Downhole tool and method of use

A downhole tool suitable for use in a wellbore that includes a wedge mandrel having a distal end; a proximate end; an outer surface; and a flowbore extending through the wedge mandrel from the proximate end to the distal end. The tool includes a fingered member disposed around the wedge mandrel. The tool includes a ball seat insert made of a reactive metal-based material, the ball seat insert disposed in the flowbore and engaged with a first set of threads. The tool includes a support platform disposed in the flowbore and engaged with a second set of threads.

Not applicable.

BACKGROUND

Field of the Disclosure

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

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 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.FIG. 1illustrates a conventional plugging system100that includes use of a downhole tool102used for plugging a section of the wellbore106drilled into formation110. The tool or plug102may be lowered into the wellbore106by way of workstring105(e.g., e-line, wireline, coiled tubing, etc.) and/or with setting tool112, as applicable. The tool102generally includes a body103with a compressible seal member122to seal the tool102against an inner surface107of a surrounding tubular, such as casing108. The tool102may include the seal member122disposed between one or more slips109,111that are used to help retain the tool102in place.

In operation, forces (usually axial relative to the wellbore106) are applied to the slip(s)109,111and the body103. As the setting sequence progresses, slip109moves in relation to the body103and slip111, the seal member122is actuated, and the slips109,111are driven against corresponding conical surfaces104. This movement axially compresses and/or radially expands the compressible member122, and the slips109,111, which results in these components being urged outward from the tool102to contact the inner wall107. In this manner, the tool102provides a seal expected to prevent transfer of fluids from one section113of the wellbore across or through the tool102to another section115(or vice versa, etc.), or to the surface. Tool102may also include an interior passage (not shown) that allows fluid communication between section113and section115when 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.

It is naturally desirable to “flow back,” i.e., from the formation to the surface, the injected fluid, or the formation fluid(s); however, this is not possible until the previously set tool or its blockage is removed. Removal of tools (or blockage) usually requires a well-intervention service for retrieval or drill-through, which is time consuming, costly, and adds a potential risk of wellbore damage.

The more metal parts used in the tool, the longer the drill-through operation takes. Because metallic components are harder to drill, such an operation may require additional trips into and out of the wellbore to replace worn out drill bits.

In the interest of cost-saving, materials that react under certain downhole conditions have been the subject of significant research in view of the potential offered to the oilfield industry. For example, such an advanced material that has an ability to degrade by mere response to a change in its surrounding is desirable because no, or limited, intervention would be necessary for removal or actuation to occur.

Such a material, essentially self-actuated by changes in its surrounding (e.g., the presence a specific fluid, a change in temperature, and/or a change in pressure, etc.) may potentially replace costly and complicated designs and may be most advantageous in situations where accessibility is limited or even considered to be impossible, which is the case in a downhole (subterranean) environment.

It is highly desirable and economically advantageous to have controls that do not rely on lengthy and costly wirelines, hydraulic control lines, or coil tubings. Furthermore, in countless situations, a subterranean piece of equipment may need to be actuated only once, after which it may no longer present any usefulness, and may even become disadvantageous when for instance the equipment must be retrieved by risky and costly interventions.

In some instances, it may be advantageous to have a device (ball, tool, component, etc.) made of a material (of composition of matter) characterized by properties where the device is mechanically strong (hard) under some conditions (such as at the surface or at ambient conditions), but degrades, dissolves, breaks, etc. under specific conditions, such as in the presence of water-containing fluids like fresh water, seawater, formation fluid, additives, brines, acids and bases, or changes in pressure and/or temperature. Thus, after a predetermined amount of time, and after the desired operation(s) is complete, the formation fluid is ultimately allowed to flow toward the surface.

It would be advantageous to configure a device (or a related activation device, such as a frac ball, or other component(s)) to utilize materials that alleviate or reduce the need for an intervention service. This would save a considerable amount of time and expense. Therefore, there is a need in the art for tools, devices, components, etc. to be of a nature that does not involve or otherwise require a drill-through process. Environmental- or bio-friendly materials are further desirous.

The ability to save operational time (and those saving operational costs) leads to considerable competition in the marketplace. Achieving any ability to save time, or ultimately cost, leads to an immediate competitive advantage.

Accordingly, there are needs in the art for novel systems and methods for isolating wellbores in a fast, 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. There is a need in the art for non-metallic downhole tools and components.

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 tool suitable for use in a wellbore. The tool may include one or more of a wedge mandrel; a fingered member disposed around the wedge mandrel; a seal element disposed around the wedge mandrel; an insert positioned between the fingered member and the seal element, and in proximity with an end of the fingered member; a ball seat insert made of a reactive metal-based material; a support platform made of the reactive metal-based material; and a lower sleeve disposed around and engaged with wedge mandrel.

The wedge mandrel may be made of a composite filament wound material. The wedge mandrel may include: a distal end; a proximate end; an outer surface; and an inner flowbore extending through the wedge mandrel from the proximate end to the distal end. The wedge mandrel may have a first outer diameter at the distal end, a second outer diameter at the proximate end. The wedge mandrel may have an angled surface (or angled linear transition surface) therebetween. In aspects, the wedge mandrel may have a second outer diameter larger than a first outer diameter.

The inner flowbore may include a first seat of threads at the distal end and a second set of threads at the proximate end. The ball seat insert may be disposed in the inner flowbore and engaged with the first set of threads. The support platform may be disposed in the inner flowbore and engaged with the second set of threads. Either or both of the first set of threads or the second set of threads may be round threads (or have a rounded thread profile).

The wedge mandrel (or its inner flowbore) may have an inner flowbore diameter in the range of about 1.5 inches to about 4 inches. The ball seat insert may include a ball seat formed therein. The ball seat insert may have a ball seat bore having an inner diameter in the range of about 0.5 inches to about 1.5 inches.

In operation, and upon setting, via pressurization a ball may be positioned in the ball seat. In aspects related to the set tool, a middle of the ball may be laterally proximate to a middle of the seal element.

One or more components of the downhole tool or the ball may be made of a reactive material formed from an initial mixture composition comprising: a low viscosity cycloaliphatic epoxy resin with an anhydride curing agent; an additive comprising a clay; and a glass. The reactive material may be formed via a curing process.

The downhole tool may include other components, including one or more of a first backup ring engaged with a first side of the seal element or a second backup ring engaged with a second side of the seal element.

The fingered member may be made from a material that includes one or more of filament wound material, fiberglass cloth wound material, and molded fiberglass composite. The fingered member may include: a circular body; a plurality of fingers extending from the circular body; a longitudinal gap formed between respective fingers; and a transition zone between the circular body and the plurality of fingers. The transition zone may include an inner member surface and an outer member surface. The inner member surface may include a first inner member groove. The outer member surface may include a first outer member groove.

The wedge mandrel may include a plurality of lateral windows configured for a plurality of respective support platform dogs to movingly engage therein. The fingered member may also have a plurality of recessed regions disposed in the circular body configured for the plurality of respective support platform dogs to engage therein.

One or more fingers of the fingered member may include a gripper insert disposed therein. The gripper insert may be made of metal, such as cast iron. The gripper may insert may be surface hardened. The gripper insert may be heat treated by way of an induction process. The gripper insert may have a gripper outer surface Rockwell hardness in the range of about 40 to about 60, and a griper inner surface Rockwell hardness in the range of about 10 to about 25.

In aspects, the downhole tool may be configured as one of a frac plug and a bridge plug.

The insert may have a circular body, a first end, a second end, and a helical winding groove formed in the circular body between the first end and the second end.

Other embodiments of the disclosure pertain to a downhole tool for use in a wellbore that may include one or more of: a wedge mandrel; a fingered member disposed around the wedge mandrel; a seal element disposed around the mandrel; an insert positioned between the fingered member and the seal element; a ball seat insert made of a reactive material, the ball seat insert disposed in the wedge mandrel; a support platform made of the reactive material, the support plate disposed in the wedge mandrel; and a lower sleeve disposed around the wedge mandrel. The reactive material may be a metal-based material.

The wedge mandrel may include a distal end; a proximate end; an outer surface; and an inner flowbore extending through the wedge mandrel from the proximate end to the distal end. The wedge mandrel may include a first outer diameter at the distal end. The wedge mandrel may include a second outer diameter at the proximate end. The outer surface may include an axially linear surface. The outer surface may include an axially angled surface. The outer surface may have a detent, which may be formed between the liner surface and the angled surface. The second outer diameter may be larger than the first outer diameter.

The ball seat insert may be engaged with an inner surface of the inner flowbore. The ball seat insert may be threadingly engaged with the inner surface. The support platform may be engaged with the inner surface. The support platform may be treadingly engaged with the inner surface. The lower sleeve may be engaged with the outer surface. The lower sleeve may be threadingly engaged with the outer surface.

The insert may be positioned and engaged with the detent. The fingered member may be disposed in the assembled configuration around the axially linear surface.

The inner flowbore may include an inner flowbore diameter in the range of about 1.5 inches to about 4 inches. The ball seat insert may have a ball seat formed therein. The ball seat insert may have a ball seat bore. The ball seat bore may have an inner bore diameter in the range of about 0.5 inches to about 1.5 inches. The support platform may have a support platform bore having an inner support platform bore diameter in the range of about 0.5 inches to about 1.5 inches.

In operation, upon setting of the downhole tool, via pressurization a ball may be positioned in the ball seat whereby a middle of the ball may be laterally proximate to a middle of the seal element.

The downhole tool may include other components, such as a first backup ring engaged with a first side of the seal element, and/or a second backup ring engaged with a second side of the seal element.

The fingered member may include: a circular body; a plurality of fingers extending from the circular body; a gap or slice formed between respective fingers; and a transition zone between the circular body and the plurality of fingers. The transition zone may include an inner member surface and an outer member surface. The inner member surface may have a first inner member groove. The outer member surface may have a first outer member groove.

The wedge mandrel may have one or more lateral mandrel windows configured for a one or more respective support platform dogs to movingly engage therein. The fingered member may have one or more recessed regions disposed in the circular body configured for the respective support platform dogs to engage therein.

The fingered member, the wedge mandrel, or both, may be made of composite filament wound material. One or more of the plurality of fingers may have a gripper insert disposed therein.

The griper insert may be metal. The griper insert may be surface hardened by way of an induction process resulting in a gripper outer surface Rockwell hardness in the range of about 40 to about 60, and a griper inner surface Rockwell hardness in the range of about 10 to about 25.

The insert may have a circular body, a first end, a second end, and a helical winding groove formed in the circular body between the first end and the second end.

One or more components of the downhole tool may be made of a cured reactive material formed from an initial mixture composition comprising: a low viscosity cycloaliphatic epoxy resin with an anhydride curing agent; an additive comprising a clay; and a glass.

Yet other embodiments of the disclosure pertain to a method of operating a downhole tool that may include one or more steps of: using a workstring to run the downhole tool into the wellbore to a desired position; actuating a setting device coupled with the downhole tool in order to set the downhole tool into at least partial engagement with a surrounding tubular; disconnecting the downhole tool from the setting device coupled therewith when the tensile load is sufficient to separation therefrom; seating a ball in a ball seat of the downhole tool; and waiting an amount of time for a reactive material to react in a sufficient manner whereby a fluid may be produced through an inner flowbore of the tool, wherein an inner flowbore diameter is in the range of about 2 inches to about 3 inches.

The downhole tool may include: a wedge mandrel further having: a distal end; a proximate end; an outer surface; and the inner flowbore extending through the mandrel from the proximate end to the distal end. The outer surface may have an axially linear surface and an axially angled surface. The tool may include: a fingered member disposed around the mandrel; a seal element disposed around the mandrel; and a ball seat insert made of the reactive material, the ball seat insert disposed in the inner flowbore at the proximate end, and engaged with the inner surface of the inner flowbore; a support platform also made of the reactive material, the support platform disposed in the inner flowbore at the distal end, and engaged with the inner surface; and a lower sleeve disposed around and engaged with the outer surface of mandrel at the distal end.

The method may include having at least one component of the downhole tool or the ball made of material made from an initial mixture composition comprising: a low viscosity cycloaliphatic epoxy resin with an anhydride curing agent; an additive comprising a clay; and a glass, and wherein the workstring comprises a grooved setting sleeve configured therewith.

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

DETAILED DESCRIPTION

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

Embodiments of the present disclosure are described in detail with reference to the accompanying Figures. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, such as to mean, for example, “including, but not limited to . . . ”. While the disclosure may be described with reference to relevant apparatuses, systems, and methods, it should be understood that the disclosure is not limited to the specific embodiments shown or described. Rather, one skilled in the art will appreciate that a variety of configurations may be implemented in accordance with embodiments herein.

Although not necessary, like elements in the various figures may be denoted by like reference numerals for consistency and ease of understanding. Numerous specific details are set forth in order to provide a more thorough understanding of the disclosure; however, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Directional terms, such as “above,” “below,” “upper,” “lower,” “front,” “back,” etc., are used for convenience and to refer to general direction and/or orientation, and are only intended for illustrative purposes only, and not to limit the disclosure.

Connection(s), couplings, or other forms of contact between parts, components, and so forth may include conventional items, such as lubricant, additional sealing materials, such as a gasket between flanges, PTFE between threads, and the like. The make and manufacture of any particular component, subcomponent, etc., may be as would be apparent to one of skill in the art, such as molding, forming, press extrusion, machining, or additive manufacturing. Embodiments of the disclosure provide for one or more components to be new, used, and/or retrofitted.

