 1902 may be made from a material, such as aluminum, that may not be configured to dissolve in the fluid. Further, in some embodiments, all or a portion of a surface of any dissolvable component may include grooves, or other structures configured to increase a surface area of the surface, so as to increase the rate of dissolution. As will be described herein, the sleeve 1900 is configured to be expanded from a first outer diameter to a second larger outer diameter upon application of a radial force.

As shown in FIG. 19, the seal member 1904 may be disposed proximate to a first or “uphole” end 1910 of the sleeve 1900 (e.g., adjacent to the shoulder 1908). Further, the engaging members 1906 may be disposed adjacent to a second or “downhole” end 1912 of the sleeve 1900. In other embodiments, the relative positioning of the seal member 1904 and the engaging members 1906 may be switched. As shown, the seal member 1904 may be a separate component that is attached to the body 1902, e.g., an O-ring, elastomeric band, or the like that may seat in a groove formed in the outer surface of the body 1902 and may, in some embodiments, be bonded thereto. In another embodiment, the seal member 1904 may be part of the sleeve 1900, e.g., integral therewith.

Although the illustrated embodiment depicts an embodiment in which the sleeve 1900 includes both the seal member 1904 and the engaging member 1906 on the body 1902, in another embodiment, the seal member 1904 and/or the engaging member 1906 may be optional and potentially omitted. In other words, the body 1902 of the sleeve 1900 may create a seal with the surrounding tubular upon expansion of the sleeve 1900 when the seal member 1904 is not used. Additionally, the body 1902 of the sleeve 1900 may grip the surrounding tubular upon expansion of the sleeve 1900 when the engaging member 1906 is not used.

FIG. 20 illustrates a partial sectional view of the downhole tool 1901 in a run-in configuration, according to an embodiment. The tool 1901 includes a setting tool 2000, which may include an inner body 2002 extending through the expandable sleeve 1900. The inner body 2002 may define a ramped surface 2004, e.g., as part of a protrusion extending outward therefrom. For example, the ramped surface 2004 may abut the second end 1912 of the expandable sleeve 1900 in the illustrated run-in configuration.

The setting tool 2000 may also include a setting sleeve 2006 positioned around the body 2002. The setting sleeve 2006 may be positioned axially adjacent to the expandable sleeve 1900, opposite to the ramped surface 2004 and may abut the first end 1910 of the sleeve 1900. For example, in the run-in position, the sleeve 1900 may be disposed between the setting sleeve 2006 and the ramped surface 2004, which may prevent the sleeve 1900 from moving axially. In some embodiments, an amount of space may be provided between the expandable sleeve 1900 and either or both of the ramped surface 2004 and/or the setting sleeve 2006. Further, it will be appreciated that the illustrated setting tool is but one example among many, and other setting tools, such as one or more embodiments of the setting tools described above or others (e.g., rotary expanders) may be employed without departing from the scope of the present disclosure.

FIG. 21 illustrates a sectional view of the sleeve 1900 in a set configuration within a surrounding tubular 2100 (e.g., casing, liner, wellbore wall, etc.), according to an embodiment. The setting tool 2000 and the sleeve 1900 may be run into a wellbore and placed within the tubular 2100 using coiled tubing, wireline or slickline, or any other conveyance system. Once the sleeve 1900 is deployed to a desired position in the tubular 2100, the setting tool 2000 may be activated to expand and set the sleeve 1900, thereby actuating the tool 1901 into the illustrated set configuration.

During activation of the setting tool 2000, the inner body 2002 may be pulled axially with respect to the sleeve 1900, e.g., in the direction indicated by arrow 2102. The body 2002 may be prevented from moving by an opposite force applied by the setting sleeve 2006. In other embodiments, the body 2002 may be stationary and the setting sleeve 2006 may push the sleeve 1900 axially with respect to the body 2005. In still other embodiments, both the setting sleeve 2006 and the body 2002 may be moved axially during setting.

Such relative movement causes the sleeve 1900 to move up the ramped surface 2004, beginning with the second end 1912 and at least partially, e.g., entirely, across the body 1902 to the first end 1910. As a result, the sleeve 1900 is radially expanded from a first outer diameter to a second, larger outer diameter. The ramped surface 2004 may thus be considered a swage. The second outer diameter may be at least as large as the inner diameter of the tubular 2100, and thus the sleeve 1900 may be pressed into engagement with an inner surface 2104 of the tubular 2100. Since the body 1902 (and the shoulder 1908) may be expanded when the sleeve 1900 is expanded, the shoulder 1908 may also increase in diameter correspondingly (potentially, but not necessarily to the same degree or proportionally).

When the sleeve 1900 engages the tubular 2100, the seal member 1904 may form a seal with the tubular 2100, and the engaging members 1906 may bite into or otherwise form a high-friction interface with the inner surface 2104 of the tubular 2100. After the sleeve 1900 is engaged with the tubular 2100, the setting tool 2000, which may have been moved axially through the sleeve 1900, may be removed from the tubular 2100.

FIG. 22 illustrates a sectional view of the downhole tool 1901 in the set configuration, with an isolation device 2200 disposed in the sleeve 1900, according to an embodiment. As shown, the setting tool 2000 has been removed to provide an open through-bore 2201 through the sleeve 1900, allowing fluid communication axially through the sleeve 1900 unless plugged. Further, the shoulder 1908 may face in an uphole direction, such that it is configured to engage or “catch” the isolation device 2200 deployed into the wellbore.

The isolation device 2200 may be a ball, dart, or any other type of obstructing member that may be deployed into the wellbore. In an embodiment, the isolation device 2200 may be made from a dissolvable material, which may be configured to dissolve in the presence of a particular fluid (e.g., an acid) for a certain amount of time.

In operation, after the sleeve 1900 is placed within the tubular 2100, the tubular 2100 may be perforated using a perforating gun (not shown). Next, the isolation device 2200 is dropped or pumped into the wellbore and subsequently is received in the sleeve 1900. The isolation device 2200 is configured to cooperate with the sleeve 1900, e.g., the shoulder 1908, to close off the bore 2201 of the sleeve 1900. This may isolate regions of the wellbore uphole of the tool 1901 from those downhole of the tool 1900. Thus, frac fluid injected into the wellbore during a fracking operation may be directed through the perforations, rather than through the bore 2201 of the sleeve 1900.

Furthermore, during the fracking operation, the frac fluid may apply a pressure, which in turn applies a force, generally in the axial direction indicated by arrow 2202, on the isolation device 2200. As a result, the isolation device 2200 may apply a force, as indicated by arrow 2204, on the sleeve 1900. Since the isolation device 2200 bears against the shoulder 1908, which may be formed as a tapered or wedge-shaped structure (in cross-section), this axial force may be partially transferred to radially-outward force, as indicated by arrow 2206. Thus, increased pressure in the wellbore uphole of tool 1901 may serve to enhance the seal by the sealing member 1904 and/or the grip of the engaging members 1906 with the surrounding tubular 2100.

