DOWNHOLE SYSTEM FOR ISOLATING SECTIONS OF A WELLBORE

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Disclosure

This disclosure generally relates to systems and related tools used in oil and gas wellbores. More specifically, the disclosure relates to downhole system that may be run into a wellbore and useable for wellbore isolation, and methods pertaining to the same. In particular embodiments, the tool may be a composite plug made of drillable materials.

2. Background of the Disclosure

An oil or gas well includes a wellbore extending into a subterranean formation at some depth below a surface (e.g., Earth's surface), and is usually lined with a tubular, such as casing, to add strength to the well. Many commercially viable hydrocarbon sources are found in “tight” reservoirs, which means the target hydrocarbon product may not be easily extracted. The surrounding formation (e.g., shale) to these reservoirs is typically has low permeability, and it is uneconomical to produce the hydrocarbons (i.e., gas, oil, etc.) in commercial quantities from this formation without the use of drilling accompanied with fracing operations.

Fracing is common in the industry and growing in popularity and general acceptance, and includes the use of a plug set in the wellbore below or beyond the respective target zone, followed by pumping or injecting high pressure frac fluid into the zone. The frac operation results in fractures or “cracks” in the formation that allow hydrocarbons to be more readily extracted and produced by an operator, and may be repeated as desired or necessary until all target zones are fractured.

A frac plug serves the purpose of isolating the target zone for the frac operation. Such a tool is usually constructed of durable metals, with a sealing element being a compressible material that may also expand radially outward to engage the tubular and seal off a section of the wellbore and thus allow an operator to control the passage or flow of fluids. For example, by forming a pressure seal in the wellbore and/or with the tubular, the frac plug allows pressurized fluids or solids to treat the target zone or isolated portion of the formation.

FIG. 1 illustrates a conventional plugging system 100 that includes use of a downhole tool 102 used for plugging a section of the wellbore 106 drilled into formation 110. The tool or plug 102 may be lowered into the wellbore 106 by way of workstring 105 (e.g., e-line, wireline, coiled tubing, etc.) and/or with setting tool 112, as applicable. The tool 102 generally includes a body 103 with a compressible seal member 122 to seal the tool 102 against an inner surface 107 of a surrounding tubular, such as casing 108. The tool 102 may include the seal member 122 disposed between one or more slips 109, 111 that are used to help retain the tool 102 in place.

In operation, forces (usually axial relative to the wellbore 106) are applied to the slip(s) 109, 111 and the body 103. As the setting sequence progresses, slip 109 moves in relation to the body 103 and slip 111, the seal member 122 is actuated, and the slips 109, 111 are driven against corresponding conical surfaces 104. This movement axially compresses and/or radially expands the compressible member 122, and the slips 109, 111, which results in these components being urged outward from the tool 102 to contact the inner wall 107. In this manner, the tool 102 provides a seal expected to prevent transfer of fluids from one section 113 of the wellbore across or through the tool 102 to another section 115 (or vice versa, etc.), or to the surface. Tool 102 may also include an interior passage (not shown) that allows fluid communication between section 113 and section 115 when desired by the user. Oftentimes multiple sections are isolated by way of one or more additional plugs (e.g., 102A).

Upon proper setting, the plug may be subjected to high or extreme pressure and temperature conditions, which means the plug must be capable of withstanding these conditions without destruction of the plug or the seal formed by the seal element. High temperatures are generally defined as downhole temperatures above 200° F., and high pressures are generally defined as downhole pressures above 7,500 psi, and even in excess of 15,000 psi. Extreme wellbore conditions may also include high and low pH environments. In these conditions, conventional tools, including those with compressible seal elements, may become ineffective from degradation. For example, the sealing element may melt, solidify, or otherwise lose elasticity, resulting in a loss the ability to form a seal barrier.

Before production operations commence, the plugs must also be removed so that installation of production tubing may occur. This typically occurs by drilling through the set plug, but in some instances the plug can be removed from the wellbore essentially intact. A common problem with retrievable plugs is the accumulation of debris on the top of the plug, which may make it difficult or impossible to engage and remove the plug. Such debris accumulation may also adversely affect the relative movement of various parts within the plug. Furthermore, with current retrieving tools, jarring motions or friction against the well casing may cause accidental unlatching of the retrieving tool (resulting in the tools slipping further into the wellbore), or re-locking of the plug (due to activation of the plug anchor elements). Problems such as these often make it necessary to drill out a plug that was intended to be retrievable.

However, because plugs are required to withstand extreme downhole conditions, they are built for durability and toughness, which often makes the drill-through process difficult. Even drillable plugs are typically constructed of a metal such as cast iron that may be drilled out with a drill bit at the end of a drill string. Steel may also be used in the structural body of the plug to provide structural strength to set the tool. The more metal parts used in the tool, the longer the drilling operation takes. Because metallic components are harder to drill through, this process may require additional trips into and out of the wellbore to replace worn out drill bits.

The use of plugs in a wellbore is not without other problems, as these tools are subject to known failure modes. When the plug is run into position, the slips have a tendency to pre-set before the plug reaches its destination, resulting in damage to the casing and operational delays. Pre-set may result, for example, because of residue or debris (e.g., sand) left from a previous frac. In addition, conventional plugs are known to provide poor sealing, not only with the casing, but also between the plug's components. For example, when the sealing element is placed under compression, its surfaces do not always seal properly with surrounding components (e.g., cones, etc.).

Downhole tools are often activated with a drop ball that is flowed from the surface down to the tool, whereby the pressure of the fluid must be enough to overcome the static pressure and buoyant forces of the wellbore fluid(s) in order for the ball to reach the tool. Frac fluid is also highly pressurized in order to not only transport the fluid into and through the wellbore, but also extend into the formation in order to cause fracture. Accordingly, a downhole tool must be able to withstand these additional higher pressures.

In addition, downhole tool technology has evolved from tools historically used in vertical orientation, which has resulted in new problems. For example, when used in a general horizontal orientation downhole tools, as well as the work string, encounter frictional resistance and gravitational force not otherwise present in a vertical orientation. In some instances, the downhole tool and/or the work string will be off-center, and even contact the surrounding tubular (e.g., casing), for thousands of feet.

Referring briefly to FIGS. 1A-1D, pitfalls associated with tool technology originally intended for vertical use, but ultimately used horizontally, may be seen. That is, in the prior art downhole tool 102 was conventionally used in a vertical orientation illustrated by FIG. 1A. This view is a partial component view of an end 114A of a mandrel 114 disposed within tool 102 and surrounded by a setting sleeve 154, as would be understood and apparent to one of skill in the art. It should be appreciated that other tool and system components exist (e.g., workstring 112, etc.) and are in place, and the FIGS. 1A-1C are for simplified illustrative purposes.

When the tool 102 is run into the well 106 and through tubular 108, the tool 102 will encounter various forces, including downward force F1, which may be a net force of pressure, gravity, etc. Tool area A1, resembling a circumferential contact region or near-contact region of the mandrel end 114A and the setting sleeve 154 incurs little to no portion of the force F1 because the area is largely parallel to the vector. The conventional tool 102 incorporates the simplest component parts that are cheapest and easily fabricated, which includes machined, linear portions. The tool 102 is easily positionable, and ultimately set, so that a largely concentric and equal annulus is formed between the tool 102 and the casing 108 (see, e.g., annulus arrows 199).

While this type of configuration is sufficient for vertical orientation, very distinct and different problems are encountered when the tool 102 is used in horizontal service. FIG. 1B readily illustrates how the tool 102, workstring 112, etc. incur various downward forces F1, resulting in the tool 102, etc. moving along the bottom portion of the casing 108. When the setting sequence begins, radial outward movement of slips and compressible member (not shown here) will ultimately urge the tool 102 toward a central position, as illustrated in FIG. 1C. However, when this occurs the tool 102, by way of, for example, area A1 experiences incredible downward forces F2. This happens because as the tool 102 begins to centralize, the workstring 112 in some manner is also urged to centralize. Thus, the weight of the workstring 112 will be transferred into the tool 102, including at a point P1 of the mandrel 114, resulting in a fracture point P1, as shown in FIG. 1D.

The most apparent solution for one of skill would be to increase clearance between the mandrel end and the setting sleeve; however, debris, sand, etc. may fill into this clearance, and then there is ultimately no clearance, resulting in a pseudo tolerance fit, as well as other problems caused by the debris that impairs the function of the tool 102.

Referring briefly to FIG. 1E, a view of a conventional setting sleeve incurring hydraulic drag is shown. In operation, when the tool 102 is set, it is often a hydraulic operation and pressurization that occurs in strokes. After the tool 102 is set and released from the string 105, the string 105 needs to be removed from the wellbore 106. The faster the removal of the string 105, the less cost incurred per foot. Increased removal speed per foot becomes paramount when well lengths start to exceed 10,000 feet.

What is needed is a downhole tool with reduced drag that would allow faster pullout.

Accordingly, there are needs in the art for novel systems and methods for isolating wellbores in a viable and economical fashion. There is a great need in the art for downhole plugging tools that form a reliable and resilient seal against a surrounding tubular. There is also a need for a downhole tool made substantially of a drillable material that is easier and faster to drill. There is a great need in the art for a downhole tool that overcomes problems encountered in a horizontal orientation. There is a need in the art to reduce the amount of time and energy needed to remove a workstring from a wellbore, including reducing hydraulic drag.

It is highly desirous for these downhole tools to readily and easily withstand extreme wellbore conditions, and at the same time be cheaper, smaller, lighter, and useable in the presence of high pressures associated with drilling and completion operations.

SUMMARY

Embodiments of the disclosure pertain to a downhole system useable for isolating sections of a wellbore that may include a work string comprising a downhole end; a setting sleeve coupled with the downhole end; and a downhole tool engaged with the setting sleeve during run-in. The downhole tool may further include a mandrel, a composite member, and/or at least one slip. The setting sleeve may include at least one channel.

The mandrel may include composite material. The composite member may be disposed about the mandrel. The at least one slip may have a one piece configuration. The at least one channel may be linear in length or shape. The at least one channel may be disposed in an outer surface of the setting sleeve.

The setting sleeve may include a plurality of linear channels disposed in the outer surface of the setting sleeve. The composite member may be made of a first material and be configured with a top and a bottom. At least one spiral groove may be formed between about the bottom to about the top.

The setting sleeve may include three groups of channels disposed in an outer surface of the setting sleeve. Each group of channels may include between about 1 and 3 channels each.

The cross-sectional shape of the at least one channel may be rounded. Any channel may have a constant or varying cross sectional shape along its length.

The at least one channel may be non-linear in length.

The setting sleeve may include an effective outer surface area greater than and an actual outer surface area.

Other aspects of the disclosure pertain to a downhole system useable for isolating sections of a wellbore that may include a work string comprising a downhole end; a setting sleeve coupled with the downhole end; and a downhole tool engaged with the setting sleeve during run-in. The downhole tool may include a composite mandrel, a composite member comprising a deformable portion and a resilient portion, a composite slip, and/or a metal slip. The setting sleeve may include at least one channel.

The composite member may be disposed about the composite mandrel. One or both of the composite slip and the metal slip may include a one piece configuration. The at least one channel may be linear in length. The at least one channel may be disposed in an outer surface of the setting sleeve.

The setting sleeve may include a plurality of linear channels disposed in an outer surface of the setting sleeve.

The setting sleeve may include three groups of channels disposed in an outer surface of the setting sleeve. One or more of the groups may include between about 1 and 3 channels each.

The cross-sectional shape of the at least one channel may be rounded. The at least one channel may be non-linear in its length or longitudinal shape. The setting sleeve may include an effective outer surface area greater than and an actual outer surface area.

Yet other embodiments of the disclosure pertain to a downhole system for isolating sections of a wellbore that may include a first end; a second end; an outer surface; an inner surface; a wall thickness formed between the inner surface and the outer surface; and at least one channel.