Numerical ranges in this disclosure may be approximate, and thus may include values outside of the range unless otherwise indicated. Numerical ranges include all values from and including the expressed lower and the upper values, in increments of smaller units. As an example, if a compositional, physical or other property, such as, for example, molecular weight, viscosity, melt index, etc., is from 100 to 1,000, it is intended that all individual values, such as 100, 101, 102, etc., and sub ranges, such as 100 to 144, 155 to 170, 197 to 200, etc., are expressly enumerated. It is intended that decimals or fractions thereof be included. For ranges containing values which are less than one or containing fractional numbers greater than one (e.g., 1.1, 1.5, etc.), smaller units may be considered to be 0.0001, 0.001, 0.01, 0.1, etc. as appropriate. These are only examples of what is specifically intended, and all possible combinations of numerical values between the lowest value and the highest value enumerated, are to be considered to be expressly stated in this disclosure.

Terms

Composition of matter: as used herein may refer to one or more ingredients or constituents that make up a material (or material of construction). For example, a material may have a composition of matter. Similarly, a device may be made of a material having a composition of matter. The composition of matter may be derived from an initial composition.

Reactive Material: as used herein may refer a material with a composition of matter having properties and/or characteristics that result in the material responding to a change over time and/or under certain conditions. Reactive material may encompass degradable, dissolvable, disassociatable, and so on.

Degradable Material: as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to a change in the integrity of the material. As one example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material softens.

Dissolvable Material: analogous to degradable material; as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to a change in the integrity of the material, including to the point of degrading, or partial or complete dissolution. As one example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material softens. As another example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material dissolves at least partially, and may dissolve completely. The material may dissolve via one or more mechanisms, such as oxidation, reduction, deterioration, go into solution, or otherwise lose sufficient mass and structural integrity.

Breakable Material: as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to brittleness. As one example, the material may be hard, rigid, and strong at ambient or surface conditions, but over time and under certain conditions, becomes brittle. The breakable material may experience breakage into multiple pieces, but not necessarily dissolution.

Disassociatable Material: as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to a change in the integrity of the material, including to the point of changing from a solid structure to a powdered material. As one example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material changes (disassociates) to a powder.

For some embodiments, a material of construction may include a composition of matter designed or otherwise having the inherent characteristic to react or change integrity or other physical attribute when exposed to certain wellbore conditions, such as a change in time, temperature, water, heat, pressure, solution, combinations thereof, etc. Heat may be present due to the temperature increase attributed to the natural temperature gradient of the earth, and water may already be present in existing wellbore fluids. The change in integrity may occur in a predetermined time period, which may vary from several minutes to several weeks. In aspects, the time period may be about 12 to about 36 hours.

In some embodiments, the material may degrade to the point of ‘mush’ or disassociate to a powder, while in other embodiments, the material may dissolve or otherwise disintegrate and be carried away by fluid flowing in the wellbore. The temperature of the downhole fluid may affect the rate change in integrity. The material need not form a solution when it dissolves in the aqueous phase. For example, the material may dissolve, break, or otherwise disassociate into sufficiently small particles (i.e., a colloid), that may be removed by the fluid as it circulates in the well. In embodiments, the material may become degradable, but not dissolvable. In other embodiments, the material may become degradable, and subsequently dissolvable. In still other embodiments, the material may become breakable (or brittle), but not dissolvable. In yet other embodiments, the material may become breakable, and subsequently dissolvable. In still yet other embodiments, the material may disassociate.

Referring now toFIGS. 2A and 2Btogether, isometric views of a system200having a downhole tool202illustrative of embodiments disclosed herein, are shown.FIG. 2Bdepicts a wellbore206formed in a subterranean formation210with a tubular208disposed therein. In an embodiment, the tubular208may be casing (e.g., casing, hung casing, casing string, etc.) (which may be cemented). A workstring212(which may include a part217of a setting tool coupled with adapter252) may be used to position or run the downhole tool202into and through the wellbore206to a desired location.

In accordance with embodiments of the disclosure, the tool202may be configured as a plugging tool, which may be set within the tubular208in such a manner that the tool202forms a fluid-tight seal against the inner surface207of the tubular208. In an embodiment, the downhole tool202may be configured as a bridge plug, whereby flow from one section of the wellbore213to another (e.g., above and below the tool202) is controlled. In other embodiments, the downhole tool202may be configured as a frac plug, where flow into one section213of the wellbore206may be blocked and otherwise diverted into the surrounding formation or reservoir210.

In yet other embodiments, the downhole tool202may also be configured as a ball drop tool. In this aspect, a ball may be dropped into the wellbore206and flowed into the tool202and come to rest in a corresponding ball seat at the end of the mandrel214. The seating of the ball may provide a seal within the tool202resulting in a plugged condition, whereby a pressure differential across the tool202may result. The ball seat may include a radius or curvature.

In other embodiments, the downhole tool202may be a ball check plug, whereby the tool202is configured with a ball already in place when the tool202runs into the wellbore. The tool202may then act as a check valve, and provide one-way flow capability. Fluid may be directed from the wellbore206to the formation with any of these configurations.

Once the tool202reaches the set position within the tubular, the setting mechanism or workstring212may be detached from the tool202by various methods, resulting in the tool202left in the surrounding tubular and one or more sections of the wellbore isolated. In an embodiment, once the tool202is set, tension may be applied to the adapter252until the threaded connection between the adapter252and the mandrel214is broken. For example, the mating threads on the adapter252and the mandrel214(256and216, respectively as shown inFIG. 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 adapter252may 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 adapter252may separate or detach from the mandrel214, resulting in the workstring212being able to separate from the tool202, 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 tool202may 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 tool202may allow for fast run in of the tool202to isolate one or more sections of the wellbore206, as well as quick and simple drill-through to destroy or remove the tool202. Drill-through of the tool202may be facilitated by components and sub-components of tool202made of drillable material that is less damaging to a drill bit than those found in conventional plugs. In an embodiment, the downhole tool202and/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 tool202may be configured with an angle, such that corresponding components may be placed under compression instead of shear.

The downhole tool202may have one or more components made of non-composite material, such as a metal or metal alloys. The downhole tool2102may have one or more components made of a reactive material (e.g., dissolvable, degradable, etc.).

In embodiments, one or more components may be made of a metallic material, such as an aluminum-based or magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions the respective component(s) may begin to dissolve, and thus alleviating the need for drill thru. In embodiments, the components of the tool202may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD.

One or more components of tool202may be made of non-dissolvable materials (e.g., materials suitable for and are known to withstand downhole environments [including extreme pressure, temperature, fluid properties, etc.] for an extended period of time (predetermined or otherwise) as may be desired).

Just the same, one or more components of a tool of embodiments disclosed herein may be made of reactive materials (e.g., materials suitable for and are known to dissolve, degrade, etc. in downhole environments [including extreme pressure, temperature, fluid properties, etc.] after a brief or limited period of time (predetermined or otherwise) as may be desired). In an embodiment, a component made of a reactive material may begin to react within about 3 to about 48 hours after setting of the downhole tool202.

The downhole tool202(and other tool embodiments disclosed herein) and/or one or more of its components may be 3D printed as would be apparent to one of skill in the art, such as via one or more methods or processes described in U.S. Pat. Nos. 6,353,771; 5,204,055; 7,087,109; 7,141,207; and 5,147, 587. See also information available at the websites of Z Corporation (www.zcorp.com); Prometal (www.prometal.com); EOS GmbH (www.eos.info); and 3D Systems, Inc. (www.3dsystems.com); and Stratasys, Inc. (www.stratasys.com and www.dimensionprinting.com) (applicable to all embodiments).

Referring now toFIGS. 2C-2Etogether, a longitudinal view, a longitudinal cross-sectional view, and an isometric component break-out view, respectively, of downhole tool202useable with system (200,FIG. 2A) and illustrative of embodiments disclosed herein, are shown. The downhole tool202may include a mandrel214that extends through the tool (or tool body)202. The mandrel214may be a solid body. In other aspects, the mandrel214may include a flowpath or bore250formed therein (e.g., an axial bore). The bore250may extend partially or for a short distance through the mandrel214, as shown inFIG. 2E. Alternatively, the bore250may extend through the entire mandrel214, with an opening at its proximate end248and oppositely at its distal end246(near downhole end of the tool202), as illustrated byFIG. 2D.

The presence of the bore250or other flowpath through the mandrel214may indirectly be dictated by operating conditions. That is, in most instances the tool202may be large enough in diameter (e.g., 4¾ inches) that the bore250may be correspondingly large enough (e.g., 1¼ inches) so that debris and junk can pass or flow through the bore250without plugging concerns. However, with the use of a smaller diameter tool202, the size of the bore250may need to be correspondingly smaller, which may result in the tool202being prone to plugging. Accordingly, the mandrel may be made solid to alleviate the potential of plugging within the tool202.

With the presence of the bore250, the mandrel214may have an inner bore surface247, which may include one or more threaded surfaces formed thereon. As such, there may be a first set of threads216configured for coupling the mandrel214with corresponding threads256of a setting adapter252.

The coupling of the threads, which may be shear threads, may facilitate detachable connection of the tool202and the setting adapter252and/or workstring (212,FIG. 2B) at the threads. It is within the scope of the disclosure that the tool202may 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 tool202. In an embodiment, the mandrel214may be configured with a failure point.

Referring briefly toFIGS. 10A and 10B, a longitudinal cross-sectional view and a longitudinal side view, respectively, of a mandrel configured with a relief point, are shown. InFIGS. 10A and 10Btogether, an embodiment of a mandrel2114configured with a relief point (or area, region, etc.)2160. The relief point2160may be formed by machining out or otherwise forming a groove2159in mandrel end2148. The groove2159may be formed circumferentially in the mandrel2114. The mandrel2114may be useable with any downhole tool embodiment disclosed herein, such as tool202,302, etc.

This type of configuration may allow, for example, where, in some applications, it may be desirable, to rip off or shear mandrel head2159instead of shearing threads2116. In this respect, failing composite (or glass fibers) in tension may be potentially more accurate then shearing threads.

Referring again toFIGS. 2C-2Etogether, the adapter252may include a stud253configured with the threads256thereon. In an embodiment, the stud253has external (male) threads256and the mandrel214has 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 tool202may 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 workstring212and setting sleeve254may be part of the plugging tool system200utilized to run the downhole tool202into the wellbore, and activate the tool202to move from an unset to set position. The set position may include seal element222and/or slips234,242engaged with the tubular (208,FIG. 2B). In an embodiment, the setting sleeve254(that may be configured as part of the setting mechanism or workstring) may be utilized to force or urge compression of the seal element222, as well as swelling of the seal element222into sealing engagement with the surrounding tubular.

Referring briefly toFIGS. 11A, 11B, and 11C, 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. 11A-11Cillustrate a sleeve1954configured with one or more grooves or channels1955configured to allow wellbore fluid to readily pass therein, therethrough, thereby, etc., consequently resulting in reduction of the hydraulic resistance (e.g., drag) against the workstring1905as it is removed from the wellbore1908. Or put another way, that hydraulic pressure above the setting sleeve1954can be ‘relieved’ or bypassed below the sleeve1954. Channels1955may 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 sleeve1954may be in operable engagement with the downhole tool1902. In an embodiment, the downhole tool1902may be a frac plug.

Because of the large pressures incurred, in using a sleeve1954with 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. 11A-11Ctogether show setting sleeve1954may have a first end1957and a second end1958. One or more channels1955may extend or otherwise be disposed a length L along the outer surface1960of the sleeve1954. The channel(s) may be parallel or substantially parallel to sleeve axis1961. One or more channels1955may be part of a channel group1962. There may be multiple channel groups1962in the sleeve1955. As shown in the Figures here, there may be three (3) channel groups1962. The groups1962of channels1955may be arranged in an equilateral pattern around the circumference of the sleeve1954. Indicator ring1956illustrates how the outer diameter (or hydraulic diameter) is effectively reduced by the presence of channel(s)1955. Or put another way, that the sleeve1954may 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).

AlthoughFIGS. 11A-11Cdepict one example, embodiments herein pertaining to the sleeve1954are 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 sleeve1954(and/or provide fluid bypass capability), but yet provide the sleeve1954with adequate integrity suitable for setting, downhole conditions, and so forth.

There may be a channel(s) arranged in a non-axial or non-linear manner, for example, as spiral-wound, helical etc. It is worth noting that although embodiments of the sleeve channel may extend from one end of the sleeve1957to approximately the other end of the sleeve1958, this need not be the case. Thus, the length of the channel L may be less than the length LS of the sleeve1955. In addition, the channel need not be continuous, such that there may be discontinuous channels.

Other variants of sleeve1954having a certain channel groove pattern or cross-sectional shape are possible, including one or more channels having a “v-notch”, as well as an ‘offset’ V-notch, an opposite offset V-notch, a “square” notch, a rounded notch, and combinations thereof (not shown). 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 disposed within the sleeve instead of on the outer surface. For example, the sleeve1954may include a channel formed within the body (or wall thickness) of the sleeve, thus forming an inner passageway for fluid to flow therethrough.

Returning again toFIGS. 2C-2Etogether, the setting device(s) and components of the downhole tool202may be coupled with, and axially and/or longitudinally movable along mandrel214. When the setting sequence begins, the mandrel214may be pulled into tension while the setting sleeve254remains stationary. The lower sleeve260may be pulled as well because of its attachment to the mandrel214by virtue of the coupling of threads218and threads262. As shown in the embodiment ofFIGS. 2C and 2D, the lower sleeve260and the mandrel214may have matched or aligned holes281A and281B, respectively, whereby one or more anchor pins211or the like may be disposed or securely positioned therein. In embodiments, brass set screws may be used. Pins (or screws, etc.)211may prevent shearing or spin-off during drilling or run-in.