After the first fracking operation is complete, another sleeve may be run into the tubular 2100 at a location above the sleeve 1900, and the process may be repeated until several (e.g., all) of the zones in the wellbore are fractured. Each sleeve may be configured to receive the same size isolation device. As mentioned above, the isolation device 2200 may be made from a dissolvable material. Accordingly, after the fracking operation is complete, the isolation device 2200 may be removed by introducing the solvent thereto (or by waiting for a certain amount of time if the solvent is already present). Similarly, the sleeve 1900 itself may be dissolvable, and thus the sleeve 1900 may be removed by introducing a solvent thereto. In other embodiments, the sleeve 1900 may be removed by deploying a gripping member and attaching the gripping member to the sleeve and pulling the sleeve from the tubular. In another embodiment, the sleeve 1900 may be removed using a mill or drill bit.

FIG. 23 illustrates a partial sectional view of another downhole tool 2300 in a run-in configuration, according to an embodiment. The tool 2300 includes an expandable sleeve 2302 and a setting tool 2304. The expandable sleeve 2302, in this embodiment, includes two or more sleeves, e.g., a first sleeve 2306 and a second sleeve 2308, which may be spaced axially apart in the run-in configuration, as shown. Regarding the first sleeve 2306, it may be configured to expand to engage and potentially form a seal with a surrounding tubular, as will be described in greater detail below. Accordingly, a seal member 2310 may be positioned around and, e.g., attached to the first sleeve 2306. Further, the first sleeve 2306 may be provided with engaging members 2312, such as teeth, wickers, grit, or a high-friction surface which may also be defined, attached, or otherwise positioned on an outer surface of the first sleeve 2306. For example, the engaging members 2312 may include a grit made from a carbide material, such as described in U.S. Pat. No. 8,579,024, which is incorporated by reference above. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above.

For example, the seal member 2310 may be positioned proximal to a first end 2315A of the first sleeve 2306, and the engaging members 2312 may be positioned proximal to a second end 2315B of the first sleeve 2306, e.g., opposite to the first end 2315A. In other embodiments, this relative positioning of the engaging members 2312 and the seal member 2310 may be swapped, and/or either or both of the engaging members 2312 and/or the seal member 2310 may be omitted.

Additionally, a first shoulder 2314 may be formed on an inner surface of the first sleeve 2306, e.g., proximate to the first end 2315A and facing in an uphole direction. In some embodiments, the shoulder 2314 may be tapered or wedge shaped. In other embodiments, the shoulder 2314 may be curved or flat. The first sleeve 2306 may also include a second shoulder 2323, which may be spaced axially apart from the first shoulder 2314 and may, in some embodiments, be relatively flat, extending inward in the radial direction.

The setting tool 2304 includes an inner body 2316 having ramped surfaces 2318A, 2318B, which may be adjacent to one another, extend outward from the inner body 2316, and face generally in opposite axial direction, e.g., on either axial side of a protrusion extending outwards from the inner body 2316. In some embodiments, the first sleeve 2306 and the second sleeve 2308 may be positioned around the inner body 2316, e.g., engaging the ramped surfaces 2318A and 2318B, respectively. The setting tool 2304 further includes a setting sleeve 2320 that is positioned adjacent to the first sleeve 2306 and is configured to entrain the first sleeve 2306 between the ramped surface 2318A and the setting sleeve 2320 prior to activation.

The second sleeve 2308 may be connected to the inner body 2316 via a connection member 2322, such as a shear pin, shear screw, adhesive, or other shearable structure or device. In some embodiments, the second sleeve 2308 may include a tapered first shoulder 2324 that may engage or face the ramped surface 2318B, and may be configured to slide axially and radially on the ramped surface 2318B. Further, the second sleeve 2308 may include a second shoulder 2326 which may be positioned on a radial outside of the second sleeve 2308 and may be configured to engage the second shoulder 2323 of the first sleeve 2306.

FIG. 24 illustrates a sectional view of the tool 2300 in a set configuration and disposed in a surrounding tubular 2400 (e.g., a casing, liner, the wellbore wall, etc.), according to an embodiment. Once the sleeve 2302 is placed within the tubular 2400 at a desired location, the setting tool 2304 may be activated to expand a portion of the sleeve 2302, thereby setting the tool 2300. During activation, the inner body 2316 is pulled in the direction indicated by arrow 2402, while the setting sleeve 2320 pushes on the first sleeve 2306 in the opposite axial direction. Eventually, the inner body 2316 moves axially relative to the first sleeve 2306 (either the inner body 2316 may be moved relative to a stationary reference plane, or the setting sleeve 2320 may move the first sleeve 2306, or both). This causes the first sleeve 2306 of the sleeve 2302 to move up the ramped surface 2318A, thereby expanding (swaging) the first sleeve 2306, including, in some embodiments, the first shoulder 2314 thereof. At the same time, the second sleeve 2308 moves relative to the expandable sleeve 2302, along with the inner body 2316 to which it is connected, such that the second sleeve 2308 is brought to a position that is radially inside of at least a portion of the first sleeve 2306. Eventually, the second shoulder 2323 of the first sleeve 2306 engages the second shoulder 2326 of the second sleeve 2308. In this position, the first shoulder 2314 of the first sleeve 2306 may be generally continuous with the first shoulder 2324 of the second sleeve 2308, e.g., the radially inner-most point of the first shoulder 2314 may be axially aligned with the radially outer-most point of the second shoulder 2326 (within a reasonable tolerance). Accordingly, the first shoulders 2314, 2324 may cooperatively provide a seat profile for engaging an isolation devices, as will be described below.

At this point, the first sleeve 2306 is radially expanded from the first outer diameter to the second larger outer diameter and into engagement with an inner surface 2404 of the tubular 2400. Thus, the first sleeve 2306 resists movement relative to the tubular 2400 because it is gripping the tubular 2400. With the second shoulders 2323, 2326 engaging one another, and the first sleeve 2306 gripping the surrounding tubular, further movement of the setting tool 2304 is resisted by the connection between the second sleeve 2308 and the inner body 2316. As such, the connection member 2322 yields under the force applied by the setting tool 2304, thus allowing the setting tool 2304 to be disconnected from the expandable sleeve 2302, while the first and second sleeves 2306, 2308 may remain in engagement with one another.

When the first sleeve 2306 of the sleeve 2302 engages the tubular 2400, the seal member 2310 forms a seal with the tubular 2400 and the engaging members 2312 may bite into the inner surface 2404 of the tubular 2400. After the sleeve 2302 is engaged with the tubular 2400, the setting tool 2304 may be removed from the tubular 2400.

FIG. 25 illustrates a sectional view of the tool 2300 in a set configuration in the tubular 2400, with the setting tool 2304 removed and an isolation device 2500 engaging the sleeve 2302, according to an embodiment. After the sleeve 2302 is set in the tubular 2400, the tubular 2400 may be perforated using a perforating gun (not shown). Next, the isolation device 2500, which may be a ball, dart, or any other type of obstructing member, is dropped or pumped into the wellbore and subsequently is received at least partially into the sleeve 2302. For example, either or both of the first shoulders 2314 and 2324 of the first and second sleeves 2306, 2308, respectively, may engage the isolation device 2500, so as to block a through-bore 2502 extending through the sleeve 2302. Since the sleeve 2302 may be sealed with the tubular 2400 as well, frac fluid injected into the wellbore during a fracking operation may be prevented from flowing past the tool 2300 and may be directed through the perforations.

During the fracking operation, the frac fluid may apply a pressure on the isolation device 2500, which may in turn generate a force in the direction indicated by arrow 2504 thereon. As a result, the isolation device 2500 may apply a force, as indicated by arrow 2506, on the sleeve 2302. With the first shoulders 2314, 2324 being wedge shaped, at least some of this axial force 256 may be transferred to a radial force, as indicated by arrow 2510, on the sleeve 2302. This may serve to further expand the sleeve 2302 and thereby enhance the seal by the sealing member 210 and/or the grip of the engaging members 2312.