The at least one channel may be linear in length or longitudinal shape. The at least one channel may be disposed in the outer surface. The at least one channel may be disposed in the inner surface. The at least one channel may be disposed in the wall thickness. The setting sleeve may further include a plurality of linear channels disposed in the outer surface. The at least one channel may include a rounded cross-sectional shape. The setting sleeve may include an effective outer surface area greater than and an actual outer surface area.

These and other embodiments, features and advantages will be apparent in the following detailed description and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the present disclosure, reference will now be made to the accompanying drawings, wherein:

FIG. 1 is a side view of a process diagram of a conventional plugging system;

FIG. 1A shows a side view of a vertical oriented plugging system;

FIG. 1B shows a side view of a horizontal oriented plugging system;

FIG. 1C shows a side view of a horizontal oriented plugging system during setting;

FIG. 1D shows a side view of a fractured plug during setting;

FIG. 1E shows a side view of a work string and setting sleeve incurring hydraulic drag during pullout;

FIGS. 2A-2B each show an isometric views of a system having a downhole tool, according to embodiments of the disclosure;

FIG. 2C shows a side longitudinal view of a downhole tool according to embodiments of the disclosure;

FIG. 2D shows a longitudinal cross-sectional view of a downhole tool according to embodiments of the disclosure;

FIG. 2E shows an isometric component break-out view of a downhole tool according to embodiments of the disclosure;

FIG. 3A shows an isometric view of a mandrel usable with a downhole tool according to embodiments of the disclosure;

FIG. 3B shows a longitudinal cross-sectional view of a mandrel usable with a downhole tool according to embodiments of the disclosure;

FIG. 3C shows a longitudinal cross-sectional view of an end of a mandrel usable with a downhole tool according to embodiments of the disclosure;

FIG. 3D shows a longitudinal cross-sectional view of an end of a mandrel engaged with a sleeve according to embodiments of the disclosure;

FIG. 4A shows a longitudinal cross-sectional view of a seal element usable with a downhole tool according to embodiments of the disclosure;

FIG. 4B shows an isometric view of a seal element usable with a downhole tool according to embodiments of the disclosure;

FIG. 5A shows an isometric view of one or more slips usable with a downhole tool according to embodiments of the disclosure;

FIG. 5B shows a lateral view of one or more slips usable with a downhole tool according to embodiments of the disclosure;

FIG. 5C shows a longitudinal cross-sectional view of one or more slips usable with a downhole tool according to embodiments of the disclosure;

FIG. 5D shows an isometric view of a metal slip usable with a downhole tool according to embodiments of the disclosure;

FIG. 5E shows a lateral view of a metal slip usable with a downhole tool according to embodiments of the disclosure;

FIG. 5F shows a longitudinal cross-sectional view of a metal slip usable with a downhole tool according to embodiments of the disclosure;

FIG. 5G shows an isometric view of a metal slip without buoyant material holes usable with a downhole tool according to embodiments of the disclosure;

FIG. 6A shows an isometric view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure;

FIG. 6B shows a longitudinal cross-sectional view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure;

FIG. 6C shows a close-up longitudinal cross-sectional view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure;

FIG. 6D shows a side longitudinal view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure;

FIG. 6E shows a longitudinal cross-sectional view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure;

FIG. 6F shows an underside isometric view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure;

FIG. 7A shows an isometric view of a bearing plate usable with a downhole tool according to embodiments of the disclosure;

FIG. 7B shows a longitudinal cross-sectional view of a bearing plate usable with a downhole tool according to embodiments of the disclosure;

FIGS. 7C-7EE show various views of a bearing plate configured with stabilizer pin inserts, usable with a downhole tool according to embodiments of the disclosure;

FIG. 8A shows an underside isometric view of a cone usable with a downhole tool according to embodiments of the disclosure;

FIG. 8B shows a longitudinal cross-sectional view of a cone usable with a downhole tool according to embodiments of the disclosure;

FIGS. 9A and 9B show an isometric view, and a longitudinal cross-sectional view, respectively, of a lower sleeve usable with a downhole tool according to embodiments of the disclosure;

FIG. 9C shows an isometric view of a lower sleeve configured with stabilizer pin inserts according to embodiments of the disclosure;

FIG. 9D shows a lateral view of the lower sleeve of FIG. 9C according to embodiments of the disclosure;

FIG. 9E shows a longitudinal cross-sectional view of the lower sleeve of FIG. 9C according to embodiments of the disclosure;

FIG. 10A shows an isometric view of a ball seat usable with a downhole tool according to embodiments of the disclosure;

FIG. 10B shows a longitudinal cross-sectional view of a ball seat usable with a downhole tool according to embodiments of the disclosure;

FIG. 11A shows a side longitudinal view of a downhole tool configured with a plurality of composite members and metal slips according to embodiments of the disclosure;

FIG. 11B shows a longitudinal cross-section view of a downhole tool configured with a plurality of composite members and metal slips according to embodiments of the disclosure;

FIGS. 12A and 12B show various views of an encapsulated downhole tool according to embodiments of the disclosure;

FIG. 13A shows an underside isometric view of an insert(s) configured with a hole usable with a slip(s) according to embodiments of the disclosure;

FIGS. 13B and 13C show underside isometric views of an insert(s) usable with a slip(s) according to embodiments of the disclosure;

FIG. 13D shows a topside isometric view of an insert(s) usable with a slip(s) according to embodiments of the disclosure;

FIGS. 14A and 14B show longitudinal cross-section views of various configurations of a downhole tool according to embodiments of the disclosure;

FIGS. 15A and 15B show an isometric and lateral side view of a metal slip according to embodiments of the disclosure;

FIG. 15C shows a lateral view of a metal sleeve engaged with a sleeve according to embodiments of the disclosure;

FIGS. 15D-15F show a close up lateral view of a stabilizer pin in varied engagement positions with an asymmetrical mating hole according to embodiments of the disclosure;

FIG. 15G shows an isometric view of a metal slip configured with four mating holes according to embodiments of the disclosure;

FIG. 16A shows a longitudinal cross-sectional view of a mandrel having a reduced contact surface mandrel end according to embodiments of the disclosure;

FIG. 16B shows a longitudinal cross-sectional view of another example of a mandrel having a reduced contact surface mandrel end according to embodiments of the disclosure;

FIG. 16C shows a longitudinal cross-sectional view of a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure;

FIG. 16D shows a longitudinal cross-sectional view of another example of a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure;

FIG. 16E a longitudinal cross-sectional view of a mandrel having a rounded reduced contact surface mandrel end according to embodiments of the disclosure;

FIG. 17A shows an isometric view of a metal slip according to embodiments of the disclosure;

FIGS. 17B and 17C show longitudinal cross-section views of the metal slip of FIG. 17A according to embodiments of the disclosure;

FIG. 17D shows an lateral view of the metal slip of FIG. 17A according to embodiments of the disclosure;

FIG. 18A shows a longitudinal side view of a system having a downhole tool in a pre-set to set position according to embodiments of the disclosure;

FIG. 18B shows a longitudinal side view of a system having a downhole tool moving from a pre-set to set position according to embodiments of the disclosure;

FIG. 18C shows a longitudinal side view of a system having a downhole in a set position according to embodiments of the disclosure;

FIG. 19 shows an isometric view of a system having a downhole tool and a channeled setting sleeve according to embodiments of the disclosure;

FIG. 19A shows a side view of the system of FIG. 19 after setting of the downhole tool according to embodiments of the disclosure;

FIG. 19B shows a side view of a channeled sleeve according to embodiments of the disclosure;

FIG. 19C shows an isometric view of the channeled sleeve of FIG. 19B according to embodiments of the disclosure;

FIG. 19D shows a lateral view of the channeled sleeve of FIG. 19B according to embodiments of the disclosure;

FIG. 19E shows an isometric view of a setting sleeve with a non-linear channel(s) according to embodiments of the disclosure;

FIG. 19F shows a lateral view of a setting sleeve with a v-notch type channel(s) according to embodiments of the disclosure;

FIG. 19G shows a lateral view of a setting sleeve with an alternative v-notch type channel(s) according to embodiments of the disclosure;

FIG. 19H shows a lateral view of a setting sleeve with a square-notch type channel(s) according to embodiments of the disclosure;

FIG. 19I shows a lateral view of a setting sleeve with a rounded-notch type channel(s) according to embodiments of the disclosure;

FIG. 19J shows a lateral view of a setting sleeve with a v-notch type channel(s) according to embodiments of the disclosure;

FIG. 19L shows a longitudinal view of a setting sleeve with an inner channel(s) according to embodiments of the disclosure;

FIG. 19M shows a longitudinal view of a setting sleeve with a shortened inner channel(s) according to embodiments of the disclosure;

FIG. 19N shows an isometric view of a setting sleeve with a multi-directional non-linear channel(s) according to embodiments of the disclosure;

FIG. 19O shows an isometric view of a setting sleeve with a plurality of discontinuous channel(s) according to embodiments of the disclosure;

DETAILED DESCRIPTION

Herein disclosed are novel apparatuses, systems, and methods that pertain to downhole tools usable for wellbore operations, details of which are described herein.

Downhole tools according to embodiments disclosed herein may include one or more anchor slips, one or more compression cones engageable with the slips, and a compressible seal element disposed therebetween, all of which may be configured or disposed around a mandrel. The mandrel may include a flow bore open to an end of the tool and extending to an opposite end of the tool. In embodiments, the downhole tool may be a frac plug or a bridge plug. Thus, the downhole tool may be suitable for frac operations. In an exemplary embodiment, the downhole tool may be a composite frac plug made of drillable material, the plug being suitable for use in vertical or horizontal wellbores.

A downhole tool useable for isolating sections of a wellbore may include the mandrel having a first set of threads and a second set of threads. The tool may include a composite member disposed about the mandrel and in engagement with the seal element also disposed about the mandrel. In accordance with the disclosure, the composite member may be partially deformable. For example, upon application of a load, a portion of the composite member, such as a resilient portion, may withstand the load and maintain its original shape and configuration with little to no deflection or deformation. At the same time, the load may result in another portion, such as a deformable portion, that experiences a deflection or deformation, to a point that the deformable portion changes shape from its original configuration and/or position.

Accordingly, the composite member may have first and second portion, or comparably an upper portion and a lower portion. It is noted that first, second, upper, lower, etc. are for illustrative and/or explanative aspects only, such that the composite member is not limited to any particular orientation. In embodiments, the upper (or deformable) portion and the lower (or resilient) portion may be made of a first material. The resilient portion may include an angled surface, and the deformable portion may include at least one groove. A second material may be bonded or molded to (or with) the composite member. In an embodiment, the second material may be bonded to the deformable portion, and at least partially fill into the at least one groove.

The deformable portion may include an outer surface, an inner surface, a top edge, and a bottom edge. The depth (width) of the at least one groove may extend from the outer surface to the inner surface. In some embodiments, the at least one groove may be formed in a spiral or helical pattern along or in the deformable portion from about the bottom edge to about the top edge. The groove pattern is not meant to be limited to any particular orientation, such that any groove may have variable pitch and vary radially.

In embodiments, the at least one groove may be cut at a back angle in the range of about 60 degrees to about 120 degrees with respect to a tool (or tool component) axis. There may be a plurality of grooves formed within the composite member. In an embodiment, there may be about two to three similarly spiral formed grooves in the composite member. In other embodiments, the grooves may have substantially equidistant spacing therebetween. In yet other embodiments, the back angle may be about 75 degrees (e.g., tilted downward and outward).

The downhole tool may include a first slip disposed about the mandrel and configured for engagement with the composite member. In an embodiment, the first slip may engage the angled surface of the resilient portion of the composite member. The downhole tool may further include a cone piece disposed about the mandrel. The cone piece may include a first end and a second end, wherein the first end may be configured for engagement with the seal element. The downhole tool may also include a second slip, which may be configured for contact with the cone. In an embodiment, the second slip may be moved into engagement or compression with the second end of the cone during setting. In another embodiment, the second slip may have a one-piece configuration with at least one groove or undulation disposed therein.