As the lower sleeve260is pulled in the direction of Arrow A, the components disposed about mandrel214between the lower sleeve260and the setting sleeve254may begin to compress against one another. This force and resultant movement causes compression and expansion of seal element222. The lower sleeve260may also have an angled sleeve end263in engagement with the slip234, and as the lower sleeve260is pulled further in the direction of Arrow A, the end263compresses against the slip234. As a result, slip(s)234may move along a tapered or angled surface228of a composite member220, and eventually radially outward into engagement with the surrounding tubular (208,FIG. 2B).

Serrated outer surfaces or teeth298of the slip(s)234may be configured such that the surfaces298prevent the slip234(or tool) from moving (e.g., axially or longitudinally) within the surrounding tubular, whereas otherwise the tool202may inadvertently release or move from its position. Although slip234is illustrated with teeth298, it is within the scope of the disclosure that slip234may be configured with other gripping features, such as buttons or inserts.

Initially, the seal element222may swell into contact with the tubular, followed by further tension in the tool202that may result in the seal element222and composite member220being compressed together, such that surface289acts on the interior surface288. The ability to “flower”, unwind, and/or expand may allow the composite member220to extend completely into engagement with the inner surface of the surrounding tubular.

The composite member220may provide other synergistic benefits beyond that of creating enhanced sealing. Without the ability to ‘flower’, the hydraulic cross-section is essentially the back of the tool. However, with a ‘flower’ effect the hydraulic cross-section becomes dynamic, and is increased. This allows for faster run-in and reduced fluid requirements compared to conventional operations. This is even of greater significance in horizontal applications. In various testing, tools configured with a composite member220required about 40 less minutes of run-in compared to conventional tools. When downhole operations run about $30,000-$40,000 per hour, a savings of 40 minutes is of significance.

Additional tension or load may be applied to the tool202that results in movement of cone236, which may be disposed around the mandrel214in a manner with at least one surface237angled (or sloped, tapered, etc.) inwardly of second slip242. The second slip242may reside adjacent or proximate to collar or cone236. As such, the seal element222forces the cone236against the slip242, moving the slip242radially outwardly into contact or gripping engagement with the tubular. Accordingly, the one or more slips234,242may be urged radially outward and into engagement with the tubular (208,FIG. 2B). In an embodiment, cone236may be slidingly engaged and disposed around the mandrel214. As shown, the first slip234may be at or near distal end246, and the second slip242may be disposed around the mandrel214at or near the proximate end248. It is within the scope of the disclosure that the position of the slips234and242may be interchanged. Moreover, slip234may be interchanged with a slip comparable to slip242, and vice versa.

Because the sleeve254is held rigidly in place, the sleeve254may engage against a bearing plate283that may result in the transfer load through the rest of the tool202. The setting sleeve254may have a sleeve end255that abuts against the bearing plate end284. As tension increases through the tool202, an end of the cone236, such as second end240, compresses against slip242, which may be held in place by the bearing plate283. As a result of cone236having freedom of movement and its conical surface237, the cone236may move to the underside beneath the slip242, forcing the slip242outward and into engagement with the surrounding tubular (208,FIG. 2B).

The second slip242may include one or more, gripping elements, such as buttons or inserts278, which may be configured to provide additional grip with the tubular. The inserts278may have an edge or corner279suitable to provide additional bite into the tubular surface. In an embodiment, the inserts278may 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, slip242may be a one-piece slip, whereby the slip242has at least partial connectivity across its entire circumference. Meaning, while the slip242itself may have one or more grooves (or notches, undulations, etc.)244configured therein, the slip242itself has no initial circumferential separation point. In an embodiment, the grooves244may be equidistantly spaced or disposed in the second slip242. In other embodiments, the grooves244may have an alternatingly arranged configuration. That is, one groove244A may be proximate to slip end241, the next groove244B may be proximate to an opposite slip end243, and so forth.

The tool202may be configured with ball plug check valve assembly that includes a ball seat286. The assembly may be removable or integrally formed therein. In an embodiment, the bore250of the mandrel214may be configured with the ball seat286formed or removably disposed therein. In some embodiments, the ball seat286may be integrally formed within the bore250of the mandrel214. In other embodiments, the ball seat286may be separately or optionally installed within the mandrel214, as may be desired.

The ball seat286may be configured in a manner so that a ball285seats or rests therein, whereby the flowpath through the mandrel214may be closed off (e.g., flow through the bore250is restricted or controlled by the presence of the ball285). For example, fluid flow from one direction may urge and hold the ball285against the seat286, whereas fluid flow from the opposite direction may urge the ball285off or away from the seat286. As such, the ball285and the check valve assembly may be used to prevent or otherwise control fluid flow through the tool202. The ball285may be conventionally made of a composite material, phenolic resin, etc., whereby the ball285may be capable of holding maximum pressures experienced during downhole operations (e.g., fracing). By utilization of retainer pin287, the ball285and ball seat286may be configured as a retained ball plug. As such, the ball285may be adapted to serve as a check valve by sealing pressure from one direction, but allowing fluids to pass in the opposite direction.

The tool202may be configured as a drop ball plug, such that a drop ball may be flowed to a drop ball seat259. The drop ball may be much larger diameter than the ball of the ball check. In an embodiment, end248may be configured with a drop ball seat surface259such that the drop ball may come to rest and seat at in the seat proximate end248. As applicable, the drop ball (not shown here) may be lowered into the wellbore (206,FIG. 2A) and flowed toward the drop ball seat259formed within the tool202. The ball seat may be formed with a radius259A (i.e., circumferential rounded edge or surface).

In other aspects, the tool202may 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 tool202. Accordingly, it should be apparent to one of skill in the art that the tool202of 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 tool202is 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 tool202may include an anti-rotation assembly that includes an anti-rotation device or mechanism282, which may be a spring, a mechanically spring-energized composite tubular member, and so forth. The device282may be configured and usable for the prevention of undesired or inadvertent movement or unwinding of the tool202components. As shown, the device282may reside in cavity294of the sleeve (or housing)254. During assembly the device282may be held in place with the use of a lock ring296. In other aspects, pins may be used to hold the device282in place.

FIG. 2Dshows the lock ring296may be disposed around a part217of a setting tool coupled with the workstring212. The lock ring296may be securely held in place with screws inserted through the sleeve254. The lock ring296may include a guide hole or groove295, whereby an end282A of the device282may slidingly engage therewith. Protrusions or dogs295A may be configured such that during assembly, the mandrel214and respective tool components may ratchet and rotate in one direction against the device282; however, the engagement of the protrusions295A with device end282B 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 device282and lock ring296may aid in keeping the rest of the tool together. As such, the device282may prevent tool components from loosening and/or unscrewing, as well as prevent tool202unscrewing or falling off the workstring212.

Drill-through of the tool202may be facilitated by the fact that the mandrel214, the slips234,242, the cone(s)236, the composite member220, 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 tool202until the downhole slip234and/or242are 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 sleeve260and any portion of mandrel214within the lower sleeve260falls into the well. If additional tool(s)202exist in the well bore beneath the tool202that is being drilled through, then the falling away portion will rest atop the tool202located further in the well bore and will be drilled through in connection with the drill through operations related to the tool202located further in the well bore. Accordingly, the tool202may be sufficiently removed, which may result in opening the tubular208.

Referring now toFIGS. 3A, 3B, 3C and 3Dtogether, 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 mandrel314, as described and understood to one of skill in the art, and may be comparable to other embodiments disclosed herein (e.g., see downhole tool202with mandrel214).

The mandrel314, which may be made from filament wound drillable material, may have a distal end346and a proximate end348. The filament wound material may be made of various angles as desired to increase strength of the mandrel314in axial and radial directions. The presence of the mandrel314may provide the tool with the ability to hold pressure and linear forces during setting or plugging operations.

The mandrel314may be sufficient in length, such that the mandrel may extend through a length of tool (or tool body) (202,FIG. 2B). The mandrel314may be a solid body. In other aspects, the mandrel314may include a flowpath or bore350formed therethrough (e.g., an axial bore). There may be a flowpath or bore350, for example an axial bore, that extends through the entire mandrel314, with openings at both the proximate end348and oppositely at its distal end346. Accordingly, the mandrel314may have an inner bore surface347, which may include one or more threaded surfaces formed thereon.

The ends346,348of the mandrel314may include internal or external (or both) threaded portions. As shown inFIG. 3C, the mandrel314may have internal threads316within the bore350configured to receive a mechanical or wireline setting tool, adapter, etc. (not shown here). For example, there may be a first set of threads316configured for coupling the mandrel314with corresponding threads of another component (e.g., adapter252,FIG. 2B). In an embodiment, the first set of threads316are shear threads. In an embodiment, application of a load to the mandrel314may be sufficient enough to shear the first set of threads316. 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 mandrel314from the workstring.

The proximate end348may include an outer taper348A. The outer taper348A 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 taper348will allow the tool to slide off easier from the setting sleeve. In an embodiment, the outer taper348A may be formed at an angle φ of about 5 degrees with respect to the axis358. The length of the taper348A may be about 0.5 inches to about 0.75 inches

There may be a neck or transition portion349, such that the mandrel may have variation with its outer diameter. In an embodiment, the mandrel314may have a first outer diameter D1that 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 portion349configured with an angled transition surface349A. A transition surface angle b may be about 25 degrees with respect to the tool (or tool component axis)358.

The transition portion349may withstand radial forces upon compression of the tool components, thus sharing the load. That is, upon compression the bearing plate383and mandrel314, 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 threads316, the mandrel314may have a second set of threads318. In one embodiment, the second set of threads318may be rounded threads disposed along an external mandrel surface345at the distal end346. The use of rounded threads may increase the shear strength of the threaded connection.

FIG. 3Dillustrates an embodiment of component connectivity at the distal end346of the mandrel314. As shown, the mandrel314may be coupled with a sleeve360having corresponding threads362configured to mate with the second set of threads318. In this manner, setting of the tool may result in distribution of load forces along the second set of threads318at an angle a away from axis358. There may be one or more balls364disposed between the sleeve360and slip334. The balls364may help promote even breakage of the slip334.

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 toFIG. 3C, the mandrel314may have a ball seat386disposed therein. In some embodiments, the ball seat386may be a separate component, while in other embodiments the ball seat386may be formed integral with the mandrel314. There also may be a drop ball seat surface359formed within the bore350at the proximate end348. The ball seat359may have a radius359A that provides a rounded edge or surface for the drop ball to mate with. In an embodiment, the radius359A of seat359may 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 radius359A may be advantageous as compared to a conventional sharp point or edge of a ball seat surface. For example, radius359A may provide the tool with the ability to accommodate drop balls with variation in diameter, as compared to a specific diameter. In addition, the surface359and radius359A 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.

The drop ball (or “frac ball”) may be any type of ball apparent to one of skill in the art and suitable for use with embodiments disclosed herein. Although nomenclature of ‘drop’ or ‘frac’ ball is used, any such ball may be a ball held in place or otherwise positioned within a downhole tool.

The drop ball may be a “smart” ball (not shown here) configured to monitor or measure downhole conditions, and otherwise convey information back to the surface or an operator, such as the ball(s) provided by Aquanetus Technology, Inc. or OpenField Technology.

In other aspects, drop ball may be made from a composite material. In an embodiment, the composite material may be wound filament. Other materials are possible, such as glass or carbon fibers, phenolic material, plastics, fiberglass composite (sheets), plastic, etc.

The drop ball may be made from a dissolvable material, such as that as disclosed in co-pending U.S. patent application Ser. No. 15/784,020, and incorporated herein by reference as it pertains to dissolvable materials. The ball may be configured or otherwise designed to dissolve under certain conditions or various parameters, including those related to temperature, pressure, and composition.

Referring now toFIGS. 4A and 4Btogether, 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 element322may 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 element322may be made from 75 to 80 Duro A elastomer material. The seal element322may be disposed between a first slip and a second slip (seeFIG. 2C, seal element222and slips234,236).

The seal element322may 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 element322may buckle, the seal element322may 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 element322provides a fluid-tight seal of the seal surface321against the tubular.

The seal element322may have one or more angled surfaces configured for contact with other component surfaces proximate thereto. For example, the seal element may have angled surfaces327and389. The seal element322may be configured with an inner circumferential groove376. The presence of the groove376assists the seal element322to initially buckle upon start of the setting sequence. The groove376may have a size (e.g., width, depth, etc.) of about 0.25 inches.

Referring now toFIGS. 5A, 5B, 5C, 5D, 5E, 5F, and 5Gtogether, 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 slips334,342described 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.

Either or both of slips334,342may be made of non-composite material, such as a metal or metal alloys. Either or both of slips334,342may be made of a reactive material (e.g., dissolvable, degradable, etc.). In embodiments, the material may be a metallic material, such as an aluminum-based or magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions the respective component(s) may begin to dissolve, and thus alleviating the need for drill thru. In embodiments, any slip of the tool embodiments disclosed herein may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD.

Slips334,342may be used in either upper or lower slip position, or both, without limitation. As apparent, there may be a first slip334, which may be disposed around the mandrel (214,FIG. 2C), and there may also be a second slip342, which may also be disposed around the mandrel. Either of slips334,342may 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 teeth398, inserts378, etc. As shown inFIGS. 5D-5F, the first slip334may include rows and/or columns399of serrations398. The gripping elements may be arranged or configured whereby the slips334,342engage 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 slip334may be a poly-moldable material. In other embodiments, the slip334may be hardened, surface hardened, heat-treated, carburized, etc., as would be apparent to one of ordinary skill in the art. However, in some instances, slips334may be too hard and end up as too difficult or take too long to drill through.