After the first fracking operation is complete, another sleeve may be run into the tubular 2400 at a location above the first sleeve 2306, and the process is repeated until all the zones in the wellbore are fractured. Each sleeve may be configured to receive the same size isolation device. After the fracking operation is complete, the sleeve may be removed by dissolving the sleeve if the sleeve is made from a dissolvable material. In an alternative embodiment, the sleeve may be removed by deploying a gripping member and attaching the gripping member to the sleeve and pulling the sleeve from the tubular. In another embodiment, the sleeve may be removed using a drill bit.

FIG. 26 illustrates a view of a portion of a slip 2600, according to an embodiment. The slip 2600 may illustrate an embodiment of the engaging members and a portion of the sleeve body discussed above. Accordingly, as depicted, the slip 2600 includes a body 2602 and a grip member 2604. The grip member 2604 is configured to engage, e.g., embed, in a tubular (not shown). As shown, the grip member 2604 may have a thread shape. A flat surface 2606 of the grip member 2604 may be coated with a grip material 2608, such as tungsten carbide coating or carbide powder. In one embodiment, the body 2602 may be made from a dissolvable material, such as a dissolvable alloy or a dissolvable composite. The dissolvable material may be configured to dissolve over a predetermined amount of time or upon contact with a specific type of fluid.

FIG. 27 illustrates a cross-sectional view of a slip member 2700, according to an embodiment. The slip member 2700 may provide an embodiment of the engaging members described above. The slip member 2700 includes a body 2702 having a plurality members 2704 which are configured to break up when the slip member 2700 is expanded. The slip member 2700 may include inserts disposed on an outer surface of the body 2702.

The body 2702 of the slip member 2700 may be made from a dissolvable material, e.g., a dissolvable matrix, such as a dissolvable alloy or a dissolvable composite. The dissolvable material may be configured to dissolve over a predetermined amount of time or upon contact with a specific type of fluid. In one embodiment, the dissolvable material may be hardened by mixing cast iron with the dissolvable material. In another embodiment, the dissolvable material matrix may include dissolvable material and ceramic powder (similar to frac sand). During the forming process of the body 2702, the dissolvable material matrix may be ground to a shape. The ceramic powder (or another material harder than 40 Rockwell Hardness—C Scale) is mixed into the dissolvable material matrix, and as a result, the final product will be able to bite into the surrounding tubular since the final product will be harder than the surrounding tubular. In another embodiment, the dissolvable material matrix may include dissolvable material and carbide. In another embodiment, the dissolvable material matrix is a powder metal mixture. For instance, the dissolvable material matrix may include a percentage of hardenable material, such cast iron, steel powder or steel flakes, and a percentage dissolvable material. The hardenable material may be hardened using induction heat treating or other common heat treat methods prior to or after being mixed within the dissolvable material matrix. The percentage of hardenable material may be from 15 percent, or about 20 percent, or about 25 to about 35 percent, about 40 percent or about 50 percent, and the remainder of the power metal mixture being dissolvable material. The powder may include a portion of ceramic powder or sand. In a further embodiment, the body 2702 may be made from dissolvable material matrix which has an outer surface that may be coated with a grip material, such as tungsten carbide coating or carbide powder.

FIG. 28A illustrates a top view of an insert 2800 which may be embedded or otherwise connected to the slip member 2700 (FIG. 27), according to an embodiment. FIG. 28B illustrates a side, cross-sectional view of the insert 2800, according to an embodiment. FIG. 28C illustrates a perspective view of a bottom 2802 of the insert 2800, according to an embodiment.

Referring to FIGS. 28A-C, the insert 2800 may include a body 2804 which may define the bottom 2802 as well as a top 2805 and an annular side 2806 extending therebetween, such that the insert 2800 is generally cylindrical. Other embodiments may have other shapes, however. The top 2805 may be configured to bite into a tubular, e.g., when the slip member 2700 is expanded in use. Accordingly, the top 2805 may be, for example, tapered, as shown, to facilitate the top 2805 cutting into the tubular.

The body 2804 may also define a bore 2808 therein, extending at least partially from top 2805 to bottom 2802. The bore 2808 in the body 2804 may be used to allow the fluid to come in contact more rapidly with a larger surface area of the dissolvable body 2804. The bore 2808 may also be promote the insert 2800 breaking apart at a predetermined time, e.g., when being milled out.

The insert 2800 may be made from a metal (e.g., a carbide, steel, hardened steel, etc.) and/or may be provide as a dissolvable material matrix, such as a dissolvable alloy or a dissolvable composite. The dissolvable material matrix may be configured to dissolve over a predetermined amount of time or upon contact with a specific type of fluid. The insert 2800 may be configured to dissolve at the same time as the body 2804 of the slip member 2700 or at a different time. In one embodiment, the dissolvable material matrix of the body 2804 is a powder metal mixture. For instance, the dissolvable material matrix may include a percentage of hardenable material, such cast iron, and a percentage dissolvable material. In another embodiment, the dissolvable material matrix of the body 460 may include dissolvable material and ceramic powder (similar to frac sand). In another embodiment, the dissolvable material matrix of the body 460 may include dissolvable material and carbide

In view of the foregoing, it will be appreciated that embodiments consistent with the tool of any of FIGS. 1-28C may be at least partially dissolvable. For example, the expandable sleeves may be at least partially dissolvable, but in other embodiments, may not be dissolvable. Further, the bodies or swages may be at least partially dissolvable, as may the isolation devices that are seated into the sleeves and/or into the swages/inner bodies. For example, the dissolvable material may be a dissolvable alloy or a dissolvable composite material. In a specific embodiment, the dissolvable material may be a material that includes magnesium. In some embodiments, some components of the tool may be dissolvable, while others may not be dissolvable, in a particular type of fluid. That is, when the dissolvable components dissolve, the non-dissolvable components may remain intact. As an illustrative example, the expandable sleeves may be made at least partially from aluminum, which may remain intact while the magnesium of the dissolvable component(s) may dissolve. Other combinations of dissolvable/non-dissolvable components and materials may be employed, without limitation, as may be found suitable by one of skill in the art. Further, the various components may be partially dissolvable and partially non-dissolvable, without departing from the scope of the present disclosure. Further, in some embodiments, all or a portion of a surface of any dissolvable component may include grooves, or other structures configured to increase a surface area of the surface, so as to increase the rate of dissolution.

FIGS. 29, 30, and 31 illustrate side, half-sectional views of a downhole tool 2900 in a run-in configuration, a set configuration, and a released configuration, respectively, according to an embodiment. The downhole tool 2900 includes an expandable sleeve 2902, a first swage 2904, and a second swage 2906. The first and second swages 2904, 2906 are positioned at least partially within an axial through-bore 2908 of the expandable sleeve 2902 and are configured to be moved axially toward one another by operating of a setting tool 2910, which may be considered part of the downhole tool 2900 in some embodiments, but, in other embodiments, may be considered part of a tool assembly that includes both the downhole tool 2900 and the setting tool 2910 as separate members.