In accordance with embodiments of the disclosure, setting of the downhole tool in the wellbore may include the first slip and the second slip in gripping engagement with a surrounding tubular, the seal element sealingly engaged with the surrounding tubular, and/or application of a load to the mandrel sufficient enough to shear one of the sets of the threads.

Any of the slips may be composite material or metal (e.g., cast iron). Any of the slips may include gripping elements, such as inserts, buttons, teeth, serrations, etc., configured to provide gripping engagement of the tool with a surrounding surface, such as the tubular. In an embodiment, the second slip may include a plurality of inserts disposed therearound. In some aspects, any of the inserts may be configured with a flat surface, while in other aspects any of the inserts may be configured with a concave surface (with respect to facing toward the wellbore).

The downhole tool (or tool components) may include a longitudinal axis, including a central long axis. During setting of the downhole tool, the deformable portion of the composite member may expand or “flower”, such as in a radial direction away from the axis. Setting may further result in the composite member and the seal element compressing together to form a reinforced seal or barrier therebetween. In embodiments, upon compressing the seal element, the seal element may partially collapse or buckle around an inner circumferential channel or groove disposed therein.

The mandrel may have a distal end and a proximate end. There may be a bore formed therebetween. In an embodiment, one of the sets of threads on the mandrel may be shear threads. In other embodiments, one of the sets of threads may be shear threads disposed along a surface of the bore at the proximate end. In yet other embodiments, one of the sets of threads may be rounded threads. For example, one of the sets of threads may be rounded threads that are disposed along an external mandrel surface, such as at the distal end. The round threads may be used for assembly and setting load retention.

The mandrel may be coupled with a setting adapter configured with corresponding threads that mate with the first set of threads. In an embodiment, the adapter may be configured for fluid to flow therethrough. The mandrel may also be coupled with a sleeve configured with corresponding threads that mate with threads on the end of the mandrel. In an embodiment, the sleeve may mate with the second set of threads. In other embodiments, setting of the tool may result in distribution of load forces along the second set of threads at an angle that is directed away from an axis.

Although not limited, the downhole tool or any components thereof may be made of a composite material. In an embodiment, the mandrel, the cone, and the first material each consist of filament wound drillable material.

In embodiments, an e-line or wireline mechanism may be used in conjunction with deploying and/or setting the tool. There may be a pre-determined pressure setting, where upon excess pressure produces a tensile load on the mandrel that results in a corresponding compressive force indirectly between the mandrel and a setting sleeve. The use of the stationary setting sleeve may result in one or more slips being moved into contact or secure grip with the surrounding tubular, such as a casing string, and also a compression (and/or inward collapse) of the seal element. The axial compression of the seal element may be (but not necessarily) essentially simultaneous to its radial expansion outward and into sealing engagement with the surrounding tubular. To disengage the tool from the setting mechanism (or wireline adapter), sufficient tensile force may be applied to the mandrel to cause mated threads therewith to shear.

When the tool is drilled out, the lower sleeve engaged with the mandrel (secured in position by an anchor pin, shear pin, etc.) may aid in prevention of tool spinning. As drill-through of the tool proceeds, the pin may be destroyed or fall, and the lower sleeve may release from the mandrel and may fall further into the wellbore and/or into engagement with another downhole tool, aiding in lockdown with the subsequent tool during its drill-through. Drill-through may continue until the downhole tool is removed from engagement with the surrounding tubular.

Referring now to FIGS. 2A and 2B together, isometric views of a system 200 having a downhole tool 202 illustrative of embodiments disclosed herein, are shown. FIG. 2B depicts a wellbore 206 formed in a subterranean formation 210 with a tubular 208 disposed therein. In an embodiment, the tubular 208 may be casing (e.g., casing, hung casing, casing string, etc.) (which may be cemented). A workstring 212 (which may include a part 217 of a setting tool coupled with adapter 252) may be used to position or run the downhole tool 202 into and through the wellbore 206 to a desired location.

In accordance with embodiments of the disclosure, the tool 202 may be configured as a plugging tool, which may be set within the tubular 208 in such a manner that the tool 202 forms a fluid-tight seal against the inner surface 207 of the tubular 208. In an embodiment, the downhole tool 202 may be configured as a bridge plug, whereby flow from one section of the wellbore 213 to another (e.g., above and below the tool 202) is controlled. In other embodiments, the downhole tool 202 may be configured as a frac plug, where flow into one section 213 of the wellbore 206 may be blocked and otherwise diverted into the surrounding formation or reservoir 210.

In yet other embodiments, the downhole tool 202 may also be configured as a ball drop tool. In this aspect, a ball may be dropped into the wellbore 206 and flowed into the tool 202 and come to rest in a corresponding ball seat at the end of the mandrel 214. The seating of the ball may provide a seal within the tool 202 resulting in a plugged condition, whereby a pressure differential across the tool 202 may result. The ball seat may include a radius or curvature.

In other embodiments, the downhole tool 202 may be a ball check plug, whereby the tool 202 is configured with a ball already in place when the tool 202 runs into the wellbore. The tool 202 may then act as a check valve, and provide one-way flow capability. Fluid may be directed from the wellbore 206 to the formation with any of these configurations.

Once the tool 202 reaches the set position within the tubular, the setting mechanism or workstring 212 may be detached from the tool 202 by various methods, resulting in the tool 202 left in the surrounding tubular and one or more sections of the wellbore isolated. In an embodiment, once the tool 202 is set, tension may be applied to the adapter 252 until the threaded connection between the adapter 252 and the mandrel 214 is broken. For example, the mating threads on the adapter 252 and the mandrel 214 (256 and 216, respectively as shown in FIG. 2D) may be designed to shear, and thus may be pulled and sheared accordingly in a manner known in the art. The amount of load applied to the adapter 252 may be in the range of about, for example, 20,000 to 40,000 pounds force. In other applications, the load may be in the range of less than about 10,000 pounds force.

Accordingly, the adapter 252 may separate or detach from the mandrel 214, resulting in the workstring 212 being able to separate from the tool 202, which may be at a predetermined moment. The loads provided herein are non-limiting and are merely exemplary. The setting force may be determined by specifically designing the interacting surfaces of the tool and the respective tool surface angles. The tool may 202 also be configured with a predetermined failure point (not shown) configured to fail or break. For example, the failure point may break at a predetermined axial force greater than the force required to set the tool but less than the force required to part the body of the tool.

Operation of the downhole tool 202 may allow for fast run in of the tool 202 to isolate one or more sections of the wellbore 206, as well as quick and simple drill-through to destroy or remove the tool 202. Drill-through of the tool 202 may be facilitated by components and sub-components of tool 202 made of drillable material that is less damaging to a drill bit than those found in conventional plugs. In an embodiment, the downhole tool 202 and/or its components may be a drillable tool made from drillable composite material(s), such as glass fiber/epoxy, carbon fiber/epoxy, glass fiber/PEEK, carbon fiber/PEEK, etc. Other resins may include phenolic, polyamide, etc. All mating surfaces of the downhole tool 202 may be configured with an angle, such that corresponding components may be placed under compression instead of shear.

Referring now to FIGS. 2C-2E together, a longitudinal view, a longitudinal cross-sectional view, and an isometric component break-out view, respectively, of downhole tool 202 useable with system (200, FIG. 2A) and illustrative of embodiments disclosed herein, are shown. The downhole tool 202 may include a mandrel 214 that extends through the tool (or tool body) 202. The mandrel 214 may be a solid body. In other aspects, the mandrel 214 may include a flowpath or bore 250 formed therein (e.g., an axial bore). The bore 250 may extend partially or for a short distance through the mandrel 214, as shown in FIG. 2E. Alternatively, the bore 250 may extend through the entire mandrel 214, with an opening at its proximate end 248 and oppositely at its distal end 246 (near downhole end of the tool 202), as illustrated by FIG. 2D.

The presence of the bore 250 or other flowpath through the mandrel 214 may indirectly be dictated by operating conditions. That is, in most instances the tool 202 may be large enough in diameter (e.g., 4¾ inches) that the bore 250 may be correspondingly large enough (e.g., 1¼ inches) so that debris and junk can pass or flow through the bore 250 without plugging concerns. However, with the use of a smaller diameter tool 202, the size of the bore 250 may need to be correspondingly smaller, which may result in the tool 202 being prone to plugging. Accordingly, the mandrel may be made solid to alleviate the potential of plugging within the tool 202.

With the presence of the bore 250, the mandrel 214 may have an inner bore surface 247, which may include one or more threaded surfaces formed thereon. As such, there may be a first set of threads 216 configured for coupling the mandrel 214 with corresponding threads 256 of a setting adapter 252.

The coupling of the threads, which may be shear threads, may facilitate detachable connection of the tool 202 and the setting adapter 252 and/or workstring (212, FIG. 2B) at a the threads. It is within the scope of the disclosure that the tool 202 may also have one or more predetermined failure points (not shown) configured to fail or break separately from any threaded connection. The failure point may fail or shear at a predetermined axial force greater than the force required to set the tool 202.

The adapter 252 may include a stud 253 configured with the threads 256 thereon. In an embodiment, the stud 253 has external (male) threads 256 and the mandrel 214 has internal (female) threads; however, type or configuration of threads is not meant to be limited, and could be, for example, a vice versa female-male connection, respectively.

The downhole tool 202 may be run into wellbore (206, FIG. 2A) to a desired depth or position by way of the workstring (212, FIG. 2A) that may be configured with the setting device or mechanism. The workstring 212 and setting sleeve 254 may be part of the plugging tool system 200 utilized to run the downhole tool 202 into the wellbore, and activate the tool 202 to move from an unset to set position. The set position may include seal element 222 and/or slips 234, 242 engaged with the tubular (208, FIG. 2B). In an embodiment, the setting sleeve 254 (that may be configured as part of the setting mechanism or workstring) may be utilized to force or urge compression of the seal element 222, as well as swelling of the seal element 222 into sealing engagement with the surrounding tubular.

The setting device(s) and components of the downhole tool 202 may be coupled with, and axially and/or longitudinally movable along mandrel 214. When the setting sequence begins, the mandrel 214 may be pulled into tension while the setting sleeve 254 remains stationary. The lower sleeve 260 may be pulled as well because of its attachment to the mandrel 214 by virtue of the coupling of threads 218 and threads 262. As shown in the embodiment of FIGS. 2C and 2D, the lower sleeve 260 and the mandrel 214 may have matched or aligned holes 281A and 281B, respectively, whereby one or more anchor pins 211 or the like may be disposed or securely positioned therein. In embodiments, brass set screws may be used. Pins (or screws, etc.) 211 may prevent shearing or spin-off during drilling or run-in.

As the lower sleeve 260 is pulled in the direction of Arrow A, the components disposed about mandrel 214 between the lower sleeve 260 and the setting sleeve 254 may begin to compress against one another. This force and resultant movement causes compression and expansion of seal element 222. The lower sleeve 260 may also have an angled sleeve end 263 in engagement with the slip 234, and as the lower sleeve 260 is pulled further in the direction of Arrow A, the end 263 compresses against the slip 234. As a result, slip(s) 234 may move along a tapered or angled surface 228 of a composite member 220, and eventually radially outward into engagement with the surrounding tubular (208, FIG. 2B).

Serrated outer surfaces or teeth 298 of the slip(s) 234 may be configured such that the surfaces 298 prevent the slip 234 (or tool) from moving (e.g., axially or longitudinally) within the surrounding tubular, whereas otherwise the tool 202 may inadvertently release or move from its position. Although slip 234 is illustrated with teeth 298, it is within the scope of the disclosure that slip 234 may be configured with other gripping features, such as buttons or inserts (e.g., FIGS. 13A-13D).

Initially, the seal element 222 may swell into contact with the tubular, followed by further tension in the tool 202 that may result in the seal element 222 and composite member 220 being compressed together, such that surface 289 acts on the interior surface 288. The ability to “flower”, unwind, and/or expand may allow the composite member 220 to extend completely into engagement with the inner surface of the surrounding tubular.