Typically, hardness on the teeth398may 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 slip334being impossible or impracticable to drill-thru.

Thus, the slip334may be configured to include one or more holes393formed therein. The holes393may be longitudinal in orientation through the slip334. The presence of one or more holes393may result in the outer surface(s)307of the metal slips as the main and/or majority slip material exposed to heat treatment, whereas the core or inner body (or surface)309of the slip334is protected. In other words, the holes393may provide a barrier to transfer of heat by reducing the thermal conductivity (i.e., k-value) of the slip334from the outer surface(s)307to the inner core or surfaces309. The presence of the holes393is believed to affect the thermal conductivity profile of the slip334, such that that heat transfer is reduced from outer to inner because otherwise when heat/quench occurs the entire slip334heats up and hardens.

Thus, during heat treatment, the teeth398on the slip334may 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 teeth398.

With the presence of one or more holes393, the hardness profile from the teeth to the inner diameter/core (e.g., laterally) may decrease dramatically, such that the inner slip material or surface309has a HRC of about ˜15 (or about normal hardness for regular steel/cast iron). In this aspect, the teeth398stay hard and provide maximum bite, but the rest of the slip334is easily drillable.

One or more of the void spaces/holes393may be filled with useful “buoyant” (or low density) material400to help debris and the like be lifted to the surface after drill-thru. The material400disposed in the holes393may 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 material400helps promote lift on debris after the slip334is drilled through. The material400may be epoxied or injected into the holes393as would be apparent to one of skill in the art.

The metal slip334may be treated with an induction hardening process. In such a process, the slip334may be moved through a coil that has a current run through it. As a result of physical properties of the metal and magnetic properties, a current density (created by induction from the e-field in the coil) may be controlled in a specific location of the teeth398. This may lend to speed, accuracy, and repeatability in modification of the hardness profile of the slip334. Thus, for example, the teeth398may have a RC in excess of 60, and the rest of the slip334(essentially virgin, unchanged metal) may have a RC less than about 15.

The slots392in the slip334may promote breakage. An evenly spaced configuration of slots392promotes even breakage of the slip334. The metal slip334may have a body having a one-piece configuration defined by at least partial connectivity of slip material around the entirety of the body, as shown inFIG. 5Dvia connectivity reference line374. The slip334may have at least one lateral groove371. The lateral groove may be defined by a depth373. The depth373may extend from the outer surface307to the inner surface309.

First slip334may 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 slip334until 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 slip334in 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 slip334compresses 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, slip234and composite member220inFIG. 2C).FIG. 5Gillustrates slip334may be a hardened cast iron slip without the presence of any grooves or holes393formed therein.

The slip342may be a one-piece slip, whereby the slip342has at least partial connectivity across its entire circumference. Meaning, while the slip342itself may have one or more grooves344configured therein, the slip342has no separation point in the pre-set configuration. In an embodiment, the grooves344may be equidistantly spaced or cut in the second slip342. In other embodiments, the grooves344may have an alternatingly arranged configuration. That is, one groove344A may be proximate to slip end341and adjacent groove344B may be proximate to an opposite slip end343. As shown in groove344A may extend all the way through the slip end341, such that slip end341is devoid of material at point372. The slip342may have an outer slip surface390and an inner slip surface391.

Where the slip342is 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 grooves344of the slip342may be designed as desired. In an embodiment, the slip342may be designed with grooves344resulting in equal distribution of radial load along the slip342. Alternatively, one or more grooves, such as groove344B may extend proximate or substantially close to the slip end343, but leaving a small amount material335therein. The presence of the small amount of material gives slight rigidity to hold off the tendency to flare. As such, part of the slip342may expand or flare first before other parts of the slip342. There may be one or more grooves344that form a lateral opening394athrough the entirety of the slip body. That is, groove344may extend a depth394from the outer slip surface390to the inner slip surface391. Depth394may define a lateral distance or length of how far material is removed from the slip body with reference to slip surface390(or also slip surface391).FIG. 5Aillustrates the at least one of the grooves344may be further defined by the presence of a first portion of slip material335aon or at first end341, and a second portion of slip material335bon or at second end343.

The slip342may have one or more inner surfaces with varying angles. For example, there may be a first angled slip surface329and a second angled slip surface333. In an embodiment, the first angled slip surface329may have a 20-degree angle, and the second angled slip surface333may 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 slip342significant engagement force, while utilizing the smallest slip342possible.

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 slip342may be used to lock the tool in place during the setting process by holding potential energy of compressed components in place. The slip342may also prevent the tool from moving as a result of fluid pressure against the tool. The second slip (342,FIG. 5A) may include inserts378disposed thereon. In an embodiment, the inserts378may be epoxied or press fit into corresponding insert bores or grooves375formed in the slip342.

Referring now toFIGS. 6A, 6B, 6C, 6D, 6E, and 6Ftogether, 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 member320(and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. The composite member320may 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 member320may be made from metal, including alloys and so forth. Moreover, as disclosed there may be numerous alternative downhole tool embodiments that do not require nor need the composite member320.

During pump down (or run in), the composite member320may ‘flower’ or be energized as a result of a pumped fluid, resulting in greater run-in efficiency (less time, less fluid required). During the setting sequence, the seal element322and the composite member320may compress together. As a result of an angled exterior surface389of the seal element322coming into contact with the interior surface388of the composite member320, a deformable (or first or upper) portion326of the composite member320may be urged radially outward and into engagement the surrounding tubular (not shown) at or near a location where the seal element322at least partially sealingly engages the surrounding tubular. There may also be a resilient (or second or lower) portion328. In an embodiment, the resilient portion328may be configured with greater or increased resilience to deformation as compared to the deformable portion326.

The composite member320may be a composite component having at least a first material331and a second material332, but composite member320may also be made of a single material. The first material331and the second material332need not be chemically combined. In an embodiment, the first material331may be physically or chemically bonded, cured, molded, etc. with the second material332. Moreover, the second material332may likewise be physically or chemically bonded with the deformable portion326. In other embodiments, the first material331may be a composite material, and the second material332may be a second composite material.

The composite member320may have cuts or grooves330formed therein. The use of grooves330and/or spiral (or helical) cut pattern(s) may reduce structural capability of the deformable portion326, such that the composite member320may “flower” out. The groove330or groove pattern is not meant to be limited to any particular orientation, such that any groove330may have variable pitch and vary radially.

With groove(s)330formed in the deformable portion326, the second material332, may be molded or bonded to the deformable portion326, such that the grooves330are filled in and enclosed with the second material332. In embodiments, the second material332may be an elastomeric material. In other embodiments, the second material332may be 60-95 Duro A polyurethane or silicone. Other materials may include, for example, TFE or PTFE sleeve option-heat shrink. The second material332of the composite member320may have an inner material surface368.

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 material332in conjunction with the grooves330may provide support for the groove pattern and reduce preset issues. With the added benefit of second material332being bonded or molded with the deformable portion326, the compression of the composite member320against the seal element322may result in a robust, reinforced, and resilient barrier and seal between the components and with the inner surface of the tubular member (e.g.,208inFIG. 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)330allow the composite member320to expand against the tubular, which may result in a formidable barrier between the tool and the tubular. In an embodiment, the groove330may be a spiral (or helical, wound, etc.) cut formed in the deformable portion326. In an embodiment, there may be a plurality of grooves or cuts330. In another embodiment, there may be two symmetrically formed grooves330, as shown by way of example inFIG. 6E. In yet another embodiment, there may be three grooves330.

As illustrated byFIG. 6C, the depth d of any cut or groove330may extend entirely from an exterior side surface364to an upper side interior surface366. The depth d of any groove330may vary as the groove330progresses along the deformable portion326. In an embodiment, an outer planar surface364A may have an intersection at points tangent the exterior side364surface, and similarly, an inner planar surface366A may have an intersection at points tangent the upper side interior surface366. The planes364A and366A of the surfaces364and366, respectively, may be parallel or they may have an intersection point367. Although the composite member320is depicted as having a linear surface illustrated by plane366A, the composite member320is 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)330or 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 surface364of the deformable member326. In an embodiment, the spiral pattern may include constant pitch (p1about the same as p2), variable radius (r1unequal to r2) on the inner surface366of the deformable member326.

In an embodiment, the groove(s)330or groove pattern may be a spiral pattern having variable pitch (p1unequal to p2), constant radius (r3about the same as r4) on the outer surface364of the deformable member326. In an embodiment, the spiral pattern may include variable pitch (p1unequal to p2), variable radius (r1unequal to r2) on the inner surface366of the deformable member320.

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 inFIG. 6B, the composite member320may have a groove pattern cut on a back angle β. A pattern cut or formed with a back angle may allow the composite member320to be unrestricted while expanding outward. In an embodiment, the back angle β may be about 75 degrees (with respect to axis258). In other embodiments, the angle β may be in the range of about 60 to about 120 degrees

The presence of groove(s)330may allow the composite member320to have an unwinding, expansion, or “flower” motion upon compression, such as by way of compression of a surface (e.g., surface389) against the interior surface of the deformable portion326. For example, when the seal element322moves, surface389is forced against the interior surface388. 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 member320to extend completely into engagement with the inner surface of the surrounding tubular.

Referring now toFIGS. 7A and 7Btogether, an isometric view and a longitudinal cross-sectional view, respectively of a bearing plate383(and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. The bearing plate383may be made from filament wound material having wide angles. As such, the bearing plate383may endure increased axial load, while also having increased compression strength.

Because the sleeve (254,FIG. 2C) may held rigidly in place, the bearing plate383may likewise be maintained in place. The setting sleeve may have a sleeve end255that abuts against bearing plate end284,384. Briefly,FIG. 2Cillustrates how compression of the sleeve end255with the plate end284may occur at the beginning of the setting sequence. As tension increases through the tool, an other end239of the bearing plate283may be compressed by slip242, forcing the slip242outward and into engagement with the surrounding tubular (208,FIG. 2B).

Inner plate surface319may be configured for angled engagement with the mandrel. In an embodiment, plate surface319may engage the transition portion349of the mandrel314. Lip323may be used to keep the bearing plate383concentric with the tool202and the slip242. Small lip323A may also assist with centralization and alignment of the bearing plate383.

Referring briefly toFIGS. 7C-7EEtogether, various views a bearing plate383(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 plate383engaged with a metal slip (e.g.,334,FIG. 5D), the bearing plate383may 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 pins364B, which may aid breaking the slip334uniformly as a result of distribution of forces against the slip334.

It is believed a durable insert pin364B may perform better than an integral configuration of the bearing plate383because of the huge massive forces that may be encountered (i.e., 30,000 lbs).

The pins364B may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins364B 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 toFIGS. 8A and 8Btogether, an underside isometric view and a longitudinal cross-sectional view, respectively, of one or more cones336(and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. In an embodiment, cone336may be slidingly engaged and disposed around the mandrel (e.g., cone236and mandrel214inFIG. 2C). Cone336may be disposed around the mandrel in a manner with at least one surface337angled (or sloped, tapered, etc.) inwardly with respect to other proximate components, such as the second slip (242,FIG. 2C). As such, the cone336with surface337may 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 cone336, such as second end340, may compress against the slip (seeFIG. 2C). As a result of conical surface337, the cone336may move to the underside beneath the slip, forcing the slip outward and into engagement with the surrounding tubular (seeFIG. 2A). A first end338of the cone336may be configured with a cone profile351. The cone profile351may be configured to mate with the seal element (222,FIG. 2C). In an embodiment, the cone profile351may be configured to mate with a corresponding profile327A of the seal element (seeFIG. 4A). The cone profile351may help restrict the seal element from rolling over or under the cone336.

Referring now toFIGS. 9A and 9B, an isometric view, and a longitudinal cross-sectional view, respectively, of a lower sleeve360(and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. During setting, the lower sleeve360will be pulled as a result of its attachment to the mandrel214. As shown inFIGS. 9A and 9Btogether, the lower sleeve360may have one or more holes381A that align with mandrel holes (281B,FIG. 2C). One or more anchor pins311may be disposed or securely positioned therein. In an embodiment, brass set screws may be used. Pins (or screws, etc.)311may prevent shearing or spin off during drilling.

As the lower sleeve360is pulled, the components disposed about mandrel between the may further compress against one another. The lower sleeve360may have one or more tapered surfaces361,361A which may reduce chances of hang up on other tools. The lower sleeve360may also have an angled sleeve end363in engagement with, for example, the first slip (234,FIG. 2C). As the lower sleeve360is pulled further, the end363presses against the slip. The lower sleeve360may be configured with an inner thread profile362. In an embodiment, the profile362may include rounded threads. In another embodiment, the profile362may be configured for engagement and/or mating with the mandrel (214,FIG. 2C). Ball(s)364may be used. The ball(s)364may be for orientation or spacing with, for example, the slip334. The ball(s)364and may also help maintain break symmetry of the slip334. The ball(s)364may be, for example, brass or ceramic.

Referring briefly toFIGS. 9C-9Etogether, an isometric, lateral, and longitudinal cross-sectional view, respectively, of the lower sleeve360configured 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 sleeve360may 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 readily pre-set, but may require a configuration that urges uniform and even breakage. In accordance with embodiments disclosed herein, the metal slip334may be configured to mate or otherwise engage with pins364A, which may aid breaking the slip334uniformly as a result of distribution of forces against the slip334.

It is plausible a durable insert pin364A may perform better than an integral pin/sleeve configuration of the lower sleeve360because of the huge massive forces that are encountered (i.e., 30,000 lbs). The pins364A may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins364A 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 pins364A 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 pins364A may be shaped and sized to a tolerance fit with slots381B. In other aspects, the pins364A may be shaped and sized to an undersized or oversized fit with slots381B. The pins364A may be held in situ with an adhesive or glue.