The first swage 2904 includes an upwardly-facing valve seat (e.g., a ball seat) 2905. Further, the expandable sleeve 2902 includes a shoulder 2912, which extends radially inwards from the bore 2908, axially between the first and second swages 2904, 2906. The shoulder 2912 is configured to provide a stop or end for movement of the first and/or second swages 2904, 2906 within the bore 2908. The shoulder 2912 may be similar in form and/or function to the shoulder 1372 of FIG. 18.

The expandable sleeve 2902 includes an inner surface 2914 that defines the bore 2908. The inner surface 2914 may be tapered, for example, as shown, include two reverse tapers as proceeding in the axial direction. The first and second swages 2904, 2906 define outer surfaces 2916, 2918, respectively, that engage the inner surface 2914 of the expandable sleeve 2902 as the first and second swages 2904, 2906 are moved toward one another within the bore 2908.

Further, the shoulder 2912 may define end faces 2915A, 2915B, which may extend from the inner surface 2914 and be configured to engage and prevent further axial movement of the first and second swages 2904, 2906, respectively. In an embodiment, the end faces 2915A, 2915B may each meet the inner surface 2914 and define an obtuse angle therewith, as shown.

The inner surface 2914 and/or either or both of the outer surfaces 2916, 2918 may include or otherwise have positioned thereon a gripping feature. In an embodiment, the gripping feature may be or include a friction-increasing material (e.g., coating) applied to the inner surface 2914 and/or either or both of the outer surfaces 2916, 2918. Such friction-increasing material may include a grit (e.g., carbide, ceramic, etc.). Further, such friction-increasing material may include a thermal-spray metal. Examples of such friction-increasing materials include one or more of those described in U.S. Pat. Nos. 8,579,024 and 7,487,840, and/or 9,920,412, which are incorporated by reference above. In other embodiments, the gripping feature may be provided by include teeth, wickers, buttons, designed to bite into (e.g., partially embed in) another material, and/or ratcheting members or other one-way movement devices.

The setting tool 2910 may include an inner body 3000, a setting sleeve 3002, and an optional bearing nut 3004. The inner body 3000 may extend through the setting sleeve 3002, and at least partially through the first and second swages 2904, 2906, and may be releaseably connected to the second swage 2906, such as through a shearable connection with the optional bearing nut 3004. In other embodiments, the body 3000 may be directly connected to the second swage 2906, e.g., by a shearable member such as a shear pin or screw, and the bearing nut 3004 may be omitted. The setting sleeve 3002 may be configured to bear upon the first swage 2902, to apply an axial force thereon towards the second swage 2904. The inner body 3000 (potentially via the bearing nut 3004) may be configured to bear upon the second swage 2904, to apply an axial force thereon towards the first swage 2902.

Accordingly, as shown in FIG. 30, the inner body 3000 may be pulled upwards (toward the left), while the setting sleeve 3002 is pushed downwards (toward the right). This causes the first and second swages 2904, 2906 to move axially toward one another within the expandable sleeve 2902, which in turn causes the expandable sleeve 2902 to deform and expand radially outwards. The distance that the swages 2904, 2906 move toward one another may be dictated by the diameter of the casing (or other oilfield tubular surrounding the tool 2900 downhole) relative to the diameters of the swages 2904, 2906 and the expandable sleeve 2902. In some cases, the swages 2904, 2906 thus may thus not contact the shoulder 2912 in the set configuration. As such, the shoulder 2912 may serve to prevent high pressures from pushing the first swage 2902 axially through the expandable sleeve 2902 (i.e., to the right, and out of the opposite end of the expandable sleeve 2902).

At some point, as shown in FIG. 31, sufficient axial forces may develop between the inner body 3000 and the second swage 2906 that the shearable connection therebetween (e.g., between the bearing nut 3004 and the inner body 3000 or between the inner body 3000 and the second swage 2906) yields, thereby releasing the inner body 3000 from connection/engagement with the second swage 2906. Friction between the first and second swages 2904, 2906 and the expandable sleeve 2902, potentially enhanced by the friction-increasing material (or another gripping feature) discussed above, may maintain the position of the first and second swages 2904, 2906, keeping the expandable sleeve 2902 radially expanded and engaging the surrounding tubular. The inner body 3000 and the setting sleeve 3002 may then be removed. The bearing nut 3004, if provided, may remain coupled to the second swage 2906, or may fall to the sump of the well. Once the inner body 3000 and setting sleeve 3002 are removed, the first swage 2904 is available to receive an obstructing member (e.g., ball) in the seat 2905, so as to obstruct fluid communication (e.g., seal) the bore 2908 of the expandable sleeve 2902.

FIG. 32 illustrates a flowchart of a method 3200 for plugging an oilfield tubular in a well, according to an embodiment. An example of the method 3200 may be understood with reference to the tool 2900 of FIGS. 29-31; however, it will be appreciated that method 3200 is not limited to any particular structure unless otherwise stated herein.

The method 3200 may include positioning the downhole tool 2900 in an oilfield tubular (e.g., casing, liner, or the wellbore wall), as at 3202. The method 3200 may also include forcing first and second swages 2904, 2906 of the downhole tool 2900 together to expand an expandable sleeve 2902 of the downhole tool 2900 into engagement with the surrounding oilfield tubular, as at 3204. As indicated at 3205, a shoulder 2912 of the expandable sleeve 2902 prevents movement of at least one of the swages 2904, 2906 therepast. It should be noted that the swages 2904, 2906 may or may not contact the shoulder 2912 during the initial expansion of the expandable sleeve 2902; indeed, in at least some embodiments, the expandable sleeve 2902 may be fully expanded into engagement with the surrounding oilfield tubular without the swages 2904, 2906 contacting the shoulder 2912. The shoulder 2912 may, in such case, serve to prevent the first swage 2904 from being forced to slide therepast and potentially downward, through the expandable sleeve 2902, e.g., when the well is plugged by the tool 2900 and pressure is increased above the tool 2900.

The method 3200 may then include deploying an obstructing member into the tubular 3206. The obstructing member (e.g., a ball or dart) may be caught in a valve seat 2905 provided by one of the swages 2904, 2906 (illustrated, by way of example, as provided by the first swage 2904). Once the expandable sleeve 2902 is expanded into engagement with the surrounding tubular and the obstructing member is caught in the valve seat 2905, the tool 2900 blocks (plugs) the tubular.

In some embodiments, the method 3200 may additionally include causing at least a portion of the expandable sleeve 2902, the first swage 2904, the second swage 2906, and/or the obstructing member to dissolve, as at 3210. For example, at least a portion of one of these components may be made at least partially from a material configured to dissolve in the presence of wellbore fluid, e.g., after a predetermined amount of time. Such materials may include various magnesium alloys.

FIG. 33 illustrates a partial sectional view of another downhole tool 3300 in a run-in configuration, according to an embodiment. The tool 3300 includes an expandable sleeve 3302 and a setting tool 3303, which may extend through a bore 3301 of the expandable sleeve 3302. The downhole tool 3300 may also include one or more swages, e.g., a first swage 3304 and a second swage 3306, which may be positioned in the bore 3301. In the illustrated embodiment, the first and second swages 3304, 3306 may be positioned proximal to opposite axial ends 3307A, 3307B of the expandable sleeve 3302 in the run-in configuration. In an embodiment, as illustrated, the second swage 3306, on the downhole side of the tool 3300, may be directly coupled to the setting tool 3303 e.g., via threads or any other connection that may yield upon a desired setting force being applied and thereafter allow the setting tool 3303 to be released from the swage 3306. The setting tool 3303, as discussed above, may include an outer body that pushes axially on the first swage 3304, pushing it toward the second swage 3306. Thus, by operation of the setting tool 3303, forces are applied on the swages 3304, 3306 in opposite axial directions, and the swages 3304, 3306 are thereby forced axially together (by moving one or both of the swages 3304, 3306 with respect to the expandable sleeve 3302). This operation sets the expandable sleeve 3302 in the wellbore.