Additional tension or load may be applied to the tool 202 that results in movement of cone 236, which may be disposed around the mandrel 214 in a manner with at least one surface 237 angled (or sloped, tapered, etc.) inwardly of second slip 242. The second slip 242 may reside adjacent or proximate to collar or cone 236. As such, the seal element 222 forces the cone 236 against the slip 242, moving the slip 242 radially outwardly into contact or gripping engagement with the tubular. Accordingly, the one or more slips 234, 242 may be urged radially outward and into engagement with the tubular (208, FIG. 2B). In an embodiment, cone 236 may be slidingly engaged and disposed around the mandrel 214. As shown, the first slip 234 may be at or near distal end 246, and the second slip 242 may be disposed around the mandrel 214 at or near the proximate end 248. It is within the scope of the disclosure that the position of the slips 234 and 242 may be interchanged. Moreover, slip 234 may be interchanged with a slip comparable to slip 242, and vice versa.

Because the sleeve 254 is held rigidly in place, the sleeve 254 may engage against a bearing plate 283 that may result in the transfer load through the rest of the tool 202. The setting sleeve 254 may have a sleeve end 255 that abuts against the bearing plate end 284. As tension increases through the tool 202, an end of the cone 236, such as second end 240, compresses against slip 242, which may be held in place by the bearing plate 283. As a result of cone 236 having freedom of movement and its conical surface 237, the cone 236 may move to the underside beneath the slip 242, forcing the slip 242 outward and into engagement with the surrounding tubular (208, FIG. 2B).

The second slip 242 may include one or more, gripping elements, such as buttons or inserts 278, which may be configured to provide additional grip with the tubular. The inserts 278 may have an edge or corner 279 suitable to provide additional bite into the tubular surface. In an embodiment, the inserts 278 may be mild steel, such as 1018 heat treated steel. The use of mild steel may result in reduced or eliminated casing damage from slip engagement and reduced drill string and equipment damage from abrasion.

In an embodiment, slip 242 may be a one-piece slip, whereby the slip 242 has at least partial connectivity across its entire circumference. Meaning, while the slip 242 itself may have one or more grooves (or notches, undulations, etc.) 244 configured therein, the slip 242 itself has no initial circumferential separation point. In an embodiment, the grooves 244 may be equidistantly spaced or disposed in the second slip 242. In other embodiments, the grooves 244 may have an alternatingly arranged configuration. That is, one groove 244A may be proximate to slip end 241, the next groove 244B may be proximate to an opposite slip end 243, and so forth.

The tool 202 may be configured with ball plug check valve assembly that includes a ball seat 286. The assembly may be removable or integrally formed therein. In an embodiment, the bore 250 of the mandrel 214 may be configured with the ball seat 286 formed or removably disposed therein. In some embodiments, the ball seat 286 may be integrally formed within the bore 250 of the mandrel 214. In other embodiments, the ball seat 286 may be separately or optionally installed within the mandrel 214, as may be desired.

The ball seat 286 may be configured in a manner so that a ball 285 seats or rests therein, whereby the flowpath through the mandrel 214 may be closed off (e.g., flow through the bore 250 is restricted or controlled by the presence of the ball 285). For example, fluid flow from one direction may urge and hold the ball 285 against the seat 286, whereas fluid flow from the opposite direction may urge the ball 285 off or away from the seat 286. As such, the ball 285 and the check valve assembly may be used to prevent or otherwise control fluid flow through the tool 202. The ball 285 may be conventionally made of a composite material, phenolic resin, etc., whereby the ball 285 may be capable of holding maximum pressures experienced during downhole operations (e.g., fracing). By utilization of retainer pin 287, the ball 285 and ball seat 286 may be configured as a retained ball plug. As such, the ball 285 may be adapted to serve as a check valve by sealing pressure from one direction, but allowing fluids to pass in the opposite direction.

The tool 202 may be configured as a drop ball plug, such that a drop ball may be flowed to a drop ball seat 259. The drop ball may be much larger diameter than the ball of the ball check. In an embodiment, end 248 may be configured with a drop ball seat surface 259 such that the drop ball may come to rest and seat at in the seat proximate end 248. As applicable, the drop ball (not shown here) may be lowered into the wellbore (206, FIG. 2A) and flowed toward the drop ball seat 259 formed within the tool 202. The ball seat may be formed with a radius 259A (i.e., circumferential rounded edge or surface).

In other aspects, the tool 202 may be configured as a bridge plug, which once set in the wellbore, may prevent or allow flow in either direction (e.g., upwardly/downwardly, etc.) through tool 202. Accordingly, it should be apparent to one of skill in the art that the tool 202 of the present disclosure may be configurable as a frac plug, a drop ball plug, bridge plug, etc. simply by utilizing one of a plurality of adapters or other optional components. In any configuration, once the tool 202 is properly set, fluid pressure may be increased in the wellbore, such that further downhole operations, such as fracture in a target zone, may commence.

The tool 202 may include an anti-rotation assembly that includes an anti-rotation device or mechanism 282, which may be a spring, a mechanically spring-energized composite tubular member, and so forth. The device 282 may be configured and usable for the prevention of undesired or inadvertent movement or unwinding of the tool 202 components. As shown, the device 282 may reside in cavity 294 of the sleeve (or housing) 254. During assembly the device 282 may be held in place with the use of a lock ring 296. In other aspects, pins may be used to hold the device 282 in place.

FIG. 2D shows the lock ring 296 may be disposed around a part 217 of a setting tool coupled with the workstring 212. The lock ring 296 may be securely held in place with screws inserted through the sleeve 254. The lock ring 296 may include a guide hole or groove 295, whereby an end 282A of the device 282 may slidingly engage therewith. Protrusions or dogs 295A may be configured such that during assembly, the mandrel 214 and respective tool components may ratchet and rotate in one direction against the device 282; however, the engagement of the protrusions 295A with device end 282B may prevent back-up or loosening in the opposite direction.

The anti-rotation mechanism may provide additional safety for the tool and operators in the sense it may help prevent inoperability of tool in situations where the tool is inadvertently used in the wrong application. For example, if the tool is used in the wrong temperature application, components of the tool may be prone to melt, whereby the device 282 and lock ring 296 may aid in keeping the rest of the tool together. As such, the device 282 may prevent tool components from loosening and/or unscrewing, as well as prevent tool 202 unscrewing or falling off the workstring 212.

Drill-through of the tool 202 may be facilitated by the fact that the mandrel 214, the slips 234, 242, the cone(s) 236, the composite member 220, etc. may be made of drillable material that is less damaging to a drill bit than those found in conventional plugs. The drill bit will continue to move through the tool 202 until the downhole slip 234 and/or 242 are drilled sufficiently that such slip loses its engagement with the well bore. When that occurs, the remainder of the tools, which generally would include lower sleeve 260 and any portion of mandrel 214 within the lower sleeve 260 falls into the well. If additional tool(s) 202 exist in the well bore beneath the tool 202 that is being drilled through, then the falling away portion will rest atop the tool 202 located further in the well bore and will be drilled through in connection with the drill through operations related to the tool 202 located further in the well bore. Accordingly, the tool 202 may be sufficiently removed, which may result in opening the tubular 208.

Referring now to FIGS. 18A, 18B, and 18C together, longitudinal side views of a system having a downhole tool moved from a pre-set to set position, illustrative of embodiments disclosed herein, are shown. System 300 may be comparable or identical in aspects, function, operation, components, etc. as that of System 200, and redundant discussion is limited for sake of brevity. Accordingly, FIGS. 18A-18C illustrate tool 302 may be positioned downhole within a tubular 308. In an embodiment, the tubular 308 may be casing (e.g., casing, hung casing, casing string, etc.). A workstring 312 may be used to position or run the tool 302 into to a desired location, as generally depicted by FIG. 18A. As a result of the horizontal orientation and downward forces (e.g., gravity) the tool 302 may have a tool axis 358 offset or eccentric to a tubular axis 308a, as the tool 302 and workstring 312 may naturally move to the bottommost part of the tubular 308 instead of being centralized.

The workstring 312 and setting sleeve 354 may be used collectively for activation of the tool 302 from an unset to set position in a manner like that of embodiments disclosed herein. The setting device(s) and components of the downhole tool 302 may be coupled with, and axially and/or longitudinally movable along mandrel 314, where the mandrel 314 may extend through the tool (or tool body) 302. When the setting sequence begins, as generally depicted in FIG. 18B, the mandrel 314 may be pulled into tension while the setting sleeve 354 remains stationary. The lower sleeve 360 and other tool 302 components may incur a setting force by way of connectivity or coupling, be it directly or indirectly, with the mandrel 314.

For example, as the lower sleeve 360 is pulled and tension occurs in the tool 302, the components disposed about mandrel 314 between the lower sleeve 360 and the setting sleeve 354 may begin to compress against one another. The sleeve 354 may engage against a bearing plate 383 that may result in the transfer load through the rest of the tool 302. As a result of cone 336 having freedom of movement, the cone 336 may move to the underside beneath the slip 342, forcing the slip 342 outward and into engagement with the surrounding tubular 308.

This force and resultant movement causes compression and/or expansion of slip 342, which subsequently results in at least part of the tool 302 being raised or moved away from the bottommost surface 307 of the tubular 308. The upward force F3 that occurs during setting and urges the tool 302 upward, and downward force F2 that occurs from gravity on the workstring 312 and results in net force(s) incurred along the tool 302, including at point P1. The force at point P1 is at least partially due to the contact area A2 as a result of an external mandrel surface 345a of a proximate mandrel end 348 that contacts the inner surface 354a of the setting sleeve 354.

FIG. 18B illustrates the tool 302, workstring 312, etc. incurring various downward forces F2, resulting in the tool 302, etc. moving along the bottom portion 307 of the casing 308, and as the setting sequence progresses, radial outward movement of slips 334, 342 and compressible member 322 will ultimately urge the tool 302 toward a central position in the tubing 308, as illustrated in FIG. 18C (where the tubing axis 308a and the tool axis 358 are concentric).

Generally tool 302 performance improves with centralization, such that, as shown in FIG. 18C, the tool 302 ultimately sets in a position that provides an effective even annulus (i.e., annulus arrows 399) around the tool 302. As a result of reduced contact area A2, the tool 302 also provides the ability for the setting sleeve 354 to have less hang-up and binding on the mandrel 314.

Manufacturing of the external mandrel surface(s) 345a may be in a conventional manner, such as a machining process. The mandrel surface(s) 345a on the proximate end 348 may be rounded, or machined with enough incremental “flat” (linear) surfaces at different angles (or slopes) to form an apparent or effective rounded surface.

The use of such surfaces helps dramatically improve any aspect of reducing clearances and at friction, while at the same time the configuration of the proximate end 348 and the setting sleeve 354 limits or prevents “flopping around” of the same. The proximate end 348 may have a first length L1, which may extend about from the transition portion 349 to a most proximate end 348b. The proximate end 348 may have a second length L2, which may be comparable to an approximate length of the mandrel 314 that may contact or engage the setting sleeve 354, such as while in a run-in configuration.

Referring briefly to FIGS. 16A, 16B, 16C, 16D, and 16E together, longitudinal cross-sectional views of a mandrel having a reduced contact surface mandrel end; another example of a mandrel having a reduced contact surface mandrel end according to embodiments of the disclosure; a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure; a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure; and a mandrel having a rounded reduced contact surface mandrel end according to embodiments of the disclosure; illustrative of embodiments disclosed herein, are shown.

In accordance with the disclosure various configurations of the proximate mandrel end 348, and particularly, an external mandrel surface 345a, may be useful for improving tool performance and reducing unwanted forces incurred by the mandrel during setting and operation. As already described, as a result of configurations related to area A2, the tool (302) provides the ability for the setting sleeve 354 to have less hang-up and binding on the mandrel 314.