In embodiments one or more of the pins364,364A may have a rounded or spherical portion configured for engagement with the metal slip (seeFIG. 3D). In other embodiments, one or more of the pins364,364A may have a planar portion365configured for engagement with the metal slip334. In yet other embodiments, one or more of the pins364,364A may be configured with a taper(s)369.

The presence of the taper(s)369may be useful to help minimize displacement in the event the metal slip334inadvertently attempts to ‘hop up’ over one of the pins364A in the instance the metal slip334did not break properly or otherwise.

One or more of the pins364A may be configured with a ‘cut out’ portion that results in a pointed region on the inward side of the pin(s)364A (see7EE). This may aid in ‘crushing’ of the pin364A during setting so that the pin364A moves out of the way.

Referring briefly toFIGS. 12A-12B, an isometric and lateral side view of a metal slip according to embodiments of the disclosure, are shown.FIGS. 12A and 12Btogether show one or more of the (mating) holes393A in the metal slip334may be configured in a round, symmetrical fashion or shape. The holes393A may be notches, grooves, etc. or any other receptacle-type shape and configuration.

A downhole tool of embodiments disclosed herein may include the metal slip334disposed, for example, about the mandrel. The metal slip334may include (prior to setting) a one-piece circular slip body configuration. The metal slip334may include a face397configured with a set or plurality of mating holes393A.FIGS. 12A and 12Billustrate there may be three mating holes393A. Although not limited to any one particular arrangement, the holes393A may be disposed in a generally or substantially symmetrical manner (e.g., equidistant spacing around the circumferential shape of the face397). 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. 12Gillustrates an embodiment where the metal slip334may include a set of mating holes having four mating holes. As shown, one or more of the mating holes393A of the set of mating holes may be circular or rounded in shape.

Referring now toFIG. 12C, a lateral view of a metal slip 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 sleeve360may be configured with a corresponding number of stabilizer pins364A. Thus, for example, the sleeve360may have a set of stabilizer pins to correspond to the set of mating holes of the slip334. In other aspects, the set of mating holes393A comprises three mating holes, and similarly the set of stabilizer pins comprises three stabilizer pins364A, as shown in the Figure. The set of mating holes may be configured in the range of about 90 to about 120 degrees circumferentially (e.g., seeFIG. 12G, arcuate segment393B being about 90 degrees). In a similar fashion, the set of stabilizer pins364A may be arranged or positioned in the range of about 90 to about 120 degrees circumferentially around the sleeve360.

Thus, in accordance with embodiments of the disclosure the metal slip334may be configured for substantially even breakage of the metal slip body during setting. Prior to setting the metal slip334may have a one-piece circular slip body. That is, at least some part or aspects of the slip334has a solid connection around the entirety of the slip.

In an embodiment, the face (397,FIG. 12A) may be configured with at least three mating holes393A. In embodiments, the sleeve360may be configured or otherwise fitted with a set of stabilizer pins equal in number and corresponding to the number of mating holes393A. Thus, each pin364A may be configured to engage a corresponding mating hole393A. Although not meant to be limited, there may be about three to five mating holes and corresponding pins.

The downhole tool may be configured for at least three portions of the metal slip334to 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 slip334may be configured to mate or otherwise engage with pins364A, which may aid breaking the slip334uniformly as a result of distribution of forces against the slip334. The sleeve360may include a set of stabilizer pins configured to engage the set of mating holes.

FIGS. 12D-12Fillustrate a lateral ‘slice’ view through the metal slip334as the pin364ainduces fracture of the slip body.

Referring briefly toFIGS. 13A-13D, one or more of the (mating) holes393A in the metal slip334may be configured in a round, symmetrical fashion or shape. Just the same, one or more of the holes393A 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 slip334to break a generally equal amount of distribution around the slip body circumference. That is, the metal slip334breaks in a manner where portions of the slip engage the surrounding tubular and the distribution of load is about equal or even around the slip334. Thus, the metal slip334may 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 slip334may 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 toFIGS. 14A, 14B, and 14Ctogether, an isometric view, a longitudinal side view, and a component breakout view, respectively, of a downhole tool with a wedge mandrel, in accordance with embodiments disclosed herein, are shown.

Downhole tool2102may be run, set, and operated as described herein and in other embodiments (such as in System200, and so forth), and as otherwise understood to one of skill in the art. Components of the downhole tool2102may be arranged and disposed about a wedge mandrel2114, as described herein and comparable to other embodiments, and as otherwise understood to one of skill in the art. Thus, downhole tool2102may be comparable or identical in aspects, function, operation, components, etc. as that of other tool embodiments disclosed herein.

All mating surfaces of the downhole tool2102may be configured with an angle, such that corresponding components may be placed under compression instead of shear. The wedge mandrel2114may extend through the tool (or tool body)2102, and include a flowpath (or bore, flowbore, inner bore, etc.)2151formed therein (e.g., an axial bore).

The wedge mandrel2114may be made of a material as described herein and in accordance with embodiments of the disclosure, such as a composite filament wound material made by the Applicant. The wedge mandrel2114may be made other materials, such as a metallic material, for example, an aluminum-based, magnesium-based, or aluminum-magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions that wedge mandrel2114may begin to dissolve, and thus alleviating the need for drill thru.

In embodiments, the wedge mandrel2114may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD.

Just the same, the wedge mandrel may be made of reactive composite material formed (cured) from an initial mixture composition of embodiments herein.

Other components may be made of non-composite material, such as a metal or metal alloys. In embodiments, the material may be a metallic material, such as an aluminum-based or magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions the respective component(s) may begin to dissolve, and thus alleviating the need for drill thru.

Downhole tool2102may include a lower sleeve2160disposed around the wedge mandrel2114. The lower sleeve2160may be threadingly engaged with the mandrel2114. As a support platform2121is pulled in tension, various components disposed about mandrel2114between the support platform2121and a setting sleeve (2154,FIG. 22A) may begin to compress against one another. This force and resultant movement may ultimately cause compression and expansion of a seal element2122

Additional tension or load may be applied to the tool2102that results in movement of the wedge mandrel2114against a fingered member2176. Accordingly, via interaction with angled surfaces of each other, one or more ends2715of the fingered member2176may be urged radially outward and into engagement with a tubular (2108). The fingered member2176may be movingly (such as slidingly) engaged and disposed around the wedge mandrel2114.

The setting sleeve (2154) may engage against a shoulder2184of the wedge mandrel2114, which may accommodate to or provide ability for the transfer of load through the rest of the tool2102. The setting sleeve may be a grooved setting sleeve in accordance with embodiments herein.

Although many configurations are possible, the fingered member2176may generally have a circular body (or ring shaped) portion2195configured for positioning on or disposal around the wedge mandrel2114. Extending from the circular body portion may be two or more fingers (dogs, protruding members, etc.)2177. In the assembled tool configuration, the fingers2177may be referred to as facing “uphole” or toward the top (proximate end) of the tool2102.

The fingered member2176may include a plurality of fingers2177. In embodiments, there may be a range of about 6 to about 12 fingers2177. The fingers2177may be configured symmetrically and equidistantly to each other. As the fingers2177are urged outwardly they may provide a synergistic effect of centralizing the downhole tool2102, which may be of greater benefit in situations where the surrounding tubular has a horizontal orientation.

Fingers2177may be formed with a gap or separation point2181therebetween. The size of the fingers2177in terms of width, length, and thickness, and the number of fingers2177may be optimized in a manner that results in the greatest ability to seal an annulus (2190, compareFIGS. 22A and 22C).

During setting, the fingered member2176(including fingers2177) may be urged along a proximate surface2149(or vice versa, the proximate surface2149may be urged against an underside of the fingered member2176). The proximate surface2149may be an angled surface or taper of wedge mandrel2114. Other components may be positioned proximate to the underside (or end2175) of fingered member2175, such as an insert2199. As the fingered member2176and the surface2149are urged together, the fingers2177may be resultantly urged radially outward toward the inner surface of the tubular (2108,FIG. 22A). One or more ends2175of corresponding fingers2177may eventually come into contact with the tubular (see contact point2186). Ends2175(of fingers) may be configured (such as by machining) with an end taper2174.

The use of an end taper2174may be multipurpose. For example, if the tool2102needs to be removed (or moved uphole) prior to setting, the ends2175of the fingers2177may be less prone to catching on surfaces as the tool2102moves uphole. In addition, the ends2175of the fingers2175may have more surface area contact with the tubular.

The surface2149may be smooth and conical in nature, which may result in smooth, linear engagement with the fingered member2176. The angled surface2149may transition to a more or less axial surface2149a(i.e., a surface that is about parallel to a longitudinal axis2158).

In aspects, the outer surface of the wedge mandrel2114may be configured with a detent (or notch)2170, approximately at the transition point from angled surface2149to axial surface2149a. In the assembled position, the ends2175of the fingers2177may reside or be positioned within or proximate to the detent2170. The arrangement of the ends2175within the detent2170may prevent inadvertent operation of the fingered member2176. In this respect, a certain amount of setting force is required to “bump” the ends of the fingers2177out of and free of the detent2170so that the fingered member2176and the surface2149can be urged together, and the fingers2177extended outwardly. As shown inFIGS. 14A and 14B, the insert2199may be directly proximate to the detent2170, and thus between the detent2170and the finger ends2177. In this respect, a certain amount of setting force may be required to “bump” the insert2199out of and free of the detent2170so that it may be urged along the surface2149.

The fingered member2176may be referred to as having a “transition zone”2110, essentially being the part of the member where the fingers2177begin to extend away from the body2195. In this respect, the fingers2177are connected to or integral with the body2195. In operation as the fingers2177are urged radially outward, a flexing (or partial break or fracture) may occur within the transition zone2110. The transition zone2110may include an outer surface2137and inner surface2129. The outer surface2137and inner surface2129may be separated by a portion or amount of material2185. The fingered member2176may be configured so that flexing, break or fracture may occur or otherwise be promoted within the material2185. Flexing or fracture may be induced within the material as a result of one or more grooves. For example, the inner surface2137may have a first finger groove2111. The outer surface2137may in addition or alternatively have a finger groove, such as a second finger groove2113.

The presence of the material2185may provide a natural “hinge” effect whereby the fingers2177become moveable from the body (ring)2195, such as when the fingered member2176is urged against surface2149. After setting one or more fingers2177may remain at least partially connected with body2195in the transition zone2110. The presence of the material2185may promote uniform flexing of the fingers2177. The length of the fingers2177and/or amount of material2185are operational variables that may be modified to suit a particular need for a respective annulus size.

Upon setting, there may be a seal2125formed in tool annulus2190. A side2115of the shoulder2184may act as a stop against components therebelow, including a backup ring2157a. Thus, the compression between the seal element2122and the backup rings2157a,bmay contribute to the formed seal. The formed seal2125may withstand pressurization of greater than 10,000 psi. In an embodiment, the seal2125withstands pressurization in the range of about 5,000 psi to about 15,000 psi.

The Figures illustrate the downhole tool2102may include other components, such as the seal element2122. The seal element2122may 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 wedge mandrel2114. The seal element2122may have an inner circumferential groove2123. The presence of the groove2123may assist the seal element2122to initially buckle upon start of the setting sequence. The groove2123may have a size (e.g., width, depth, etc.) of about 0.25 inches.

On either side of the seal element may be a backup ring. As shown there may be a first backup ring2157aand a second backup ring2157b. In the assembled configuration, the insert2199may be positioned between the ends2175of the fingers2177and the second backup ring2157b.

The fingers2177may have a respective gripper insert2191fitted or otherwise disposed therein. Although not limited to any particular number, type or size, there may be a respective gripper insert2191disposed in the finger(s)2177. The gripper insert2191may be positioned within a window (or hole, opening, etc.)2188formed in any respective finger2177. Although not necessary, the window2188may extend the entire depth of the thickness of the finger2177. In this respect, the gripper insert2191may be positioned therein, wherein its underside may be proximate to the wedge mandrel outer surface. Although illustrated as such, every finger2177need not have a window2188and/or gripper insert2191. Moreover, the fingers2177need not have any windows2188and/or inserts2191at all. Although not shown here, buttons2180may be disposed directly into the fingers2177.

The fingered member2176may have one or more recessed regions (or hole, opening, etc.)2128to accommodate respective dogs2120of the support platform2121. Similarly, the wedge mandrel2114may have one or more mandrel windows2119also to accommodate respective dogs2120of the support platform2121.

Components of the downhole tool2102may be arranged and disposed about the wedge mandrel2114, as described herein and in other embodiments, and as otherwise understood to one of skill in the art. Thus, downhole tool2102may be comparable or identical in aspects, function, operation, components, etc. as that of other tool embodiments provided for herein, and redundant discussion is limited for sake of brevity, while structural (and functional) differences are discussed in with detail, albeit in a non-limiting manner.

The tool2102may be deployed and set with a conventional setting tool (not shown) such as a Model 10, 20 or E-4 Setting Tool available from Baker Oil Tools, Inc., Houston, Tex. Once the tool2102reaches the set position within the tubular, the setting mechanism or workstring may be detached from the tool2102by various methods, resulting in the tool2102left in the surrounding tubular and one or more sections of the wellbore isolated.

Referring now toFIGS. 15A and 15Btogether, an isometric view and a longitudinal side cross-sectional view of a wedge mandrel usable with a downhole tool, in accordance with embodiments disclosed herein, are shown. Components of the downhole tool may be arranged and disposed about the wedge mandrel2114, as described and understood to one of skill in the art, and may be comparable to other embodiments disclosed herein (e.g., see downhole tool202with mandrel214).