In an embodiment, at least a portion of an outer diameter surface 3308 of the expandable sleeve 3302 is configured to engage and seal with a surrounding tubular (e.g., a casing, a liner, the wellbore wall, etc.). To facilitate such engagement, grit may be applied (e.g., embedded, integrally-formed with, adhered to, or in any other way secured to) the outer diameter surface 3308. In at least one example, one or more bands of grit (six are shown: 3310A, 3310B, 3310C, 3310D, 3310E, 3310F) may be provided, which may at least partially encircle the outer diameter surface 3308, but may be separated axially apart from one another. In other embodiments, the bands 3310A-F may extend outwards from a common layer of grit that connects together the individual bands 3310A-F. For example, the bands of grit 3310A-F may include a grit made from a carbide material, such as described in U.S. Pat. No. 8,579,024, which is incorporated by reference above. In some embodiments, the grit may be provided as a thermal-spray metal, such as WEARSOX®, for example, as disclosed in U.S. Pat. Nos. 7,487,840, and/or 9,920,412, incorporated by reference above.

In some embodiments, the band of grit 3310A formed at the uphole axial end 3307A, and/or the band of grit 3310F formed at the downhole axial end 3307B, may extend outward radially, past the extent of the other bands of grid 3310B-F and/or axially past the respective end 3307A or 3307B, providing a sacrificial wear surface to protect the remaining grit bands 3310B-F, the expandable sleeve 3302, and/or the swages 3304, 3306 from abrasion during run-in and use.

When the expandable sleeve 3302 is expanded by forcing the first and second swages 3304, 3306 together, at least some of the bands of grit 3310A-F may be successively driven into the surrounding tubular, e.g., depending on how far into the expandable sleeve 3302 the respective swages 3304, 3306 are driven. As such, the bands of grit 3310A-F that engage the surrounding tubular may not only increase the friction of the engagement between the expandable sleeve 3302 and the surrounding tubular, but may also form a seal therewith. As such, a separate, e.g., elastomeric, sealing element may not be necessary and may be omitted because the bands of grit 3310A-F may both grip and seal with the surrounding tubular.

FIG. 34 illustrates a side, cross-sectional view of a downhole tool 3400 in a set or “expanded” configuration. As shown, the tool 3400 includes an expandable sleeve 3402 and two swages 3404, 3406, similar to those described above, positioned in a bore 3401 of the sleeve 3402. During run-in, prior to adducting the swages 3404, 3406, the expandable sleeve 3402 may be cylindrical, at least on its outer diameter surface, which may facilitate run-in. As the swages 3404, 3406 are adducted together, end portions 3408A, 3408B of the expandable sleeve 3402 that contact the swages 3404, 3406 are pushed radially outward, into engagement with a surrounding tubular 3407, along the curved outer surface 3409 of the swage 3404, 3406.

Thus, the expandable sleeve 3402 incrementally expands, defining the expanded end portions 3408A, 3408B that contact, anchor to, and at least partially seal with the surrounding tubular 3407, while providing curved transitions 3410A, 3410B to a narrower, unexpanded middle portion 3412 (where the swages 3404, 3406 have not or do not reach), and thus defining an “hour glass” shape. Further, the unexpanded portion 3412 may define a gap 3414 with the surrounding tubular 3407, even when the end portions 3408A, 3410B engage the surrounding tubular 3407. As mentioned above, the grit or another gripping and/or gripping and sealing feature may be provided between swages 3404, 3406 and the expandable sleeve 3402 and/or between the expandable sleeve 3402 and the surrounding tubular 3407. In particular, the grit may be applied to the outer diameter surface of at least a portion of the end portions 3408A, 3408B so as to engage, grip, and at least partially seal with the surrounding tubular 3407 when the end portions 3408A, 3408B are expanded.

The expandable sleeve 3402 may also define a shoulder 3420 extending radially inward into the bore 3401. The shoulder 3420 may be aligned with the unexpanded portion 3412. The shoulder 3420 may be configured to engage the swages 3404, 3406 in some situations, so as to prevent further adduction of the swages 3404, 3406. This may prevent the unexpanded portion 3412 from being expanded, in addition to, in at least some examples, preventing the first and/or second swage 3404, 3406 from being ejected from the bore 3401 by fluid pressure.

As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; “uphole” and “downhole”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”

The foregoing has outlined features of several embodiments so that those skilled in the art may better understand the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.