The proximate end 348 may include an outer taper 348A, which may be generally linear with an approximate cross-sectional slope s1 made with reference to an appropriate x-y axis as would be apparent to one of skill. The outer taper 348A may suitable to help prevent the tool from getting stuck or binding. For example, during setting the use of a smaller tool may result in the tool binding on the setting sleeve, whereby the presence of the outer taper 348A will allow the tool mandrel end 348 to slide off easier from the setting sleeve 354. In an embodiment, the outer taper 348A may be formed at an angle of about 5 degrees with respect to an axis (358).

There may be a neck or transition portion 349, such that the mandrel may have variation with its outer diameter. The surface 345a of the transition portion 349 may be generally linear with an approximate cross-sectional slope s3 made with reference to an appropriate x-y axis as would be apparent to one of skill.

Between the taper 348A and the transition 349 may be another generally linear surface 354b with an approximate cross-sectional slope s2. In a run-in configuration, the surface 354b may be engaged with the sleeve 354 around the circumference of the parts, and as essentially illustrated by area A2. The surfaces of the mandrel end 348 may intersect at points, such as point(s) 397. The intersecting points 397 may be distinctly pointed, have rounded (or smoothed) surfaces), etc.

FIG. 16B illustrates how mandrel end 348 may have additional (linear) surfaces at different angles (or slopes, e.g., s1-s7) to form an apparent or effective rounded surface. FIG. 16C illustrates by way of example how the external mandrel end may have a combination of generally linear surfaces (e.g., of approximate slope s1, s3) and surfaces having a curvature r1. The presence of a curvature r1 may be useful for further minimizing contact between the mandrel end and the setting sleeve. Comparably FIG. 16E illustrates the surface of the mandrel end having a substantially curved surface, including radius of curvature r6.

The external mandrel surface 345a of the proximate end 348 may have an apparent length L1, which may be with reference from a straight line from about the transition region 349 to an absolute furthest endpoint of the proximate end 348. The external mandrel surface 345a of the proximate end 348 may have an apparent length L2, which may be with reference from a straight line from about the distance of the surface 345a intended to contact, engage, or otherwise be nearmost to the setting sleeve 354 prior to setting, such as during run-in. In aspects, the length L1 is greater than the length L2. As would be apparent, the mandrel 314 may be configured with the end mandrel surface 345a having a greater area A1 than a proximate settling sleeve engagement surface A2.

Manufacturing of the external mandrel surface(s) 345a may be in a conventional manner, such as a machining process. The mandrel surface(s) 345a on the mandrel end 348 may be rounded, linear, combinations, etc. The surface(s) may be readily machined with enough incremental “flat” (linear) surfaces at different angles (or slopes) to form an apparent or effective rounded surface.

Referring briefly to FIGS. 19, 19A, 19B, 19C, and 19D, a pre-setting downhole view, a downhole view, a longitudinal side body view, an isometric view, and a lateral cross sectional view, respectively, of a setting sleeve having a reduced hydraulic diameter illustrative of embodiments disclosed herein, are shown. FIGS. 19 and 19A illustrate a sleeve 1954 configured with one or more grooves or channels 1955 configured to allow wellbore fluid F to readily pass therein, therethrough, thereby, etc., consequently resulting in reduction of the hydraulic resistance (e.g., drag) against the workstring 1905 as it is removed from the wellbore 1908. Or put another way, that hydraulic pressure above the setting sleeve 1954 can be ‘relieved’ or bypassed below the sleeve 1954. Channels 1955 may also provide pressure relief during perforation because at least some of the pressure (or shock) wave can be alleviated. Prior to setting and removal, the sleeve 1954 may be in operable engagement with the downhole tool 1902. In an embodiment, the downhole tool 1902 may be a frac plug.

Because of the large pressures incurred, in using a sleeve 1954 with reduced hydraulic cross-section, it is important to maintain integrity. That is, any sleeve of embodiments disclosed herein must still be robust and inherent in strength to withstand shock pressure, setting forces, etc., and avoid component failure or collapse.

FIGS. 19B-19D together show setting sleeve 1954 may have a first end 1957 and a second end 1958. One or more channels 1955 may extend or otherwise be disposed a length L along the outer surface 1960 of the sleeve 1954. The channel(s) may be parallel or substantially parallel to sleeve axis 1961. One or more channels 1955 may be part of a channel group 1962. There may be multiple channel groups 1962 in the sleeve 1955. As shown in the Figures here, there may be three (3) channel groups 1962. The groups 1962 of channels 1955 may be arranged in an equilateral pattern around the circumference of the sleeve 1954. Indicator ring 1956 illustrates how the outer diameter (or hydraulic diameter) is effectively reduced by the presence of channel(s) 1955. Or put another way, that the sleeve 1954 may have an effective outer surface area greater than an actual outer surface area (e.g., because the actual outermost surface area of the sleeve in the circumferential sense is “void” of area).

Although FIGS. 19B-19D depict one example, embodiments herein pertaining to the sleeve 1954 are not meant to be limited thereby. One of skill in the art would appreciate there may be other configurations of channel(s) suitable to reduce the hydraulic diameter of the sleeve 1954 (and/or provide fluid bypass capability), but yet provide the sleeve 1954 with adequate integrity suitable for setting, downhole conditions, and so forth.

Additional figures depict other embodiments of the disclosure. FIG. 19E shows there may be a channel(s) 1955 arranged in a non-axial or non-linear manner, such as spiral-wound, helical etc. It is worth noting that although embodiments of the sleeve channel 1955 shown herein may have the channel 1955 extending from one end of the sleeve 1957 to approximately the other end of the sleeve 1958, this need not be the case. Thus, the length of the channel L may be less than the length LS of the sleeve 1955. Yet the length of the channel L may also be greater than the length LS of the sleeve 1955, as would be the case with the non-axial or non-linear embodiment shown in FIG. 19E. In addition, the channel 1955 need not be continuous, such that there may be discontinuous channels 1955A, B, C, as shown in FIG. 19O.

FIGS. 19F-19J show other variants of sleeve 1954 having a certain channel groove pattern or cross-sectional shape, including one or more channels 1955 having a “v-notch”, as well as an ‘offset’ V-notch (FIG. 19F), an opposite offset V-notch (FIG. 19G), a “square” notch (FIG. 19H), a rounded notch (FIG. 19I), and combinations thereof (not shown). In addition, although FIGS. 19F-19H show three (3) groups of channels, other embodiments of possible, such as four groups (FIG. 19I), two groups (FIG. 19J), and so forth. Moreover, although the groups of channels may be disposed or arranged equidistantly apart, the groups may just as well have an unequal or random placement or distribution. Although the channel pattern or cross-sectional shape may be consistent and continuous, the scope of the disclosure is not limited to such a pattern. Thus, the pattern or cross-sectional shape may vary or have random discontinuities.

Yet other embodiments may include one or more channels 1955 disposed within the sleeve instead of on the outer surface. FIGS. 19L and 19M show sleeve 1954 may include a channel 1955 formed within the body (or wall thickness) of the sleeve, thus forming an inner passageway for fluid to flow therethrough. The channel may thus have a first inlet 1971 and a first outlet 1972. As mentioned before, the length L of the channel may be the same or about equal to, less than, or greater than the sleeve length LS.

Referring now to FIGS. 3A, 3B, 3C and 3D together, an isometric view and a longitudinal cross-sectional view of a mandrel usable with a downhole tool, a longitudinal cross-sectional view of an end of a mandrel, and a longitudinal cross-sectional view of an end of a mandrel engaged with a sleeve, in accordance with embodiments disclosed herein, are shown. Components of the downhole tool may be arranged and disposed about the mandrel 314, as described and understood to one of skill in the art. The mandrel 314, which may be made from filament wound drillable material, may have a distal end 346 and a proximate end 348. The filament wound material may be made of various angles as desired to increase strength of the mandrel 314 in axial and radial directions. The presence of the mandrel 314 may provide the tool with the ability to hold pressure and linear forces during setting or plugging operations.

The mandrel 314 may be sufficient in length, such that the mandrel may extend through a length of tool (or tool body) (202, FIG. 2B). The mandrel 314 may be a solid body. In other aspects, the mandrel 314 may include a flowpath or bore 350 formed therethrough (e.g., an axial bore). There may be a flowpath or bore 350, for example an axial bore, that extends through the entire mandrel 314, with openings at both the proximate end 348 and oppositely at its distal end 346. Accordingly, the mandrel 314 may have an inner bore surface 347, which may include one or more threaded surfaces formed thereon.

The ends 346, 348 of the mandrel 314 may include internal or external (or both) threaded portions. As shown in FIG. 3C, the mandrel 314 may have internal threads 316 within the bore 350 configured to receive a mechanical or wireline setting tool, adapter, etc. (not shown here). For example, there may be a first set of threads 316 configured for coupling the mandrel 314 with corresponding threads of another component (e.g., adapter 252, FIG. 2B). In an embodiment, the first set of threads 316 are shear threads. In an embodiment, application of a load to the mandrel 314 may be sufficient enough to shear the first set of threads 316. Although not necessary, the use of shear threads may eliminate the need for a separate shear ring or pin, and may provide for shearing the mandrel 314 from the workstring.

The proximate end 348 may include an outer taper 348A. The outer taper 348A may help prevent the tool from getting stuck or binding. For example, during setting the use of a smaller tool may result in the tool binding on the setting sleeve, whereby the use of the outer taper 348 will allow the tool to slide off easier from the setting sleeve. In an embodiment, the outer taper 348A may be formed at an angle φ of about 5 degrees with respect to the axis 358. The length of the taper 348A may be about 0.5 inches to about 0.75 inches

There may be a neck or transition portion 349, such that the mandrel may have variation with its outer diameter. In an embodiment, the mandrel 314 may have a first outer diameter D1 that is greater than a second outer diameter D2. Conventional mandrel components are configured with shoulders (i.e., a surface angle of about 90 degrees) that result in components prone to direct shearing and failure. In contrast, embodiments of the disclosure may include the transition portion 349 configured with an angled transition surface 349A. A transition surface angle b may be about 25 degrees with respect to the tool (or tool component axis) 358.

The transition portion 349 may withstand radial forces upon compression of the tool components, thus sharing the load. That is, upon compression the bearing plate 383 and mandrel 314, the forces are not oriented in just a shear direction. The ability to share load(s) among components means the components do not have to be as large, resulting in an overall smaller tool size.

In addition to the first set of threads 316, the mandrel 314 may have a second set of threads 318. In one embodiment, the second set of threads 318 may be rounded threads disposed along an external mandrel surface 345 at the distal end 346. The use of rounded threads may increase the shear strength of the threaded connection.

FIG. 3D illustrates an embodiment of component connectivity at the distal end 346 of the mandrel 314. As shown, the mandrel 314 may be coupled with a sleeve 360 having corresponding threads 362 configured to mate with the second set of threads 318. In this manner, setting of the tool may result in distribution of load forces along the second set of threads 318 at an angle a away from axis 358. There may be one or more balls 364 disposed between the sleeve 360 and slip 334. The balls 364 may help promote even breakage of the slip 334.

Accordingly, the use of round threads may allow a non-axial interaction between surfaces, such that there may be vector forces in other than the shear/axial direction. The round thread profile may create radial load (instead of shear) across the thread root. As such, the rounded thread profile may also allow distribution of forces along more thread surface(s). As composite material is typically best suited for compression, this allows smaller components and added thread strength. This beneficially provides upwards of 5-times strength in the thread profile as compared to conventional composite tool connections.

With particular reference to FIG. 3C, the mandrel 314 may have a ball seat 386 disposed therein. In some embodiments, the ball seat 386 may be a separate component, while in other embodiments the ball seat 386 may be formed integral with the mandrel 314. There also may be a drop ball seat surface 359 formed within the bore 350 at the proximate end 348. The ball seat 359 may have a radius 359A that provides a rounded edge or surface for the drop ball to mate with. In an embodiment, the radius 359A of seat 359 may be smaller than the ball that seats in the seat. Upon seating, pressure may “urge” or otherwise wedge the drop ball into the radius, whereby the drop ball will not unseat without an extra amount of pressure. The amount of pressure required to urge and wedge the drop ball against the radius surface, as well as the amount of pressure required to unwedge the drop ball, may be predetermined. Thus, the size of the drop ball, ball seat, and radius may be designed, as applicable.