The wedge mandrel2114, which may be made from filament wound drillable material, may have a distal end2146and a proximate end2148. The filament wound material may be made of various angles as desired to increase strength of the wedge mandrel2114in axial and radial directions.

The wedge mandrel2114may include a flowpath (or bore, flowbore, etc.)2151formed therethrough (e.g., an axial bore). The2151, for example an axial bore, may extend through the entire wedge mandrel2114, with openings at both the proximate end2148and oppositely at its distal end2146. Accordingly, the wedge mandrel2114may have an inner bore surface2147, which may include one or more threaded surfaces2116formed thereon.

The ends2146,2148of the wedge mandrel2114may include internal or external (or both) threaded portions. As shown, the wedge mandrel2114may have internal threads2116within the bore2151configured to receive a ball seat insert (not shown here). In an embodiment, the first set of threads2116may be rounded threads.

The outer surface of the wedge mandrel2114may include a neck or transition portion surface2149, such that the mandrel may have variation with its outer diameter. In an embodiment, the wedge mandrel2114may have a first outer diameter D21that is greater than a second outer diameter D22. The transition surface may have an angle with respect to the tool (or tool component axis). The angled surface2149may end or otherwise transition to an axial external surface2149a. There may be a bump or detent2170formed therebetween.

In addition to the first set of threads2116, the wedge mandrel2114may have a second set of threads2117. In one embodiment, the second set of threads2117may be rounded threads disposed along an external mandrel surface at the distal end346. The use of rounded threads may increase the strength of the threaded connection.

For example, when mated with a lower sleeve (2160) having corresponding rounded threads, this may result in distribution of load forces along the threaded connection therebetween at an angle away from the long axis. 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.

Although described and shown as rounded, the threads2116and2117could be other thread profiles, including those suitable for use in filament wound composite material.

The wedge mandrel2114may have a shoulder2184on the proximate end2148. One side of the shoulder2184may be compressible against an end (2155) of a setting sleeve (2154) during setting. Another side2115of the shoulder2184may act as a stop against components therebelow, including a backup ring2157a.

On occasion it may be necessary or otherwise desired to produce a fluid from the formation while leaving a set plug in place. The ID of a conventional bore size (1 inch or less) is normally adequate to allow drop balls to pass therethrough, but may be inadequate for production. In order to produce desired fluid flow, it often becomes necessary to drill out a set tool—this requires a stop in operations, rig time, drill time, and related operator and equipment costs.

On the other hand, the presence of the oversized ID2131of bore2151, and thus a larger cross-sectional area as compared to bore250, provides effective and efficient production capability through the tool2102without the need to resort to drilling of the tool. The ID2131may be in the range of about greater than 1 inch to less than 4 inches. In an embodiment, the ID2131may be between about 2 inches to about 3 inches.

The wedge mandrel2114may include one or more mandrel windows (or slots, etc.)2119formed therein. Although not meant to be limited to any particular size or shape,FIGS. 15A-15Bshow there may be about three windows2119, which may be generally rectangular in nature.

Although not shown here, it may be the case that the end2148of the wedge mandrel may be configured with a respective wedge mandrel ball seat. One of skill would appreciate a larger ball (as compared to ball2163) may be needed. In embodiments, such a ball may have a diameter of about 2 inches to about 4 inches.

Referring now toFIGS. 16A and 16Btogether, an isometric view and a longitudinal side cross-sectional view of a ball seat insert usable with a downhole tool, in accordance with embodiments disclosed herein, are shown. The ball seat insert2135may be a generally frustoconcial shaped component configured for engagement into the wedge mandrel (2114).

For a downhole tool where there is no concern over bore size, a ball seat may be formed into the mandrel. However, where large bore size (i.e., to accommodate production) is desired, this would require a large diameter ball seat, along with reduced wall thickness of the mandrel. This may be structurally limiting, and so use of the ball seat insert2135may be useful to overcome these shortcomings (seeFIG. 22Cwhere the ball seat insert provides axial support against radial forces incurred during setting of the downhole tool2102, and radial support for pressure/collapse).

In embodiments, the ball seat insert2135may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD. Just the same, the insert2135may be made of reactive composite material formed from an initial mixture composition of embodiments herein. As another example, the ball seat may be made of a metal material like that produced by Bubbletight, LLC of Needville, Tex., as would be apparent to one of skill in the art, including fresh-water reactive composite metal, ambient-temperature fresh-water reactive composite metal, ambient-temperature fresh-water reactive elastomeric polymer, and high-strength brine-degradable reactive metal.

Other components may be made of materials as described herein, including reactive composite, cured, and metal materials.

Generally speaking, the material of ball seat insert2135may be configured to react. The time to react from start to finish (i.e., to the point where the ball seat insert no longer has a durable threaded connection with the wedge mandrel—seeFIG. 22D) may be in the range of about 3 hours to about 48 hours.

The ball seat insert2135may be configured to include one or more holes2130formed therein. Although not meant to be limited to any particular number, shape, orientation, or size, the holes2130may be longitudinal in orientation through the insert2135. The presence of one or more holes2130may result in the surface(s) of the insert2135having greater exposure to the fluid that promotes reactivity of the material. One or more holes2130may extend entirely through the ball seat insert. However, other holes2130may only extend to a certain depth, such as shown inFIG. 16B. The holes2130may be optimized to promote the most surface contact, yet at the same time not detract from the durability and pressure integrity of the insert2135.

The ball seat insert2135may have a set of insert threads2145. The insert threads2145may be configured to mate with corresponding threads (i.e.,2116) of the wedge mandrel (2114). Although not meant to be limited, the threads2145may be rounded threads.

The ball seat insert2135may have an insert hollow or bore2139, which may be suitable for the adapter shaft (2153) to pass therethrough. The wider end of the insert2135may have an insert groove2142, which may be generally circumferential in nature. The insert groove2142may be suitable for fitting an O-ring therein.

The insert2135may be configured with a ball seat surface2159such that a drop ball may come to rest and seat at in the seat. As applicable, the drop ball (not shown here) may be lowered into the wellbore and flowed toward the drop ball seat2159. Alternatively, the ball may be held within the tool during run-in, thus alleviating the need for flowdown. The ball seat2159may be formed with a radius2159a(i.e., circumferential rounded edge or surface).

Referring now toFIGS. 17A and 17Btogether, an isometric view and a longitudinal side cross-sectional view of a fingered member usable with a downhole tool, in accordance with embodiments disclosed herein, are shown. Although many configurations are possible, the fingered member2176may generally have a circular body (or ring shaped) portion2195configured for positioning on or disposal around the wedge mandrel (2114). Extending from the circular body portion may be two or more fingers (dogs, protruding members, etc.)2177. Although not meant to be limiting, the fingered member2176may be made from a filament wound composite material in accordance with embodiments herein, and as would be apparent to one of skill in the art. The fingered member2176may be made from a reactive material, such as that made from an initial mixture composition described herein. The reactive material may be a cured material.

The fingered member2176may include a plurality of fingers2177. In embodiments, there may be a range of about 6 to about 12 fingers2177. The fingers2177may be configured symmetrically and equidistantly to each other. Fingers2177may be formed with a gap or separation point2181therebetween. The size of the fingers2177in terms of width, length, and thickness, and the number of fingers2177may be optimized in a manner that results in the greatest ability to seal an annulus (2190, compareFIGS. 22A and 22C). Ends2175(of fingers) may be configured (such as by machining) with an end taper2174.

The fingered member2176may be referred to as having a “transition zone”2110, essentially being the part of the member where the fingers2177begin to extend away from the body2195. In this respect, the fingers2177are connected to or integral with the body2195. In operation as the fingers2177are urged radially outward, a flexing (or partial break or fracture) may occur within the transition zone2110. The transition zone2110may include an outer surface2137and inner surface2129. The outer surface2137and inner surface2129may be separated by a portion or amount of material2185. The fingered member2176may be configured so that the flexing, break or fracture occurs within the material2185. Flexing or fracture may be induced within the material as a result of one or more grooves.

The fingers2177may have a respective gripper insert or carriage2191fitted or otherwise disposed therein. Although not limited to any particular number, type or size, there may be a respective gripper insert2191disposed in the finger(s)2177.

In embodiments, the gripper insert2191may be a poly-moldable material. In other embodiments, the gripper insert2191may be a durable metal, such as cast iron. In aspects, the insert2191may be hardened, surface hardened, heat-treated, carburized, etc., as would be apparent to one of ordinary skill in the art.FIG. 17Cillustrates the gripper insert2191disposed in the finger end2175as being configured with serrated teeth2198.

The gripper insert2191may be treated with an induction hardening process. In such a process, block or ring of metal may be moved through a coil that has a current run through it. As a result of physical properties of the metal and magnetic properties, a current density (created by induction from the e-field in the coil) may be controlled in a specific location. The insert2191may be machined from this treated metal. Such a process may lend to speed, accuracy, and repeatability in modification of the hardness profile of the gripper insert2191. As such, for example, the teeth2198may have a RC in excess of 60, and the rest of the insert2191(essentially virgin, unchanged metal) may have a RC less than about 15. In embodiments the gripper insert2191may be made of a reactive material in accordance with embodiments herein.

During heat treatment of the insert itself, the teeth2198may heat up and harden resulting in heat-treated outer area/teeth, but not the rest of the insert. 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 teeth2198. Serrated outer surfaces or teeth2198of the may be configured such that the surfaces2198prevent the fingered member (or tool) from moving (e.g., axially or longitudinally) when the tool is set within the surrounding tubular. The use of the insert2191being made of metal provides bite characteristics normally associated with a metal slip, while at the same time the material of the fingered member2176may be easily drillable composite material. Moreover, the bite area may be enlarged versus that of buttons.

Still, as shown inFIGS. 17A and 17B, the gripper insert2191may be configured within one more buttons2180disposed therein. The buttons2180may be of any durable material suitable to provide sufficient bite into a surrounding tubular, such as ceramic or steel. Any button2180may have a flat surface or concave surface. In an embodiment, the concave surface may include a depression formed therein. One or more of the buttons2180may have a sharpened (e.g., machined) edge or corner2182, which allows the button2180greater biting ability.

The gripper insert2191may be positioned within a window (or hole, opening, etc.)2188formed in any respective finger2177. Although not necessary, the window2188may extend the entire depth of the thickness of the finger2177. In this respect, the gripper insert2191may be positioned therein, wherein its underside may be proximate to the wedge mandrel outer surface. The insert2191may have a tight tolerance fit with the window2188. To aid securing the insert2188therein, an adhesive or the like may be used.

Briefly, an underside of the insert2191may be configured with an abrasive surface2183, such as that shown in side view inFIG. 17D(see also17B). With respect toFIGS. 17A and 17B, the abrasive surface2183may be useful for preventing the fingered member2176from inadvertent movement along mandrel surface2149. In embodiments, the abrasive surface2183may be mini-serrations. One of skill would appreciate that although illustrated as such, every finger2177need not have a window2188and/or gripper insert2191.

The fingered member2176may have one or more recessed regions (or hole, opening, etc.)2128to accommodate respective dogs (2120) of a support platform (2121) Similarly, the wedge mandrel2114may have one or more mandrel windows2114also to accommodate respective dogs2120of the support platform.

Referring now toFIGS. 18A, 18B, and 18Ctogether, a side expanded view, a side collapsed view, and an isometric view, respectively, of an insert, in accordance with embodiments disclosed herein, are shown. The insert2199may have a circular body2187, having a first end2196and a second end2133.

A groove or winding2194may be formed between the first end2196and the second end2133. As the insert2199may be ring-shaped, there may be a hollow2193in the body2187. Accordingly, the insert2199may be configured for positioning onto and/or around the wedge mandrel (2114). The use of the groove2194may be beneficial as while it is desirous for insert2199to have some degree of rigidity, it is also desirous for the insert2199to expand (unwind, flower, etc.) beyond the original OD of the tool, including along the angled surface of the wedge mandrel

In this respect, the insert2199may be made of a high elongation material (e.g., physical properties of ˜100% elongation). Insert2199material may be glass or carbon fiber or nanocarbon/nanosilica reinforced. The insert2199may durable enough to withstand compressive forces, but still expand or otherwise unwind upon being urged outwardly by the wedge mandrel. The insert2199may be made of PEEK (polyether ether ketone).

The groove2194may be continuous through the body2197. However, the groove2194may be discontinuous, whereby a plurality of grooves are formed with (or otherwise defined by) a material portion present between respective grooves. The groove(s)2197may be helically formed in nature resulting in a ‘spring-like’ insert. An edge2192of the first end2196may be positionable within a notch or detent (2170) of the wedge mandrel Although not shown, a filler may be disposed within the groove(s)2194. Use of the filler may help provide stabilization to the tool (and its components) during run-in. In embodiments, the filler may be made of silicone.

To maintain the collapsed position of the insert2197, a securing member2144may be used. Accordingly, the insert2197may be configured with an insert bore2144a. In an embodiment, the securing member2144may be a nylon screw.

Referring now toFIGS. 19A and 19Btogether, an engaged side view and an exploded side view, respectively, of a seal element between a first and second backup ring, in accordance with embodiments disclosed herein, are shown.

The seal element2122may 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 element322may be made from 75 to 80 Duro A elastomer material. The seal element322may be disposed between a first backup ring2157aand a second backup ring2157b. In a similar manner, the backup rings2157a,bmay be made of an elastomeric and/or poly material, such as rubber, nitrile rubber, Viton or polyeurethane. In an embodiment, the backup rings2157a,bmay be made from 75 to 80 Duro A elastomer material. In an embodiment, the backup rings2157a,bmay be made from PEEK, Teflon, or nylon type material.