Claims

1. A downhole tool, comprising: an expandable sleeve defining a bore extending axially therethrough;a first swage positioned at least partially within the bore and comprising a valve seat configured to receive an obstructing member, such that the obstructing member and the first swage substantially prevent fluid communication through the bore when the obstructing member is seated in the valve seat; anda second swage positioned at least partially within the bore,wherein the first and second swages are configured to be moved toward one another in the bore at least partially by operation of a setting tool, such that, as the first and second swages are moved toward one another, the first and second swages engage end portions of the expandable sleeve and progressively, as the first and second swages are moved relative to the expandable sleeve, deform the end portions of the expandable sleeve radially outwards and into engagement with a surrounding tubular, andwherein the expandable sleeve, in an expanded configuration in which the end portions engage the surrounding tubular, defines a middle portion axially between the expanded end portions that is not engaged by the first and second swages, wherein the middle portion is not expanded by the first and second swages, or is expanded by the first and second swages radially by a distance that is less than a distance by which the end portions expand, and wherein the middle portion is configured to form a gap with the surrounding tubular when the expandable sleeve is in the expanded configuration.
2. The tool of claim 1, further comprising a gripping feature on an outer diameter surface of the expandable sleeve, wherein the gripping feature is configured to engage the surrounding tubular, and to form a seal between the expandable sleeve and the surrounding tubular.
3. The tool of claim 2, wherein the gripping feature comprises a band of grit applied to the outer diameter surface.
4. The tool of claim 3, wherein the band of grit is positioned on one of the end portions.
5. The tool of claim 1, further comprising a plurality of bands of grit, each extending at least partially circumferentially around an outer diameter surface of the expandable sleeve and being separated axially apart from one another.
6. The tool of claim 5, wherein one of the plurality of bands of grit extends axially past an axial end of the expandable sleeve.
7. The tool of claim 1, wherein, in the expanded configuration, the expandable sleeve defines curved sections between the respective end portions and the middle portion.
8. The tool of claim 1, wherein the expandable sleeve defines a shoulder extending radially inward into the bore, and being aligned with the middle portion, and wherein the shoulder is configured to prevent the first and second swages from moving therepast.
9. The tool of claim 8, wherein the shoulder comprises a first end face extending from a first portion of the bore, and a second end face extending from a second portion of the bore, wherein the first end face and the first portion of the bore define a first end-face angle where the first portion and the first end face meet, and wherein the second end face and the second portion of the bore define a second end-face angle where the second portion and the second end face meet, the first and second end-face angles each being non-zero.
10. The tool of claim 1, wherein the first swage comprises a curved outer surface, and wherein the expandable sleeve comprises an inner surface at least partially defining the bore, wherein the outer surface is configured to engage the inner surface when the first swage is moved with respect to the expandable sleeve.
11. The tool of claim 10, further comprising a gripping feature on the outer surface, the inner surface, or both, wherein the gripping feature is configured to resist movement of the first swage relative to the expandable sleeve in at least one axial direction.
12. The tool of claim 1, wherein the expandable sleeve is at least partially formed from a material configured to dissolve in a wellbore.
13. The downhole tool of claim 1, wherein the middle portion is not expanded by engagement with the first and second swages.
14. A tool assembly, comprising: a downhole tool comprising: an expandable sleeve defining a bore therethrough;a first swage positioned at least partially within the bore and comprising a valve seat configured to receive an obstructing member, such that the obstructing member and the first swage substantially prevent fluid communication through the bore when the obstructing member is seated in the valve seat; anda second swage positioned at least partially within the bore; and a setting tool, comprising:an outer body configured to engage the first swage and apply a force on the first swage directed toward the second swage; andan inner body extending through the first swage, the expandable sleeve, and the second swage, the inner body being coupled to the second swage and configured to apply a force on the second swage opposite in direction to the force on the first swage,wherein the first and second swages are configured to be moved toward one another in the bore at least partially by operation of the setting tool, such that, as the first and second swages are moved toward one another, the first and second swages engage end portions of the expandable sleeve and progressively, as the first and second swages are moved relative to the expandable sleeve, deform the end portions of the expandable sleeve radially outwards and into engagement with a surrounding tubular, andwherein the expandable sleeve, in an expanded configuration in which the end portions engage the surrounding tubular, defines a middle portion between the expanded end portions that is not engaged by the first and second swages, wherein the middle portion is not expanded by the first and second swages or is expanded by the first and second swages radially by a distance that is less than a distance by which the end portions expand, and wherein the middle portion is configured to form a gap with the surrounding tubular when the expandable sleeve is in the expanded configuration.
15. The tool assembly of claim 14, wherein the inner body of the setting tool is directly coupled to the second swage.
16. The tool assembly of claim 14, wherein the downhole tool further comprises a gripping feature on an outer diameter surface of the expandable sleeve, wherein the gripping feature is configured to engage the surrounding tubular, and to form a seal between the expandable sleeve and the surrounding tubular.
17. The tool assembly of claim 16, wherein the gripping feature comprises a band of grit applied to the outer diameter surface on at least one of the end portions.
18. The tool assembly of claim 14, wherein the downhole tool further comprises a plurality of bands of grit, each extending at least partially circumferentially around an outer diameter surface of the expandable sleeve and being separated axially apart from one another.
19. The tool assembly of claim 14, wherein the expandable sleeve defines a shoulder extending radially inward into the bore, and being aligned with the middle portion, and wherein the shoulder is configured to prevent the first and second swages from moving therepast.
20. The tool assembly of claim 19, wherein the first swage comprises a curved outer surface, and wherein the expandable sleeve comprises an inner surface at least partially defining the bore, wherein the outer surface is configured to engage the inner surface when the first swage is moved with respect to the expandable sleeve, wherein the downhole tool further comprises a gripping feature on the outer surface, the inner surface, or both, and wherein the gripping feature is configured to resist movement of the first swage relative to the expandable sleeve in at least one axial direction.
21. The downhole tool of claim 14, wherein the inner body of the setting tool is configured to release from connection with the second swage when the force applied on the second swage reaches a predetermined amount.
22. A downhole tool, comprising: an expandable sleeve defining a bore extending axially therethrough;a first swage positioned at least partially within the bore and comprising a valve seat configured to receive an obstructing member, such that the obstructing member and the first swage substantially prevent fluid communication through the bore when the obstructing member is seated in the valve seat;a second swage positioned at least partially within the bore; anda gripping and sealing feature applied to at least a portion of an outer diameter surface of the expandable sleeve,wherein the first and second swages are configured to be moved toward one another in the bore at least partially by operation of a setting tool, such that, as the first and second swages are moved toward one another, the first and second swages engage respective end portions of the expandable sleeve and progressively, as the first and second swages are moved relative to the expandable sleeve, deform the respective end portions of the expandable sleeve radially outwards and into engagement with a surrounding tubular,wherein the expandable sleeve, in an expanded configuration in which the end portions engage the surrounding tubular, defines a middle portion between the expanded end portions that is not engaged by the first and second swages, wherein the middle portion is not expanded by the first and second swages or is expanded by the first and second swages radially by a distance that is less than a distance by which the end portions expand, wherein the middle portion is configured to form a gap with the surrounding tubular when the expandable sleeve is in the expanded configuration, andwherein the gripping and sealing feature applied to the outer diameter surface grips and seals with the surrounding tubular.
23. The downhole tool of claim 22, wherein the gripping and sealing feature comprises a grit applied to the outer diameter surface.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent application having Ser. No. 15/727,390, filed on Oct. 6, 2017, which claims priority to U.S. Provisional Patent Application having Ser. No. 62/550,273, which was filed on Aug. 25, 2017, and which is also a continuation-in-part of U.S. patent application having Ser. No. 15/217,090, which was filed on Jul. 22, 2016 and claims priority to U.S. Provisional Patent Application having Ser. No. 62/196,712, filed on Jul. 24, 2015, and U.S. Provisional Patent Application having Ser. No. 62/319,564, filed on Apr. 7, 2016. Each of these priority applications is incorporated herein by reference in its entirety.

US Referenced Citations (169)