The use of a small curvature or radius 359A may be advantageous as compared to a conventional sharp point or edge of a ball seat surface. For example, radius 359A may provide the tool with the ability to accommodate drop balls with variation in diameter, as compared to a specific diameter. In addition, the surface 359 and radius 359A may be better suited to distribution of load around more surface area of the ball seat as compared to just at the contact edge/point of other ball seats.

Referring now to FIGS. 6A, 6B, 6C, 6D, 6E, and 6F together, an isometric view, a longitudinal cross-sectional view, a close-up longitudinal cross-sectional view, a side longitudinal view, a longitudinal cross-sectional view, and an underside isometric view, respectively, of a composite deformable member 320 (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. The composite member 320 may be configured in such a manner that upon a compressive force, at least a portion of the composite member may begin to deform (or expand, deflect, twist, unspring, break, unwind, etc.) in a radial direction away from the tool axis (e.g., 258, FIG. 2C). Although exemplified as “composite”, it is within the scope of the disclosure that member 320 may be made from metal, including alloys and so forth.

During the setting sequence, the seal element 322 and the composite member 320 may compress together. As a result of an angled exterior surface 389 of the seal element 322 coming into contact with the interior surface 388 of the composite member 320, a deformable (or first or upper) portion 326 of the composite member 320 may be urged radially outward and into engagement the surrounding tubular (not shown) at or near a location where the seal element 322 at least partially sealingly engages the surrounding tubular. There may also be a resilient (or second or lower) portion 328. In an embodiment, the resilient portion 328 may be configured with greater or increased resilience to deformation as compared to the deformable portion 326.

The composite member 320 may be a composite component having at least a first material 331 and a second material 332, but composite member 320 may also be made of a single material. The first material 331 and the second material 332 need not be chemically combined. In an embodiment, the first material 331 may be physically or chemically bonded, cured, molded, etc. with the second material 332. Moreover, the second material 332 may likewise be physically or chemically bonded with the deformable portion 326. In other embodiments, the first material 331 may be a composite material, and the second material 332 may be a second composite material.

The composite member 320 may have cuts or grooves 330 formed therein. The use of grooves 330 and/or spiral (or helical) cut pattern(s) may reduce structural capability of the deformable portion 326, such that the composite member 320 may “flower” out. The groove 330 or groove pattern is not meant to be limited to any particular orientation, such that any groove 330 may have variable pitch and vary radially.

With groove(s) 330 formed in the deformable portion 326, the second material 332, may be molded or bonded to the deformable portion 326, such that the grooves 330 are filled in and enclosed with the second material 332. In embodiments, the second material 332 may be an elastomeric material. In other embodiments, the second material 332 may be 60-95 Duro A polyurethane or silicone. Other materials may include, for example, TFE or PTFE sleeve option—heat shrink. The second material 332 of the composite member 320 may have an inner material surface 368.

Different downhole conditions may dictate choice of the first and/or second material. For example, in low temp operations (e.g., less than about 250 F), the second material comprising polyurethane may be sufficient, whereas for high temp operations (e.g., greater than about 250 F) polyurethane may not be sufficient and a different material like silicone may be used.

The use of the second material 332 in conjunction with the grooves 330 may provide support for the groove pattern and reduce preset issues. With the added benefit of second material 332 being bonded or molded with the deformable portion 326, the compression of the composite member 320 against the seal element 322 may result in a robust, reinforced, and resilient barrier and seal between the components and with the inner surface of the tubular member (e.g., 208 in FIG. 2B). As a result of increased strength, the seal, and hence the tool of the disclosure, may withstand higher downhole pressures. Higher downhole pressures may provide a user with better frac results.

Groove(s) 330 allow the composite member 320 to expand against the tubular, which may result in a formidable barrier between the tool and the tubular. In an embodiment, the groove 330 may be a spiral (or helical, wound, etc.) cut formed in the deformable portion 326. In an embodiment, there may be a plurality of grooves or cuts 330. In another embodiment, there may be two symmetrically formed grooves 330, as shown by way of example in FIG. 6E. In yet another embodiment, there may be three grooves 330.

As illustrated by FIG. 6C, the depth d of any cut or groove 330 may extend entirely from an exterior side surface 364 to an upper side interior surface 366. The depth d of any groove 330 may vary as the groove 330 progresses along the deformable portion 326. In an embodiment, an outer planar surface 364A may have an intersection at points tangent the exterior side 364 surface, and similarly, an inner planar surface 366A may have an intersection at points tangent the upper side interior surface 366. The planes 364A and 366A of the surfaces 364 and 366, respectively, may be parallel or they may have an intersection point 367. Although the composite member 320 is depicted as having a linear surface illustrated by plane 366A, the composite member 320 is not meant to be limited, as the inner surface may be non-linear or non-planar (i.e., have a curvature or rounded profile).

In an embodiment, the groove(s) 330 or groove pattern may be a spiral pattern having constant pitch (p₁about the same as p₂), constant radius (r₃about the same as r₄) on the outer surface 364 of the deformable member 326. In an embodiment, the spiral pattern may include constant pitch (p₁about the same as p₂), variable radius (r₁unequal to r₂) on the inner surface 366 of the deformable member 326.

In an embodiment, the groove(s) 330 or groove pattern may be a spiral pattern having variable pitch (p₁unequal to p₂), constant radius (r₃about the same as r₄) on the outer surface 364 of the deformable member 326. In an embodiment, the spiral pattern may include variable pitch (p₁unequal to p₂), variable radius (r₁unequal to r₂) on the inner surface 366 of the deformable member 320.

As an example, the pitch (e.g., p₁, p₂, etc.) may be in the range of about 0.5 turns/inch to about 1.5 turns/inch. As another example, the radius at any given point on the outer surface may be in the range of about 1.5 inches to about 8 inches. The radius at any given point on the inner surface may be in the range of about less than 1 inch to about 7 inches. Although given as examples, the dimensions are not meant to be limiting, as other pitch and radial sizes are within the scope of the disclosure.

In an exemplary embodiment reflected in FIG. 6B, the composite member 320 may have a groove pattern cut on a back angle β. A pattern cut or formed with a back angle may allow the composite member 320 to be unrestricted while expanding outward. In an embodiment, the back angle β may be about 75 degrees (with respect to axis 258). In other embodiments, the angle β may be in the range of about 60 to about 120 degrees

The presence of groove(s) 330 may allow the composite member 320 to have an unwinding, expansion, or “flower” motion upon compression, such as by way of compression of a surface (e.g., surface 389) against the interior surface of the deformable portion 326. For example, when the seal element 322 moves, surface 389 is forced against the interior surface 388. Generally the failure mode in a high pressure seal is the gap between components; however, the ability to unwind and/or expand allows the composite member 320 to extend completely into engagement with the inner surface of the surrounding tubular.

Referring now to FIGS. 4A and 4B together, a longitudinal cross-sectional view and an isometric view of a seal element (and its subcomponents), respectively, usable with a downhole tool in accordance with embodiments disclosed herein are shown. The seal element 322 may be made of an elastomeric and/or poly material, such as rubber, nitrile rubber, Viton or polyurethane, and may be configured for positioning or otherwise disposed around the mandrel (e.g., 214, FIG. 2C). In an embodiment, the seal element 322 may be made from 75 Duro A elastomer material. The seal element 322 may be disposed between a first slip and a second slip (see FIG. 2C, seal element 222 and slips 234, 236).

The seal element 322 may be configured to buckle (deform, compress, etc.), such as in an axial manner, during the setting sequence of the downhole tool (202, FIG. 2C). However, although the seal element 322 may buckle, the seal element 322 may also be adapted to expand or swell, such as in a radial manner, into sealing engagement with the surrounding tubular (208, FIG. 2B) upon compression of the tool components. In a preferred embodiment, the seal element 322 provides a fluid-tight seal of the seal surface 321 against the tubular.

The seal element 322 may have one or more angled surfaces configured for contact with other component surfaces proximate thereto. For example, the seal element may have angled surfaces 327 and 389. The seal element 322 may be configured with an inner circumferential groove 376. The presence of the groove 376 assists the seal element 322 to initially buckle upon start of the setting sequence. The groove 376 may have a size (e.g., width, depth, etc.) of about 0.25 inches.

Slips. Referring now to FIGS. 5A, 5B, 5C, 5D, 5E, 5F, and 5G together, an isometric view, a lateral view, and a longitudinal cross-sectional view of one or more slips, and an isometric view of a metal slip, a lateral view of a metal slip, a longitudinal cross-sectional view of a metal slip, and an isometric view of a metal slip without buoyant material holes, respectively, (and related subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. The slips 334, 342 described may be made from metal, such as cast iron, or from composite material, such as filament wound composite. During operation, the winding of the composite material may work in conjunction with inserts under compression in order to increase the radial load of the tool.

Slips 334, 342 may be used in either upper or lower slip position, or both, without limitation. As apparent, there may be a first slip 334, which may be disposed around the mandrel (214, FIG. 2C), and there may also be a second slip 342, which may also be disposed around the mandrel. Either of slips 334, 342 may include a means for gripping the inner wall of the tubular, casing, and/or well bore, such as a plurality of gripping elements, including serrations or teeth 398, inserts 378, etc. As shown in FIGS. 5D-5F, the first slip 334 may include rows and/or columns 399 of serrations 398. The gripping elements may be arranged or configured whereby the slips 334, 342 engage the tubular (not shown) in such a manner that movement (e.g., longitudinally axially) of the slips or the tool once set is prevented.

In embodiments, the slip 334 may be a poly-moldable material. In other embodiments, the slip 334 may be hardened, surface hardened, heat-treated, carburized, etc., as would be apparent to one of ordinary skill in the art. However, in some instances, slips 334 may be too hard and end up as too difficult or take too long to drill through.

Typically, hardness on the teeth 398 may be about 40-60 Rockwell. As understood by one of ordinary skill in the art, the Rockwell scale is a hardness scale based on the indentation hardness of a material. Typical values of very hard steel have a Rockwell number (HRC) of about 55-66. In some aspects, even with only outer surface heat treatment the inner slip core material may become too hard, which may result in the slip 334 being impossible or impracticable to drill-thru.

Thus, the slip 334 may be configured to include one or more holes 393 formed therein. The holes 393 may be longitudinal in orientation through the slip 334. The presence of one or more holes 393 may result in the outer surface(s) 307 of the metal slips as the main and/or majority slip material exposed to heat treatment, whereas the core or inner body (or surface) 309 of the slip 334 is protected. In other words, the holes 393 may provide a barrier to transfer of heat by reducing the thermal conductivity (i.e., k-value) of the slip 334 from the outer surface(s) 307 to the inner core or surfaces 309. The presence of the holes 393 is believed to affect the thermal conductivity profile of the slip 334, such that that heat transfer is reduced from outer to inner because otherwise when heat/quench occurs the entire slip 334 heats up and hardens.

Thus, during heat treatment, the teeth 398 on the slip 334 may heat up and harden resulting in heat-treated outer area/teeth, but not the rest of the slip. In this manner, with treatments such as flame (surface) hardening, the contact point of the flame is minimized (limited) to the proximate vicinity of the teeth 398.

With the presence of one or more holes 393, the hardness profile from the teeth to the inner diameter/core (e.g., laterally) may decrease dramatically, such that the inner slip material or surface 309 has a HRC of about ˜15 (or about normal hardness for regular steel/cast iron). In this aspect, the teeth 398 stay hard and provide maximum bite, but the rest of the slip 334 is easily drillable.

One or more of the void spaces/holes 393 may be filled with useful “buoyant” (or low density) material 400 to help debris and the like be lifted to the surface after drill-thru. The material 400 disposed in the holes 393 may be, for example, polyurethane, light weight beads, or glass bubbles/beads such as the K-series glass bubbles made by and available from 3M. Other low-density materials may be used.