The seal element2122may 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 element2122may buckle, the seal element2122may also be adapted to expand or swell, such as in a radial manner, into sealing engagement with the surrounding upon compression of the tool components. In aspects, the seal element2122may be suitable to provide a fluid-tight seal of the seal surface against the tubular. The seal element322may be configured with an inner circumferential groove (2123,FIG. 14C).

The seal element2122may have one or more angled surfaces configured for contact with other component surfaces proximate thereto. For example, the seal element may have angled surfaces2140aand2140b. Respective underside grooves (not viewable here) of the first backup ring2157aand the second backup ring2157bmay be configured for mating with the angled surfaces2140aand2140b.

Referring now toFIGS. 20A and 20Btogether, an isometric view and a lateral side view of a support platform usable with a downhole tool, in accordance with embodiments disclosed herein, are shown. The support plate2121may be a generally round shaped component configured for engagement into the wedge mandrel (2114).

During setting, the support plate2121will be pulled as a result of its attachment to the setting tool (via elongated shaft2153). As the support plate2121is pulled, the components disposed about the wedge mandrel between the may further compress against one another.

In embodiments, the support plate2121may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD. Just the same, the support plate2121may be made of reactive composite material formed from an initial mixture composition of embodiments herein. As another example, the ball seat may be made of a metal material like that produced by Bubbletight, LLC of Needville, Tex., as would be apparent to one of skill in the art, including fresh-water reactive composite metal, ambient-temperature fresh-water reactive composite metal, ambient-temperature fresh-water reactive elastomeric polymer, and high-strength brine-degradable reactive metal.

Generally speaking, the material of support plate2121may be configured to react. The time to react from start to finish (i.e., to the point where the support plate no longer has a durable engagement with the wedge mandrel—compare22C with22D) may be in the range of about 3 hours to about 48 hours.

The support plate2121may be configured to include one or more holes2134formed therein. Although not meant to be limited to any particular number, shape, orientation, or size, the holes2134may be longitudinal in orientation through the plate2121. The presence of one or more holes2134may result in the surface(s) of the support plate2121having greater exposure to the fluid that promotes reactivity of the material. One or more holes2134may extend entirely through the ball seat insert. However, other holes2134may only extend to a certain depth. The holes2134may be optimized to promote the most surface contact, yet at the same time not detract from the durability of the support plate2121.

The support plate2121may have a plate hollow or bore2138, which may be suitable for the adapter shaft (2153) to fit and engage therein. Accordingly, the support plate2121may have a set of plate threads2124. The plate threads2124may be configured to mate with corresponding threads (i.e.,2156) of the elongated setting tool adapter shaft2153. Although not meant to be limited, the threads2124may be shear threads.

The body of the support plate may include one or more protruding member or dogs2120. As shown there may be about three dogs2120. An uphole side2109of the dogs may be engaged with an end of a fingered member (seeFIG. 22B, end2174aengaged with uphole side2109).

Referring now toFIGS. 21A and 21Btogether, an isometric view and a longitudinal side view of a lower sleeve usable with a downhole tool, in accordance with embodiments disclosed herein, are shown. The lower sleeve2160may be a generally round shaped component configured for engagement into the wedge mandrel (2114). The lower sleeve2160may be made of filament wound composite material. In other embodiments, the lower sleeve2160may be made of a reactive material, such as that described herein.

The lower sleeve2160may be in threaded engagement with the mandrel214by virtue of the coupling of mandrel threads (2117) and sleeve threads2162. The lower sleeve2160may have one or more tapered surfaces361,361A which may reduce chances of hang up on other tools. The lower sleeve360may also have an angled sleeve end363in engagement with, for example, the first slip (234,FIG. 2C).

Although not shown here, one or more anchor pins may be disposed or securely positioned laterally through the lower sleeve2160and into engagement with the wedge mandrel. In an embodiment, brass set screws may be used. Pins (or screws, etc.) may prevent shearing or spin off during drilling.

Referring now toFIGS. 22A, 22B, 22C, and 22Dtogether, a longitudinal cross-sectional view of a system having downhole tool run to a location within a tubular, a longitudinal side cross-sectional view of the downhole tool ofFIG. 22Amoved to a set position, a longitudinal side cross-sectional view of the downhole tool ofFIG. 22Aset in a tubular and separated from a workstring, and a longitudinal side cross-sectional view of a the downhole tool ofFIG. 22Ahaving various internal components removed therefrom, respectively, in accordance with embodiments disclosed herein, are shown.

System2100may include a wellbore2106formed in a subterranean formation with a tubular2108disposed therein. A workstring2112(shown only partially here and with a general representation, and which may include a part of a setting tool or device coupled with adapter2152) may be used to position or run the downhole tool2102into and through the wellbore2106to a desired location.

The downhole tool2102may be configured, assembled, run, set, and usable in a similar manner to tool embodiments described herein and in other embodiments (such as in System200, and so forth), and as otherwise understood to one of skill in the art. Components of the downhole tool2102may be arranged and disposed about a wedge mandrel2114, as described herein and comparable to other embodiments, and as otherwise understood to one of skill in the art. Thus, downhole tool2102may be comparable or identical in aspects, function, operation, components, etc. as that of other tool embodiments disclosed herein.

The wedge mandrel2114may be made of a material as described herein and in accordance with embodiments of the disclosure, such as a composite filament wound material made by the Applicant. The wedge mandrel2114may be made other materials, such as a metallic material, for example, an aluminum-based, magnesium-based, or aluminum-magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions that wedge mandrel2114may begin to dissolve, and thus alleviating the need for drill thru. Just the same, the wedge mandrel may be made of reactive composite material formed from an initial mixture composition of embodiments herein.

Downhole tool2102may include a lower sleeve2160disposed around the wedge mandrel2114. The lower sleeve2160may be threadingly engaged with the mandrel2114. As a support platform2121is pulled in tension, various components disposed about mandrel2114between the support platform2121and a setting sleeve (2154,FIG. 22A) may begin to compress against one another. This force and resultant movement may ultimately cause compression and expansion of a seal element2122.

Additional tension or load may be applied to the tool2102that results in movement of the wedge mandrel2114against a fingered member2176. Accordingly, via interaction with angled surfaces of each other, one or more ends2175of the fingered member2176may be urged radially outward and into engagement with tubular2108. The fingered member2176may be movingly (such as slidingly) engaged and disposed around the wedge mandrel2114.

The setting sleeve2154may engage against a shoulder2184of the wedge mandrel2114, which may accommodate to or provide ability for the transfer load through the rest of the tool2102. The setting sleeve may be a grooved setting sleeve in accordance with embodiments herein.

Although many configurations are possible, the fingered member2176may generally have a circular body (or ring shaped) portion2195configured for positioning on or disposal around the wedge mandrel2114. Extending from the circular body portion may be two or more fingers (dogs, protruding members, etc.)2177. In the assembled tool configuration, the fingers2177may be referred to as facing “uphole” or toward the top (proximate end) of the tool2102.

The fingered member2176may include a plurality of fingers2177. In embodiments, there may be a range of about 6 to about 12 fingers2177. The fingers2177may be configured symmetrically and equidistantly to each other. As the fingers2177are urged outwardly they may provide a synergistic effect of centralizing the downhole tool2102, which may be of greater benefit in situations where the surrounding tubular has a horizontal orientation.

During setting, the fingered member2176(including fingers2177, with respective underside2197) may be urged along a proximate surface2149(or vice versa, the proximate surface2149may be urged against an underside of the fingered member2176). The proximate surface2149may be an angled surface or taper of wedge mandrel2114. Other components may be positioned proximate to the underside (or end2175) of fingered member2175, such as an insert2199. As the fingered member2176and the surface2149are urged together, the fingers2177may be resultantly urged radially outward toward the inner surface of the tubular2108. One or more ends2175of corresponding fingers2177may eventually come into contact with the tubular (such as at contact point2186). Ends2175(of fingers) may be configured (such as by machining) with an end taper. The ends2175of the fingers2177may have surface area contact with the tubular2108, as illustrated by a length2189of contact surfaces (proximate to contact point2186).

The surface2149may be smooth and conical in nature, which may result in smooth, linear engagement with the fingered member2176. The angled surface2149may transition to a more or less axial surface2149a(i.e., a surface that is about parallel to a longitudinal axis2158).

In aspects, the outer surface of the wedge mandrel2114may be configured with a detent (or notch)2170, approximately at the transition point from angled surface2149to axial surface2149a. In the assembled position, the ends2175of the fingers2177may reside or be positioned within or proximate to the detent2170. The arrangement of the ends2175within the detent2170may prevent inadvertent operation of the fingered member2176. In this respect, a certain amount of setting force is required to “bump” the ends of the fingers2177out of and free of the detent2170so that the fingered member2176and the surface2149can be urged together, and the fingers2177extended outwardly. As shown, the insert2199may be directly proximate to the detent2170, and thus inbetween the detent2170and the finger ends2177. In this respect, a certain amount of setting force is required to “bump” the insert2199out of and free of the detent2170so that it may be urged along the surface2149.

The fingered member2176may be referred to as having a “transition zone”2110, essentially being the part of the member where the fingers2177begin to extend away from the body2195. In this respect, the fingers2177are connected to or integral with the body2195. In operation as the fingers2177are urged radially outward, a flexing (or partial break or fracture) may occur within the transition zone2110. The transition zone2110may include an outer surface2137and inner surface2129. The outer surface2137and inner surface2129may be separated by a portion or amount of material2185. The fingered member2176may be configured so that the flexing, break or fracture occurs within the material2185. Flexing or fracture may be induced within the material as a result of one or more grooves. For example, the inner surface2137may have a first finger groove2111. The outer surface2137may in addition or alternatively have a finger groove, such as a second finger groove2113.

The presence of the material2185may provide a natural “hinge” effect whereby the fingers2177become moveable from the body (ring)2195, such as when the fingered member2176is urged against surface2149. After setting one or more fingers2177may remain at least partially connected with body2195in the transition zone2110. The presence of the material2185may promote uniform flexing of the fingers2177. The length of the fingers2177and/or amount of material2185are operational variables that may be modified to suit a particular need for a respective annulus size.

As shown in the Figures, the downhole tool2102may include other components, such as the seal element2122. The seal element2122may 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 wedge mandrel2114. The seal element2122may have an inner circumferential groove2123. The presence of the groove2123may assist the seal element2122to initially buckle upon start of the setting sequence. The groove2123may have a size (e.g., width, depth, etc.) of about 0.25 inches.

On either side of the seal element may be a backup ring. As shown there may be a first backup ring2157aand a second backup ring2157b. In the assembled configuration, the insert2199may be positioned between the ends2175of the fingers2177and the second backup ring2157b.

The fingers2177may have a respective gripper insert2191fitted or otherwise disposed therein. Although not limited to any particular number, type or size, there may be a respective gripper insert2191disposed in the finger(s)2177. The gripper insert2191may be positioned within a window (or hole, opening, etc.) formed in any respective finger2177. In this respect, the gripper insert2191may be positioned therein, wherein its underside may be proximate to the wedge mandrel outer surface.

The fingered member2175may have one or more recessed regions (or hole, opening, etc.) to accommodate respective dogs2120of the support platform2121. Similarly, the wedge mandrel2114may have one or more mandrel windows2119also to accommodate respective dogs2120of the support platform.

Components of the downhole tool2102may be arranged and disposed about the wedge mandrel2114, as described herein and in other embodiments, and as otherwise understood to one of skill in the art. Thus, downhole tool2102may be comparable or identical in aspects, function, operation, components, etc. as that of other tool embodiments provided for herein, and redundant discussion is limited for sake of brevity, while structural (and functional) differences are discussed in with detail, albeit in a non-limiting manner.

The tool2102may be deployed and set with a conventional setting tool (not shown) such as a Model 10, 20 or E-4 Setting Tool available from Baker Oil Tools, Inc., Houston, Tex. Once the tool2102reaches the set position within the tubular, the setting mechanism or workstring may be detached from the tool2102by various methods, resulting in the tool2102left in the surrounding tubular and one or more sections of the wellbore isolated.

Once the tool2102reaches the set position within the tubular2108, the setting mechanism or workstring2112may be detached from the tool2102by various methods, resulting in the tool2102left in the surrounding tubular, whereby one or more sections of the wellbore may be isolated.

In an embodiment, once the tool2102is set, tension may be further applied to the setting tool/adapter2152until the elongated stud2153is detached from the support platform2120. The amount of load applied to the adapter2152may cause separation (disconnect via tensile failure) in the range of about, for example, 20,000 to 40,000 pounds force. The load may be about 25,000 to 30,000 pounds force. In other applications, the load may be in the range of less than about 10,000 pounds force.

The adapter2152may include the stud2153configured with the threads thereon. In an embodiment, the stud may have external (male) threads and the wedge mandrel2114may have 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 adapter2152may be made of a durable material, such as a metal or alloy like 4140 steel alloy. Although not necessary, there may be an adapter port2153awithin the stud2153, which may be useful to provide pressure equalization. The stud2153may have a lateral (outer) diameter suitable enough for passing through bores2138,2139. In aspects, the lateral diameter may be about 1 inch. The lateral diameter may be in the range of about 0.5 inches to about 1.5 inches. The bores2138,2139may have a comparable inner diameter.

Accordingly, the adapter2152may separate or detach from the downhole tool2102, resulting in the workstring2112being able to separate from the tool2102, 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.