Number	Name	Date	Kind
2189697	Baker	Feb 1940	A
2222233	Mize	Nov 1940	A
2225143	Baker et al.	Dec 1940	A
4483399	Colgate	Nov 1984	A
4901794	Baugh et al.	Feb 1990	A
5131468	Lane et al.	Jul 1992	A
5325923	Surjaatmadja et al.	Jul 1994	A
5396957	Surjaatmadja et al.	Mar 1995	A
5479986	Gano et al.	Jan 1996	A
5623993	Buskirk et al.	Apr 1997	A
5709269	Head	Jan 1998	A
6354373	Vercaemer et al.	Mar 2002	B1
6446323	Metcalfe et al.	Sep 2002	B1
6662876	Lauritzen	Dec 2003	B2
6684958	Williams et al.	Feb 2004	B2
6702029	Metcalfe et al.	Mar 2004	B2
6722437	Vercaemer et al.	Apr 2004	B2
7093656	Maguire	Aug 2006	B2
7104322	Whanger et al.	Sep 2006	B2
7150318	Freeman	Dec 2006	B2
7168494	Starr et al.	Jan 2007	B2
7168499	Cook et al.	Jan 2007	B2
7172025	Eckerlin	Feb 2007	B2
7195073	Fraser, III	Mar 2007	B2
7255178	Slup et al.	Aug 2007	B2
7273110	Pedersen et al.	Sep 2007	B2
7322416	Burris, II et al.	Jan 2008	B2
7350582	McKeachnie et al.	Apr 2008	B2
7350588	Simpson et al.	Apr 2008	B2
7363967	Burris, II et al.	Apr 2008	B2
7367389	Duggan et al.	May 2008	B2
7367391	Stuart et al.	May 2008	B1
7373990	Harrall et al.	May 2008	B2
7395856	Murray	Jul 2008	B2
7422060	Hammami et al.	Sep 2008	B2
7451815	Hailey, Jr.	Nov 2008	B2
7464764	Xu	Dec 2008	B2
7475736	Lehr et al.	Jan 2009	B2
7503392	King et al.	Mar 2009	B2
7520335	Richard et al.	Apr 2009	B2
7527095	Bloess et al.	May 2009	B2
7530582	Truchsess et al.	May 2009	B2
7552766	Gazewood	Jun 2009	B2
7562704	Wood et al.	Jul 2009	B2
7584790	Johnson	Sep 2009	B2
7603758	Cook et al.	Oct 2009	B2
7607476	Tom et al.	Oct 2009	B2
7647964	Akbar et al.	Jan 2010	B2
7661481	Todd et al.	Feb 2010	B2
7665537	Patel et al.	Feb 2010	B2
7665538	Robisson et al.	Feb 2010	B2
7690436	Turley et al.	Apr 2010	B2
7757758	O'Malley et al.	Jul 2010	B2
7798236	McKeachnie et al.	Sep 2010	B2
7814978	Steele et al.	Oct 2010	B2
7832477	Cavender et al.	Nov 2010	B2
7861744	Fly et al.	Jan 2011	B2
7861774	Fehr et al.	Jan 2011	B2
7921925	Maguire et al.	Apr 2011	B2
8016032	Mandrell et al.	Sep 2011	B2
8079413	Frazier	Dec 2011	B2
8267177	Vogel et al.	Sep 2012	B1
8276670	Patel	Oct 2012	B2
8291982	Murray et al.	Oct 2012	B2
8307892	Frazier	Nov 2012	B2
8327931	Agrawal et al.	Dec 2012	B2
8336616	McClinton	Dec 2012	B1
8397820	Fehr et al.	Mar 2013	B2
8403037	Agrawal et al.	Mar 2013	B2
8425651	Xu et al.	Apr 2013	B2
8459347	Stout	Jun 2013	B2
8567494	Rytlewski et al.	Oct 2013	B2
8573295	Johnson et al.	Nov 2013	B2
8579024	Mailand et al.	Nov 2013	B2
8631876	Xu et al.	Jan 2014	B2
8636074	Nutley et al.	Jan 2014	B2
8684096	Harris et al.	Apr 2014	B2
8776884	Xu et al.	Jul 2014	B2
8905149	Bailey et al.	Dec 2014	B2
8936085	Boney et al.	Jan 2015	B2
8950504	Xu et al.	Feb 2015	B2
8978776	Spray	Mar 2015	B2
9010416	Xu et al.	Apr 2015	B2
9016363	Xu et al.	Apr 2015	B2
9033041	Baihly et al.	May 2015	B2
9033060	Xu et al.	May 2015	B2
9057260	Kelbie et al.	Jun 2015	B2
9080403	Xu et al.	Jul 2015	B2
9080439	O'Malley et al.	Jul 2015	B2
9101978	Xu et al.	Aug 2015	B2
9206659	Zhang et al.	Dec 2015	B2
9309733	Xu et al.	Apr 2016	B2
9334702	Allen et al.	May 2016	B2
9382790	Bertoja et al.	Jul 2016	B2
9574415	Xu et al.	Feb 2017	B2
9605508	Xu et al.	Mar 2017	B2
9752423	Lynk	Sep 2017	B2
9909384	Chauffe et al.	Mar 2018	B2
20030062171	Maguire et al.	Apr 2003	A1
20040060700	Vert et al.	Apr 2004	A1
20040069485	Ringgengberg et al.	Apr 2004	A1
20040177952	Turley et al.	Sep 2004	A1
20040244968	Cook et al.	Dec 2004	A1
20050011650	Harrall et al.	Jan 2005	A1
20050139359	Maurer et al.	Jun 2005	A1
20050199401	Patel et al.	Sep 2005	A1
20050205266	Todd et al.	Sep 2005	A1
20050211446	Ricalton et al.	Sep 2005	A1
20050217866	Watson et al.	Oct 2005	A1
20060185855	Jordan et al.	Aug 2006	A1
20070000664	Ring et al.	Jan 2007	A1
20070044958	Rytlewski et al.	Mar 2007	A1
20070272418	Corre et al.	Nov 2007	A1
20080066923	Xu	Mar 2008	A1
20080073074	Frazier	Mar 2008	A1
20080135248	Talley et al.	Jun 2008	A1
20080142223	Xu et al.	Jun 2008	A1
20090044949	King et al.	Feb 2009	A1
20090065196	Holland et al.	Mar 2009	A1
20090242213	Braddick	Oct 2009	A1
20090266560	Ring et al.	Oct 2009	A1
20100032167	Adam et al.	Feb 2010	A1
20100116489	Nelson	May 2010	A1
20100170682	Brennan, III	Jul 2010	A1
20100270031	Patel	Oct 2010	A1
20100270035	Ring et al.	Oct 2010	A1
20100276159	Mailand	Nov 2010	A1
20100314127	Swor et al.	Dec 2010	A1
20100319427	Lohbeck	Dec 2010	A1
20100319927	Yokley et al.	Dec 2010	A1
20110005779	Lembcke	Jan 2011	A1
20110048743	Stafford et al.	Mar 2011	A1
20110132143	Xu et al.	Jun 2011	A1
20110132619	Agrawal et al.	Jun 2011	A1
20110132621	Agrawal et al.	Jun 2011	A1
20110132623	Moeller	Jun 2011	A1
20110240295	Porter et al.	Oct 2011	A1
20110266004	Hallundbaek et al.	Nov 2011	A1
20110284232	Huang	Nov 2011	A1
20120024109	Xu et al.	Feb 2012	A1
20120055669	Levin et al.	Mar 2012	A1
20120067583	Zimmerman et al.	Mar 2012	A1
20120111566	Sherman et al.	May 2012	A1
20120118583	Johnson et al.	May 2012	A1
20120132426	Xu et al.	May 2012	A1
20120168163	Bertoja et al.	Jul 2012	A1
20120199341	Kellner et al.	Aug 2012	A1
20120205873	Turley	Aug 2012	A1
20120247767	Themig et al.	Oct 2012	A1
20120273199	Cresswell et al.	Nov 2012	A1
20130008671	Booth	Jan 2013	A1
20130062063	Baihly et al.	Mar 2013	A1
20130081825	Lynde et al.	Apr 2013	A1
20130186615	Hallubaek et al.	Jul 2013	A1
20130186616	Xu et al.	Jul 2013	A1
20130299185	Xu et al.	Nov 2013	A1
20140014339	O'Malley et al.	Jan 2014	A1
20140076571	Frazier et al.	Mar 2014	A1
20150068757	Hofman et al.	Mar 2015	A1
20150075774	Raggio	Mar 2015	A1
20150129215	Xu et al.	May 2015	A1
20150184485	Xu et al.	Jul 2015	A1
20150218904	Chauffe et al.	Aug 2015	A1
20160160591	Xu et al.	Jun 2016	A1
20160186511	Coronado	Jun 2016	A1
20160305215	Harris et al.	Oct 2016	A1
20160312557	Kitzman	Oct 2016	A1
20170101843	Waterhouse et al.	Apr 2017	A1
20170130553	Harris	May 2017	A1

Foreign Referenced Citations (15)