The advantageous use of material 400 helps promote lift on debris after the slip 334 is drilled through. The material 400 may be epoxied or injected into the holes 393 as would be apparent to one of skill in the art.

The slots 392 in the slip 334 may promote breakage. An evenly spaced configuration of slots 392 promotes even breakage of the slip 334.

First slip 334 may be disposed around or coupled to the mandrel (214, FIG. 2B) as would be known to one of skill in the art, such as a band or with shear screws (not shown) configured to maintain the position of the slip 334 until sufficient pressure (e.g., shear) is applied. The band may be made of steel wire, plastic material or composite material having the requisite characteristics in sufficient strength to hold the slip 334 in place while running the downhole tool into the wellbore, and prior to initiating setting. The band may be drillable.

When sufficient load is applied, the slip 334 compresses against the resilient portion or surface of the composite member (e.g., 220, FIG. 2C), and subsequently expand radially outwardly to engage the surrounding tubular (see, for example, slip 234 and composite member 220 in FIG. 2C).

FIG. 5G illustrates slip 334 may be a hardened cast iron slip without the presence of any grooves or holes 393 formed therein.

Referring briefly to FIGS. 11A and 11B together, a side longitudinal view and a longitudinal cross-sectional view, respectively, of a downhole tool 1102 configured with a plurality of composite members 1120, 1120A and metal slips 1134, 1142, according to embodiments of the disclosure, are shown. The slips 1134, 1142 may be one-piece in nature, and be made from various materials such as metal (e.g., cast iron) or composite. It is known that metal material results in a slip that is harder to drill-thru compared to composites, but in some applications it might be necessary to resist pressure and/or prevent movement of the tool 1102 from two directions (e.g., above/below), making it beneficial to use two slips 1134 that are metal. Likewise, in high pressure/high temperature applications (HP/HT), it may be beneficial/better to use slips made of hardened metal. The slips 1134, 1142 may be disposed around 1114 in a manner discussed herein.

It is within the scope of the disclosure that tools described herein may include multiple composite members 1120, 1120A. The composite members 1120, 1120A may be identical, or they may different and encompass any of the various embodiments described herein and apparent to one of ordinary skill in the art.

Referring again to FIGS. 5A-5C, slip 342 may be a one-piece slip, whereby the slip 342 has at least partial connectivity across its entire circumference. Meaning, while the slip 342 itself may have one or more grooves 344 configured therein, the slip 342 has no separation point in the pre-set configuration. In an embodiment, the grooves 344 may be equidistantly spaced or cut in the second slip 342. In other embodiments, the grooves 344 may have an alternatingly arranged configuration. That is, one groove 344A may be proximate to slip end 341 and adjacent groove 344B may be proximate to an opposite slip end 343. As shown in groove 344A may extend all the way through the slip end 341, such that slip end 341 is devoid of material at point 372.

Where the slip 342 is devoid of material at its ends, that portion or proximate area of the slip may have the tendency to flare first during the setting process. The arrangement or position of the grooves 344 of the slip 342 may be designed as desired. In an embodiment, the slip 342 may be designed with grooves 344 resulting in equal distribution of radial load along the slip 342. Alternatively, one or more grooves, such as groove 344B may extend proximate or substantially close to the slip end 343, but leaving a small amount material 335 therein. The presence of the small amount of material gives slight rigidity to hold off the tendency to flare. As such, part of the slip 342 may expand or flare first before other parts of the slip 342.

The slip 342 may have one or more inner surfaces with varying angles. For example, there may be a first angled slip surface 329 and a second angled slip surface 333. In an embodiment, the first angled slip surface 329 may have a 20-degree angle, and the second angled slip surface 333 may have a 40-degree angle; however, the degree of any angle of the slip surfaces is not limited to any particular angle. Use of angled surfaces allows the slip 342 significant engagement force, while utilizing the smallest slip 342 possible.

The use of a rigid single- or one-piece slip configuration may reduce the chance of presetting that is associated with conventional slip rings, as conventional slips are known for pivoting and/or expanding during run in. As the chance for pre-set is reduced, faster run-in times are possible.

The slip 342 may be used to lock the tool in place during the setting process by holding potential energy of compressed components in place. The slip 342 may also prevent the tool from moving as a result of fluid pressure against the tool. The second slip (342, FIG. 5A) may include inserts 378 disposed thereon. In an embodiment, the inserts 378 may be epoxied or press fit into corresponding insert bores or grooves 375 formed in the slip 342.

Referring briefly to FIGS. 13A-13D together, an underside isometric view of an insert(s) configured with a hole, an underside isometric views of another insert(s), and a topside isometric view of an insert(s), respectively, usable with the slip(s) of the present disclosure are shown. One or more of the inserts 378 may have a flat surface 380A or concave surface 380. In an embodiment, the concave surface 380 may include a depression 377 formed therein. One or more of the inserts 378 may have a sharpened (e.g., machined) edge or corner 379, which allows the insert 378 greater biting ability.

Referring now to FIGS. 8A and 8B together, an underside isometric view and a longitudinal cross-sectional view, respectively, of one or more cones 336 (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. In an embodiment, cone 336 may be slidingly engaged and disposed around the mandrel (e.g., cone 236 and mandrel 214 in FIG. 2C). Cone 336 may be disposed around the mandrel in a manner with at least one surface 337 angled (or sloped, tapered, etc.) inwardly with respect to other proximate components, such as the second slip (242, FIG. 2C). As such, the cone 336 with surface 337 may be configured to cooperate with the slip to force the slip radially outwardly into contact or gripping engagement with a tubular, as would be apparent and understood by one of skill in the art.

During setting, and as tension increases through the tool, an end of the cone 336, such as second end 340, may compress against the slip (see FIG. 2C). As a result of conical surface 337, the cone 336 may move to the underside beneath the slip, forcing the slip outward and into engagement with the surrounding tubular (see FIG. 2A). A first end 338 of the cone 336 may be configured with a cone profile 351. The cone profile 351 may be configured to mate with the seal element (222, FIG. 2C). In an embodiment, the cone profile 351 may be configured to mate with a corresponding profile 327A of the seal element (see FIG. 4A). The cone profile 351 may help restrict the seal element from rolling over or under the cone 336.

Referring now to FIGS. 9A and 9B, an isometric view, and a longitudinal cross-sectional view, respectively, of a lower sleeve 360 (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. During setting, the lower sleeve 360 will be pulled as a result of its attachment to the mandrel 214. As shown in FIGS. 9A and 9B together, the lower sleeve 360 may have one or more holes 381A that align with mandrel holes (281B, FIG. 2C). One or more anchor pins 311 may be disposed or securely positioned therein. In an embodiment, brass set screws may be used. Pins (or screws, etc.) 311 may prevent shearing or spin off during drilling.

As the lower sleeve 360 is pulled, the components disposed about mandrel between the may further compress against one another. The lower sleeve 360 may have one or more tapered surfaces 361, 361A which may reduce chances of hang up on other tools. The lower sleeve 360 may also have an angled sleeve end 363 in engagement with, for example, the first slip (234, FIG. 2C). As the lower sleeve 360 is pulled further, the end 363 presses against the slip. The lower sleeve 360 may be configured with an inner thread profile 362. In an embodiment, the profile 362 may include rounded threads. In another embodiment, the profile 362 may be configured for engagement and/or mating with the mandrel (214, FIG. 2C). Ball(s) 364 may be used. The ball(s) 364 may be for orientation or spacing with, for example, the slip 334. The ball(s) 364 and may also help maintain break symmetry of the slip 334. The ball(s) 364 may be, for example, brass or ceramic.

Referring briefly to FIGS. 9C-9E together, an isometric, lateral, and longitudinal cross-sectional view, respectively, of the lower sleeve 360 configured with stabilizer pin inserts, and usable with a downhole tool in accordance with embodiments disclosed herein, are shown. In addition to the ball(s) 364, the lower sleeve 360 may be configured with one or more stabilizer pins (or pin inserts) 364A.

A possible difficulty with a one-piece metal slip is that instead of breaking evenly or symmetrically, it may be prone to breaking in a single spot or an uneven manner, and then fanning out (e.g., like a fan belt). If this it occurs, it may problematic because the metal slip (e.g., 334, FIG. 5D) may not engage the casing (or surrounding surface) in an adequate, even manner, and the downhole tool may not be secured in place. Some conventional metal slips are “segmented” so the slip expands in mostly equal amounts circumferentially; however, it is commonly understood and known that these type of slips are very prone to pre-setting or inadvertent setting.

In contrast, the one-piece slip configuration is very durable, takes a lot of shock, and will not pre-set, but may require a configuration that urges uniform and even breakage. In accordance with embodiments disclosed herein, the metal slip 334 may be configured to mate or otherwise engage with pins 364A, which may aid breaking the slip 334 uniformly as a result of distribution of forces against the slip 334 (see FIG. 18A).

It is plausible a durable insert pin 364A may perform better than an integral pin/sleeve configuration of the lower sleeve 360 because of the huge massive forces that are encountered (i.e., 30,000 lbs). The pins 364A may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins 364A are easily drillable.

This configuration is advantageous over changing breakage points on the metal slip because doing so would impact the strength of the slip, which is undesired. Accordingly, this configuration may allow improved breakage without impacting strength of the slip (i.e., ability to hold set pressure). In the instances where strength is not of consequence, a composite slip (i.e., a slip more readily able to break evening) could be used—use of metal slip is typically used for greater pressure conditions/setting requirements.

The pins 364A may be formed or manufactured by standard processes, and then cut (or machined, etc.) to an adequate or desired shape, size, and so forth. The pins 364A may be shaped and sized to a tolerance fit with slots 381B. In other aspects, the pins 364A may be shaped and sized to an undersized or oversized fit with slots 381B. The pins 364A may be held in situ with an adhesive or glue.

In embodiments one or more of the pins 364, 364A may have a rounded or spherical portion configured for engagement with the metal slip (see FIG. 3D). In other embodiments, one or more of the pins 364, 364A may have a planar portion 365 configured for engagement with the metal slip 334. In yet other embodiments, one or more of the pins 364, 364A may be configured with a taper(s) 369.

The presence of the taper(s) 369 may be useful to help minimize displacement in the event the metal slip 334 inadvertently attempts to ‘hop up’ over one of the pins 364A in the instance the metal slip 334 did not break properly or otherwise.

One or more of the pins 364A may be configured with a ‘cut out’ portion that results in a pointed region on the inward side of the pin(s) 364A (see 7EE). This may aid in ‘crushing’ of the pin 364A during setting so that the pin 364A moves out of the way.

Referring briefly to FIGS. 15A-15B, an isometric and lateral side view of a metal slip according to embodiments of the disclosure, are shown. FIGS. 15A and 15B together show one or more of the (mating) holes 393A in the metal slip 334 may be configured in a round, symmetrical fashion or shape. The holes 393A may be notches, grooves, etc. or any other receptacle-type shape and configuration.

A downhole tool of embodiments disclosed herein may include the metal slip 334 disposed, for example, about the mandrel. The metal slip 334 may include (prior to setting) a one-piece circular slip body configuration. The metal slip 334 may include a face 397 configured with a set or plurality of mating holes 393A. FIGS. 15A and 15B illustrate there may be three mating holes 393A. Although not limited to any one particular arrangement, the holes 393A may be disposed in a generally or substantially symmetrical manner (e.g., equidistant spacing around the circumferential shape of the face 397). In addition, although illustrated as generally the same size, one or more holes may vary in size (e.g., dimensions of width, depth, etc.). FIG. 15G illustrates an embodiment where the metal slip 334 may include a set of mating holes having four mating holes.