Referring briefly toFIG. 22E, a close-up side cross-sectional view of an alternative adapter connection to a downhole tool, in accordance with embodiments of the disclosure, is shown. As shown, stud2153may alternatively connect to a lower ring2121a. In this respect, the stud2153may pass through a bore2138of a support plate2121(instead of engaging therewith) and instead threadingly engage into the lower ring2121a. The lower ring2121amay be made of filament wound composite material, which may be configured with shear threads. This type of configuration may be useful for predictability of shearing versus that of shearing from the metal support plate2121.

Referring again to22A-22D, the downhole tool2102may include the wedge mandrel2114configured with a bore2151, and a respective inner bore surface2147. The inner surface2147may include one or more threaded surfaces formed thereon. As such, there may be a first set of threads2116configured for coupling the wedge mandrel2114with corresponding threads2145of a ball seat insert2135. Although not meant to be limited, each of these threads may be rounded threads.

The ball seat insert2135may be made of a material of embodiments herein, such as a reactive material (which may be metallic or plastic in nature). The ball seat insert2135may be configured to include one or more holes2130formed therein. Although not meant to be limited to any particular number, shape, orientation, or size, the holes2130may be longitudinal in orientation through the insert2135. The presence of one or more holes2130may result in the surface(s) of the insert2135having greater exposure to the fluid that promotes reactivity of the material. One or more holes2130may extend entirely through the ball seat insert. However, other holes2130may only extend to a certain depth.

The ball seat insert2135may have an insert hollow or bore2139, which may be suitable for the adapter shaft2153to pass therethrough. The wider end of the insert2135may have an insert groove, which may be generally circumferential in nature. The insert groove may be suitable for fitting an o-ring2179therein.

The insert2135may be configured with a ball seat surface2159such that a drop ball may come to rest and seat at in the seat. As applicable, the drop ball (not shown here) may be lowered into the wellbore and flowed toward the drop ball seat2159. Alternatively, the ball may be held within the tool during run-in, thus alleviating the need for flowdown. The ball seat2159may be formed with a radius (i.e., circumferential rounded edge or surface).

The downhole tool2102may be run into wellbore to a desired depth or position by way of the workstring2112that may be configured with the setting device or mechanism. The workstring2112and setting sleeve2154may be part of the system2100utilized to run the downhole tool2102into the wellbore, and activate the tool2102to move from an unset (e.g.,21A) to set position (e.g.,21C). Although not meant to be limited to any particular type or configuration, the setting sleeve2154may be like of that other embodiments disclosed herein, such as that ofFIGS. 11A-11C. Briefly,FIG. 21Billustrates how compression of a sleeve end2155with a should end2184of the wedge mandrel2114may occur at the beginning of the setting sequence, whereby subsequently tension may increase through the tool2102.

Although not shown here, the downhole tool2102may include an anti-rotation assembly that includes an anti-rotation device or mechanism (e.g., see282,FIGS. 2C and 2D, and related text), which may be a spring, a mechanically spring-energized composite tubular member, and so forth. The device may be configured and usable for the prevention of undesired or inadvertent movement or unwinding of the tool2102components.

On occasion it may be necessary or otherwise desired to produce a fluid from the formation while leaving a set plug in place. However, an inner diameter (ID) of a bore (e.g.,250,FIG. 2D) in a mandrel (214) may be too narrow to effectively and efficiently produce the fluid—thus in embodiments it may be desirous to have an oversized ID2131through the tool2102. The ID of a conventional bore size is normally adequate to allow drop balls to pass therethrough, but may be inadequate for production. In order to produce desired fluid flow, it often becomes necessary to drill out a set tool—this requires a stop in operations, rig time, drill time, and related operator and equipment costs.

On the other hand, the presence of the oversized ID2131of bore2151, and thus a larger cross-sectional area as compared to bore250, provides effective and efficient production capability through the tool2102without the need to resort to drilling of the tool. However, a reduced wall thickness2127of mandrel2114may be problematic to the characteristics of the tool2102, especially during the setting sequence. This may especially be the case for composite material.

As a large bore2151may result in reduced wall thickness2127, this may in turn reduce tensile strength and collapse strength. As such the downhole tool2102may be configured in a manner to withstand the setting sequence, but yet be able to provide the oversized ID2131.

In accordance with the disclosure, components of tool2102may be made of reactive materials (e.g., materials suitable for and are known to dissolve in downhole environments [including extreme pressure, temperature, fluid properties, etc.] after a brief or limited period of time (predetermined or otherwise) as may be desired). In an embodiment, a component made of a reactive material may begin to dissolve within about 3 to about 48 hours after setting of the downhole tool.

In aspects, the wedge mandrel2114may be made a material made from a composition described herein. The wedge mandrel2114may be made of a material that is adequate to provide durability and strength to the tool2102for a sufficient amount of time that includes run-in, setting and frac.

The downhole tool2102may include the wedge mandrel2114extending through the tool (or tool body)2102, such that other components of the tool2102may be disposed therearound. The wedge mandrel2114may include the flowpath or bore2151formed therein (e.g., an axial bore). The bore2151may extend partially or for a short distance through the mandrel2114, or the bore2151may extend through the entire wedge mandrel2114, with an opening at its proximate end2148and oppositely at its distal end2146.

The presence of the bore or other flowpath through the wedge mandrel2114may indirectly be dictated by operating conditions. That is, in most instances the tool2102may be large enough in outer diameter (e.g., in a range of about 4-5 inches) such that the bore2151may be correspondingly large enough (e.g., 3-4 inches) so that fluid F may be produced therethrough. One of skill would appreciate these ranges may generally be applicable to a 5.5″ casing and that scale may be modified for the tool and any of its components as applicable to changes in casing ID.

As illustrated, the ball seat insert2135may be disposed at a depth (or length, distance, etc.) D from the proximate mandrel end2148. The depth D may be of a distance whereby the ball seat2159may be proximately unaligned to where the seal element2122is initially positioned, as shown inFIG. 22A.

The location of the ball seat2159at depth D may be useful to obtain additional lateral strength once the ball2163rests therein. That is, significant forces are felt by the mandrel during the setting sequence, especially in the area of where the sealing element2122is energized, as well as pressure differential between the annulus external to the tool and the bore2151(in some instances the differential may be in the range about 10,000 psi). These forces may be transferred laterally through the wedge mandrel2114, and since the mandrel2114may have a limited wall thickness2127, there exists the possibility of collapse; however, the ball2163, in conjunction with the ball seat insert2135, may provide added strength and reinforcement in the lateral direction.

FIG. 22Cillustrates how, upon setting, the ball2163may be urged against the ball seat2159. In embodiments, a middle region of the energized sealing element2122may be substantially laterally proximate to a middle ball section of the ball2163. Thus, the seal element2122may be movable along surface2149.

The amount of pressure required to urge and wedge the ball2163against the ball seat2159may be predetermined. Thus, the size of the ball2163(e.g., ball diameter2132), ball seat2159, and radius (2159a) may be designed, as applicable.

The ball seat2159may be configured in a manner so that when2163seats therein, a flowpath through the wedge mandrel may be closed off (e.g., flow through the bore is restricted by the presence of the ball). The ball2163may be made of a composite material, whereby the ball2163may be capable of holding maximum pressures during downhole operations (e.g., fracing). In aspects, the ball2163may be made of a reactive material of embodiments herein.FIG. 22Aillustrates how the downhole tool2102may have a ‘ball in place’ configuration, whereby the ball is disposed within the tool during setup, and thus alleviating the need for flowdown. Upon removable of the shaft2153from the insert bore2139, the ball2163will be free to move into the seat2159.

The support plate2121may be a generally round shaped component configured for engagement into the wedge mandrel2114. During setting, the support plate2121will be pulled as a result of its attachment to the setting tool (via elongated shaft2153). As the support plate2121is pulled, the components disposed about the wedge mandrel2114and between the support plate2121and end2155of setting sleeve2154may further compress against one another.

In embodiments, the support plate2121may be made of a material of embodiments herein, such as a reactive material (which may be metallic or plastic in nature). Generally speaking, the material of support plate2121may be configured to react. The time to react from start to finish (i.e., to the point where the support plate no longer has a durable engagement with the wedge mandrel2114may be in the range of about 3 hours to about 48 hours.

The support plate2121may be configured to include one or more holes2134formed therein. Although not meant to be limited to any particular number, shape, orientation, or size, the holes2134may be longitudinal in orientation through the plate2121. The presence of one or more holes2134may result in the surface(s) of the support plate2121having greater exposure to the fluid that promotes reactivity of the material. One or more holes2134may extend entirely through the ball seat insert. However, other holes2134may only extend to a certain depth. The holes2134may be optimized to promote the most surface contact, yet at the same time not detract from the durability of the support plate2121.

The support plate2121may have a plate hollow or bore2138, which may be suitable for the adapter shaft (2153) to fit and engage therein. Accordingly, the support plate2121may have a set of plate threads2124. The plate threads2124may be configured to mate with corresponding threads (i.e.,2156) of the elongated setting tool adapter shaft2153. Although not meant to be limited, the threads2124may be shear threads.

The body of the support plate may include one or more protruding member or dogs2120. As shown there may be about three dogs2120. In the assembled configuration, an uphole side2109of the dogs2120may be engaged with an end surface2174aof a downhole end2173of the fingered member2176.

It should be apparent to one of skill in the art that the tool2102of 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 tool2102is properly set, fluid pressure may be increased in the wellbore2106, such that further downhole operations, such as fracture in a target zone, may commence.

The downhole tool2102may have one or more components 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. The downhole tool2102may have one or more components made of non-composite material, such as a metal or metal alloys. The downhole tool2102may have one or more components made of a reactive material (e.g., dissolvable, degradable, etc.).

Accordingly, components of tool2102may be made of non-dissolvable materials (e.g., materials suitable for and are known to withstand downhole environments [including extreme pressure, temperature, fluid properties, etc.] for an extended period of time (predetermined or otherwise) as may be desired).

Just the same, one or more components of a tool of embodiments disclosed herein may be made of a reactive material (e.g., a material suitable for and known to dissolve, degrade, etc. in downhole environments [including extreme pressure, temperature, fluid properties, etc.] after a brief or limited period of time (predetermined or otherwise) as may be desired). In an embodiment, a component of the downhole tool made of a reactive material may begin to react within about 3 to about 48 hours after setting of the downhole tool2102.

The reactive material may be formed from an initial or starting mixture composition that may include about 100 parts by weight base resin system that comprises an epoxy with a curing agent (or ‘hardener’). The final composition may be substantially the same as the initial composition, subject to differences from any reaction during curing.

The base resin may be desirably prone to break down in a high temp and/or high pressure aqueous environment. The epoxy may be a cycloaliphatic epoxy resin with a low viscosity and a high glass transition temperature. The epoxy may be characterized by having high adhesability with fibers. As an example, the epoxy may be 3,4-epoxycyclohexylmethyl-3′,4′-epoxycyclohexane-carboxylate.

The hardener may be an anhydride, i.e., anhydride-based. For example, the curing agent may be a methyl carboxylic, such as methyl-5-norborene-2, 3-dicarboxylic anhydride. The hardener may include, and be pre-catalyzed with, an accelerator. The accelerator may be imidazole-based.

The accelerator may help in saving or reducing the curing time.

The ratio of epoxy to curing agent may be in the range of about 0.5 to about 1.5. In more particular aspects, the ratio may be about 0.9 to about 1.0.

Processing conditions of the base resin system may include multiple stages of curing.

The composition may include an additive comprising a clay. The additive may be a solid in granular or powder form. The additive may be about 0 to about 30 parts by weight of the composition of a montmorillonite-based clay. In aspects, the clay may be about 0 to about 20 parts by weight of the composition. The additive may be an organophilic clay.

An example of a suitable clay additive may be CLAYTONE® APA by BYK Additives, Inc.

The composition may include a glass, such as glass bubbles or spheres (including microspheres and/or nanospheres). The glass may be about 0 to about 20 parts by weight of the composition. In aspects, the glass may be about 5 to about 15 parts by weight of the composition.

An example of a suitable glass may be 3M Glass Bubbles 342XHS by 3M.

The composition may include a fiber. The fiber may be organic. The fiber may be a water-soluble fiber. The fiber may be in the range of about 0 to about 30 parts by weight of the composition. In aspects, the fiber may be in the range of about 15 to about 25 parts by weight.

The fiber may be made of a sodium polyacrylate-based material. The fiber may resemble a thread or string shape. In aspects, the fiber may have a fiber length in the range of about 0.1 mm to about 2 mm. The fiber length may be in the range of about 0.5 mm to about 1 mm. The fiber length may be in the range of substantially 0 mm to about 6 mm.

The fiber may be a soluble fiber like EVANESCE™ water soluble fiber from Technical Absorbents Ltd.

The composition is subjected to curing in order to yield a finalized product. A device of the disclosure may be formed during the curing process, or subsequently thereafter. The composition may be cured with a curing process of the present disclosure.

In other embodiments, components may be made of a material that may have brittle characteristics under certain conditions. In yet other embodiments, components may be made of a material that may have disassociatable characteristics under certain conditions.

One of skill in the art would appreciate that the material may be the same material and have the same composition, but that the physical characteristic of the material may change, and thus depend on variables such as curing procedures or downhole conditions.

The material may be a resin. The resin may be an anhydride-cured epoxy material. It may be possible to use sodium polyacrylate fiber in conjunction therewith, although any fiber that has dissolvable properties associated with it

Embodiments herein provide for the ability to produce fluids, such as water, oil, other hydrocarbons, gaseous or liquidous, without having to drill out or remove an isolation tool. This saves time, reduces cost, and allows production to commence, without having to wait on a rig.

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 may be 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.