Number	Date	Country
091776	Feb 2015	AR
2010214651	Mar 2012	AU
2251525	Nov 2010	EP
2345308	Jul 2000	GB
2448449	Oct 2008	GB
2448449	Dec 2008	GB
2482078	Jan 2012	GB
2010039131	Apr 2010	WO
2011023743	Nov 2011	WO
2011137112	Nov 2011	WO
2014014591	Jan 2014	WO
2014014591	Jan 2014	WO
2014100072	Jun 2014	WO
2016160003	Oct 2016	WO
2017151384	Sep 2017	WO

Non-Patent Literature Citations (41)

Entry
Tae Wook Park (Authorized Officer), International Search Report and Written Opinion dated Nov. 4, 2016, PCT Application No. PCT/US2016/043545, filed Jul. 22, 2016, pp. 1-18.
Hinkie et al., “Multizone Completion with Accurately Placed Stimulation Through Casing Wall”, SPE Production and Operations Symposium, Mar. 31-Apr. 3, 2007, pp. 1-4.
Anjum et al., “Solid Expandable Tubular Combined with Swellable Elastomers Facilitate Multizonal Isolation and Fracturing, with Nothing Left in the Well Bore to Drill for Efficient Development of Tight Gas Reservoirs in Cost Effective Way”, SPE International Oil & Gas Conference, Jun. 8-10, 2010, pp. 1-16.
Vargus et al., “Completion System Allows for Interventionless Stimulation Treatments in Horizontal Wells with Multiple Shale Pay Zones”, SPE Annual Technical Conference, Sep. 2008, pp. 1-8.
Gorra, et al., “Expandable Zonal Isolation Barrier (ZIB) Provides a Long-Term Well Solution as a High Differential Pressure Metal Barrier to Flow”, Brazilian Petroleum Technical Papers, 2010, Abstract only, 1 page.
Vargus, et al., “System Enables Multizone Completions”, The American Oil & Gas Reporter, 2009, Abstract only, 1 page.
Vargus, et al., “Completion System Allows for Interventionless Stimulation Treatments in Horizontal Wells with Multiple Shale Pay Zones”, Annual SPE Technical Conference, Sep. 2008, Abstract only, 1 page.
Zhang et al., High Strength Nanostructured Materials and Their Oil Field Applications, SPE 157092, SPE International, 2012, pp. 1-6.
Xu et al., Smart Nanostructured Materials Deliver High Reliability Completion Tools for Gas Shale Fracturing, SPE 146586, SPE International, 2011, pp. 1-6.
Larimore et al., Overcoming Completion Challenges with Interventionless Devices—Case Study—The “Disappearing Plug”, SPE 63111, SPE International, 2000, pp. 1-13.
King et al., A Methodology for Selecting Interventionless Packer Setting Techniques, SPE-90678-MS, Society of Petroleum Engineers, 2004, pp. 1-3.
Xu et al., Declaration Under 37 CFR 1.132, U.S. Appl. No. 14/605,365, filed Jan. 26, 2015, pp. 1-4.
Non-Final Office Action dated May 20, 2014, U.S. Appl. No. 13/466,322, filed May 8, 2012, pp. 1-111.
Notice of Allowance dated Sep. 16, 2014, U.S. Appl. No. 13/466,322, filed May 8, 2012, pp. 1-10.
Notice of Allowance dated Oct. 29, 2014, U.S. Appl. No. 13/466,322, filed May 8, 2012, pp. 1-10.
Non-Final Office Action dated Aug. 1, 2014, U.S. Appl. No. 13/358,317, filed Jan. 25, 2012, pp. 1-15.
Notice of Allowance dated Jan. 9, 2015, U.S. Appl. No. 13/358,317, filed Jan. 25, 2012, pp. 1-7.
Non-Final Office Action dated Jul. 30, 2014, U.S. Appl. No. 13/466,329, filed May 8, 2012, pp. 1-16.
Final Office Action dated Dec. 18, 2014, U.S. Appl. No. 13/466,329, filed May 8, 2012, pp. 1-12.
Notice of Allowance dated Mar. 11, 2015, U.S. Appl. No. 13/466,329, filed May 8, 2012, pp. 1-5.
Non-Final Office Action dated Nov. 26, 2014, U.S. Appl. No. 13/358,307, filed Jan. 25, 2012, pp. 1-17.
Notice of Allowance dated Mar. 25, 2015, U.S. Appl. No. 13/358,307, filed Jan. 25, 2012, pp. 1-12.
Non-Final Office Action dated Oct. 6, 2014, U.S. Appl. No. 13/358,332, filed Jan. 25, 2012, pp. 1-15.
Notice of Allowance dated Apr. 7, 2015, U.S. Appl. No. 13/358,332, filed Jan. 25, 2012, pp. 1-8.
Non-Final Office Action dated Mar. 17, 2015, U.S. Appl. No. 13/705,972, filed Dec. 5, 2012, pp. 1-23.
Final Office Action dated Oct. 2, 2015, U.S. Appl. No. 13/705,972, filed Dec. 5, 2012, pp. 1-20.
Advisory Action dated Nov. 20, 2015, U.S. Appl. No. 13/705,972, filed Dec. 5, 2012, pp. 1-4.
Notice of Allowance dated Jan. 29, 2016, U.S. Appl. No. 13/705,972, filed Dec. 5, 2012, pp. 1-5.
Non-Final Office Action dated Jan. 15, 2016, U.S. Appl. No. 14/605,365, filed Jan. 26, 2015, pp. 1-10.
Final Office Action dated Jun. 22, 2016, U.S. Appl. No. 14/605,365, filed Jan. 26, 2015, pp. 1-15.
Advisory Action dated Sep. 21, 2016, U.S. Appl. No. 14/605,365, filed Jan. 26, 2015, pp. 1-4.
Notice of Allowance dated Dec. 19, 2016, U.S. Appl. No. 14/605,365, filed Jan. 26, 2015, pp. 1-7.
Non-Final Office Action dated Jun. 23, 2014, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-12.
Non-Final Office Action dated Dec. 9, 2014, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-12.
Non-Final Office Action dated Jun. 25, 2015, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-17.
Final Office Action dated Dec. 9, 2015, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-97.
Non-Final Office Action dated Feb. 22, 2016, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-10.
Final Office Action dated Sep. 6, 2016, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-24.
Advisory Action dated Dec. 6, 2016, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-4.
Notice of Allowance dated Feb. 1, 2017, U.S. Appl. No. 13/466,311, filed May 8, 2012, pp. 1-8.
Tae Wook Park (Authorized Officer), International Search Report and Written Opinion dated Nov. 1, 2018, PCT Application No. PCT/US2018/042993, filed Jul. 20, 2018, pp. 1-14.

Related Publications (1)

	Number	Date	Country
	20180266205 A1	Sep 2018	US

Provisional Applications (3)

Number	Date	Country
62550273	Aug 2017	US
62319564	Apr 2016	US
62196712	Jul 2015	US

Continuation in Parts (2)

	Number	Date	Country
Parent	15727390	Oct 2017	US
Child	15985637		US
Parent	15217090	Jul 2016	US
Child	15727390		US

Downhole tool with an expandable sleeve

Information

Patent Number

Date Filed

Date Issued

Inventors

Original Assignees

Examiners

Agents

CPC

Field of Search

CPC

International Classifications

Abstract