Referring now to FIG. 15C, a lateral view of a metal sleeve engaged with a sleeve according to embodiments of the disclosure, is shown. As illustrated, an engaging body or surface of a downhole tool, such as a sleeve 360 may be configured with a corresponding number of stabilizer pins 364A. Thus, for example, the sleeve 360 may have a set of stabilizer pins to correspond to the set of mating holes of the slip 334. In other aspects, the set of mating holes 393A comprises three mating holes, and similarly the set of stabilizer pins comprises three stabilizer pins 364A, as shown in the Figure. The set of mating holes may configured in the range of about 90 to about 120 degrees circumferentially (e.g., see FIG. 15G, arcuate segment 393B being about 90 degrees). In a similar fashion, the set of stabilizer pins 364A may be arranged or positioned in the range of about 90 to about 120 degrees circumferentially around the sleeve 360.

Thus, in accordance with embodiments of the disclosure the metal slip 334 may be configured for substantially even breakage of the metal slip body during setting. Prior to setting the metal slip 334 may have a one-piece circular slip body. That is, at least some part or aspects of the slip 334 has a solid connection around the entirety of the slip.

In an embodiment, the face (397, FIG. 15A) may be configured with at least three mating holes 393A. In embodiments, the sleeve 360 may be configured or otherwise fitted with a set of stabilizer pins equal in number and corresponding to the number of mating holes 393A. Thus, each pin 364A may be configured to engage a corresponding mating hole 393A.

The downhole tool may be configured for at least three portions of the metal slip 334 to be in gripping engagement with a surrounding tubular after setting. The set of stabilizer pins may be disposed in a symmetrical manner with respect to each other. The set of mating holes may be disposed in a symmetrical manner with respect to each other.

In accordance with embodiments disclosed herein, the metal slip 334 may be configured to mate or otherwise engage with pins 364A, which may aid breaking the slip 334 uniformly as a result of distribution of forces against the slip 334. The sleeve 360 may include a set of stabilizer pins configured to engage the set of mating holes.

Referring briefly to FIGS. 17A-17D, one or more of the (mating) holes 393A in the metal slip 334 may be configured in a round, symmetrical fashion or shape. Just the same, one or more of the holes 393A may additionally or alternatively be configured in an asymmetrical fashion or shape. In an embodiment, one or more of the holes may be configured in a ‘tear drop’ fashion or shape.

Each of these aspects may contribute to the ability of the metal slip 334 to break a generally equal amount of distribution around the slip body circumference. That is, the metal slip 334 breaks in a manner where portions of the slip engage the surrounding tubular and the distribution of load is about equal or even around the slip 334. Thus, the metal slip 334 may be configured in a manner so that upon breakage load may be applied from the tool against the surrounding tubular in an approximate even or equal manner circumferentially (or radially).

The metal slip 334 may be configured in an optimal one-piece configuration that prevents or otherwise prohibits pre-setting, but ultimately breaks in an equal or even manner comparable to the intent of a conventional “slip segment” metal slip.

Referring now to FIGS. 7A and 7B together, an isometric view and a longitudinal cross-sectional view, respectively of a bearing plate 383 (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. The bearing plate 383 may be made from filament wound material having wide angles. As such, the bearing plate 383 may endure increased axial load, while also having increased compression strength.

Because the sleeve (254, FIG. 2C) may held rigidly in place, the bearing plate 383 may likewise be maintained in place. The setting sleeve may have a sleeve end 255 that abuts against bearing plate end 284, 384. Briefly, FIG. 2C illustrates how compression of the sleeve end 255 with the plate end 284 may occur at the beginning of the setting sequence. As tension increases through the tool, an other end 239 of the bearing plate 283 may be compressed by slip 242, forcing the slip 242 outward and into engagement with the surrounding tubular (208, FIG. 2B).

Inner plate surface 319 may be configured for angled engagement with the mandrel. In an embodiment, plate surface 319 may engage the transition portion 349 of the mandrel 314. Lip 323 may be used to keep the bearing plate 383 concentric with the tool 202 and the slip 242. Small lip 323A may also assist with centralization and alignment of the bearing plate 383.

Referring briefly to FIGS. 7C-7EE together, various views a bearing plate 383 (and its subcomponents) configured with stabilizer pin inserts, usable with a downhole tool in accordance with embodiments disclosed herein, are shown. When applicable, such as when the downhole tool is configured with the bearing plate 383 engaged with a metal slip (e.g., 334, FIG. 5D), the bearing plate 383 may be configured with one or more stabilizer pins (or pin inserts) 364B.

In accordance with embodiments disclosed herein, the metal slip may be configured to mate or otherwise engage with pins 364B, which may aid breaking the slip 334 uniformly as a result of distribution of forces against the slip 334.

It is believed a durable insert pin 364B may perform better than an integral configuration of the bearing plate 383 because of the huge massive forces that may be encountered (i.e., 30,000 lbs).

The pins 364B may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins 364B may be easily drillable. This configuration may allow improved breakage without impacting strength of the slip (i.e., ability to hold set pressure). In the instances where strength is not of consequence, a composite slip (i.e., a slip more readily able to break evening) could be used—use of metal slip is used for greater pressure conditions/setting requirements.

Referring now to FIGS. 10A and 10B together, an isometric view and a longitudinal cross-sectional view, respectively, of a ball seat 386 (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. Ball seat 386 may be made from filament wound composite material or metal, such as brass. The ball seat 386 may be configured to cup and hold a ball 385, whereby the ball seat 386 may function as a valve, such as a check valve. As a check valve, pressure from one side of the tool may be resisted or stopped, while pressure from the other side may be relieved and pass therethrough.

In an embodiment, the bore (250, FIG. 2D) of the mandrel (214, FIG. 2D) may be configured with the ball seat 386 formed therein. In some embodiments, the ball seat 386 may be integrally formed within the bore of the mandrel, while in other embodiments, the ball seat 386 may be separately or optionally installed within the mandrel, as may be desired. As such, ball seat 386 may have an outer surface 386A bonded with the bore of the mandrel. The ball seat 386 may have a ball seat surface 386B.

The ball seat 386 may be configured in a manner so that when a ball (385, FIG. 3C) seats therein, a flowpath through the mandrel may be closed off (e.g., flow through the bore 250 is restricted by the presence of the ball 385). The ball 385 may be made of a composite material, whereby the ball 385 may be capable of holding maximum pressures during downhole operations (e.g., fracing).

As such, the ball 385 may be used to prevent or otherwise control fluid flow through the tool. As applicable, the ball 385 may be lowered into the wellbore (206, FIG. 2A) and flowed toward a ball seat 386 formed within the tool 202. Alternatively, the ball 385 may be retained within the tool 202 during run in so that ball drop time is eliminated. As such, by utilization of retainer pin (387, FIG. 3C), the ball 385 and ball seat 386 may be configured as a retained ball plug. As such, the ball 385 may be adapted to serve as a check valve by sealing pressure from one direction, but allowing fluids to pass in the opposite direction.

Referring now to FIGS. 12A and 12B together, longitudinal side views of an encapsulated downhole tool in accordance with embodiments disclosed herein, are shown. In embodiments, the downhole tool 1202 of the present disclosure may include an encapsulation. Encapsulation may be completed with an injection molding process. For example, the tool 1202 may be assembled, put into a clamp device configured for injection molding, whereby an encapsulation material 1290 may be injected accordingly into the clamp and left to set or cure for a pre-determined amount of time on the tool 1202 (not shown).

Encapsulation may help resolve presetting issues; the material 1290 is strong enough to hold in place or resist movement of, tool parts, such as the slips 1234, 1242, and sufficient in material properties to withstand extreme downhole conditions, but is easily breached by tool 1202 components upon routine setting and operation. Example materials for encapsulation include polyurethane or silicone; however, any type of material that flows, hardens, and does not restrict functionality of the downhole tool may be used, as would be apparent to one of skill in the art.

Referring now to FIGS. 14A and 14B together, longitudinal cross-sectional views of various configurations of a downhole tool in accordance with embodiments disclosed herein, are shown. Components of downhole tool 1402 may be arranged and operable, as described in embodiments disclosed herein and understood to one of skill in the art.

The tool 1402 may include a mandrel 1414 configured as a solid body. In other aspects, the mandrel 1414 may include a flowpath or bore 1450 formed therethrough (e.g., an axial bore). The bore 1450 may be formed as a result of the manufacture of the mandrel 1414, such as by filament or cloth winding around a bar. As shown in FIG. 14A, the mandrel may have the bore 1450 configured with an insert 1414A disposed therein. Pin(s) 1411 may be used for securing lower sleeve 1460, the mandrel 1414, and the insert 1414A. The bore 1450 may extend through the entire mandrel 1414, with openings at both the first end 1448 and oppositely at its second end 1446. FIG. 14B illustrates the end 1448 of the mandrel 1414 may be fitted with a plug 1403.

In certain circumstances, a drop ball may not be a usable option, so the mandrel 1414 may optionally be fitted with the fixed plug 1403. The plug 1403 may be configured for easier drill-thru, such as with a hollow. Thus, the plug may be strong enough to be held in place and resist fluid pressures, but easily drilled through. The plug 1403 may be threadingly and/or sealingly engaged within the bore 1450.

The ends 1446, 1448 of the mandrel 1414 may include internal or external (or both) threaded portions. In an embodiment, the tool 1402 may be used in a frac service, and configured to stop pressure from above the tool 1401. In another embodiment, the orientation (e.g., location) of composite member 1420B may be in engagement with second slip 1442. In this aspect, the tool 1402 may be used to kill flow by being configured to stop pressure from below the tool 1402. In yet other embodiments, the tool 1402 may have composite members 1420, 1420A on each end of the tool. FIG. 14A shows composite member 1420 engaged with first slip 1434, and second composite member 1420A engaged with second slip 1442. The composite members 1420, 1420A need not be identical. In this aspect, the tool 1402 may be used in a bidirectional service, such that pressure may be stopped from above and/or below the tool 1402. A composite rod may be glued into the bore 1450.

Advantages.

Embodiments of the downhole tool are smaller in size, which allows the tool to be used in slimmer bore diameters. Smaller in size also means there is a lower material cost per tool. Because isolation tools, such as plugs, are used in vast numbers, and are generally not reusable, a small cost savings per tool results in enormous annual capital cost savings.

A synergistic effect is realized because a smaller tool means faster drilling time is easily achieved. Again, even a small savings in drill-through time per single tool results in an enormous savings on an annual basis.

Advantageously, the configuration of components, and the resilient barrier formed by way of the composite member results in a tool that can withstand significantly higher pressures. The ability to handle higher wellbore pressure results in operators being able to drill deeper and longer wellbores, as well as greater frac fluid pressure. The ability to have a longer wellbore and increased reservoir fracture results in significantly greater production.

Embodiments of the disclosure provide for the ability to remove the workstring faster and more efficiently by reducing hydraulic drag.

As the tool may be smaller (shorter), the tool may navigate shorter radius bends in well tubulars without hanging up and presetting. Passage through shorter tool has lower hydraulic resistance and can therefore accommodate higher fluid flow rates at lower pressure drop. The tool may accommodate a larger pressure spike (ball spike) when the ball seats.

The composite member may beneficially inflate or umbrella, which aids in run-in during pump down, thus reducing the required pump down fluid volume. This constitutes a savings of water and reduces the costs associated with treating/disposing recovered fluids.

One piece slips assembly are resistant to preset due to axial and radial impact allowing for faster pump down speed. This further reduces the amount of time/water required to complete frac operations.

While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations. The use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like.

Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention. The inclusion or discussion of a reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide background knowledge; or exemplary, procedural or other details supplementary to those set forth herein.

Number	Date	Country
61526217	Aug 2011	US
61558207	Nov 2011	US
61846527	Jul 2013	US
61865064	Aug 2013	US

	Number	Date	Country
Parent	13592004	Aug 2012	US
Child	14532965		US
Parent	14332243	Jul 2014	US
Child	13592004		US
Parent	14458011	Aug 2014	US
Child	14332243		US

DOWNHOLE SYSTEM FOR ISOLATING SECTIONS OF A WELLBORE

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CPC

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Abstract

Description

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CROSS-REFERENCE TO RELATED APPLICATIONS

Provisional Applications (4)

Continuation in Parts (3)